Document ID: FERC-2023-1134-0001
Agency: ferc
Document Type: Rule
Title: Improvements to Generator Interconnection Procedures and Agreements
Posted Date: 2023-09-06T04:00Z

[Federal Register Volume 88, Number 171 (Wednesday, September 6, 2023)]
[Rules and Regulations]
[Pages 61014-61349]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-16628]

[[Page 61013]]

Vol. 88

Wednesday,

No. 171

September 6, 2023

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Improvements to Generator Interconnection Procedures and Agreements; 
Final Rule

  Federal Register / Vol. 88, No. 171 / Wednesday, September 6, 2023 / 
Rules and Regulations  

[[Page 61014]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM22-14-000; Order No. 2023]

Improvements to Generator Interconnection Procedures and 
Agreements

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission or FERC) 
is adopting reforms to its pro forma Large Generator Interconnection 
Procedures, pro forma Small Generator Interconnection Procedures, pro 
forma Large Generator Interconnection Agreement, and pro forma Small 
Generator Interconnection Agreement to address interconnection queue 
backlogs, improve certainty, and prevent undue discrimination for new 
technologies. The reforms are intended to ensure that the generator 
interconnection process is just, reasonable, and not unduly 
discriminatory or preferential.

DATES: This final rule is effective November 6, 2023.

FOR FURTHER INFORMATION CONTACT: Tristan Kessler (Technical 
Information), Office of Energy Policy and Innovation, 888 First Street 
NE, Washington, DC 20426, (202) 502-6608, [email protected].
    Franklin Jackson (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-6464, 
[email protected].
    Sarah Greenberg (Legal Information), Office of the General Counsel, 
888 First Street NE, Washington, DC 20426, (202) 502-6230, 
[email protected].

SUPPLEMENTARY INFORMATION: 

Table of Contents

Paragraph Numbers

I. Introduction 1
    A. Historical Framework: Order Nos. 2003, 2006, and 845 11.
    B. Regional Transmission Planning and Cost Allocation and 
Generator Interconnection Advance Notice of Proposed Rulemaking 18
    C. Notice of Proposed Rulemaking 20
    D. Joint Federal-State Task Force on Electric Transmission 25
II. Overall Need for Reform 27
    A. NOPR 27
    B. Comments 30
    C. Commission Determination 37
III. Reforms 61
    A. Reforms To Implement a First-Ready, First-Served Cluster 
Study Process 61
    1. Interconnection Information Access 61
    2. Cluster Study Process 165
    3. Allocation of Cluster Study Costs 405
    4. Allocation of Cluster Network Upgrade Costs 422
    5. Shared Network Upgrades 468
    6. Increased Financial Commitments and Readiness Requirements 
490
    7. Transition Process 814
    B. Reforms To Increase the Speed of Interconnection Queue 
Processing 872
    1. Elimination of the Reasonable Efforts Standard 872
    2. Affected Systems 1026
    3. Optional Resource Solicitation Study 1294
    C. Reforms To Incorporate Technological Advancements Into the 
Interconnection Process 1324
    1. Increasing Flexibility in the Generator Interconnection 
Process 1324
    2. Incorporating the Enumerated Alternative Transmission 
Technologies Into the Generator Interconnection Process 1534
    3. Modeling and Ride-Through Requirements for Non-Synchronous 
Generating Facilities 1621
    D. Issues Beyond the Scope of this Rulemaking 1736
    1. Comments 1736
    2. Commission Determination 1743
IV. Compliance Procedures 1744
    A. NOPR Proposal 1744
    B. Comments 1747
    1. Compliance Filing Deadline 1747
    2. Regional Flexibility 1750
    3. Reciprocity Tariffs 1759
    4. Effective Date 1760
    5. Miscellaneous 1761
    C. Commission Determination 1762
V. Information Collection Statement 1772
VI. Environmental Analysis 1779
VII. Regulatory Flexibility Act 1780
VIII. Document Availability 1783
IX. Effective Date and Congressional Notification 1785

I. Introduction

    1. This final rule requires all public utility transmission 
providers to adopt revised pro forma Large Generator Interconnection 
Procedures (LGIP), pro forma Small Generator Interconnection Procedures 
(SGIP), pro forma Large Generator Interconnection Agreements (LGIA), 
and pro forma Small Generator Interconnection Agreements (SGIA).\1\ 
These revisions will ensure that interconnection customers are able to 
interconnect to the transmission system in a reliable, efficient, 
transparent, and timely manner, and will prevent undue discrimination.
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    \1\ Section 201(e) of the Federal Power Act (FPA) defines 
``public utility'' to mean ``any person who owns or operates 
facilities subject to the jurisdiction of the Commission under this 
subchapter.'' 16 U.S.C. 824(e). A non-public utility that seeks 
voluntary compliance with the reciprocity condition of a tariff may 
satisfy that condition by filing a tariff, which includes the pro 
forma LGIP, the pro forma SGIP, the pro forma LGIA, and the pro 
forma SGIA. See Standardization of Generator Interconnection 
Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 
104 FERC ] 61,103, at PP 1, 616 (2003), order on reh'g, Order No. 
2003-A, 69 FR 15932 (Mar. 5, 2004), 106 FERC ] 61,220, order on 
reh'g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ] 
61,287 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (July 
18, 2005), 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of 
Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007) (NARUC 
v. FERC). As stated in the pro forma LGIP, pro forma LGIA, pro forma 
SGIP, and pro forma SGIA, transmission provider ``shall mean the 
public utility (or its designated agent) that owns, controls, or 
operates transmission or distribution facilities used for the 
transmission of electric energy in interstate commerce and provides 
transmission service under the [Transmission Provider's Tariff]. The 
term . . . should be read to include the Transmission Owner when the 
Transmission Owner is separate from the Transmission Provider.'' Pro 
forma LGIP section 1; pro forma LGIA art. 1; pro forma SGIP attach. 
1; pro forma SGIA attach. 1.
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    2. Twenty years ago the Commission issued Order No. 2003, in which 
the Commission required all public utilities that own, control, or 
operate facilities used for transmitting electric energy in interstate 
commerce to have on file standard procedures and a standard agreement 
for interconnecting generating facilities larger than 20 megawatts (MW) 
(called the pro forma LGIP and the pro forma LGIA).\2\ The Commission 
stated its expectation that the changes would prevent undue 
discrimination, preserve reliability, increase energy supply, and lower 
wholesale prices for customers by increasing the amount and variety of 
new generation that would compete in the wholesale electricity 
market.\3\ The Commission further stated that the standard procedures 
would facilitate market entry for generation competitors by reducing 
interconnection costs and time.\4\ In Order No. 2006, the Commission 
adopted standard procedures and a standard agreement for 
interconnecting generating facilities no larger than 20 MW (called the 
pro forma SGIP and the pro forma SGIA), citing the same purposes 
outlined in Order No. 2003.\5\
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    \2\ Order No. 2003, 104 FERC ] 61,103 at P 2.
    \3\ Id. P 1.
    \4\ Id. P 12.
    \5\ Standardization of Small Generator Interconnection 
Agreements & Procs., Order No. 2006, 111 FERC ] 61,220, at PP 15, 
35-36, order on reh'g, Order No. 2006-A, 70 FR 71760 (Dec. 30, 
2005), 113 FERC ] 61,195 (2005), order granting clarification, Order 
No. 2006-B, 71 FR 42587 (July 27, 2006), 116 FERC ] 61,046 (2006).
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    3. The electricity sector has transformed significantly since the 
issuance of Order Nos. 2003 and 2006. The growth of new resources 
seeking to interconnect to the transmission system and the differing 
characteristics of those resources have created new challenges for the 
generator interconnection process. These new challenges are creating 
large interconnection queue

[[Page 61015]]

backlogs and uncertainty regarding the cost and timing of 
interconnecting to the transmission system, increasing costs for 
consumers. Backlogs in the generator interconnection process, in turn, 
can create reliability issues as needed new generating facilities are 
unable to come online in an efficient and timely manner. While the 
Commission recognized these issues and sought to address them in Order 
No. 845,\6\ it is clear that further action is needed. Therefore, we 
believe that it is necessary to reform the Commission's standard 
interconnection procedures and agreements to ensure that 
interconnection customers are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner, 
thereby ensuring that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly 
discriminatory or preferential.
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    \6\ See Reform of Generator Interconnection Procs. & Agreements, 
Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ] 61,043, at P 24 
(2018), order on reh'g, Order No. 845-A, 84 FR 8156 (Mar. 6, 2019) 
166 FERC ] 61,137, order on reh'g, Order No. 845-B, 168 FERC ] 
61,092 (2019).
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    4. Accordingly, we adopt reforms to the Commission's pro forma LGIP 
and pro forma LGIA. Specifically, as explained in detail in this final 
rule, we adopt reforms to: (1) implement a first-ready, first-served 
cluster study process; \7\ (2) increase the speed of interconnection 
queue processing; and (3) incorporate technological advancements into 
the interconnection process.
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    \7\ A first-ready, first-served cluster study process improves 
efficiency in the interconnection study process by including the 
following elements: increased access to information prior to 
entering the queue; a mechanism to study interconnection requests in 
groups where all interconnection requests in the group are equally 
queued and of equal study priority; and increased financial 
commitments and readiness requirements to enter and proceed through 
the queue. In contrast, the existing first-come, first-served serial 
study process in the pro forma LGIA and LGIP provides limited 
information to interconnection customers prior to entering the 
queue, assigns interconnection requests an individual queue position 
based solely on the date of entry into the queue, and contains 
limited financial and readiness requirements.
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    5. First, in order to implement a first-ready, first-served cluster 
study process, this final rule requires: (1) transmission providers to 
publicly post available information pertaining to generator 
interconnection; (2) transmission providers to use cluster studies as 
the interconnection study method; (3) transmission providers to 
allocate cluster study costs on a pro rata and per capita basis; (4) 
transmission providers to allocate network upgrade costs based on a 
proportional impact method; (5) interconnection customers to pay study 
and commercial readiness deposits as part of the cluster study process; 
(6) interconnection customers to demonstrate site control at the time 
of submission of the interconnection request; and (7) transmission 
providers to impose withdrawal penalties on interconnection customers 
for withdrawing from the interconnection queue, with certain 
exceptions. We also require transmission providers to adopt a 
transition process to move from the existing serial interconnection 
process to the new cluster study process.
    6. Second, in order to increase the speed of interconnection queue 
processing, this final rule: (1) eliminates the reasonable efforts 
standard for conducting interconnection studies and imposes a financial 
penalty on transmission providers that fail to meet interconnection 
study deadlines; and (2) establishes an affected system study process 
and associated pro forma affected system agreements.
    7. Third, in order to incorporate technological advancements into 
the interconnection process, this final rule requires transmission 
providers to: (1) allow more than one generating facility to co-locate 
on a shared site behind a single point of interconnection and share a 
single interconnection request; (2) evaluate the proposed addition of a 
generating facility at the same point of interconnection prior to 
deeming such an addition a material modification if the addition does 
not change the originally requested interconnection service level; (3) 
allow interconnection customers to access the surplus interconnection 
service process once the original interconnection customer has an 
executed LGIA or requests the filing of an unexecuted LGIA; (4) use 
operating assumptions in interconnection studies that reflect the 
proposed charging behavior of an electric storage resource; and (5) 
evaluate the list of alternative transmission technologies enumerated 
in this final rule during the generator interconnection study process. 
This final rule also requires interconnection customers requesting to 
interconnect a non-synchronous generating facility to: (1) provide the 
transmission provider with the models needed for accurate 
interconnection studies; and (2) have the ability to maintain power 
production at pre-disturbance levels and provide dynamic reactive power 
to maintain system voltage during transmission system disturbances and 
within physical limits. Finally, this final rule requires that all 
newly interconnecting large generating facilities provide ride through 
capability consistent with any standards and guidelines that are 
applied to other generating facilities in the balancing authority area 
on a comparable basis.
    8. We also adopt reforms to the pro forma SGIP and pro forma SGIA. 
Specifically, as explained in detail in this final rule, for small 
generating facilities we propose reforms to incorporate the enumerated 
alternative transmission technologies into the interconnection process, 
and to provide modeling and ride through requirements for non-
synchronous generating facilities.
    9. Many of the reforms adopted in this final rule track the notice 
of proposed rulemaking's \8\ (NOPR) proposed reforms closely. However, 
as discussed more fully below, we have revised aspects of the reforms 
pertaining to the cluster study process, allocation of cluster study 
and network upgrade costs, increased financial commitments and 
readiness requirements, financial penalties for delayed interconnection 
studies, the affected system study process, pro forma affected system 
agreements, the material modification process, operating assumptions 
for interconnection studies, incorporating the enumerated alternative 
transmission technologies, and ride through requirements. Additionally, 
as discussed more fully below, we decline to adopt the NOPR proposals 
pertaining to informational interconnection studies, shared network 
upgrades, the optional resource solicitation study, and the alternative 
transmission technologies annual report.
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    \8\ Improvements to Generator Interconnection Procs. & 
Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ] 61,194 (2022) 
(NOPR).
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    10. We recognize that transmission providers have undertaken 
efforts to address interconnection queue management issues. This final 
rule is not intended to divert or slow the potential progress 
represented by those efforts, and we encourage transmission providers 
to continue to innovate to remedy their identified interconnection 
queue management issues. We note that the compliance obligations that 
result from this final rule will be evaluated in light of the 
independent entity variation standard for regional transmission 
organizations (RTO) and independent system operators (ISO) and the 
consistent with or superior to standard for non-RTO/ISO transmission 
providers.\9\
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    \9\ Order No. 2003, 104 FERC ] 61,103 at P 26; see infra section 
IV.
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A. Historical Framework: Order Nos. 2003, 2006, and 845

    11. In Order No. 2003, the Commission recognized a need for a

[[Page 61016]]

standard set of interconnection procedures for transmission providers 
and a single, uniformly applicable interconnection agreement for large 
generating facilities.\10\ The Commission noted that generator 
interconnection is a ``critical component of open access transmission 
service and thus is subject to the requirement that utilities offer 
comparable service under the [pro forma open access transmission tariff 
(tariff)].'' \11\ The Commission found that it was appropriate to 
establish a standard set of generator interconnection procedures to 
``minimize opportunities for undue discrimination and expedite the 
development of new generation, while protecting reliability and 
ensuring that rates are just and reasonable.'' \12\ To this end, the 
Commission adopted the pro forma LGIP and pro forma LGIA and amended 
its regulations to require all transmission providers to incorporate 
these standard procedures and agreement into their tariffs.\13\
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    \10\ Order No. 2003, 104 FERC ] 61,103 at P 11. Large generating 
facilities are defined to mean ``a Generating Facility having a 
Generating Facility Capacity of more than 20 MW.'' Pro forma LGIP 
section 1.
    \11\ Order No. 2003, 104 FERC ] 61,103 at P 9 (citing Tenn. 
Power Co., 90 FERC ] 61,238 (2000)).
    \12\ Id. P 11.
    \13\ 18 CFR 35.28(f)(1) (2022).
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    12. To initiate the generator interconnection process set forth in 
the Commission's pro forma LGIP,\14\ the interconnection customer 
submits an interconnection request for its proposed generating facility 
that includes preliminary documentation of the site of the proposed 
generating facility, certain technical information about the proposed 
generating facility, and the expected commercial operation date of the 
proposed generating facility, along with a refundable deposit of 
$10,000.\15\ After the transmission provider determines that the 
interconnection request is complete, the interconnection request enters 
the transmission provider's interconnection queue with other pending 
interconnection requests and is assigned a queue position based on the 
time and date of its receipt.\16\ The queue position determines the 
order in which the transmission provider studies the interconnection 
requests in its interconnection queue.\17\
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    \14\ While we provide a broad description of the process in the 
Commission's pro forma LGIP as background here, we recognize that 
many transmission providers have adopted (and the Commission has 
accepted) variations to many of the terms in the Commission's pro 
forma LGIP and pro forma LGIA. Consequently, some or many of the 
details of a particular transmission provider's generator 
interconnection procedures may vary considerably from the broad 
description provided here.
    \15\ Order No. 2003, 104 FERC ] 61,103 at P 35; pro forma LGIP 
sections 3.1, 3.4.
    \16\ Pro forma LGIP section 4.1.
    \17\ Id.
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    13. Transmission providers must schedule a scoping meeting with the 
interconnection customer to discuss possible points of interconnection 
for the proposed generating facility and exchange technical 
information, which is followed by a series of interconnection studies 
to evaluate the proposed interconnection in detail.\18\ Transmission 
providers study interconnection requests in three phases: (1) the 
interconnection feasibility study (feasibility study); \19\ (2) the 
interconnection system impact study (system impact study); \20\ and (3) 
the interconnection facilities study (facilities study).\21\ These 
studies contain the power flow, short circuit, and stability analyses 
necessary to: (1) identify any adverse impacts on the transmission 
providers' transmission system or any affected systems; \22\ (2) 
determine the interconnection facilities and network upgrades \23\ 
needed to reliably interconnect the generating facility; and (3) 
estimate the interconnection customer's cost responsibility for these 
facilities.\24\ The pro forma LGIP requires that transmission providers 
use reasonable efforts to complete: (1) feasibility studies within 45 
calendar days; (2) system impact studies within 90 calendar days; and 
(3) facilities studies within 90 or 180 calendar days, depending on the 
interconnection customer's requested accuracy margin.\25\
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    \18\ Order No. 2003, 104 FERC ] 61,103 at P 36; pro forma LGIP 
sections 3.4.4, 6-8.
    \19\ The pro forma LGIP defines a feasibility study as ``a 
preliminary evaluation of the system impact and cost of 
interconnecting the Generating Facility to the Transmission 
Provider's Transmission System.'' The scope of a feasibility study 
is described in section 6 of the pro forma LGIP. Pro forma LGIP 
sections 1, 6.
    \20\ The pro forma LGIP defines a system impact study as ``an 
engineering study that evaluates the impact of the proposed 
interconnection on the safety and reliability of Transmission 
Provider's Transmission System and, if applicable, an Affected 
System.'' In particular, a system impact study identifies and 
details ``the system impacts that would result if the Generating 
Facility were interconnected without project modifications or system 
modifications, focusing on the Adverse System Impacts identified in 
the [feasibility study], or to study potential impacts, including 
but not limited to those identified in the Scoping Meeting.'' Id. 
section 1.
    \21\ The pro forma LGIP defines a facilities study as ``a study 
conducted by the Transmission Provider or a third-party consultant 
for the Interconnection Customer to determine a list of facilities 
(including Transmission Provider's Interconnection Facilities and 
Network Upgrades as identified in the [system impact study]), the 
cost of those facilities, and the time required to interconnect the 
Generating Facility with the Transmission Provider's Transmission 
System.'' The scope of a facilities study is described in section 8 
of the pro forma LGIP. Id. sections 1, 8.
    \22\ The pro forma LGIP defines an affected system as an 
electric system other than the transmission provider's transmission 
system that may be affected by the proposed interconnection. Id. 
section 1; pro forma LGIA art. 1.
    \23\ For purposes of this final rule, unless otherwise noted, 
``network upgrades'' refer to interconnection-related network 
upgrades. More specifically, the pro forma LGIP and pro forma LGIA 
provide that, ``Network Upgrades shall mean the additions, 
modifications, and upgrades to the Transmission Provider's 
Transmission System required at or beyond the point at which the 
Interconnection Facilities connect to the Transmission Provider's 
Transmission System to accommodate the interconnection of the Large 
Generating Facility to the Transmission Provider's Transmission 
System.'' Pro forma LGIP section 1; pro forma LGIA art. 1.
    \24\ Order No. 2003, 104 FERC ] 61,103 at PP 35-37; pro forma 
LGIP sections 6-8. The interconnection customer is responsible for 
the actual costs of interconnection studies and any necessary 
restudies. Pro forma LGIP section 13.3.
    \25\ Pro forma LGIP sections 6.3, 7.4, 8.3.
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    14. At the completion of the facilities study, the pro forma LGIP 
requires the transmission provider to issue a report on the best 
estimate of the costs to effectuate the requested interconnection and 
provide a draft generator interconnection agreement to the 
interconnection customer.\26\ If the interconnection customer wishes to 
proceed, after negotiations, the interconnection customer enters into a 
generator interconnection agreement with the transmission provider or, 
in specific circumstances, requests that the transmission provider file 
the agreement with the Commission unexecuted.\27\ The transmission 
provider is responsible for the construction of all network upgrades, 
but, as further discussed below, the interconnection customer has the 
option to build these facilities in certain circumstances.\28\
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    \26\ Order No. 2003, 104 FERC ] 61,103 at P 38. Section 11.1 of 
the pro forma LGIP requires the transmission provider to tender a 
draft LGIA to the interconnection customer ``in the form of 
Transmission Provider's FERC-approved standard form LGIA.''
    \27\ If the transmission provider and interconnection customer 
execute an LGIA that conforms to the transmission provider's 
Commission-approved standard form LGIA, the agreement does not need 
to be filed with the Commission (if the transmission provider has 
such a standard form LGIA on file and submits an Electronic 
Quarterly Report). Alternatively, the transmission provider must 
file an LGIA with the Commission for review and approval if: (1) the 
interconnection customer determines that negotiations with the 
transmission provider over the terms of an LGIA are at an impasse 
and requests submission of the unexecuted LGIA with the Commission; 
or (2) the LGIA does not conform to the transmission provider's 
Commission-approved standard form LGIA. See Order No. 2003-A, 106 
FERC ] 61,220 at P 201; pro forma LGIP sections 11.2-11.3.
    \28\ Order No. 2003, 104 FERC ] 61,103 at PP 351-354; pro forma 
LGIA art. 5.1.3.
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    15. Similar to Order No. 2003, in Order No. 2006, the Commission 
recognized the need for standardized

[[Page 61017]]

interconnection procedures and agreements for small generating 
facilities with a capacity of 20 MW or less.\29\ In addition to 
establishing a pro forma interconnection study process for small 
generating facilities similar to the process for large generating 
facilities established in Order No. 2003, the Commission included: (1) 
a ``fast track process'' \30\ that uses technical screens to evaluate a 
certified small generating facility no larger than 2 MW; and (2) a ``10 
[kilowatt (kW)] inverter process'' \31\ that uses the same technical 
screens to evaluate a certified inverter-based small generating 
facility no larger than 10 kW.\32\ The Commission later issued Order 
No. 792,\33\ in which the Commission revised the pro forma SGIP and pro 
forma SGIA to provide for interconnection customers to receive point of 
interconnection information in advance of submitting an interconnection 
request, increase the threshold for participation in the fast track 
process to five MW, and to specifically include electric storage 
devices.\34\
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    \29\ Order No. 2006, 111 FERC ] 61,220 at P 36.
    \30\ Pro forma SGIP section 2.1.
    \31\ Id. attach. 5.
    \32\ Order No. 2006, 111 FERC ] 61,220 at PP 36, 38-39.
    \33\ Small Generator Interconnection Agreements & Procs., Order 
No. 792, 78 FR 73240 (Dec. 5, 2013), 145 FERC ] 61,159 (2013), 
clarifying, Order No. 792-A, 146 FERC ] 61,214 (2014).
    \34\ See Order No. 792, 145 FERC ] 61,159 at P 1.
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    16. In response to concerns voiced to the Commission about 
interconnection queue management, in 2007, the Commission held a 
technical conference,\35\ and later issued an order \36\ addressing 
interconnection queue issues in RTOs/ISOs. In the order, the Commission 
noted that some transmission providers were not processing their 
interconnection queues within the timelines established in the pro 
forma LGIP, and in certain cases, were greatly exceeding them.\37\ The 
Commission stated that, although it ``may need to [impose solutions] if 
the RTOs and ISOs do not act themselves,'' each RTO/ISO would have an 
opportunity to work with its stakeholders to develop its own 
solutions.\38\ As further discussed below, following the order, 
multiple RTOs/ISOs submitted queue reform proposals to the Commission, 
some of which moved away from a so-called ``first-come, first-served'' 
approach (whereby interconnection requests are processed in the order 
they are received) to a so-called ``first-ready, first-served'' 
approach (whereby interconnection requests are processed based on when 
interconnection customers meet certain project development 
milestones).\39\ The reason for this move was to allow interconnection 
customers with interconnection requests for generating facilities more 
likely to achieve commercial operation to move faster instead of being 
delayed by interconnection requests that were higher in the 
interconnection queue but making limited or no progress towards 
commercial operation and creating unreasonable queue delays.
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    \35\ Interconnection Queuing Practices, Notice of Technical 
Conference, Docket No. AD08-2-000 (issued Nov. 2, 2007).
    \36\ Interconnection Queuing Pracs., 122 FERC ] 61,252 (2008) 
(2008 Technical Conference Order).
    \37\ Id. P 3.
    \38\ Id. P 8.
    \39\ See, e.g., Sw. Power Pool, Inc., 128 FERC ] 61,114 (2009); 
Midwest Indep. Transmission Sys. Operator, Inc., 124 FERC ] 61,183 
(2008); Cal. Indep. Sys. Operator Corp., 124 FERC ] 61,292 (2008).
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    17. In 2018, the Commission issued Order No. 845, in which the 
Commission made the most comprehensive revisions to the pro forma LGIP 
and pro forma LGIA since their adoption in Order No. 2003. In Order No. 
845, the Commission concluded that reforms to the pro forma LGIP and 
pro forma LGIA were needed to mitigate concerns regarding systemic 
inefficiencies, remedy discriminatory practices, and address recent 
developments, including changes in the resource mix and emergence of 
new technologies.\40\ The Commission therefore adopted reforms designed 
to improve certainty for interconnection customers, promote more 
informed interconnection decisions, and enhance the generator 
interconnection process.\41\
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    \40\ Order No. 845, 163 FERC ] 61,043 at P 7.
    \41\ Id. P 2.
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B. Regional Transmission Planning and Cost Allocation and Generator 
Interconnection Advance Notice of Proposed Rulemaking

    18. On July 15, 2021, the Commission issued an advance notice of 
proposed rulemaking (ANOPR) in Docket No. RM21-17-000, presenting 
potential reforms to the Commission's requirements governing the 
regional transmission planning and cost allocation and generator 
interconnection processes.\42\ Specific to the generator 
interconnection process, the Commission sought comment on whether and 
which reforms may be necessary to ensure a more purposeful integration 
of the generator interconnection process with the regional transmission 
planning and cost allocation processes, establish a faster and more 
efficient interconnection queueing process, and promote a more 
efficient and cost-effective allocation of network upgrade costs.\43\ 
For instance, the Commission noted that the cost of network upgrades 
can depend largely on both the timing of when the interconnection 
customer enters the interconnection queue and where the interconnection 
customer proposes to interconnect its generating facility. Therefore, 
the Commission noted, interconnection customers may submit multiple 
interconnection requests in an effort to determine the most favorable 
point of interconnection \44\ that minimizes their network upgrade 
costs.\45\ The Commission stated that this practice, in turn, may lead 
to late-stage withdrawals of the excess interconnection requests, which 
can then impede the transmission provider's ability to process its 
interconnection queue in an efficient manner. As a result, the 
Commission stated that it may be time to consider reforms to the 
generator interconnection process that would make it more efficient and 
ensure that generating facilities that are more ``ready'' than others 
are not unduly delayed in the interconnection queue.
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    \42\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation & Generator Interconnection, 86 FR 40266 
(July 15, 2021), 176 FERC ] 61,024 (2021) (ANOPR).
    \43\ Id. P 5.
    \44\ The pro forma LGIP defines point of interconnection as 
``the point, as set forth in Appendix A to the Standard Large 
Generator Interconnection Agreement, where the Interconnection 
Facilities connect to the Transmission Provider's Transmission 
System.'' Pro forma LGIP section 1.
    \45\ ANOPR, 176 FERC ] 61,024 at P 41.
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    19. On April 21, 2022, the Commission issued a notice of proposed 
rulemaking (Transmission Planning and Cost Allocation NOPR) proposing 
reforms to its existing regional transmission planning and cost 
allocation requirements in the same proceeding as it issued the 
ANOPR.\46\ While the Transmission Planning and Cost Allocation NOPR did 
not address many of the concerns raised by the Commission in the ANOPR 
with respect to the generator interconnection queue process, the 
Commission noted in the Transmission Planning and Cost Allocation NOPR 
that it would continue to review the record and that it expected to 
address possible inadequacies through subsequent proceedings that 
propose reforms, as warranted, related to that topic.\47\ The 
Commission took that next step with the reforms proposed

[[Page 61018]]

in the NOPR in this proceeding, many of which we adopt in this final 
rule.
---------------------------------------------------------------------------

    \46\ Bldg. for the Future Through Elec. Reg'l Transmission Plan. 
& Cost Allocation & Generator Interconnection, 87 FR 26504 (May 4, 
2022), 179 FERC ] 61,028 (2022).
    \47\ Id. P 10.
---------------------------------------------------------------------------

C. Notice of Proposed Rulemaking

    20. On June 16, 2022, the Commission issued the NOPR, proposing 
reforms focused on improving aspects of the pro forma LGIP, pro forma 
LGIA, pro forma SGIP, and pro forma SGIA. The Commission also sought 
comment on, but did not propose, tariff revisions on other issues.
    21. First, the Commission proposed reforms focused on improving 
interconnection processes to ensure interconnection customers can 
proceed in an efficient and timely manner.\48\ Among those, the 
Commission proposed to: (1) require transmission providers to offer an 
optional informational interconnection study to serve as additional 
information for prospective interconnection customers in deciding 
whether to submit an interconnection request and set minimum 
requirements for transmission providers to publicly post available 
information pertaining to generator interconnection; \49\ (2) require 
transmission providers to implement a first-ready, first-served cluster 
study process that allocates costs associated with cluster studies and 
identified network upgrades consistent with the discussion below; \50\ 
and (3) impose more stringent financial commitments and readiness 
requirements on interconnection customers, including increased study 
deposits, more stringent site control requirements, a commercial 
readiness framework, and higher withdrawal penalties.\51\ To implement 
these reforms, the Commission also proposed to require transmission 
providers to establish a transition process.\52\
---------------------------------------------------------------------------

    \48\ NOPR, 179 FERC ] 61,194 at P 4.
    \49\ Id. PP 42-52.
    \50\ Id. PP 56-101.
    \51\ Id. PP 104-148.
    \52\ Id. PP 150-160.
---------------------------------------------------------------------------

    22. Second, the Commission proposed three reforms to increase the 
speed of interconnection queue processing, including: (1) revisions to 
eliminate the reasonable efforts standard for interconnection study 
processing; \53\ (2) revisions to establish an affected system study 
process, along with necessary pro forma affected system agreements; 
\54\ and (3) revisions to establish an optional resource solicitation 
study.\55\
---------------------------------------------------------------------------

    \53\ Id. PP 168-173.
    \54\ Id. PP 182-215.
    \55\ Id. PP 223-237.
---------------------------------------------------------------------------

    23. Finally, the Commission proposed three reforms to incorporate 
technological advancements into the interconnection study process. With 
these reforms, the Commission proposed to require transmission 
providers to: (1) increase flexibility in the generator interconnection 
process by allowing generating facilities to co-locate, allow the 
interconnection customer to request the addition of a generating 
facility to an existing interconnection request, increase the 
availability of surplus interconnection service, and allow 
interconnection customers to propose operating assumptions for their 
generating facilities; \56\ (2) incorporate the enumerated alternative 
transmission technologies into the interconnection study process at the 
request of the interconnection customer; \57\ and (3) list required 
modeling standards for inclusion in all interconnection requests that 
include inverter-based resources (IBRs), as well as require certain 
performance standards from IBRs during system disturbances.\58\
---------------------------------------------------------------------------

    \56\ Id. PP 242-288.
    \57\ Id. PP 297-302.
    \58\ Id. PP 328-341.
---------------------------------------------------------------------------

    24. In response to the NOPR, 189 comments were filed.\59\ These 
comments have informed our determinations in this final rule.
---------------------------------------------------------------------------

    \59\ Appendix A lists the entities that submitted comments on 
the NOPR and the shortened names used through this final rule to 
describe those entities.
---------------------------------------------------------------------------

D. Joint Federal-State Task Force on Electric Transmission

    25. On June 17, 2021, the Commission established a Joint Federal-
State Task Force on Electric Transmission (Task Force) to formally 
explore broad categories of transmission-related topics.\60\ The 
Commission explained that the development of new transmission 
infrastructure implicated a host of different issues, including 
generator interconnection. The Task Force is comprised of all FERC 
Commissioners as well as representatives from 10 state commissions 
nominated by the National Association of Regulatory Utility 
Commissioners (NARUC), with two originating from each NARUC region.\61\ 
The Task Force convenes for multiple formal meetings annually, which 
are open to the public. Since its creation and as of the date of 
issuance of this final rule, the Task Force has met seven times.
---------------------------------------------------------------------------

    \60\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC 
] 61,224, at PP 1, 6 (2021).
    \61\ An up-to-date list of Task Force members, as well as 
additional information on the Task Force, is available on the 
Commission's website at: https://www.ferc.gov/TFSOET. Public 
materials related to the Task Force, including transcripts from 
public meetings, are available in the Commission's eLibrary in 
Docket No. AD21-15-000.
---------------------------------------------------------------------------

    26. The discussion at the May 2022 meeting focused on 
interconnection issues, including generator interconnection queue 
processes and backlogs. The Task Force members discussed: the primary 
challenges preventing more efficient processing of interconnection 
queues; specific improvements to interconnection processes (such as 
tighter applicant requirements to enter and remain in the queue, 
clustering, fast tracking, tighter deadlines on transmission providers 
completing studies, and minimizing reiterative studies); and how to 
balance near-term improvements to the interconnection procedures with 
longer-term regional transmission planning and development.\62\
---------------------------------------------------------------------------

    \62\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022).
---------------------------------------------------------------------------

II. Overall Need for Reform

A. NOPR

    27. In the NOPR, the Commission noted that the serial first-come, 
first-served study process was adopted at a time when most 
interconnection requests were for large traditional generating 
facilities that would use readily available transmission capacity.\63\ 
The Commission stated that the continued use of this process in the 
face of dramatic changes to the electric power industry, principally 
the surge in interconnection requests, the rapidly changing resource 
mix, evolving market forces, and the emergence of new technologies, has 
led to a growing backlog of interconnection requests and study delays 
for many transmission providers.\64\ The Commission also stated that 
these interconnection queue backlogs and study delays create 
uncertainty and inhibit project developers' ability to interconnect 
generating facilities to the transmission system.\65\ The Commission 
preliminarily found that the existing pro forma LGIP, pro forma LGIA, 
pro forma SGIP, and pro forma SGIA may be insufficient to ensure that 
new generating facilities are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner and to 
thereby ensure that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly

[[Page 61019]]

discriminatory or preferential.\66\ Further, because the 
interconnection queue backlogs and study delays afflicting generator 
interconnection service nationwide hinder the timely development of new 
generation and thereby stifle competition in the wholesale electric 
markets, the Commission also preliminarily found that the Commission's 
pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA 
result in rates, terms, and conditions in the wholesale electric 
markets that are unjust, unreasonable, and unduly discriminatory or 
preferential.
---------------------------------------------------------------------------

    \63\ NOPR, 179 FERC ] 61,194 at P 18.
    \64\ Id. PP 18-20.
    \65\ Id. P 19 (citing Joint Fed.-State Task Force on Elec. 
Transmission, Technical Conference, Docket No. AD21-15-000, Tr. 
15:21-16:1 (Ted Thomas) (May 6, 2022) (May Joint Task Force Tr.) 
(``Houston, we have a problem. As stated in the NARUC ANOPR 
comments, existing methods for interconnecting new resources to the 
transmission grid are inadequate and inefficient because of the time 
necessary to interconnect new resources and the corresponding 
network upgrade costs.'')).
    \66\ Id. P 22 (citing May Joint Task Force Tr. 23:6-11 (Riley 
Allen) (``Ultimately, this system is not working efficiently now and 
those inefficiencies translate into costs. It's not just cost on the 
developers, but I find from my decades of experience that, if there 
are inefficiencies in the system, they ultimately have to be borne 
by the loads and ratepayer interests.'')).
---------------------------------------------------------------------------

    28. The Commission stated that its preliminary findings were based 
on several features of the Commission's existing generator 
interconnection procedures and agreements that are of concern, 
specifically: (1) the information (or lack thereof) available to 
prospective interconnection customers and the commitments required of 
them to enter and progress through the interconnection queue; (2) the 
reliance on a serial first-come, first-served study process and the 
standard to which transmission providers are held for meeting 
interconnection study deadlines; (3) the protocols for affected systems 
studies; (4) the provisions for studying new or hybrid generation 
technologies and considering alternative transmission technologies; and 
(5) the performance requirements for non-synchronous generating 
facilities, including wind, solar, and electric storage facilities.\67\
---------------------------------------------------------------------------

    \67\ Id. PP 23-36 (citing May Joint Task Force Tr. 70:20-71:6 
(Matthew Nelson) (analogizing reiterative studies to going to the 
supermarket to buy ingredients for a recipe without knowing how much 
the ingredients cost, finding out at the register that they cost too 
much for your budget, and having to ``go home, get a new recipe, and 
start it all over again'')).
---------------------------------------------------------------------------

    29. The Commission found that some of the same issues persist in 
the small generating facility context and, therefore, proposed limited 
reforms to the pro forma SGIP and pro forma SGIA to incorporate 
alternative transmission technologies into the interconnection process 
and to provide modeling and performance requirements for non-
synchronous generating facilities.\68\
---------------------------------------------------------------------------

    \68\ Id. P 5.
---------------------------------------------------------------------------

B. Comments

    30. The vast majority of commenters overwhelmingly agree with the 
Commission's preliminary conclusion that there is a need to reform the 
Commission's pro forma interconnection procedures and agreements to 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner, thereby ensuring that rates, terms, and conditions for 
Commission-jurisdictional services are just, reasonable, and not unduly 
discriminatory or preferential.\69\ These commenters generally agree 
that the unprecedented volume of generation in the interconnection 
queue, which is almost equal to the current U.S. generation fleet, has 
resulted in severe backlogs in interconnection processes across the 
country.\70\ For example, the Ohio Commission Consumer Advocate states 
that ``there is an urgent need to clear the current generator 
interconnection queue backlog and to facilitate timely and economic 
interconnection of new resources in a way that responds to current and 
future market conditions.'' \71\ EEI recognizes that, despite many 
efforts underway across the country to fix individual transmission 
provider interconnection queue processes, there is still a need for the 
Commission to address backlogs and improve certainty in the 
interconnection queue process.\72\ Several commenters assert that these 
interconnection backlogs have resulted in commercial uncertainty 
regarding both the magnitude of identified upgrade costs and the 
timeline for completion of interconnection studies, delayed project 
development, increased costs for consumers due to the prevention of new 
supply from reaching the market, and impaired reliability.\73\ Senators 
Hickenlooper and King note that, in the past decade, 23% of proposed 
generating facilities reached commercial operation, while 72% were 
withdrawn.\74\ ELCON and APPA-LPPC both argue that uncertainty, on the 
part of both transmission provider and generator project developer, 
inevitably leads to an increase in costs to consumers.\75\ U.S. DOE 
submits a recent report published by the Lawrence Berkeley National 
Laboratory, which finds that interconnection costs in MISO have 
escalated as the number of interconnection requests has increased.\76\ 
Specifically, the report finds that interconnection costs in MISO 
doubled for projects completed between 2019-2021 compared to projects 
completed prior to 2018, and cost estimates tripled for projects still 
active in the queue between the same time periods. Some commenters 
agree that the existing interconnection rules in the pro forma LGIP and 
pro forma LGIA create an incentive for interconnection customers to 
submit interconnection requests even if they are not prepared to

[[Page 61020]]

move forward with their projects, in order to secure a favorable 
position in the interconnection queue or in an attempt to obtain 
locations with available transmission capacity.\77\ They assert that 
the withdrawal of each speculative interconnection request triggers 
reassessments and possible restudies by the transmission provider that 
can increase the timing and interconnection cost for lower-queued 
interconnection requests. Several commenters point to ambitious climate 
goals (such as the United States' commitment to reducing net greenhouse 
gas emissions by 50-52% by 2030 under the Paris Climate Agreement) and 
argue that: (1) these changes will likely spur greater investment in 
new generation and exacerbate the delays in processing interconnection 
requests; and/or (2) without an efficient and transparent 
interconnection process, none of the clean energy generating facilities 
intended to meet these goals can be effectively deployed.\78\ Consumers 
Energy argues that delays in processing interconnection requests will 
exacerbate resource adequacy challenges.\79\
---------------------------------------------------------------------------

    \69\ ACE-NY Initial Comments at 2; ACE-NY Reply Comments at 5; 
AEE Initial Comments at 3, 5; AEE Reply Comments at 5; AES Initial 
Comments at 2; Affected Interconnection Customers Initial Comments 
at 2; Ameren Initial Comments at 2; APPA-LPPC Reply Comments at 2; 
Avangrid Initial Comments at 6, 8; Bonneville Initial Comments at 3; 
CESA Initial Comments at 3; CESA Reply Comments at 1; Clean Energy 
Associations Initial Comments at 8; Clean Energy Buyers Initial 
Comments at 3; Clean Energy States Initial Comments at 2-3; Colorado 
Commission Initial Comments at 1; Consumers Energy Initial Comments 
at 2; Cypress Creek Initial Comments at 1; Dominion Initial Comments 
at 4; EEI Initial Comments at 2; EEI Reply Comments at 3; EDF 
Renewables Initial Comments at 1-2; Enel Initial Comments at 2; 
Energy Keepers Initial Comments at 2; Evergreen Action Initial 
Comments at 1; Eversource Initial Comments at 2; Fervo Energy 
Initial Comments at 2; Google Initial Comments at 2; Guzman Energy 
Initial Comments at 2; Hannon Armstrong Initial Comments at 1; 
Hydropower Commenters Initial Comments at 5; Illinois Commission 
Initial Comments at 2-3, 5; Interwest Initial Comments at 3; 
Interwest Reply Comments at 2; ISO-NE Initial Comments at 2-3; MISO 
TOs Initial Comments at 2, 6; NARUC Initial Comments at 3; New 
Jersey Commission Initial Comments at 4-9; NY Commission and NYSERDA 
Initial Comments at 3; NV Energy Initial Comments at 3; Ohio 
Commission Consumer Advocate Initial Comments at 3-4; OMS Initial 
Comments at 2; [Oslash]rsted Initial Comments at 5; Pine Gate 
Initial Comments at 8; PJM Initial Comments at 1, 4; PJM Coalition 
Initial Comments at 1; RWE Renewables Initial Comments at 1; 
Senators Hickenlooper and King Initial Comments at 1-2; Shell 
Initial Comments at 5-6; State Agencies Initial Comments at 1-2; 
TAPS Initial Comments at 1; Union of Concerned Scientists Reply 
Comments at 1; UMPA Initial Comments at 1; WATT Coalition Initial 
Comments at 1; Xcel Initial Comments at 8.
    \70\ AEE Initial Comments at 3; Apple Initial Comments at 1; 
Bonneville Initial Comments at 3; Clean Energy Buyers Initial 
Comments at 3; Colorado Commission Initial Comments at 2, 8-11; EDF 
Renewables Initial Comments at 2; Evergreen Action Initial Comments 
at 1; Eversource Initial Comments at 2; Interwest Initial Comments 
at 1-2; NV Energy Initial Comments at 2-3; Ohio Commission Consumer 
Advocate Initial Comments at 3-4; [Oslash]rsted Initial Comments at 
2; Senators Hickenlooper and King Initial Comments at 1-2; U.S. 
Chamber of Commerce Initial Comments at 5; UMPA Initial Comments at 
1.
    \71\ Ohio Commission Consumer Advocate Initial Comments at 3-4.
    \72\ EEI Reply Comments at 3.
    \73\ ACE-NY Initial Comments at 2; AEE Initial Comments at 4; 
EDF Renewables Initial Comments at 2; ELCON Initial Comments at 2; 
Fervo Energy Initial Comments at 2; PJM Coalition Initial Comments 
at 2; Xcel Reply Comments at 1.
    \74\ Senators Hickenlooper and King Initial Comments at 1 
(citing Joseph Rand et al., Lawrence Berkeley Nat'l Lab., Queued Up: 
Characteristics of Power Plants Seeking Transmission Interconnection 
(Apr. 2022) (Queued Up 2022), https://emp.lbl.gov/sites/default/files/queued_up_2021_04-13-2022.pdf)).
    \75\ ELCON Initial Comments at 2; APPA-LPPC Initial Comments at 
2.
    \76\ U.S. DOE Initial Comments at 1 (citing Joachim Seel et al., 
Lawrence Berkeley Nat'l Lab., Interconnection Cost Analysis in the 
MISO Territory at 1 (Oct. 2022)).
    \77\ Clean Energy Buyers Initial Comments at 3; Dominion Initial 
Comments at 4-5; PJM Initial Comments at 12; U.S. Chamber of 
Commerce Initial Comments at 4-5.
    \78\ AEP Initial Comments at 2; Affected Interconnection 
Customers Initial Comments at 2; Allen Meyer Initial Comments at 1; 
Apple Initial Comments at 1; Bretton C Little Initial Comments at 1; 
Colorado Commission Initial Comments at 13-14; EDF Renewables 
Initial Comments at 2-3 (referencing Inflation Reduction Act, Pub. 
L. 117-169 (2022)); ELCON Initial Comments at 2; Evergreen Action 
Initial Comments at 2; GSCE Initial Comments at 5-6; Individual 
Signatories Initial Comments at 1-2; Interwest Comments at 1-2; 
National Grid Initial Comments at 2; Payton Alaama Reply Comments at 
1; Pine Gate Reply Comments at 3-4; Rick K Lathrop Reply Comments at 
1; Shell Initial Comments at 6; State Agencies Initial Comments at 
8-9 (citing Int'l Energy Agency, Net Zero by 2050: A Roadmap for the 
Global Energy Sector (2021) https://www.iea.org/reports/net-zero-by-2050; The United States' Nationally Determined Contribution (2021), 
https://www4.unfccc.int/sites/ndcstaging/PublishedDocuments/United%20States%20of%20America%20First/United%20States%20NDC%20April%2021%202021%20Final.pdf; White House, 
FACT SHEET: Biden Administration Jumpstarts Offshore Wind Energy 
Projects to Create Jobs (Mar. 29, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/03/29/fact-sheet-biden-administration-jumpstarts-offshore-wind-energy-projects-to-create-jobs/); Sue Hilton Initial Comments at 1; Union of Concerned 
Scientists Reply Comments at 6; Vistra Initial Comments at 4.
    \79\ Consumers Energy Initial Comments at 7.
---------------------------------------------------------------------------

    31. A small subset of commenters, while supporting an overall need 
for reform, disagree with some of the Commission's preliminary 
conclusions about the need for reform.\80\ A few other commenters claim 
that there is no basis for the Commission's preliminary conclusion that 
speculative projects that enter the interconnection queue and later 
withdraw, causing cascading restudies, are responsible for 
interconnection queue backlogs.\81\ A few commenters assert that the 
Commission did not take into account pertinent factors affecting 
interconnection queue sizes, such as an increase in the development of 
smaller, more diverse generating facilities.\82\
---------------------------------------------------------------------------

    \80\ For instance, Affected Interconnection Customers disagree 
with the Commission's reference to a nationwide shortage of 
qualified engineers and contend that the Commission fails to support 
this conclusion with any evidence beyond statements made by CAISO 
and MISO. Affected Interconnection Customers Initial Comments at 14 
(citing NOPR, 179 FERC ] 61,194 at P 20 n.67).
    \81\ CREA and NewSun Initial Comments at 35-37 (countering that 
interconnection requests do not reach commercial operation due to 
other reasons such as permitting or financing difficulties); NextEra 
Initial Comments at 4; Public Interest Organizations Initial 
Comments at 1-7 (arguing that the rate of queue withdrawal has been 
consistent over the last decade); SEIA Reply Comments at 1.
    \82\ AEE Initial Comments at 6-7; Pine Gate Reply Comments at 4; 
SEIA Reply Comments at 1.
---------------------------------------------------------------------------

    32. Three comments note that various transmission providers use 
vastly different interconnection procedures from the pro forma 
procedures established in Order No. 2003 and argue that there is an 
insufficient legal foundation under FPA section 206 to demonstrate that 
all of these approved interconnection procedures are unjust, 
unreasonable, and unduly discriminatory or preferential.\83\ Southern 
disagrees entirely with the Commission's preliminary conclusion that 
there is a need for reform.\84\ Southern argues that the Commission 
based its proposed actions in the NOPR on conjecture and thus failed to 
provide substantial evidence or engage in reasoned decision-making to 
demonstrate that the current interconnection processes are unjust and 
unreasonable.\85\ In addition, Southern contends that the Commission's 
proposals are arbitrary and capricious because they impose a broadly 
applicable remedy to a problem that does not exist uniformly.\86\
---------------------------------------------------------------------------

    \83\ Early Adopters Coalition Initial Comments at 1-2; 
PacifiCorp Initial Comments at 9; Southern Initial Comments at 10-
11.
    \84\ Southern Initial Comments at 10-12; Southern Reply Comments 
at 1, 4.
    \85\ Southern Initial Comments at 10 (citing Emera Me. v. FERC, 
854 F.3d 9, 24 (D.C. Cir. 2017)); Southern Reply Comments at 1, 4.
    \86\ Southern Initial Comments at 11-12.
---------------------------------------------------------------------------

    33. Southern further asserts that the Commission failed to provide 
any actual evidence that its proposals will reduce interconnection 
queue backlogs or increase certainty for interconnection customers.\87\
---------------------------------------------------------------------------

    \87\ Id. at 10; Southern Reply Comments at 5.
---------------------------------------------------------------------------

    34. Some commenters argue that the sum of the NOPR may actually 
slow study processes, increase backlogs, and may unintentionally 
increase costs to ratepayers.\88\ For example, CAISO asserts that 
shortening study timelines results in rushed, unreliable studies which 
would ultimately require more iteration and longer interconnection 
queue processing times.\89\ Additionally, NextEra argues that the NOPR 
provides few, if any, solutions relevant to those regions that have 
already implemented cluster studies yet continue to experience 
significant study delays.\90\ Further, some commenters oppose any 
generic one-size-fits-all reform, arguing that queue reform is best 
left to the regional level.\91\
---------------------------------------------------------------------------

    \88\ CAISO Initial Comments at 3; Dominion Initial Comments at 
7; New York State Department Initial Comments at 2; NextEra Reply 
Comments at 2; NRECA Initial Comments at 7.
    \89\ CAISO Initial Comments at 3.
    \90\ NextEra Reply Comments at 7.
    \91\ Avangrid Initial Comments at 36-37; Southern Initial 
Comments at 14-15.
---------------------------------------------------------------------------

    35. Several commenters generally support the suite of proposed 
reforms in their entirety.\92\ As discussed in detail in each section 
below discussing individual reforms, most commenters either support 
specific proposals or suggest that the Commission prioritize certain 
proposed reforms. For instance, Consumers Energy supports reforms that 
increase the speed of interconnection queue processing because it 
claims that the reforms provide clarity for resource planners and 
interconnection customers as well as improve the reliability of the 
bulk electric system and the clean energy resource transformation.\93\ 
Google urges the Commission to prioritize reforms that provide a level 
playing field for both utility-backed resources and independent power 
producer-developed resources.\94\ Google also expresses concern that 
the layering of increased study deposits, more stringent site control 
requirements, the proposed commercial readiness requirements, and 
withdrawal penalties may place undue burden on interconnection 
customers if the Commission does not also adopt proposals for more 
publicly available interconnection information, firm study deadlines, 
and penalties for missed study deadlines.\95\
---------------------------------------------------------------------------

    \92\ APPA-LPPC Initial Comments at 2-3; APPA-LPPC Reply Comments 
at 2; Apple Initial Comments at 1; ACORE Initial Comments at 2; 
Amazon Initial Comments at 2; Evergreen Action Initial Comments at 
1-4; Individual Signatories Initial Comments at 1; PJM Coalition 
Initial Comments at 2.
    \93\ Consumers Energy Initial Comments at 10-11.
    \94\ Google Initial Comments at 3.
    \95\ Id. at 16.
---------------------------------------------------------------------------

    36. Some commenters support adopting most or all of the limited

[[Page 61021]]

reforms to the pro forma SGIP and pro forma SGIA proposed in the 
NOPR.\96\ For instance, Microgrid Resources asserts that including the 
proposed reforms in the pro forma SGIP is necessary to reflect the 
operating assumptions of, and to provide equitable treatment for, 
microgrids and other behind-the-meter resources.\97\ Microgrid 
Resources asserts that, if the Commission succeeds in expediting 
interconnections for large generating facilities, while small 
generating facility interconnections languish, it will bias the system 
against smaller local generating facilities that are the backbone of 
community resilience.
---------------------------------------------------------------------------

    \96\ Bonneville Initial Comments at 24 (supporting applying some 
of the Commission's proposed reforms to the pro forma SGIP and pro 
forma SGIA (e.g., commercial readiness requirements), but asking 
that transmission providers be granted flexibility to determine 
which reforms should be applicable to small generator procedures and 
agreements); IREC Initial Comments at 3 (stating that the pro forma 
SGIP lacks the necessary provisions to safely and reliably 
interconnect storage to the electric grid while enabling its unique 
operating characteristics); Microgrid Resources Initial Comments at 
8-9; Xcel Initial Comments at 19 (supporting applying reforms to 
small generating facilities requesting energy only interconnection 
service).
    \97\ Microgrid Resources Initial Comments at 8-9.
---------------------------------------------------------------------------

C. Commission Determination

    37. Based on the record, including comments submitted in response 
to the NOPR, as discussed below, we find that there is substantial 
evidence to support the conclusion that the existing pro forma 
generator interconnection procedures and agreements are unjust, 
unreasonable, and unduly discriminatory or preferential.\98\ We 
therefore adopt the preliminary findings in the NOPR concerning the 
need for reform \99\ and, pursuant to FPA section 206, conclude that 
certain revisions to the pro forma open access transmission tariff and 
the Commission's regulations are necessary to ensure rates that are 
just, reasonable, and not unduly discriminatory or preferential. 
Specifically, we find that the existing pro forma generator 
interconnection procedures and agreements are insufficient to ensure 
that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner, thereby ensuring that rates, terms, and conditions for 
Commission-jurisdictional services are just, reasonable, and not unduly 
discriminatory or preferential. Absent reform, the current 
interconnection process will continue to cause interconnection queue 
backlogs, longer development timelines, and increased uncertainty 
regarding the cost \100\ and timing of interconnecting to the 
transmission system. These backlogs and delays, and the resulting 
timing and cost uncertainty,\101\ hinder the timely development of new 
generation and thereby stifle competition in the wholesale electric 
markets resulting in rates, terms, and conditions that are unjust, 
unreasonable, and unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \98\ 16 U.S.C. 824e(a); 18 CFR 385.206 (2022).
    \99\ NOPR, 179 FERC ] 61,194 at PP 18-36.
    \100\ See May Joint Task Force Tr. 74:9-21 (Andrew French) 
(stating that generator developers complain principally about cost 
certainty and cost sharing and that ``cost certainty is the much 
bigger issue'' given that ``an essential element of being able to 
sell a product is to know what your inputs are so you can market 
it'').
    \101\ See May Joint Task Force Tr. 23:18-25 (Jason Stanek) 
(expressing frustration with the status quo and agreement that it is 
``no longer tenable'' considering the inability of generators to 
interconnect in a timely manner, e.g., there are ``2,500 projects 
under study [in the MACRUC region] and about a half of them have 
been in the queue since at least 2001'').
---------------------------------------------------------------------------

    38. Indeed, recent data support the Commission's preliminary 
findings in the NOPR that the dramatic increase in the number of 
interconnection requests and limited transmission capacity are 
increasing interconnection queue backlogs across all regions of the 
country.\102\ As of the end of 2022, there were over 10,000 active 
interconnection requests in interconnection queues throughout the 
United States, representing over 2,000 gigawatts (GW) of potential 
generation and storage capacity.\103\ This potential generation is the 
largest interconnection queue size on record, more than four times the 
total volume (in GW) of the interconnection queues in 2010, and a 40% 
increase over the interconnection queue size from just the year 
prior.\104\ These trends are not exclusive to any one region of the 
country. Instead, every single region has faced an increase in both 
interconnection queue size and the length of time interconnection 
customers are spending in the interconnection queue prior to commercial 
operation in recent years.\105\ This is true for RTO/ISO and non-RTO/
ISO regions alike. The non-RTO/ISO west and southeast regions both have 
faced queue size increases ranging from tripling to a 12-fold increase 
while also seeing longer timelines between interconnection requests and 
commercial operation dates.\106\ Furthermore, the uncertainty and 
delays in the interconnection queues have resulted in fewer than 25% of 
interconnection requests, by capacity, reaching commercial operation 
between 2000 and 2017 in any region of the country--with some regions 
as low as 8%.\107\
---------------------------------------------------------------------------

    \102\ Joseph Rand et al., Lawrence Berkeley Nat'l Lab., Queued 
Up: Characteristics of Power Plants Seeking Transmission 
Interconnection, at 7-8 (Apr. 2023) (Queued Up 2023), https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf; see 
also Order No. 845, 163 FERC ] 61,043 at P 305 (requiring 
transmission providers to post interconnection study metrics). See 
appendix B to this final rule, which provides an overview of recent 
data based on reporting by transmission providers in compliance with 
Order No. 845.
    \103\ Queued Up 2023 at 7-8.
    \104\ Id. at 10.
    \105\ Id. at 9, 32.
    \106\ Id. at 9, 32.
    \107\ Id. at 3, 21.
---------------------------------------------------------------------------

    39. Additionally, recent data continue to show that interconnection 
customers are waiting longer in the interconnection queue before 
withdrawing their interconnection requests,\108\ even as overall 
interconnection study timelines are increasing in many regions.\109\ 
For example, AEE states that, as of February 2022, all 2,274 projects 
waiting for an interconnection agreement in the PJM interconnection 
queue had been waiting for a year or more; 33% (758 projects) had been 
waiting more than 500 days, 22% (497 projects) have been stuck for more 
than two years, and 7% (166 projects) have been waiting more than three 
years.\110\ NV Energy explains that several western utilities that are 
not currently part of an RTO/ISO are experiencing an unprecedented high 
volume of requests in excess of the utility's peak load.\111\ AEE notes 
that wait times for generating facilities in interconnection queues 
nationwide have increased from 2.1 years for generating facilities 
built in 2000-2010 to 3.7 years for those built in 2011-2021.\112\ And 
despite efforts to address

[[Page 61022]]

these challenges,\113\ interconnection queue backlogs and delays have 
persisted and worsened. For generating facilities built in 2022, wait 
times in the interconnection queue saw a marked increase to now roughly 
five years.\114\
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    \108\ Id. at 25 (reporting that, although the median withdrawal 
duration has been relatively consistent over time, the mean 
withdrawal duration and distributions have edged higher in recent 
years).
    \109\ Id. at 27.
    \110\ AEE Initial Comments at 4 (citing Advanced Energy Economy, 
``In PJM, Renewable Energy Projects Are Getting Stuck'' (February 
2022), https://blog.aee.net/in-pjm-renewable-energy-projects-are-getting-stuck).
    \111\ NV Energy Initial Comments at 2-3. NV Energy explains that 
it has a peak load of 9,400 MW with an interconnection queue backlog 
for projects totaling more than 27,000 MW; Idaho Power has a peak 
load of 3,751 MW with an interconnection queue backlog of over 
18,000 MW; PacifiCorp has a peak load of 13,000 MW with an 
interconnection queue backlog of over 45,000 MW; and APS has a peak 
load of 7,600 MW with an interconnection queue backlog of over 
50,000 MW.
    \112\ AEE Initial Comments at 4 (citing Queued Up 2022); see 
also ACE-NY Initial Comments at 2 (arguing that the ability of New 
York to meet its clean energy goals is threatened by an 
interconnection process that is too slow); Affected System 
Interconnection Customers Initial Comments at 2 (stating that 
Affected System Interconnection Customers have navigated the 
generator interconnection queues of various transmission providers 
around the country and experienced firsthand the inefficiencies and 
delays, which represent the greatest obstacle to achieving 
commercial operation of a new energy project); GSCE Initial Comments 
at 5-6 (contending that an average of 6,000 MW of new solar, wind, 
and batteries must be added each year until 2045 to reach 
California's electric sector carbon-neutrality requirement, but that 
over the past decade California has only succeeded with adding an 
average of 1,000 MW of utility-scale solar and 300 MW of wind to the 
transmission system each year).
    \113\ Order No. 845, 163 FERC ] 61,043 at P 24.
    \114\ Queued Up 2023 at 31; see also Shell Initial Comments at 6 
(describing multiple instances of five to six years until execution 
of an interconnection agreement, four years waiting for an initial 
``kick-off'' call, two years waiting for a feasibility study, three 
years waiting for a system impact study, and over two years waiting 
for a facilities study).
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    40. Delays in the interconnection study process are an important 
contributor to interconnection queue backlogs nationwide. For instance, 
based on the recent interconnection study metrics transmission 
providers posted in compliance with Order No. 845, of the 2,179 
interconnection studies completed in 2022, 68% were issued late.\115\ 
Furthermore, at the end of 2022, an additional 2,544 studies were 
delayed (i.e., ongoing and past their deadline).\116\ All of the RTOs/
ISOs except CAISO and 14 non-RTO/ISO transmission providers reported 
delayed studies at the end of 2022.\117\
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    \115\ This is based on data provided by transmission providers 
in compliance with Order No. 845. See appendix B to this final rule 
for the underlying data. Note that data from SPP is omitted here and 
in follow-on references to Order No. 845 data in this determination. 
This is because during 2022, SPP was transitioning to a new 
interconnection study process, and thus its data is not comparable 
to the other transmission providers.
    \116\ Id. Note that the vast majority of these studies (2,211) 
were in PJM.
    \117\ Id. CAISO revised the interconnection study deadlines of 
their queue cluster 14 to account for the unprecedented increase in 
interconnection requests. Cal. Indep. Sys. Operator Corp., 176 FERC 
] 61,207 (2021).
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    41. Consistent with the NOPR, we find that numerous factors have 
contributed to the increasing volume of interconnection requests, 
including a rapidly changing resource mix, market forces, and emerging 
technologies. For example, the interconnection queues in all parts of 
the country are now predominantly made up of comparatively new 
technologies that have operating characteristics and generally shorter 
construction cycles that were not taken into account when the 
Commission issued Order No. 2003, such as solar, battery storage, and 
hybrid resources, as older, larger generating facilities retire.\118\ 
The Colorado Commission notes that solar projects account for roughly 
half of the cumulative requests in the five RTO/ISO queues and likely 
an even greater percentage of the most recent requests.\119\ In 
addition to the drastic increase in the number of interconnection 
requests in all regions of the country, evidence shows that 
interconnection studies have increased in complexity since the 
Commission issued Order No. 2003, potentially straining transmission 
provider resources.\120\ At the same time, we find that available 
transmission capacity has been largely or fully utilized in many 
regions, creating situations where interconnection customers face 
significant network upgrade cost assignments to interconnect their 
proposed generating facilities.\121\ For example, as referenced by the 
U.S. DOE, a recent report finds that interconnection costs in MISO 
doubled for generating facilities for which the interconnection studies 
were completed between 2019 and 2021 as compared to those completed 
prior to 2019, and cost estimates tripled for proposed generating 
facilities still active in the interconnection queue between the same 
time periods.\122\ These cost increases are similar to those being 
faced in NYISO and PJM, where interconnection costs, per kW, have 
doubled (or more) for recently completed generating facilities.\123\ As 
a result, we find that this combination of increased volume of diverse 
interconnection requests and insufficient transmission capacity leading 
to higher costs to interconnect, which can result in interconnection 
request withdrawals, has resulted in longer interconnection queue 
processing times and larger, more delayed interconnection queues.
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    \118\ Queued Up 2023 at 9; see also Colorado Commission Comments 
at 9 (stating that the growth of solar project interconnection 
requests is a significant cause of the overall supply and demand 
imbalance across all RTOs/ISOs as well as other regions).
    \119\ Colorado Commission Initial Comments at 9.
    \120\ See, e.g., NYISO Initial Comments at 6-7 (stating that 
``[s]tudies are only becoming more complex with the expanding scope 
of ISO/RTOs' interconnection responsibilities''); Xcel Initial 
Comments at 7 (stating that ``in many cases study models with large 
clusters are difficult to solve . . . Ensuring new transmission 
lines are realistic and even validating substation designs and 
locations takes significant work to be done properly'').
    \121\ See, e.g., ACORE Initial Comments at 2 (noting that 
``upgrades based on generation interconnection may be a sub-optimal, 
expensive, and ultimately ineffective way to accomplish transmission 
expansion''); AEE Initial Comments at 3 (asserting that 
``inefficient and impeded interconnection processes lead to 
unacceptable delays and artificially high interconnection costs''); 
EDF Renewables Initial Comments at 3.
    \122\ Joachim Seel et al., Generator Interconnection Cost 
Analysis in the Midcontinent Independent System Operator (MISO) 
Territory, at 1, 4-5 (2022), https://emp.lbl.gov/interconnection_costs.
    \123\ Julia Mulvaney Kemp et al., Interconnection Cost Analysis 
in the NYISO Territory (2023), https://emp.lbl.gov/publications/interconnection-cost-analysis-nyiso (showing that costs have doubled 
for generating facilities studied since 2017, relative to costs for 
generating facilities studied from 2006 to 2016); Joachim Seel et 
al., Interconnection Cost Analysis in the PJM Territory (2023), 
https://emp.lbl.gov/publications/interconnection-cost-analysis-pjm 
(showing that costs for recent ``complete'' generating facilities 
have doubled on average relative to costs from 2000-2019).
---------------------------------------------------------------------------

    42. In response to comments asserting that the Commission did not 
take into account other factors affecting interconnection queue sizes, 
such as the development of smaller, more diverse generating facilities, 
in its preliminary findings on the need for reform in the NOPR,\124\ we 
find that the record shows that interconnection queue sizes are 
increasing in both number of interconnection requests and in total MW 
capacity in all regions of the country and such increases are not due 
to an influx of any particular size of proposed generating facility. 
Moreover, data show that the median duration for all generating 
facilities that enter the interconnection queue hovers around 30 
months, independent of the size of the interconnection request.\125\
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    \124\ See, e.g., Pine Gate Reply Comments at 4 (stating that 
``the days of . . . large, conventional resources are waning as the 
majority of interconnection requests are now comprised of smaller, 
more diverse resource'' and that ``[l]arger interconnection queues 
are, to a certain extent, a natural byproduct of this change''); 
SEIA Reply Comments at 1 (contending that interconnection requests 
have increased in number ``because newer projects are smaller and 
have less capacity'' and ``[m]ore interconnection requests are 
needed to integrate the same amount of generation capacity into the 
grid'').
    \125\ Queued Up 2023 at 29.
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    43. Interconnection queue backlogs and delays have created 
uncertainty for interconnection customers regarding the timing and cost 
of ultimately interconnecting to the transmission system. We agree with 
commenters that such uncertainty, on the part of both transmission 
provider and interconnection customer, may lead to an increase in costs 
to consumers.\126\ First, delayed interconnection study results or 
unexpected cost increases can disrupt numerous aspects of generating 
facility development.\127\ Cost

[[Page 61023]]

uncertainty poses an especially significant obstacle because 
interconnection customers may not be able to finance substantial 
increases in unexpected interconnection costs. Second, transmission 
providers may face uncertainty regarding the size and makeup of the 
interconnection queue and the commercial viability of the project in 
the interconnection queue, creating inefficiencies in the study 
process, increasing interconnection study costs, and delayed study 
results. Such uncertainty, either on the part of transmission providers 
or interconnection customers, are ultimately passed through to 
consumers through higher transmission or energy rates.\128\ Increases 
in energy rates may result from wholesale customers having limited 
access to new and more competitive supplies of generation. Conversely, 
efficient interconnection queues and well-functioning wholesale markets 
deliver benefits to consumers by driving down wholesale electricity 
costs.
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    \126\ See, e.g., Ameren Initial Comments at 2; ELCON Initial 
Comments at 2; ELCON Initial Comments at 2; Xcel Initial Comments at 
8.
    \127\ See, e.g., Interwest Initial Comments at 8 (contending 
that ``[t]he harm to interconnection customers associated with 
interconnection study delays can be significant and costly, 
including liquidated damages if compliance with a commercial 
operation deadline is at risk'').
    \128\ Ameren Initial Comments at 2.
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    44. As the interconnection queue backlogs and study delays continue 
and even increase, we find that the Commission's existing rules 
contained in the pro forma LGIP, pro forma LGIA, pro forma SGIP, and 
pro forma SGIA result in rates, terms, and conditions for Commission-
jurisdictional services that are unjust, unreasonable, and unduly 
discriminatory or preferential. Not only do the problems described 
above lead to an inability of interconnection customers to interconnect 
to the transmission system in a reliable, efficient, transparent, and 
timely manner, they also hinder the timely development of new 
generation, thereby stifling competition in the wholesale electric 
markets. We, therefore, find that reform to the Commission's existing 
pro forma generator interconnection procedures and agreements is 
necessary.
    45. Our findings that the existing pro forma LGIP, pro forma LGIA, 
pro forma SGIP, and pro forma SGIA must be reformed are based on the 
following features of these existing rules: (1) the information (or 
lack thereof) available to prospective interconnection customers and 
the commitments required of them to enter and progress through the 
interconnection queue; (2) the reliance on a serial first-come, first-
served study process and the ``reasonable efforts'' standard that 
transmission providers are held to for meeting interconnection study 
deadlines; (3) the protocols (or lack thereof) for affected system 
studies; (4) the provisions for studying new generating facility 
technologies and evaluating the list of alternative transmission 
technologies enumerated in this final rule; and (5) the modeling or 
performance requirements (or lack thereof) for non-synchronous 
generating facilities, including wind, solar, and electric storage 
facilities. We discuss each of these five features below.
    46. First, we find that existing pro forma generator 
interconnection procedures and agreements fail to contain a process by 
which an interconnection customer can obtain information about 
potential interconnection costs at a specific location or point of 
interconnection prior to submitting an interconnection request. Without 
this information, it is difficult for interconnection customers to 
assess the commercial viability of a specific proposed generating 
facility prior to entering the interconnection queue.\129\ Furthermore, 
we find that for interconnection customers, the pro forma 
interconnection procedures and agreements fail to include meaningful 
financial commitment requirements to enter and stay in the 
interconnection queue and lack of stringent requirements to establish 
the commercial viability of proposed generating facilities.\130\ As a 
result, interconnection customers often submit multiple interconnection 
requests for proposed generating facilities at various points of 
interconnection, knowing that not all of the proposed generating 
facilities will reach commercial operation, as an exploratory mechanism 
to obtain information to allow the interconnection customer to choose 
to proceed with the interconnection request representing the most 
favorable site in terms of potential interconnection-related 
costs.\131\ For instance, recent interconnection study metrics posted 
by transmission providers continue to show that some interconnection 
customers are withdrawing interconnection requests before any studies 
are completed.\132\ While interconnection customers may withdraw at any 
stage of the interconnection process, to do so before any study is 
completed indicates that interconnection customers may lack information 
prior to entering the interconnection queue and are entering to obtain 
valuable information about the commercial viability of their proposed 
projects vis-[agrave]-vis other interconnection customers in the queue 
or cluster.
---------------------------------------------------------------------------

    \129\ See, e.g., Fervo Energy Initial Comments at 2-3 (stating 
that ``the incidence of interconnection applications simply intended 
to solicit information discovery from the transmission provider . . 
. is a significant defect in today's queue process''); Google 
Initial Comments at 4 (asserting that ``there is extreme information 
asymmetry in the interconnection process,'' with transmission owners 
and their affiliates having greater access than independent power 
producers to information on the relative cost of interconnection at 
different points).
    \130\ See, e.g., Dominion Initial Comments at 4 (stating that 
``owners of speculative projects remain in the queue process for as 
long as they possibly can in the hopes that their project somehow 
becomes viable''); U.S. Chamber of Commerce Initial Comments at 5 
(concurring with the NOPR that there is a ``lack of stringent 
financial commitments and readiness requirements on interconnection 
customers'').
    \131\ See, e.g., Clean Energy Associations Initial Comments at 
11 (stating that ``[i]n most cases, customers must actually enter 
the queue to ascertain what upgrade costs they will be responsible 
for''); Clean Energy Buyers Initial Comments at 3 (stating that 
inefficiencies in the serial study queue are ``compounded by 
exploratory interconnection requests that are based on developers' 
attempts to obtain locations with available transmission 
capacity''); NY Commission and NYSERDA Initial Comments at 6-7 
(stating that ``increased access to valuable information . . . could 
deter developers from submitting multiple, speculative 
[interconnection requests]'').
    \132\ Based on data provided by transmission providers in 
compliance with Order No. 845 (showing that 35% of withdrawals in 
2022 took place before any studies had been completed). See appendix 
B to this final rule for the underlying data.
---------------------------------------------------------------------------

    47. Second, the existing serial first-come, first-served study 
process in the pro forma LGIP requires transmission providers to 
process interconnection requests in the order in which the transmission 
provider receives them. This approach creates incentives for 
interconnection customers to submit exploratory or speculative 
interconnection requests pursuant to which interconnection customers 
seek to secure valuable queue positions as early as possible, even if 
they are not prepared to move forward with the proposed generating 
facility. Such generating facilities are often not commercially viable 
and, thus, the interconnection customers ultimately withdraw from the 
interconnection queue. We agree with commenters that the withdrawal of 
speculative interconnection requests that trigger reassessments and 
possible restudies by the transmission provider can delay the timing 
and increase the cost to interconnect for lower-queued interconnection 
requests.
    48. In summary, we find that the lack of (1) access of information 
about a specific location or point of interconnection prior to 
submitting an interconnection request and (2) meaningful financial 
commitments in the pro forma interconnection procedures and agreements 
for interconnection customers to enter and stay in the interconnection 
queue, as well as the existing serial first-come,

[[Page 61024]]

first-served study process, all incentivize interconnection customers 
to submit speculative interconnection requests that contribute to 
interconnection study backlogs, delays, and uncertainty, and, in turn, 
unjust and unreasonable Commission-jurisdictional rates.
    49. We disagree with commenters' assertions that there is no basis 
to find that speculative interconnection requests are responsible for 
interconnection queue backlog and delays. We highlight that more than 
70% of interconnection requests were withdrawn from the interconnection 
queue between 2000 and 2017.\133\ Although we recognize that there are 
various reasons an interconnection customer may withdraw its request 
from the interconnection queue, a withdrawal indicates an inability to 
reach commercial operation. Because a withdrawal can trigger costly 
restudies and create uncertainty in the interconnection process for 
interconnection customers and transmission providers alike, withdrawals 
of commercially non-viable interconnection requests from the 
interconnection queue is a significant contributing factor to 
interconnection queue backlogs and delays.\134\ Late-stage withdrawals 
of interconnection requests are also increasing.\135\ Late-stage 
withdrawals present a significant problem, as they can trigger 
restudies for other interconnection customers that can result in 
significant increases to the interconnection costs attributed to those 
customers and the timeline for completion of interconnection studies, 
which can result in further late-stage withdrawals, thus exacerbating 
the interconnection queue backlogs and delays.\136\
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    \133\ Queued Up 2023 at 18 (reporting that 72% of all 
interconnection requests submitted from 2000-2017 were withdrawn).
    \134\ See, e.g., Ohio Commission Consumer Advocate Initial 
Comments at 8 (stating that ``[e]ach withdrawn project entails PJM 
restudy on lower-queued projects, which delays the processing of new 
service queues and may have the consequence of a cascade of 
withdrawals'').
    \135\ Queued Up 2023 at 22.
    \136\ See, e.g., AEE Initial Comments at 4-5; Queued Up 2023 at 
22.
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    50. We also find that interconnection queue backlogs and delays, 
and the accompanying uncertainty, are further compounded because 
transmission providers have limited incentive to perform 
interconnection studies in a timely manner. Under the pro forma LGIP, 
transmission providers are held to a ``reasonable efforts'' standard in 
completing interconnection studies consistent with their tariff-imposed 
deadlines. However, this standard offers significant discretion to the 
transmission providers in extending their own deadlines. The record 
demonstrates that a majority of transmission providers across the 
country regularly fail to meet interconnection study deadlines.\137\ 
Despite pervasive delays in completing interconnection studies by 
transmission providers, we acknowledge that transmission providers have 
faced few, if any, consequences for failing to meet their tariff-
imposed study deadlines under the reasonable efforts standard.\138\ 
This outcome stands in stark contrast to interconnection customers that 
face financial and commercial consequences due to late interconnection 
study results and may be considered withdrawn from the interconnection 
queue for failing to meet their tariff-imposed deadlines.\139\ For 
these reasons, we find that the existing pro forma LGIP requirement for 
transmission providers to make a reasonable effort to meet 
interconnection study deadlines contributes to the interconnection 
study backlogs, delays, and uncertainty that erects barriers to new 
generation.\140\ Therefore, we find that the use of a reasonable 
efforts standard in the existing pro forma LGIP results in Commission-
jurisdictional rates that are unjust and unreasonable.
---------------------------------------------------------------------------

    \137\ For example, based on data submitted by transmission 
providers in compliance with Order No. 845, 80% of transmission 
providers had delayed studies in at least one of the past three 
years (2020-2022) and 57% had delayed studies in at least two.b See 
also NARUC Initial Comments at 13 (stating ``nearly all transmission 
providers across the country, including many transmission providers 
that have implemented queue reforms, regularly fail to meet 
interconnection study deadlines'').
    \138\ See, e.g., Clean Energy Associations Initial Comments at 
43-44 (stating that ``[a]t present, there is no specific incentive 
for delivering on-time and accurate studies, and late or inaccurate 
studies bring few if any consequences'').
    \139\ See, e.g., ACE-NY Initial Comments at 3 (``Project 
developers have strict deadlines they must adhere to in the 
interconnection process, with penalties that include the forced 
withdrawal of the project from the queue.'').
    \140\ See, e.g., NARUC Initial Comments at 13-14 (contending 
that ``the tendency to miss deadlines introduces uncertainty in a 
process that is important to bringing new generation online in a 
timely and cost-effective manner'').
---------------------------------------------------------------------------

    51. Third, the pro forma LGIP includes no requirements regarding 
how or when transmission providers should complete affected system 
studies. Without requirements, affected system studies often lag behind 
those completed by the transmission provider to whose transmission 
system the interconnection customer proposes to interconnect (the so-
called host transmission provider) and are sometimes completed very 
late in the interconnection process, causing an additional round of 
delays and cost uncertainty for interconnection customers.\141\ 
Additionally, for transmission providers that have procedures for how 
to complete affected system studies in their tariffs or other documents 
(e.g., business practice manuals or joint operating agreements), the 
procedures are not consistent, may be hard for interconnection 
customers to locate, and may not represent the actual practices in use 
by the transmission provider, thus still creating uncertainty for 
interconnection customers. As a result, we find that the lack of 
consistent requirements for affected system modeling and procedures 
results in Commission-jurisdictional rates that are unjust, 
unreasonable, and unduly discriminatory or preferential.
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    \141\ See, e.g., MISO Initial Comments at 72 (stating that ``the 
need to wait for affected systems studies is the cause of the 
majority of delays in the MISO study process''); May Joint Task 
Force Tr. 65:2-8 (Dan Scripps) (citing affected systems studies as 
``a growing source of delay and cost uncertainty for interconnection 
customers, both in terms of just the timelines involved and the 
difficulty in pinning those down'').
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    52. Fourth, we find that the Commission's pro forma LGIP fails to 
accommodate the operating characteristics and technical capabilities of 
electric storage resources when it comes to specific interconnection 
procedures and modeling. As stated above, the interconnection queues 
predominantly consist of new technologies which have operating 
characteristics that differ from synchronous resources and were not 
anticipated when the Commission established the pro forma generator 
interconnection procedures and agreements in Order Nos. 2003 and 2006. 
Specifically, electric storage resources can be charged and dispatched 
on a flexible, as-available basis, and are less likely than synchronous 
generating facilities to withdraw energy from the transmission system 
during peak load conditions or discharge during light load 
conditions.\142\ However, the existing pro forma generator 
interconnection procedures and agreements do not contemplate these 
operating characteristics or technical capabilities of electric storage 
resources. As a result, we find that electric storage resources

[[Page 61025]]

(whether standalone, co-located generating facilities, or part of a 
hybrid generating facility), may be studied under inappropriate 
operating assumptions (e.g., charging at full capacity during peak load 
conditions) that result in assigning unnecessary network upgrades and 
increased costs to interconnection customers. Therefore, we find that 
the Commission's pro forma LGIP's lack of ability to modify operating 
assumptions for electric storage resources results in Commission-
jurisdictional rates that are unjust, unreasonable, and unduly 
discriminatory or preferential.
---------------------------------------------------------------------------

    \142\ See, e.g., Bonneville Initial Comments at 22-23 (stating 
that ``storage resources are less likely to charge during peak load 
conditions or discharge during light load conditions, and . . . 
those considerations can be factored into assumptions used in 
interconnection studies''); NARUC Initial Comments at 37 (stating 
that ``assuming that an energy storage device will withdraw energy 
during peak demand . . . fails to recognize that those resources are 
likely to be highly responsive to price signals from the 
transmission provider and can improve reliability'').
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    53. Additionally, the record supports a finding that the existing 
pro forma interconnection procedures regarding material modifications 
do not provide for consistent evaluation of technology additions to an 
existing interconnection request.\143\ We find that the record 
demonstrates that automatically deeming a request to add a generating 
facility to an existing interconnection request to be a material 
modification creates a significant barrier to access to the 
transmission system.\144\ As a result, we find the existing pro forma 
LGIP and pro forma LGIA results in Commission-jurisdictional rates that 
are unjust and unreasonable.
---------------------------------------------------------------------------

    \143\ See, e.g., NARUC Initial Comments at 35 (stating that the 
``loss of queue position as a result of adding a generating facility 
that does not increase the requested service level or cause 
reliability issues . . . is an inefficient and discriminatory 
outcome'').
    \144\ See, e.g., AEE Initial Comments at 40-41; Public Interest 
Organizations Initial Comments at 45-47; SEIA Initial Comments at 
38-39.
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    54. Finally, the record supports a finding that the Commission's 
pro forma LGIP and pro forma SGIP fail to require the consideration of 
alternative transmission technologies that can be deployed more quickly 
to be used as network upgrades in place of, and at a lower cost than, 
traditional network upgrades.\145\ In addition, commenters contend that 
some alternative transmission technologies could provide substantial 
benefits by resolving thermal overloads and avoiding voltage collapse, 
allowing for better use of the existing transmission system, improving 
reliability, and reducing interconnection request withdrawals, 
restudies, and overall interconnection delays.\146\ We find that 
failing to require transmission providers to evaluate the list of 
alternative transmission technologies enumerated in this final rule 
results in interconnection customers paying more than is just and 
reasonable to reliably interconnect new generating facilities, 
resulting in Commission-jurisdictional rates that are unjust, 
unreasonable, and unduly discriminatory or preferential. Because the 
benefits of the enumerated alternative transmission technologies 
identified above are present across all interconnection processes, 
regardless of the size of the interconnection request, we find that the 
failure to evaluate the enumerated alternative transmission 
technologies results in both the pro forma LGIP and pro forma SGIP 
being unjust, unreasonable, and unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \145\ See, e.g., NARUC Initial Comments at 38 (stating that 
``failing to consider alternative transmission technologies that can 
be deployed both more quickly and at lower costs than network 
upgrades may render Commission-jurisdictional rates unjust and 
unreasonable''); OMS Initial Comments at 19 (agreeing that ``failing 
to consider these alternative transmission technologies runs the 
risk of implementing longer lead-time network upgrades at a higher 
cost'').
    \146\ See, e.g., AEE Initial Comments at 42 (stating that 
alternative transmission technologies ``provide benefits beyond 
potential costs savings, including maximizing limited rights-of-way 
and potentially avooiding or minimizing environmental and property 
impacts taht can bog down siting and permitting proceedings''); Ohio 
Commission Consumer Advocate Initial Comments at 15 (stating that 
``[t]hese grid-enhancing technologies (`GETs') can improve 
opertations, enhance system reliability, contribute to capacity, and 
more'' and ``[s]ome [grid-enhancing technologies] could provide 
substantial benefits by resolving thermal overloads and avoiding 
voltage collapse, among other things''); WATT Coalition Initial 
Comments at 2 (referring to the report Unlocking the Queue with Grid 
Enhancing Technologies that showed that application of the three 
grid-enhancing technologies in the Kansas and Oklahoma transmission 
systems would enable twice as much renewable energy to interconnect 
out of the queues without any traditional transmission upgrades.).
---------------------------------------------------------------------------

    55. Fifth, we find that the Commission's existing pro forma LGIP 
and pro forma SGIP do not include a modeling requirement for non-
synchronous generating facilities, which is necessary to enable the 
transmission provider to assess and model the facility's ability to 
respond appropriately to transmission system disturbances. These 
modeling requirements include: (1) a validated, user-defined root mean 
square (RMS) positive sequence dynamic model; (2) an appropriately 
parameterized, generic library RMS positive sequence dynamic model; and 
(3) a validated electromagnetic transient (EMT) model, if the 
transmission provider performs an EMT study as part of the 
interconnection study process. Additionally, we find that accurate and 
validated models are necessary to address study delays and to ensure 
that transmission providers identify the necessary interconnection 
facilities and network upgrades to accommodate the interconnection 
request and appropriate assignment of interconnection costs. As a 
result, we find that the lack of a modeling requirement for non-
synchronous generating facilities in the pro forma LGIP and pro forma 
SGIP results in rates that are unjust, unreasonable, and unduly 
discriminatory or preferential.
    56. Furthermore, the physical characteristics of synchronous 
generating facilities allow them to continue to inject electric current 
during transmission system disturbances, as required by the pro forma 
LGIA and pro forma SGIA.\147\ However, non-synchronous generating 
facilities do not face a comparable requirement and many cease 
injecting current through ``momentary cessation,'' which creates 
reliability issues on the transmission system.\148\ Moreover, without 
requirements for non-synchronous generating facilities to remain 
connected to and synchronized with the transmission system, 
interconnection studies may not accurately model expected behavior and 
identify the appropriate interconnection facilities and network 
upgrades to accommodate the interconnection request, skewing the 
assignment of interconnection costs. As a result, we find that the lack 
of comparable requirements for non-synchronous generating facilities to 
remain ``connected to and synchronized with the [t]ransmission 
[s]ystem'' in the pro forma LGIA and pro forma SGIA results in rates 
that are unjust, unreasonable, and unduly discriminatory or 
preferential.
---------------------------------------------------------------------------

    \147\ Pro forma LGIA art. 9.7.3 and pro forma SGIA art. 1.5.7 
require synchronous generating facilities to remain ``connected to 
and synchronized with'' the transmission system during system 
disturbances.
    \148\ See, e.g., NERC Initial Comments at 9 (stating that 
``improper planning and operation of [non-synchronous resources] can 
pose a significant risk to . . . reliability'' and adding that 
``risk mitigation measures . . . have been inconsistently adopted by 
industry''); MISO TOs Initial Comments at 32-33 (concurring with the 
Commission that ``with more and more non-synchronous generation 
facilities entering the interconnection queue, the lack of a 
requirement for such resources to respond to system disturbances 
becomes `more consequential' '').
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    57. In response to commenters that express broad opposition to the 
need for reform, we disagree with assertions that the existence of 
regional variation in interconnection procedures across the country 
creates an insufficient legal foundation under FPA section 206 to 
demonstrate that rates are unjust, unreasonable, and unduly 
discriminatory or preferential. Similarly, we disagree with assertions 
that reforms to the pro forma generator interconnection procedures and 
agreements are arbitrary and capricious because the problems identified 
herein do not exist uniformly. As an initial matter, the ``Commission 
may rely on `generic' or `general' findings of a systemic problem to 
support imposition

[[Page 61026]]

of an industry-wide solution.'' \149\ That some interconnection 
processes may fare better in the face of industry-wide challenges would 
be ``as unastonishing as it is irrelevant.'' \150\ The Commission may 
reasonably rely on rulemaking to address the systemic drivers leading 
to widespread interconnection queue backlogs and delays, 
notwithstanding regional variation among interconnection procedures.
---------------------------------------------------------------------------

    \149\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 67 (D.C. Cir. 
2014) (quoting Interstate Nat. Gas Ass'n of Am. v. FERC, 285 F.3d 
18, 37 (2002)).
    \150\ Id. (quoting Wis. Gas v. FERC, 770 F.2d 1144, 1157 (D.C. 
Cir. 1985)).
---------------------------------------------------------------------------

    58. Moreover, as noted above, every region of the country is seeing 
an increase in both interconnection queue size and the length of time 
interconnection customers are spending in the interconnection queue 
prior to commercial operation in recent years.\151\ Furthermore, the 
uncertainty and delays in the interconnection queues have resulted in 
fewer than 25% of interconnection requests, by capacity, reaching 
commercial operation between 2000 and 2017 in any region of the 
country--with some regions as low as 8%.\152\ For example, only 10% of 
interconnection requests, by capacity, have reached commercial 
operation in the non-RTO/ISO southeast region between 2000 and 
2017.\153\ Additionally, the challenges being faced across the country 
will be further compounded in the future given the recent spikes in 
interconnection queue sizes. In the non-RTO/ISO southeast region, the 
interconnection queue size has more than tripled between 2014 and 2022, 
with the increase predominantly made up of solar, storage, and hybrid 
generating facilities, adding potential complexity to future 
interconnection queue study processes.\154\ To the extent existing pro 
forma interconnection procedures, such as first-come, first-served 
study processes, have worked in the past for smaller or less complex 
queues, such experience is not indicative of what will be necessary in 
the future to ensure that a growing number of interconnection requests 
are processed in a reliable, efficient, transparent, and timely 
manner.\155\ Finally, as recognized in Order No. 2003, interconnection 
queue delays may ``provide[] an unfair advantage to utilities that own 
both transmission and generation facilities,'' \156\ making it 
exceedingly necessary that interconnection delays are addressed in all 
regions of the country, especially those where transmission providers 
continue to own both transmission and generation.\157\ As discussed 
above, because interconnection queue backlogs and delays afflict 
generator interconnection service nationwide, which hinders the timely 
development of new generation and thereby stifles competition in the 
wholesale electric markets, reforms are necessary to ensure Commission-
jurisdictional rates are just, reasonable, and not unduly 
discriminatory or preferential.
---------------------------------------------------------------------------

    \151\ Queued Up 2023 at 9, 32.
    \152\ Id. at 3, 21.
    \153\ Id. at 21.
    \154\ Id. at 9.
    \155\ See, e.g., Public Interest Organization Initial Comments 
at 17; R Street Initial Comments at 3.
    \156\ Order No. 2003, 104 FERC ] 61,103 at P 11.
    \157\ See, e.g., Pine Gate Initial Comments at 15; AEE Reply 
Comments at 22.
---------------------------------------------------------------------------

    59. We are not persuaded by commenters' concerns that the reforms 
proposed in the NOPR, many of which we adopt in this final rule, will 
be counterproductive in addressing the need for reform. As discussed in 
more detail throughout this final rule, we believe that the reforms 
adopted herein, as a whole, will improve the efficiency of study 
processes, reduce interconnection queue backlogs, and thereby ensure 
just, reasonable, and not unduly discriminatory or preferential rates. 
We believe that, on balance, the reforms will produce efficiencies by, 
for example, reducing speculative interconnection requests and 
interconnection request withdrawals, which in turn will reduce the time 
and resources spent in interconnection studies and restudies thereby 
decreasing interconnection queue backlogs and delays. Additionally, the 
majority of the individual reforms that the Commission proposed in the 
NOPR and we adopt in this final rule have already been implemented in 
one or more regions in order to improve the interconnection process, 
demonstrating incremental improvements. This final rule uses some of 
these individual and incremental improvements as a basis for a broad 
suite of reforms that, in their entirety, have not yet been adopted by 
any region and we believe will ensure that interconnection customers 
are able to interconnect to the transmission system in a reliable, 
efficient, transparent, and timely manner. In some cases, such as for 
the commercial readiness reforms adopted in this final rule, we have 
significantly modified the NOPR proposal based on comments received.
    60. Having concluded that the existing pro forma generator 
interconnection procedures and agreements are unjust, unreasonable, and 
unduly discriminatory or preferential, we turn, as we are required to 
do under FPA section 206,\158\ to determining the replacement rate, 
described--at some length--below.
---------------------------------------------------------------------------

    \158\ 16 U.S.C. 824e(a); see, e.g., FERC v. Electric Power 
Supply Ass'n, 577 US 260, 277 (2016) (``If FERC sees a violation of 
[the just and reasonable] standard, it must take remedial action.'')
---------------------------------------------------------------------------

III. Reforms

A. Reforms To Implement a First-Ready, First-Served Cluster Study 
Process

1. Interconnection Information Access
a. Need for Reform
i. NOPR
    61. The Commission noted its concern regarding the lack of 
information available to prospective interconnection customers 
regarding potential interconnection costs prior to submitting an 
interconnection request.\159\ The Commission stated that, without this 
information, it is difficult for interconnection customers to assess 
the viability of a specific proposed generating facility. Subsequently, 
interconnection customers submit multiple speculative interconnection 
requests in an attempt to obtain information through the system impact 
study process about the costs associated with various project 
configurations. The Commission preliminarily found that the 
Commission's pro forma LGIP and pro forma LGIA are unjust, 
unreasonable, and unduly discriminatory or preferential and that 
reforms are needed to allow interconnection customers to interconnect 
in a reliable, efficient, transparent, and timely manner, thereby 
ensuring that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly 
discriminatory or preferential.\160\
---------------------------------------------------------------------------

    \159\ NOPR, 179 FERC ] 61,194 at P 40.
    \160\ Id. P 39.
---------------------------------------------------------------------------

ii. Comments
    62. Several commenters contend that it is a rational response to a 
lack of pre-interconnection queue information for interconnection 
customers to submit multiple interconnection requests to gain 
information on which interconnection sites are favorable and hedge 
risks, which leads to withdrawals that exacerbate unmanageable 
interconnection queue backlogs.\161\ ELCON and Environmental Defense

[[Page 61027]]

Fund argue that the lack of sufficient information and unexpected cost 
escalation are the primary reasons interconnection requests are 
withdrawn, leading to delays and inefficiencies.\162\
---------------------------------------------------------------------------

    \161\ AES Initial Comments at 3; Affected Interconnection 
Customers Initial Comments at 30; Clean Energy Buyers Initial 
Comments at 5-6; CREA and NewSun Initial Comments at 45; 
Environmental Defense Fund Initial Comments at 3; ELCON Initial 
Comments at 3; Northwest and Intermountain Initial Comments at 5; 
Public Interest Organizations Initial Comments at 18.
    \162\ Environmental Defense Fund Initial Comments at 3; ELCON 
Initial Comments at 4.
---------------------------------------------------------------------------

    63. Many commenters agree with the goal of providing additional 
information prior to entering the interconnection queue.\163\ Some 
commenters state that additional information prior to entering the 
interconnection queue is beneficial,\164\ in particular access to 
information on potential network upgrades and the cost and time to 
interconnect.\165\ Many commenters expect that potential 
interconnection customers' access to additional information prior to 
entering the interconnection queue will reduce speculative 
interconnection requests, thus promoting reliability and cost savings 
by encouraging more optimal interconnection requests that can be 
processed more efficiently and at lower overall cost.\166\
---------------------------------------------------------------------------

    \163\ ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP 
Initial Comments at 12; AES Initial Comments at 3; Affected 
Interconnection Customers Initial Comments at 30; APS Initial 
Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers 
Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON 
Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial 
Comments at 15; MISO Initial Comments at 20-21; NARUC Initial 
Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and 
NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs 
Initial Comments at 8; Pacific Northwest Utilities Initial Comments 
at 13; PJM Initial Comments at 45; Puget Sound Initial Comments at 
5; WAPA Initial Comments at 5.
    \164\ AEP Initial Comments at 12; APS Initial Comments at 4.
    \165\ EEI Reply Comments at 7-8; New Jersey Commission Initial 
Comments at 23; NV Energy Initial Comments at 13.
    \166\ Affected Interconnection Customers Initial Comments at 30; 
Clean Energy States Initial Comments at 3; Duke Southeast Utilities 
Initial Comments at 6; Environmental Defense Fund Initial Comments 
at 3; ELCON Initial Comments at 3-4; Fervo Energy Initial Comments 
at 2-3; Google Initial Comments at 4-5; NARUC Initial Comments at 4-
5; NESCOE Reply Comments at 3; New Jersey Commission Initial 
Comments at 20-22; New York State Department Initial Comments at 8; 
Pacific Northwest Utilities Initial Comments at 13; Public Interest 
Organizations Initial Comments at 18; Puget Sound Initial Comments 
at 5; SDG&E Initial Comments at 3-4.
---------------------------------------------------------------------------

    64. Several commenters note the importance of additional 
interconnection information access in light of the other reforms 
proposed in the NOPR. AES contends that it would be inequitable for the 
Commission to increase security deposits to stay in the interconnection 
queue under the NOPR proposal to increase study and LGIA deposits 
without requiring transmission providers to provide sufficient 
information to interconnection customers.\167\ Vistra asserts that the 
proposals to provide additional information will complement the 
exclusive site control proposals and provide an avenue for prospective 
interconnection customers to select the most viable sites on which to 
obtain rights and develop a location, which is a costly and time-
consuming process, before entering the interconnection queue.\168\ 
Northwest and Intermountain argue that, in order for the other proposed 
reforms in the NOPR to be effective, potential interconnection 
customers must have a solution to the problem of identifying optimal 
interconnection locations and configurations that is timely, cost-
effective, and accurate.\169\
---------------------------------------------------------------------------

    \167\ AES Initial Comments at 13.
    \168\ Vistra Initial Comments at 4.
    \169\ Northwest and Intermountain Initial Comments at 9.
---------------------------------------------------------------------------

    65. Google contends that pre-queue information is necessary because 
there is an extreme information asymmetry between independent power 
producers and transmission owners and their generating affiliates, 
which have greater access to planning information, including load 
growth, relative cost of interconnecting at different points, points of 
chronic congestion where upgrades might be needed, and planned local 
upgrades.\170\ Google asserts that this information asymmetry is 
particularly pronounced in the non-RTO/ISO regions, and allows 
transmission owners and their affiliates to identify the best locations 
for interconnection more quickly than independent power producers.
---------------------------------------------------------------------------

    \170\ Google Initial Comments at 3-4.
---------------------------------------------------------------------------

    66. On the other hand, Dominion argues that there is no evidence in 
the record that a lack of information is slowing down the 
interconnection queue process or that transmission providers are not 
engaged in good faith reviews of interconnection requests.\171\ 
According to Dominion, the Commission should focus on making the 
interconnection process more efficient and speedier, and the best way 
to achieve these goals is through the first-ready, first-served cluster 
study reform. While APPA-LPPC support transparency in the generator 
interconnection process and share the Commission's view that the 
availability of transmission system information should reduce the 
incentive to submit speculative interconnection requests, they argue 
that sufficient information is currently publicly available.\172\
---------------------------------------------------------------------------

    \171\ Dominion Reply Comments at 8-9.
    \172\ APPA-LPPC Initial Comments at 11.
---------------------------------------------------------------------------

iii. Commission Determination
    67. We find that, absent reforms to require transmission providers 
to provide additional interconnection information, which can be used by 
interconnection customers prior to submitting an interconnection 
request, speculative interconnection requests will likely remain at 
current levels and continue to contribute to interconnection study 
delays and add costs to the interconnection process. Although 
submitting multiple interconnection requests to gain information may be 
a rational response to a lack of pre-interconnection queue information, 
this practice increases interconnection study delays.\173\ We also 
agree with commenters that additional access to interconnection 
information is a valuable goal \174\ as it can increase the likelihood 
that an interconnection request is viable when submitted. We disagree 
with commenters that current information requirements are 
sufficient.\175\ While certain information is currently available 
through the feasibility study process, as part of our reforms discussed 
below, we eliminate the feasibility study. Therefore, we find it 
necessary to provide a means for interconnection customers to obtain 
additional information prior to entering the interconnection queue. We 
concur with comments that additional access to interconnection 
information prior to entering the interconnection queue is important 
for interconnection customers to make informed decisions, particularly 
given the increased requirements for interconnection customers adopted 
in this final rule, such as increased study deposits and site control, 
as discussed

[[Page 61028]]

below.\176\ We also agree that commenters raise a valid concern that an 
information asymmetry exists between independent power producers and 
transmission owner affiliates, in particular in non-RTO/ISO 
regions.\177\
---------------------------------------------------------------------------

    \173\ See AES Initial Comments at 3; Affected Interconnection 
Customers Initial Comments at 30; Clean Energy Buyers Initial 
Comments at 5-6; CREA and NewSun Initial Comments at 45; 
Enviornmental Defense Fund Initial Comments at 3; ELCON Initial 
Comments at 3; Northwest and Intermountain Initial Comments at 5; 
Public Interest Organizations Initial Comments at 18.
    \174\ ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP 
Initial Comments at 12; AES Initial Comments at 3; Affected 
Interconnection Customers Initial Comments at 30; APS Initial 
Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers 
Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON 
Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial 
Comments at 15; MISO Initial Comments at 20-21; NARUC Initial 
Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and 
NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs 
Initial Comments at 8; Pacific Northwest Utilities Initial
    Comments at 13; PJM Initial Comments at 45; Puget Sound Initial 
Comments at 5; WAPA Initial Comments at 5.
    \175\ APPA-LPPC Initial Comments at 9.
    \176\ AES Initial Comments at 13; Northwest and Intermountain 
Initial Comments at 9; Vistra Initial Comments at 4.
    \177\ Google Initial Comments at 3-5.
---------------------------------------------------------------------------

b. Informational Interconnection Study
i. NOPR Proposal
    68. In the NOPR, the Commission proposed to revise the Commission's 
pro forma LGIP to require transmission providers to offer an 
informational interconnection study for prospective interconnection 
customers.\178\ The Commission proposed that the informational 
interconnection study would provide cost estimates for the transmission 
provider's interconnection facilities and network upgrade costs 
specific to the interconnection scenario detailed in the study 
agreement. The Commission also proposed to include new definitions for 
an informational interconnection study and informational 
interconnection study agreement.
---------------------------------------------------------------------------

    \178\ NOPR, 179 FERC ] 61,194 at P 42.
---------------------------------------------------------------------------

    69. Under the Commission's proposal, prospective interconnection 
customers could request up to five separate informational 
interconnection studies at a time.\179\ The Commission explained that 
each configuration of an interconnection request would require a 
separate informational interconnection study. The Commission proposed 
that the informational interconnection study would be at the 
interconnection customer's expense, and each study would require a 
$10,000 deposit, subject to a true-up based on actual study costs.
---------------------------------------------------------------------------

    \179\ Id. P 43.
---------------------------------------------------------------------------

    70. The Commission proposed that, within seven business days of the 
receipt of a prospective interconnection customer's request for an 
informational interconnection study, the transmission provider would 
have to provide the prospective interconnection customer with an 
informational interconnection study agreement.\180\ The Commission 
explained that the informational interconnection study agreement would 
specify the technical data that the prospective interconnection 
customer must provide and an estimate of the expected costs of the 
study, including, to the extent known by the transmission provider, an 
estimate of the study costs expected to be incurred by any relevant 
affected systems. Under the proposal, the prospective interconnection 
customer would have 10 business days to execute the agreement and 
deliver it to the transmission provider, along with the relevant 
technical data and study deposit, after which the transmission provider 
would have 45 calendar days to complete the study.
---------------------------------------------------------------------------

    \180\ Id. P 44.
---------------------------------------------------------------------------

    71. The Commission proposed that the informational interconnection 
study would consist of a sensitivity analysis based on the assumptions 
specified in the informational interconnection study agreement.\181\ 
Under the proposal, the informational interconnection study would 
identify potential interconnection facilities and network upgrades that 
may be required to interconnect the prospective interconnection 
customer's proposed generating facility, including an approximation of 
the costs of such interconnection facilities and network upgrades. The 
Commission noted that the transmission provider would also coordinate 
with affected systems that may be impacted by the prospective 
interconnection customer's request to provide information on affected 
systems-related issues.
---------------------------------------------------------------------------

    \181\ Id. P 45.
---------------------------------------------------------------------------

    72. The Commission proposed an informational interconnection study 
agreement form, which explains that the informational interconnection 
study is performed solely for informational purposes and is not binding 
on either party.\182\ The proposed agreement also requires the study 
report to provide specific information, including, at a minimum: (1) 
preliminary identification of any circuit breaker short circuit 
capability limits exceeded; (2) preliminary identification of any 
thermal overload or voltage limit violations; and (3) estimated network 
upgrade costs related to the identified overloads and violations.
---------------------------------------------------------------------------

    \182\ Id. P 46.
---------------------------------------------------------------------------

    73. The Commission sought comment on: (1) whether the informational 
interconnection study, as proposed, would provide prospective 
interconnection customers with sufficient and timely information to 
inform decision-making prior to submitting an interconnection request; 
(2) whether transmission providers should be required to establish a 
request window of a limited number of days each year in which potential 
interconnection customers can request an optional informational 
interconnection study; and (3) the burdens on transmission providers of 
conducting informational studies and whether other options, such as the 
proposal discussed below for public interconnection information, might 
strike a better balance of providing interconnection customers with 
useful information while making efficient use of transmission provider 
resources.\183\
---------------------------------------------------------------------------

    \183\ Id. PP 47-48.
---------------------------------------------------------------------------

    74. Additionally, the Commission proposed to add new section 3.1.2 
to the pro forma LGIP, which provides that interconnection customers 
evaluating different options (such as different sizes, sites, or 
voltages) are encouraged but not required to use the new informational 
interconnection study proposed in the NOPR before entering the cluster 
study.\184\
---------------------------------------------------------------------------

    \184\ Id. P 66.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    75. Several commenters support the NOPR proposal to require 
transmission providers to offer an informational interconnection study 
to prospective interconnection customers.\185\ Several commenters agree 
that the informational interconnection study proposal could reduce the 
number of speculative or other interconnection requests \186\ and 
improve the efficiency of siting decisions.\187\ Some commenters expect 
that these changes will have other benefits for the interconnection 
process, including cost savings from fewer and more viable 
interconnection requests,\188\ a reduced need for project withdrawals 
and queue restudies,\189\ and reduced burden on transmission providers, 
which will result in fewer interconnection study delays.\190\
---------------------------------------------------------------------------

    \185\ Affected Interconnection Customers Initial Comments at 30; 
Clean Energy States Initial Comments at 4; Consumers Energy Initial 
Comments at 3; Duke Southeast Utilities Initial Comments at 6; 
Evergreen Action Initial Comments at 3; Fervo Energy Initial 
Comments at 2; Illinois Commission Initial Comments at 6; Interwest 
Initial Comments at 4, 7; NESCOE Reply Comments at 2; Public 
Interest Organizations Initial Comments at 18; Southern Initial 
Comments at 28; Tesla Initial Comments at 4; Tri-State Initial 
Comments at 5.
    \186\ Fervo Energy Initial Comments at 2-3; Google Initial 
Comments at 4; NRECA Initial Comments at 13; NY Commission and 
NYSERDA Initial Comments at 6-8.
    \187\ Duke Southeast Utilities Initial Comments at 6-7; ISO-NE 
Initial Comments at 18; NARUC Initial Comments at 5; NRECA Initial 
Comments at 13; Pine Gate Initial Comments at 13-14; Tesla Initial 
Comments at 4.
    \188\ Evergreen Action Initial Comments at 3; NARUC Initial 
Comments at 5.
    \189\ Evergreen Action Initial Comments at 3; NRECA Initial 
Comments at 13.
    \190\ Google Initial Comments at 4.
---------------------------------------------------------------------------

    76. MISO and Fervo Energy state that it is helpful for a 
prospective interconnection customer to compare how various MW sizes, 
points of interconnection, or other scenarios could affect costs, 
especially for prospective interconnection customers that cannot 
perform such analysis in house, and that the NOPR's

[[Page 61029]]

informational interconnection study proposal would assist in these 
goals.\191\ Pacific Northwest Organizations argue that, without upfront 
interconnection cost information, independent power producers may be 
discouraged from entering the interconnection queue if they are 
subjected to higher withdrawal fees, which may result in preventing 
them from being considered in request for proposals (RFPs) in the 
Pacific Northwest.\192\
---------------------------------------------------------------------------

    \191\ Fervo Energy Initial Comments at 2; MISO Initial Comments 
at 22.
    \192\ Pacific Northwest Organizations Initial Comments at 3-4.
---------------------------------------------------------------------------

    77. Some commenters stress the importance of the informational 
interconnection study in light of the other reforms proposed in the 
NOPR. For instance, Northwest and Intermountain aver that the 
informational study will be the primary resource for interconnection 
customers to demonstrate the feasibility and cost effectiveness of 
their interconnection plan and will serve as the foundation for 
subsequent negotiations for the documents that will establish 
commercial readiness of their project for the cluster study 
process.\193\ Pacific Northwest Organizations assert that the NOPR's 
proposed commercial readiness framework would be problematic in the 
region without something like the informational interconnection study 
to discover costs before entering the queue.\194\
---------------------------------------------------------------------------

    \193\ Northwest and Intermountain Initial Comments at 6-7.
    \194\ Pacific Northwest Organizations Initial Comments at 3.
---------------------------------------------------------------------------

    78. Several commenters are generally supportive of the NOPR 
proposal but either (1) offer qualifications to that support \195\ or 
(2) request specific changes to the proposal.\196\
---------------------------------------------------------------------------

    \195\ Idaho Power Initial Comments at 3 (stating that it only 
supports the proposal if the informational interconnection study 
requirements are less prescriptive and allow for more flexibility); 
NRECA Initial Comments at 8 (stating that it does not oppose the 
proposal as long as the final rule includes a larger package of 
reforms to reduce speculative interconnection requests and speed up 
interconnection queues as well as affords reasonable flexibility on 
compliance); Ohio Commission Consumer Advocate Initial Comments at 6 
(stating that informational studies should not interfere with other 
interconnection studies).
    \196\ ACE-NY Initial Comments at 10; Avangrid Initial Comments 
at 21; Clean Energy Buyers Initial Comments at 7; ELCON Initial 
Comments at 4-5; NY Commission and NYSERDA Initial Comments at 6-7; 
Pattern Energy Initial Comments at 20; Pine Gate Initial Comments at 
11-13; Southern Initial Comments at 28.
---------------------------------------------------------------------------

(b) Comments in Opposition
    79. Many commenters oppose the NOPR proposal to require 
transmission providers to offer an informational interconnection study 
to prospective interconnection customers.\197\ Many commenters argue 
that the informational interconnection study proposal could be a burden 
or divert resources,\198\ which they contend would increase delays for 
the interconnection queue and other studies.\199\ Dominion insists that 
the decision as to whether to offer informational interconnection 
studies should be the transmission provider's and must have 
limits.\200\ Longroad Energy states that transmission-interconnected 
generating facilities are typically complex facilities with unique 
operating characteristics which would be poorly approximated in 
simplified studies.\201\ Environmental Defense Fund states that, while 
it supported the informational interconnection studies proposal in its 
initial comments, after review of the other comments submitted, it 
recommends that the Commission reconsider the proposal and ensure that 
any informational interconnection study reform not delay other 
interconnection processes.\202\
---------------------------------------------------------------------------

    \197\ AECI Initial Comments at 3; AEP Initial Comments at 7; AEP 
Reply Comments at 2; APPA-LPPC Initial Comments at 3; Avangrid 
Initial Comments at 21; Bonneville Initial Comments at 3; CAISO 
Initial Comments at 5; Clean Energy Associations Initial Comments at 
13; Dominion Reply Comments at 5; EEI Initial Comments at 11; EEI 
Reply Comments at 7-8; Enel Initial Comments at 9; ENGIE Initial 
Comments at 2; Eversource Initial Comments at 5; Indicated PJM TOs 
Initial Comments at 12; Indicated PJM TOs Reply Comments at 14; 
Longroad Energy Reply Comments at 3; NextEra Initial Comments at 5; 
NextEra Reply Comments at 8; North Dakota Commission Initial 
Comments at 3-4; NV Energy Initial Comments at 14; OMS Initial 
Comments at 5; [Oslash]rstead Initial Comments at 7; PG&E Initial 
Comments at 9; PJM Initial Comments at 45; PPL Initial Comments at 
4; SEIA Initial Comments at 3; SPP Initial Comments at 2, 3-4; 
Vermont Electric and Vermont Transco Initial Comments at 3; WIRES 
Initial Comments at 8.
    \198\ AECI Initial Comments at 3; AEE Reply Comments at 5-6; AEP 
Initial Comments at 7-8; AEP Reply Comments at 2; AES Initial 
Comments at 4; Alliant Energy Initial Comments at 4; APPA-LPPC 
Initial Comments at 9; APS Initial Comments at 5; Bonneville Initial 
Comments at 3; CAISO Initial Comments at 6; Clean Energy Buyers 
Initial Comments at 6; Clean Energy States Initial Comments at 4; 
Dominion Reply Comments at 5-6; Environmental Defense Fund Reply 
Comments at 5; EEI Initial Comments at 11-12; EEI Reply Comments at 
8-9; ELCON Initial Comments at 4-5; Enel Initial Comments at 9; 
ENGIE Initial Comments at 2; Eversource Initial Comments at 5; 
Google Initial Comments at 5; Idaho Power Initial Comments at 3; 
Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply 
Comments at 14; Longroad Energy Reply Comments at 4-5; MISO Reply 
Comments at 17; National Grid Initial Comments at 9; NESCOE Reply 
Comments at 2; NextEra Reply Comments at 8-9, 11-12; New Jersey 
Commission Initial Comments at 21; North Dakota Commission Initial 
Comments at 3-4; NRECA Initial Comments at 14; NV Energy Initial 
Comments at 14; NYISO Initial Comments at 16; OMS Initial Comments 
at 5; Pine Gate Initial Comments at 12; PPL Initial Comments at 4-6; 
SDG&E Initial Comments at 3-4; SEIA Initial Comments at 3; SEIA 
Reply Comments at 4; SoCal Edison Initial Comments at 12; Tesla 
Initial Comments at 4; Vermont Electric and Vermont Transco Initial 
Comments at 3; WIRES Initial Comments at 8.
    \199\ AECI Initial Comments at 3; AEP Initial Comments at 7-8; 
AEP Reply Comments at 2-3; AES Initial Comments at 4; Alliant Energy 
Initial Comments at 4; APS Initial Comments at 4; Bonneville Initial 
Comments at 3; CAISO Initial Comments at 6; Dominion Initial 
Comments at 9; Duke Southeast Utilities Initial Comments at 7-8; 
Environmental Defense Fund Reply Comments at 5; EEI Initial Comments 
at 11; ELCON Initial Comments at 4-5; Eversource Initial Comments at 
5-6; Google Initial Comments at 5; Idaho Power Initial Comments at 
3; Indicated PJM TOs Initial Comments at 13; MISO Reply Comments at 
17; National Grid Initial Comments at 7, 10-11; NESCOE Reply 
Comments at 2; NextEra Reply Comments at 8; New Jersey Commission 
Initial Comments at 21; North Dakota Commission Initial Comments at 
3-4; NRECA Initial Comments at 14; NYISO Initial Comments at 16-19; 
OMS Initial Comments at 5; Pennsylvania Commission Initial Comments 
at 11; PG&E Initial Comments at 9; PG&E Reply Comments at 5; Pine 
Gate Initial Comments at 12; PJM Initial Comments at 45; PPL Initial 
Comments at 4; SEIA Initial Comments at 4; SoCal Edison Initial 
Comments at 12; Tesla Initial Comments at 4.
    \200\ Dominion Reply Comments at 5.
    \201\ Longroad Energy Reply Comments at 7.
    \202\ Environmental Defense Fund Reply Comments at 5.
---------------------------------------------------------------------------

    80. Several commenters contend that the informational 
interconnection study proposal would not likely be valuable.\203\ Clean 
Energy Associations assert that the proposed informational 
interconnection study would provide no information related to 
stability-driven network upgrades, rendering it near-useless in areas 
where stability limits are most typically the driver of network 
upgrades.\204\ APPA-LPPC warn that informational interconnection 
studies could engender controversy because prospective interconnection 
customers would, notwithstanding the informational nature of the 
studies, likely rely upon the study results in

[[Page 61030]]

making investment decisions, even though the informational study 
results would inevitably diverge from the actual interconnection study 
results.\205\
---------------------------------------------------------------------------

    \203\ AEE Initial Comments at 9-10; AEE Reply Comments at 5-6; 
AEP Initial Comments at 7; AEP Reply Comments at 2; Alliant Energy 
Initial Comments at 4; CAISO Initial Comments at 5-6; Clean Energy 
Associations Initial Comments at 14; CREA and NewSun Initial 
Comments at 42; Dominion Reply Comments at 5; EEI Initial Comments 
at 12; EEI Reply Comments at 8; Enel Initial Comments at 9; ENGIE 
Initial Comments at 2; Eversource Initial Comments at 5-6; Indicated 
PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at 
14; ISO-NE Initial Comments at 19; Longroad Energy Reply Comments at 
3; MISO Initial Comments at 20-21; MISO Reply Comments at 17-18; 
NextEra Initial Comments at 5, 10-11; NextEra Reply Comments at 9; 
North Dakota Commission Initial Comments at 4; NRECA Initial 
Comments at 14; NV Energy Initial Comments at 14; NYISO Initial 
Comments at 17; OMS Initial Comments at 5; Pacific Northwest 
Utilities Initial Comments at 8 n.13; PG&E Initial Comments at 9; 
PG&E Reply Comments at 4; PJM Initial Comments at 45; SDG&E Initial 
Comments at 3-4; SEIA Initial Comments at 3; SEIA Reply Comments at 
3; SoCal Edison Initial Comments at 11-12; WIRES Initial Comments at 
8.
    \204\ Clean Energy Associations Initial Comments at 14.
    \205\ APPA-LPPC Initial Comments at 12.
---------------------------------------------------------------------------

    81. Several commenters argue that the proposal is not an 
improvement over the status quo.\206\ National Grid and NextEra assert 
that it is unclear how the proposal would save any time compared to the 
status quo, and that the best way for an interconnection customer to 
obtain the necessary information is by entering and proceeding through 
the interconnection queue with transmission providers focusing on 
actual studies.\207\ NextEra adds that the proposed informational 
interconnection study is only informative in extreme cases, such as 
very limited capacity available on a transmission line, which the 
interconnection customer should be able to identify themselves.\208\
---------------------------------------------------------------------------

    \206\ National Grid Initial Comments at 9; New Jersey Commission 
Initial Comments at 21; Vermont Electric and Vermont Transco Initial 
Comments at 3.
    \207\ National Grid Initial Comments at 9; NextEra Initial 
Comments at 12.
    \208\ NextEra Initial Comments at 12.
---------------------------------------------------------------------------

    82. CREA and NewSun express concern that the NOPR proposal places 
too much reliance on the usefulness of the informational 
interconnection study in order to justify the financial readiness and 
commitment NOPR proposals.\209\ They assert that the informational 
interconnection study is not a useful replacement for the feasibility 
study, which takes into account the impact of other interconnection 
customers in the interconnection queue cluster. Therefore, CREA and 
NewSun ask the Commission to instead retain the feasibility study as 
part of the cluster study process to allow interconnection customers to 
obtain cluster-level information on likely costs and network upgrades 
before proceeding further with major deposits and irretrievable 
commitments.
---------------------------------------------------------------------------

    \209\ CREA and NewSun Initial Comments at 46-47.
---------------------------------------------------------------------------

    83. Several commenters point to the experience with similar studies 
in SPP and MISO as evidence that the optional informational 
interconnection study proposal will be little-used in practice.\210\ 
SPP reports that its interconnection customers explained that their 
time could be more effectively spent working on the more definitive 
system impact studies, that the feasibility and preliminary impact 
studies did not provide results that could be relied on in making 
business decisions, and that this same outcome would be true of the 
proposed informational interconnection study.\211\
---------------------------------------------------------------------------

    \210\ AEE Initial Comments at 10; AEP Initial Comments at 8,12; 
Clean Energy Associations Initial Comments at 14; Enel Initial 
Comments at 9-10; Longroad Energy Reply Comments at 3-4; MISO 
Initial Comments at 21; NextEra Reply Comments at 8; Omaha Public 
Power Initial Comments at 3; SEIA Reply Comments at 3; SPP Initial 
Comments at 3. NextEra argues that transmission providers with large 
numbers of interconnection requests have tried optional 
interconnection studies and have not found them to be useful. 
NextEra Reply Comments at 10.
    \211\ SPP Initial Comments at 3.
---------------------------------------------------------------------------

    84. Several commenters point to the inability of the informational 
interconnection studies to provide reliable cost estimates \212\ and 
believe that the information provided in these studies will be quickly 
outdated.\213\ The New Jersey Commission is concerned that this 
approach may not materially reduce the uncertainty interconnection 
customers currently face.\214\ In particular, many commenters contend 
that the informational interconnection study is not meaningful in the 
context of a cluster interconnection
---------------------------------------------------------------------------

    \212\ AEP Initial Comments at 8; Ameren Initial Comments at 5; 
CAISO Initial Comments at 5; Clean Energy Associations Initial 
Comments at 14; CREA and NewSun Initial Comments at 43; Cyprus Creek 
Initial Comments at 13; Enel Initial Comments at 9; Interwest 
Initial Comments at 7-8; NextEra Initial Comments at 5; NRECA 
Initial Comments at 14; PJM Initial Comments at 45; SoCal Edison 
Initial Comments at 11-12.
    \213\ AEP Initial Comments at 8; Alliant Energy Initial Comments 
at 4; Dominion Initial Comments at 10; Enel Initial Comments at 9; 
Eversource Initial Comments at 9; Interwest Initial Comments at 7-8; 
PJM Initial Comments at 45; PJM TOs Initial Comments at 13; SEIA 
Reply Comments at 4.
    \214\ New Jersey Commission Initial Comments at 21.
---------------------------------------------------------------------------

    process.\215\ Commenters argue that, because the informational 
interconnection study does not provide information on other 
interconnection customers that would enter the interconnection queue at 
the same time, there is no guarantee that the study results will even 
approximate the actual network upgrade costs determined by the cluster 
results.\216\
---------------------------------------------------------------------------

    \215\ Id.; AEE Initial Comments at 9-10; Avangrid Initial 
Comments at 23-24; Clean Energy Associations Initial Comments at 14; 
CREA and NewSun Initial Comments at 43; Dominion Reply Comments at 
6; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial 
Comments at 9; Eversource Initial Comments at 9-10; ISO-NE Initial 
Comments at 18-19; MISO Initial Comments at 21; NRECA Initial 
Comments at 14; NV Energy Initial Comments at 14; PJM Initial 
Comments at 45; PPL Initial Comments at 5; SEIA Initial Comments at 
4-5; SEIA Reply Comments at 3-4; SoCal Edison Initial Comments at 
12; SPP Initial Comments at 2-3.
    \216\ AEE Initial Comments at 9-10; CAISO Initial Comments at 5-
6; CREA and NewSun Initial Comments at 44; Dominion Initial Comments 
at 10; Duke Southeast Utilities Initial Comments at 7; EEI Reply 
Comments at 8; Indicated PJM TOs Initial Comments at 13; ISO-NE 
Initial Comments at 18-19; MISO Initial Comments at 22; NextEra 
Initial Comments at 11-12; New Jersey Commission Initial Comments at 
21; PG&E Reply Comments at 5; PPL Initial Comments at 5; SEIA Reply 
Comments at 3-4; SoCal Edison Initial Comments at 12.
---------------------------------------------------------------------------

    85. Some commenters expect the proposal will work against the 
Commission's goal of faster interconnection queue processing.\217\ Some 
commenters state that any reduction in speculative interconnection 
requests will be offset by an increase in speculative informational 
interconnection requests, which would require transmission providers to 
shift their focus from the actual interconnection queue to this more 
burdensome informational interconnection process, which is outside of 
their interconnection study process.\218\ NRECA states that, if the 
proposal is included in the final rule, the Commission should ensure 
that it is limited and is not expanded into an elaborate serial study 
process prior to the cluster study process.\219\ Avangrid notes that 
some transmission providers have recently eliminated interconnection 
studies to reduce interconnection queue processing time.\220\ 
Pennsylvania Commission asserts that the Commission should assess the 
results of the NOPR's proposed reforms before requiring any new study 
processes that may further slow the interconnection queue process.\221\
---------------------------------------------------------------------------

    \217\ AEE Reply Comments at 6; AEP Initial Comments at 11; 
Avangrid Initial Comments at 22-23; CAISO Initial Comments at 6; 
Dominion Reply Comments at 6-7; National Grid Initial Comments at 7; 
NESCOE Reply Comments at 2; NV Energy Initial Comments at 14; 
Pennsylvania Commission Initial Comments at 11-12.
    \218\ AECI Initial Comments at 4; AEP Initial Comments at 11; 
APPA-LPPC Initial Comments at 11-12; Bonneville Initial Comments at 
3 (citing NOPR, 179 FERC ] 61,194 at PP 20, 22, 166); Clean Energy 
Buyers Initial Comments at 6; Dominion Reply Comments at 6; NextEra 
Initial Comments at 12; NYISO Initial Comments at 17; Pennsylvania 
Commission Initial Comments at 11 (explaining that because the 
informational study is not binding on any party, the study does not 
move projects through the interconnection queue).
    \219\ NRECA Initial Comments at 14.
    \220\ Avangrid Initial Comments at 23 (citing NOPR, 179 FERC ] 
61,194 at P 56 n.111).
    \221\ Pennsylvania Commission Initial Comments at 11-12.
---------------------------------------------------------------------------

    86. Several commenters note the challenge of staffing to fulfill 
the informational interconnection study requirements given the limited 
number of qualified planners and engineers.\222\
---------------------------------------------------------------------------

    \222\ Id. at 11; AEP Initial Comments at 10-11; APPA-LPPC 
Initial Comments at 12; Avangrid Initial Comments at 22-23; 
Bonneville Initial Comments at 5; Eversource Initial Comments at 5-
6; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply 
Comments at 14; LADWP Initial Comments at 2; OMS Initial Comments at 
5.
---------------------------------------------------------------------------

    87. Several commenters urge the Commission to weigh the benefits 
against the burdens to determine whether to adopt the informational 
interconnection study proposal.\223\

[[Page 61031]]

WAPA states that, while it agrees that it is important to provide 
prospective interconnection customers with additional information, it 
has concerns about the proposed timelines and penalties, the potential 
amount of informational interconnection study requests it could 
receive, and its ability to process up to five simultaneous 
informational interconnection study requests per interconnection 
customer.\224\ According to Vermont Electric and Vermont Transco, even 
if the informational interconnection studies envisioned by the NOPR 
provide interconnection customer benefits, the burdens of providing 
informational interconnection studies with cost estimates under the 
NOPR's short proposed time frames and low deposit amounts would be 
considerable especially for smaller companies such as Vermont Electric 
and Vermont Transco.\225\ Other commenters contend that the 
informational interconnection study proposal has insufficient 
benefits.\226\
---------------------------------------------------------------------------

    \223\ Ameren Initial Comments at 5; R Street Initial Comments at 
9; Xcel Initial Comments at 20.
    \224\ WAPA Initial Comments at 4-5.
    \225\ Vermont Electric and Vermont Transco Initial Comments at 
3.
    \226\ Id.; AEP Initial Comments at 7; AES Initial Comments at 4; 
EEI Initial Comments at 11; ENGIE Initial Comments at 2; NextEra 
Initial Comments at 10-11; [Oslash]rstead Initial Comments at 7; PJM 
Initial Comments at 45; SEIA Initial Comments at 3.
---------------------------------------------------------------------------

    88. Given PJM's opposition to the informational interconnect study, 
it recommends modifying the proposed new section 3.1.2 to the pro forma 
LGIP to encourage, but not require, interconnection customers 
evaluating different project characteristics to use a prescreening 
tool, such as the queue scope tool PJM is developing, prior to 
submitting an interconnection request.\227\
---------------------------------------------------------------------------

    \227\ PJM Initial Comments at 19 (explaining that the queue 
scope is an interactive prescreening tool that will allow 
interconnection customers to screen potential points of 
interconnection and assess grid capacity (head room) based on a 
given amount of MW injection or withdrawal at a given point of 
interconnection and that the tool will be available at no charge). 
PJM's proposed section 3.1.2 of the pro forma LGIP would read: 
``Interconnection Customers evaluating different options . . . to 
use the prescreening tool (Section 6.1 of this LGIP) before entering 
the Cluster Study.''
---------------------------------------------------------------------------

iii. Commission Determination
    89. We decline to adopt the NOPR proposal to modify the pro forma 
LGIP to require transmission providers to offer an informational 
interconnection study for prospective interconnection customers. We are 
persuaded by commenters' concerns that requiring an informational 
interconnection study could divert the transmission provider's 
resources away from the cluster studies we require in this final rule 
and undermine the benefits of those reforms that seek to reduce 
interconnection study delays, costs, and burden on constrained 
engineering labor. Moreover, we agree with commenters that highlight 
the various limitations of an informational interconnection study. 
Notably, an informational interconnection study, as proposed in the 
NOPR, would have provided a serial, snapshot-in-time analysis on the 
impact of a single interconnection request, but, in the context of the 
subsequent cluster study, the actual impact of an interconnection 
request within a larger cluster would reflect different assumptions and 
differ from the informational interconnection study, providing minimal 
or no value to interconnection customers. The cost estimates that 
result from such an informational interconnection study would bear 
little correspondence to costs determined during a cluster study 
process and thus provide minimal value to interconnection customers.
    90. We also find persuasive comments that the informational 
interconnection study requirement proposed in the NOPR is not the most 
effective way to provide interconnection customers with the needed pre-
interconnection queue information. At the same time, we continue to 
believe that there is a lack of information available to prospective 
interconnection customers prior to entering the interconnection queue, 
especially given other interconnection customer-related reforms adopted 
in this final rule.\228\ Therefore, as discussed below, we adopt the 
NOPR proposal to set minimum requirements for transmission providers to 
publicly post available information pertaining to generator 
interconnection.\229\ We find that the posting of this information 
provides a better balance between the benefits of additional 
information for prospective interconnection customers and the burdens 
on transmission providers.
---------------------------------------------------------------------------

    \228\ See Northwest and Intermountain Initial Comments at 6-7.
    \229\ See infra section III.A.1.c.iii.
---------------------------------------------------------------------------

    91. In response to commenters that support the informational 
interconnection study NOPR proposal, below we explain how several of 
the NOPR proposals that we adopt in this final rule address their 
specific concerns. To address commenters' concerns with the number of 
speculative interconnection requests,\230\ we adopt more stringent site 
control requirements and increased commercial readiness deposit 
requirements,\231\ which we believe will better address these concerns 
than the informational interconnection study proposal. Additionally, we 
find that the minimum requirements for transmission providers to 
publicly post available information pertaining to generator 
interconnection \232\ and the existing requirements in section 2.3 of 
the pro forma LGIP for transmission providers to post up-to-date base 
case study models on their Open Access Same-time Information System 
(OASIS) or other password-protected websites will improve the 
efficiency of siting decisions \233\ and will provide interconnection 
customers with information about the feasibility of their 
interconnection plans.\234\
---------------------------------------------------------------------------

    \230\ Fervo Energy Initial Comments at 2-3; Google Initial 
Comments at 4; NRECA Initial Comments at 13; NY Commission and 
NYSERDA Initial Comments at 6-8.
    \231\ See infra sections III.A.6.b.iii, III.A.6.c.iii.
    \232\ See infra section III.A.1.c.iii.
    \233\ Duke Southeast Utilities Initial Comments at 6-7; ISO-NE 
Initial Comments at 18; NARUC Initial Comments at 5; NRECA Initial 
Comments at 13; Pine Gate Initial Comments at 13-14; Tesla Initial 
Comments at 4.
    \234\ Northwest and Intermountain Initial Comments at 6-7; 
Pacific Northwest Organizations Initial Comments at 3.
---------------------------------------------------------------------------

    92. We are not persuaded that the informational interconnection 
study proposal would benefit the interconnection process through: (1) 
cost savings from fewer, more feasible interconnection requests; \235\ 
(2) a reduced need for interconnection request withdrawals and 
restudies; \236\ and (3) accurate upfront interconnection cost 
information.\237\ On the contrary, the Commission's adoption of the 
cluster study reforms in this final rule \238\ means that the serial 
nature of the informational interconnection study would fail to reflect 
the outcome of the cluster study, and thus would provide minimal, if 
any, benefits to interconnection customers.\239\ We also no longer 
believe that adopting the informational interconnection study

[[Page 61032]]

proposal would reduce burdens on transmission providers.\240\ This is 
because the record overwhelmingly demonstrates that the proposal would 
result in additional burdens on transmission providers and would likely 
cause transmission providers to divert resources from their cluster 
study process to conduct informational interconnection studies,\241\ 
thus increasing study delays and costs. Similarly, we decline CREA and 
NewSun's request that the Commission retain the feasibility study 
instead of the informational interconnection study. As we discuss 
below, the feasibility study was required for the serial study process 
but is no longer relevant for the cluster study process.\242\ We 
believe that our requirement for transmission providers to publicly 
post certain interconnection information will provide interconnection 
customers with the information they need prior to entering the 
interconnection queue, and therefore decline to adopt CREA and NewSun's 
request to maintain the feasibility study.
---------------------------------------------------------------------------

    \235\ Evergreen Action Initial Comments at 3; NARUC Initial 
Comments at 5.
    \236\ Evergreen Action Initial Comments at 3; NRECA Initial 
Comments at 13.
    \237\ Fervo Energy Initial Comments at 2; MISO Initial Comments 
at 22; Pacific Northwest Organizations Initial Comments at 3-4.
    \238\ See infra section III.A.2.
    \239\ See AEE Initial Comments at 9-10; Avangrid Initial 
Comments at 23-24; Clean Energy Associations Initial Comments at 14; 
CREA and NewSun Initial Comments at 43; Dominion Reply Comments at 
6; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial 
Comments at 9; Eversource Initial Comments at 9-10; ISO-NE Initial 
Comments at 18-19; MISO Initial Comments at 21; New Jersey 
Commission Initial Comments at 21; NRECA Initial Comments at 14; NV 
Energy Initial Comments at 14; PJM Initial Comments at 45; PPL 
Initial Comments at 5; SEIA Initial Comments at 4-5; SEIA Reply 
Comments at 3-4; SoCal Edison Initial Comments at 12; SPP Initial 
Comments at 2-3.
    \240\ See Google Initial Comments at 5 (arguing that the 
informational interconnection study requirement alone would likely 
increase the burden on transmission providers in a way that would 
lengthen delays).
    \241\ Id.; AECI Initial Comments at 3; AEE Reply Comments at 5-
6; AEP Initial Comments at 7-8; AEP Reply Comments at 2; AES Initial 
Comments at 4; Alliant Energy Initial Comments at 4; APPA-LPPC 
Initial Comments at 9; APS Initial Comments at 5; Bonneville Initial 
Comments at 3; CAISO Initial Comments at 6; Clean Energy Buyers 
Initial Comments at 6; Clean Energy States Initial Comments at 4; 
Dominion Reply Comments at 5-6; Environmental Defense Fund Reply 
Comments at 5; EEI Initial Comments at 11-12; EEI Reply Comments at 
8-9; ELCON Initial Comments at 4-5; Enel Initial Comments at 9; 
ENGIE Initial Comments at 2; Eversource Initial Comments at 5; Idaho 
Power Initial Comments at 3; Indicated PJM TOs Initial Comments at 
12; Indicated PJM TOs Reply Comments at 14; Longroad Energy Reply 
Comments at 4-5; MISO Reply Comments at 17; National Grid Initial 
Comments at 9; NESCOE Reply Comments at 2; New Jersey Commission 
Initial Comments at 21; NextEra Reply Comments at 8-9, 11-12; North 
Dakota Commission Initial Comments at 3-4; NRECA Initial Comments at 
14; NV Energy Initial Comments at 14; NYISO Initial Comments at 16; 
OMS Initial Comments at 5; Pine Gate Initial Comments at 12; PPL 
Initial Comments at 4-6; SDG&E Initial Comments at 3-4; SEIA Initial 
Comments at 3; SEIA Reply Comments at 4; SoCal Edison Initial 
Comments at 12; Tesla Initial Comments at 4; Vermont Electric and 
Vermont Transco Initial Comments at 3; WIRES Initial Comments at 8.
    \242\ See infra section III.A.2.f.iii.
---------------------------------------------------------------------------

    93. Because we do not adopt the NOPR proposal to require 
transmission providers to offer an informational interconnection study, 
we decline to adopt the proposal to add new section 3.1.2 to the pro 
forma LGIP to encourage interconnection customers to use the 
informational interconnection study.
c. Public Interconnection Information
i. NOPR Proposal
    94. In the NOPR, the Commission proposed to require transmission 
providers to maintain and make publicly available an interactive visual 
representation of available interconnection capacity (commonly known as 
a ``heatmap'') as well as a table of relevant interconnection metrics 
that allow prospective interconnection customers to see certain 
estimates of a potential generating facility's effect on the 
transmission provider's transmission system.\243\ Specifically, the 
Commission proposed to revise section 6.4 of the pro forma LGIP to 
require transmission providers to post on their public website a 
heatmap of estimated incremental injection capacity (in MW) available 
at each bus in the transmission provider's footprint under N-1 
conditions, as well as provide a table of results showing the estimated 
impact of the addition of a proposed project (based on the user-
specified MW amount, voltage level, and point of interconnection) for 
each monitored facility impacted by the proposed project on: (1) the 
distribution factor; (2) the MW impact (based on the proposed project 
size and the distribution factor); (3) the percentage impact on the 
monitored facility (based on the MW values of the proposed project and 
the monitored facility rating); (4) the percentage of power flow on the 
monitored facility before the proposed project; and (5) the percentage 
power flow on the monitored facility after the injection of the 
proposed project. The Commission explained that these metrics would be 
calculated based on the power flow model of the cluster study or 
restudy with the transfer simulated from each bus to the whole 
transmission provider's footprint (to approximate Network Resource 
Interconnection Service (NRIS)), and with the incremental capacity at 
each bus decremented by the existing and queued generation in the 
cluster (based on the existing or requested interconnection service 
limit of the generation). The Commission proposed to require 
transmission providers to update this information within 30 days after 
the completion of each cluster study and restudy.
---------------------------------------------------------------------------

    \243\ NOPR, 179 FERC ] 61,194 at P 51.
---------------------------------------------------------------------------

    95. The Commission sought comment on whether: (1) there are any 
security concerns with this proposed requirement; and (2) the 
assumptions specified for the analysis are the right set of 
assumptions.\244\
---------------------------------------------------------------------------

    \244\ Id. P 52.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    96. Many commenters express support for the NOPR's proposal to 
require transmission providers to provide public interconnection 
information.\245\ Several commenters agree that the NOPR proposal will 
provide valuable information to interconnection customers before they 
enter the interconnection queue.\246\ Several commenters aver that the 
proposal could reduce the number of interconnection requests withdrawn 
\247\ and therefore could reduce costs for all parties.\248\ Alliant 
Energy and Clean Energy Associations also see value in the standardized 
format of the proposed

[[Page 61033]]

public interconnection information.\249\ R Street states that a 
properly done visual representation of interconnection capacity can be 
a ``powerful decentralized self-screening tool.'' \250\ R Street states 
that better information and simpler deliverability requirements shift 
congestion performance risk to generating facilities while reducing 
barriers to entry.\251\ The Ohio Commission Consumer Advocate states 
that the visual map of available interconnection capacity would be 
useful both to transmission providers and interconnection customers and 
would encourage information sharing on transmission system congestion 
during the interconnection process.\252\ Google argues that making 
these data publicly available to consumers would allow buyers to make 
informed choices regarding power procurement.\253\ Additionally, Google 
asserts that there needs to be a standard of reasonable care applied to 
ensure that the publicly available information is reasonably current 
and useful to avoid exploratory interconnection requests.\254\ SEIA 
argues that greater transparency will increase competition between 
merchant and utility developed generating facilities, benefiting 
consumers.\255\ Illinois Commission contends that, if properly 
implemented, the NOPR proposal will increase the pace at which new 
generating facilities can connect to the transmission system, 
furthering state policy objectives.\256\
---------------------------------------------------------------------------

    \245\ ACE-NY Initial Comments at 11; AES Initial Comments at 3; 
Affected Interconnection Customers Initial Comments at 30; APPA-LPPC 
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial 
Comments at 7; Clean Energy Associations Initial Comments at 12; 
Clean Energy Buyers Initial Comments at 6-7; Colorado Commission 
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA 
and NewSun Initial Comments at 44-45; Duke Southeast Utilities 
Initial Comments at 6; Environmental Defense Fund Initial Comments 
at 3; Environmental Defense Fund Reply Comments at 2-3; ELCON 
Initial Comments at 4; ENGIE Initial Comments at 2; Evergreen Action 
Initial Comments at 3; Fervo Energy Initial Comments at 2; Google 
Initial Comments at 14; Google Reply Comments at 6; Illinois 
Commission Initial Comments at 6; Interwest Initial Comments at 7; 
New Jersey Commission Initial Comments at 11-12; Northwest and 
Intermountain Initial Comments at 9-10; NY Commission and NYSERDA 
Initial Comments at 8; [Oslash]rsted Initial Comments at 7; Pattern 
Energy Initial Comments at 23; Pine Gate Initial Comments at 13; 
Public Interest Organizations Initial Comments at 18-19; R Street 
Initial Comments at 8, 10; Southern Initial Comments at 28; Tesla 
Initial Comments at 6-7; Vistra Initial Comments at 1, 4.
    \246\ Alliant Energy Initial Comments at 5; Clean Energy 
Associations Initial Comments at 12; CREA and NewSun Initial 
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6; 
EEI Initial Comments at 12-13; ELCON Initial Comments at 6; ENGIE 
Initial Comments at 2; Evergreen Action Initial Comments at 3; Fervo 
Energy Initial Comments at 2-3; Illinois Commission Initial Comments 
at 6; Indicated PJM TOs Initial Comments at 14; Indicated PJM TOs 
Reply Comments 6; ISO-NE Initial Comments at 26-27; New Jersey 
Commission Initial Comments at 12; NY Commission and NYSERDA Initial 
Comments at 8; Ohio Commission Consumer Advocate Initial Comments at 
7; Pacific Northwest Utilities Initial Comments at 13; SEIA Initial 
Comments at 5.
    \247\ CESA Initial Comments at 9; CESA Reply Comments at 3; 
Consumers Energy Initial Comments at 3; CREA and NewSun Initial 
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6; 
Environmental Defense Fund Initial Comments at 3; EEI Initial 
Comments at 12-13; ELCON Initial Comments at 6; Evergreen Action 
Initial Comments at 3; Google Initial Comments at 14; Illinois 
Commission Initial Comments at 6-7; New Jersey Commission Initial 
Comments at 12; NY Commission and NYSERDA Initial Comments at 8; 
Pacific Northwest Utilities Initial Comments at 13; SEIA Initial 
Comments at 5.
    \248\ Evergreen Action Initial Comments at 3; New Jersey 
Commission Initial Comments at 12.
    \249\ Alliant Energy Initial Comments at 5; Clean Energy 
Associations Initial Comments at 12.
    \250\ R Street Initial Comments at 10.
    \251\ R Street Reply Comments at 2.
    \252\ Ohio Commission Consumer Advocate Initial Comments at 7.
    \253\ Google Initial Comments at 4.
    \254\ Google Reply Comments at 7.
    \255\ SEIA Reply Comments at 5.
    \256\ Illinois Commission Initial Comments at 6.
---------------------------------------------------------------------------

    97. Some commenters contend that the proposal to provide public 
interconnection information is not overly burdensome.\257\ APPA-LPPC 
members report that the information posting and interactive capability 
described in the NOPR could be feasibly implemented with available 
industry system simulation tools.\258\ Clean Energy Associations state 
that heatmaps should be as automated as possible, without significant 
commitments of staff or resources.\259\
---------------------------------------------------------------------------

    \257\ APPA-LPPC Initial Comments at 16; Clean Energy 
Associations Initial Comments at 12-13; Google Initial Comments at 
14; New York State Department Initial Comments at 8; Pennsylvania 
Commission Initial Comments at 13; SEIA Initial Comments at 6.
    \258\ APPA-LPPC Initial Comments at 16.
    \259\ Clean Energy Associations Initial Comments at 13.
---------------------------------------------------------------------------

    98. Several commenters point to the fact that some transmission 
providers are already developing such tools as evidence that these 
tools are unlikely to cause further delays to stressed interconnection 
queues or additional burden on transmission providers.\260\ For 
instance, some commenters note that MISO already offers a heatmap that 
represents geographically advantageous siting locations.\261\ Several 
commenters also note that PJM is developing such a tool.\262\ PJM 
states that in 2023 its queue scope tool will provide a congestion map 
with colors or symbols indicating the worst flowgate loading at each 
point of interconnection.\263\ SPP states that it is also developing a 
tool to be implemented by 2025 that would provide much of the 
functionality described in the Commission's public information proposal 
to new interconnections.\264\
---------------------------------------------------------------------------

    \260\ Id. at 12; Environmental Defense Fund Reply Comments at 3; 
ENGIE Initial Comments at 2-3; Pennsylvania Commission Initial 
Comments at 13.
    \261\ CESA Reply Comments at 5; Fervo Energy Reply Comments at 
3; OMS Initial Comments at 3, 6; R Street Initial Comments at 10; 
SEIA Initial Comments at 6.
    \262\ CESA Reply Comments at 4; Fervo Energy Reply Comments at 
3; Indicated PJM TOs Initial Comments at 14; Ohio Commission 
Consumer Advocate Initial Comments at 7; Pennsylvania Commission 
Initial Comments at 13; PJM Initial Comments at 48; PPL Initial 
Comments at 9; R Street Initial Comments at 10; SEIA Initial 
Comments at 6.
    \263\ PJM Initial Comments at 46-47.
    \264\ SPP Initial Comments at 4.
---------------------------------------------------------------------------

    99. Several commenters contend that the public information proposal 
is a more reasonable balance of costs and benefits relative to the 
informational interconnection study proposal.\265\ Pennsylvania 
Commission states that, once a public information tool is established, 
it may require fewer ongoing resources, continuing to inform 
interconnection customers while freeing those resources for additional 
interconnection studies as compared to the proposed informational 
interconnection study.\266\
---------------------------------------------------------------------------

    \265\ Ameren Initial Comments at 5; APPA-LPPC Initial Comments 
at 16; APS Initial Comments at 5; Bonneville Initial Comments at 5; 
Pennsylvania Commission Initial Comments at 13; PJM Initial Comments 
at 45-48; R Street Initial Comments at 10.
    \266\ Pennsylvania Commission Initial Comments at 13.
---------------------------------------------------------------------------

(b) Comments in Opposition
    100. A few commenters oppose the NOPR proposal to require 
transmission providers to provide public interconnection 
information.\267\ A larger number of commenters express reservations 
about the proposal,\268\ in particular regarding its usefulness \269\ 
or the burden it creates.\270\ Other commenters request that the 
Commission make public interconnection information posting 
optional.\271\
---------------------------------------------------------------------------

    \267\ Avangrid Reply Comments at 4; El Paso Electric Initial 
Comments at 8; PG&E Initial Comments at 9.
    \268\ AEP Initial Comments at 13; Idaho Power Initial Comments 
at 3; NextEra Initial Comments at 12-13; Omaha Public Power Initial 
Comments at 4; PacifiCorp Initial Comments at 13-14; SPP Initial 
Comments at 4; Tri-State Initial Comments at 4; WAPA Initial 
Comments at 7-8.
    \269\ AEP Initial Comments at 13; Idaho Power Initial Comments 
at 3; ISO-NE Initial Comments at 17; Longroad Energy Reply Comments 
at 7; Omaha Public Power Initial Comments at 4; PacifiCorp Initial 
Comments at 13-14; SPP Initial Comments at 4; WAPA Initial Comments 
at 7-8.
    \270\ AECI Initial Comments at 5; Dominion Initial Comments at 
12; National Grid Initial Comments at 7; NextEra Initial Comments at 
12-13; Omaha Public Power Initial Comments at 4; PacifiCorp Initial 
Comments at 13-14; SPP Initial Comments at 4.
    \271\ AEP Initial Comments at 13; Avangrid Initial Comments at 
21-22; SPP Initial Comments at 4.
---------------------------------------------------------------------------

    101. Several commenters argue that the proposal to require 
transmission providers to provide public interconnection information is 
not useful,\272\ particularly because it might not provide sufficient 
detail \273\ or commercially actionable information for interconnection 
customers.\274\ Commenters explain that heatmaps are specific to a 
moment in time and thus not representative of actual available 
injection across the transmission system, which is ever-changing.\275\ 
NextEra observes that heatmaps do not contain actionable information 
for interconnection and instead focus on energy prices and 
congestion.\276\ ISO-NE, MISO, and Omaha Public Power note that a 
visual representation of interconnection capacity cannot account for 
all of the conditions identified in a system impact study, including 
different system stresses, operability issues (e.g., N-1-1), stability 
and voltage issues, and weak transmission system issues.\277\

[[Page 61034]]

Longroad Energy asserts that generator interconnection heatmaps or 
hosting capacity maps can be of some use for interconnections to the 
distribution system but are unlikely to be beneficial for projects 
interconnecting at transmission voltages.\278\
---------------------------------------------------------------------------

    \272\ Dominion Initial Comments at 13; Idaho Power Initial 
Comments at 3; ISO-NE Initial Comments at 17; NextEra Initial 
Comments at 12; New York State Department Initial Comments at 8; 
NYISO Initial Comments at 17; Omaha Public Power Initial Comments at 
4; PacifiCorp Initial Comments at 14.
    \273\ AECI Initial Comments at 5; Dominion Initial Comments at 
13; Longroad Energy Reply Comments at 7; National Grid Initial 
Comments at 8; New York State Department Initial Comments at 8; 
Omaha Public Power Initial Comments at 4.
    \274\ AEE Initial Comments at 9; Cypress Creek Initial Comments 
at 13; NextEra Initial Comments at 12.
    \275\ AECI Initial Comments at 5; AEP Initial Comments at 13; 
New York State Department Initial Comments at 8; NYISO Initial 
Comments at 17.
    \276\ NextEra Initial Comments at 12.
    \277\ ISO-NE Initial Comments at 17; MISO Initial Comments at 26 
(citing NOPR, 179 FERC ] 61,194 at P 50 & n.105); Omaha Public Power 
Initial Comments at 4.
    \278\ Longroad Energy Reply Comments at 7.
---------------------------------------------------------------------------

    102. Some commenters do not believe that the heatmap proposal will 
appreciably reduce speculative interconnection requests.\279\ MISO 
explains that, in its experience, few interconnection customers use its 
interconnection heatmap tool and instead tend to use their own 
tools.\280\ Puget Sound states that, even with a heatmap, if an 
interconnection customer has a request that would require energy 
transfer across balancing authorities, it would have to submit an 
interconnection request to get information on the scope of necessary 
network upgrades.\281\ NV Energy asserts that a heatmap of its 
transmission system would be of little value, appearing as though there 
is no available transfer capacity, because the generation in its 
interconnection queue is more than five times the level of NV Energy 
load.\282\ Meanwhile, Puget Sound states that a heatmap of its 
territory would only account for generation and interconnection 
capacity in its balancing authority footprint even though its 
transmission goes beyond this footprint.\283\
---------------------------------------------------------------------------

    \279\ Idaho Power Initial Comments at 3; PPL Initial Comments at 
9.
    \280\ MISO Initial Comments at 25-26.
    \281\ Puget Sound Initial Comments at 6.
    \282\ NV Energy Initial Comments at 10.
    \283\ Puget Sound Initial Comments at 6.
---------------------------------------------------------------------------

    103. Several commenters contend that a heatmap tool as proposed 
would be less useful in a cluster study than it is in a serial process 
because it cannot include similarly queued generation.\284\ Ohio 
Commission Consumer Advocate questions whether it will capture the 
``dynamic elements'' of cluster studies and restudies.\285\ PacifiCorp 
and AEP state that the mere fact that an area is not shown as congested 
on a heatmap does not mean that it will be a suitable interconnection 
location, particularly if multiple interconnection customers seek to 
interconnect there.\286\
---------------------------------------------------------------------------

    \284\ CAISO Initial Comments at 8; CREA and NewSun Initial 
Comments at 48; Duke Southeast Utilities Initial Comments at 6-7; 
MISO Initial Comments at 26; Ohio Commission Consumer Advocate 
Initial Comments at 7; PacifiCorp Initial Comments at 15.
    \285\ Ohio Commission Consumer Advocate Initial Comments at 7.
    \286\ AEP Initial Comments at 13; PacifiCorp Initial Comments at 
15.
---------------------------------------------------------------------------

    104. Longroad Energy and PacifiCorp express concern that the 
heatmap tools would not be restricted to prospective interconnection 
customers and could instead be used by third-party consultants for 
their own business interests; for instance, real estate speculators 
could use the information to secure exclusive site control for 
locations that show significant generator interconnection 
capacity.\287\ According to Longroad Energy, such risk is particularly 
harmful to wind and solar generation interconnection customers' needs 
for large tracts of land to accommodate their generation 
equipment.\288\
---------------------------------------------------------------------------

    \287\ Longroad Energy Reply Comments at 7; PacifiCorp Initial 
Comments at 15.
    \288\ Longroad Energy Reply Comments at 7.
---------------------------------------------------------------------------

    105. Some commenters assert that maintaining the heatmap and 
posting required information on available interconnection capacity 
would be burdensome for transmission providers, especially in non-RTO/
ISO regions.\289\ Similarly, NV Energy states that it participates in 
the CAISO energy imbalance market and its energy management system does 
not currently have the technical functionality to build an interactive 
map that shows information like the available interconnection 
capacity.\290\ Some commenters argue that the heatmaps may provide 
insufficient benefit to justify cost, resources, and time it would take 
to produce them.\291\ Omaha Public Power further asserts that 
interconnection customers will likely find it more valuable for a 
transmission provider invest in more reliable and consequential 
studies.\292\ Pacific Northwest Utilities assert that the Commission 
should present additional data regarding the benefits of requiring a 
heatmap before mandating their use.\293\ Clean Energy Associations 
recommend that the Commission consider other means of increasing 
information to prospective interconnection customers, such as public 
scoping meetings prior to the prospective interconnection customers 
entering the interconnection queue.\294\
---------------------------------------------------------------------------

    \289\ National Grid Initial Comments at 7-8; PacifiCorp Initial 
Comments at 13; Tri-State Initial Comments at 7.
    \290\ NV Energy Initial Comments at 10.
    \291\ Dominion Initial Comments at 13; National Grid Initial 
Comments at 8; NextEra Initial Comments at 12; New York State 
Department Initial Comments at 8; Omaha Public Power Initial 
Comments at 4; Pacific Northwest Utilities Initial Comments at 14; 
PPL Initial Comments at 9; Tri-State Initial Comments at 4; WAPA 
Initial Comments at 7.
    \292\ Omaha Public Power Initial Comments at 4.
    \293\ Pacific Northwest Utilities Initial Comments at 14.
    \294\ Clean Energy Associations Initial Comments at 14.
---------------------------------------------------------------------------

    106. Some commenters express concern that the public information 
proposal will impose new costs on ratepayers and market 
participants.\295\ WAPA states that, given its defined appropriations 
and budgets, it is difficult to create new programs, unlike for larger 
investor-owned utilities or RTOs/ISOs.\296\ Dominion estimates that 
implementation would require a large up-front financial commitment, 
potentially for third-party software and personnel hours, and longer-
term financial commitment to maintain such a site.\297\ NV Energy 
contends that creating such a heatmap showing interconnection 
capabilities would require finding an eligible software, an ongoing 
expense.\298\
---------------------------------------------------------------------------

    \295\ New York State Department Initial Comments at 8; SoCal 
Edison Initial Comments at 13.
    \296\ WAPA Initial Comments at 7.
    \297\ Dominion Initial Comments at 12.
    \298\ NV Energy Initial Comments at 10.
---------------------------------------------------------------------------

    107. Several commenters speak to the burden of additional staffing 
needs to provide public interconnection information. National Grid 
states that the interactive visual representation tool, even if 
contracted from a third party, would require significant time 
commitments from numerous personnel with relevant and advanced 
expertise in transmission and interconnection engineering.\299\ Tri-
State notes that the Commission has recognized the lack of available 
engineers and that imposing a heatmap requirement would exacerbate the 
problem.\300\ Dominion and Duke Southeast Utilities state that any 
additional process would require additional financial and personnel 
resources, and also burden the same personnel that are already engaged 
in managing the interconnection queue.\301\ El Paso Electric argues 
that transmission providers should not be required to allocate human 
resources from interconnection studies to monthly transmission line 
capacity estimates because the staff reallocation could cause 
interconnection study backlogs.\302\ PacifiCorp states that this burden 
will be particularly onerous to transmission providers outside RTO/ISO 
regions, which have comparatively few transmission staff 
available.\303\
---------------------------------------------------------------------------

    \299\ National Grid Initial Comments at 7-8.
    \300\ Tri-State Initial Comments at 8.
    \301\ Dominion Initial Comments at 13; Duke Southeast Utilities 
Initial Comments at 7.
    \302\ El Paso Electric Initial Comments at 7.
    \303\ PacifiCorp Initial Comments at 13.
---------------------------------------------------------------------------

    108. Several commenters suggest that interconnection customers, on 
their own or with consultants, can perform studies with the available 
information that would provide estimates on available capacity similar 
to that produced under

[[Page 61035]]

the NOPR proposal.\304\ PPL states that interconnection customers can 
make their own such maps using transmission planning models the 
Commission makes available following a Freedom of Information Act 
request.\305\ APPA-LPPC argue that the Commission fails to establish 
that the information already available to prospective interconnection 
customers under the existing pro forma LGIP, along with the substantial 
supplement implemented with Order No. 845, is inadequate.\306\ SoCal 
Edison states that the information included in the NOPR proposal and 
more is already available if interconnection customers request it from 
the Commission for their own studies or use studies developed by 
transmission providers.\307\ The Ohio Commission Consumer Advocate 
states that the determination of a suitable site depends largely on the 
location and geography of the resources, which is publicly available 
from national labs and the U.S. Energy Information Administration.\308\
---------------------------------------------------------------------------

    \304\ Id. at 15; AEP Initial Comments at 8; APPA-LPPC Initial 
Comments at 9; El Paso Electric Initial Comments at 7; PPL Initial 
Comments at 9; SoCal Edison Initial Comments at 14.
    \305\ PPL Initial Comments at 9.
    \306\ APPA-LPPC Initial Comments at 9.
    \307\ SoCal Edison Initial Comments at 14.
    \308\ Ohio Commission Consumer Advocate Initial Comments at 6-7.
---------------------------------------------------------------------------

    109. Several commenters state that sufficient data are already 
required to be posted on OASIS.\309\ According to Idaho Power, Order 
No. 2003-A required interconnection study reports to be publicly 
available and provide locational and cost information for previously 
studied interconnections, but this has not reduced the amount of 
interconnection requests at congested locations.\310\ SoCal Edison and 
NYISO state that this information is already available in FERC Form 
715, where it is protected with a non-disclosure agreement as critical 
energy infrastructure information (CEII) and has the benefit of being 
available in one centralized location.\311\ On the other hand, ACE-NY 
disagrees with the assertion that FERC Form 715 provides sufficient 
information for interconnection customers to do their own analysis, 
asserting that the FERC Form 715 database base cases do not contain 
sufficient data about the generation interconnection queue and study 
assumptions and are therefore inadequate.\312\ Rather, ACE-NY argues 
that more detailed base cases such as those currently being made 
available by MISO and PJM, should be required.
---------------------------------------------------------------------------

    \309\ Duke Southeast Utilities Initial Comments at 6-7; Idaho 
Power Initial Comments at 3; NV Energy Initial Comments at 10; 
PacifiCorp Initial Comments at 14-15.
    \310\ Idaho Power Initial Comments at 3.
    \311\ NYISO Initial Comments at 17; SoCal Edison Initial 
Comments at 14.
    \312\ ACE-NY Reply Comments at 3-4.
---------------------------------------------------------------------------

    110. Several commenters state that the usefulness of public 
interconnection information proposal will depend on the implementation 
details.\313\ For example, Illinois Commission and CESA recognize that 
the accuracy of the heatmaps is an important part of how useful they 
will be.\314\ Puget Sound states that it has considered creating such a 
heatmap but has concerns about its effectiveness given implementation 
challenges.\315\ SPP states that technology, information, and tools are 
quickly evolving and that a standardization tool might be obsolete 
before it is implemented.\316\ CESA explains that currently CAISO 
provides static, snapshot-in-time transmission capability estimates 
that are helpful but do not capture locational granularity or other 
projects already in the interconnection queue, making it difficult to 
make an informed project siting decision and at times requiring data 
requests of CAISO.\317\ For this reason, CESA stresses that the 
heatmaps and associated data must be made available in a user-friendly 
format. CREA and NewSun argue that the Commission should be careful not 
to overestimate the ability to forecast interconnection costs and 
project viability that will ultimately result from a cluster 
study.\318\ Several commenters stress that any potential increase in 
transparency and interconnection process performance resulting from 
this proposal must outweigh the additional burden imposed on 
transmission providers.\319\
---------------------------------------------------------------------------

    \313\ CESA Initial Comments at 8-9; Illinois Commission Initial 
Comments at 6; Puget Sound Initial Comments at 6; SPP Initial 
Comments at 4.
    \314\ CESA Initial Comments at 9; Illinois Commission Initial 
Comments at 6.
    \315\ Puget Sound Initial Comments at 6.
    \316\ SPP Initial Comments at 4.
    \317\ CESA Initial Comments at 8.
    \318\ CREA and NewSun Initial Comments at 48.
    \319\ Cypress Creek Initial Comments at 14; EEI Initial Comments 
at 12-13; Eversource Initial Comments at 11; New Jersey Commission 
Initial Comments at 22-23; New York State Department Initial 
Comments at 8-9.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) Metrics
    111. While some commenters agree with the Commission's proposed 
table of metrics,\320\ multiple commenters suggest additional metrics 
that should be posted.\321\ For instance, Public Interest Organizations 
request information on the available interconnection capacity 
(including, at a minimum, a snapshot of existing available 
interconnection capacity and associated transmission during high load 
conditions for each substation) including projects already in the 
interconnection queue, and the capacity those projects are 
requesting,\322\ as well as metrics on whether power flows from a point 
of interconnection are likely to serve low income and people of color 
communities (which would be consistent with Executive Order 
13985).\323\ Other commenters suggest that the posted metrics should 
also include: circuit strength and the harmonics of transmission system 
elements; \324\ limiting elements at a substation or associated 
transmission infrastructure; \325\ the level of congestion and resource 
curtailment by location (historic, current, and/or expected); \326\ 
overload conditions; \327\ contingencies that drive the impacts to the 
monitored facility; \328\ for a given transmission line, information on 
the circuit (e.g., single or double), the conductor type, pole types, 
the ratings of the equipment, and the age of the equipment; \329\ 
flowgate data, such as disconnect switches, breakers, transformers, 
conductors, series reactors, and ground clearances of lines; \330\ 
change file models of network upgrades for deliverability in advance of 
providing study results; \331\ base case models paired with 
contingencies including local contingencies (below

[[Page 61036]]

200 kV); \332\ incremental injection capacity available at each bus in 
the transmission provider's footprint under N-1 conditions with a five-
year outlook; \333\ the rating of the monitored facility; \334\ 
estimated costs of interconnection or transmission service, including 
where interconnection is likely to be costly and not costly; \335\ 
proposed upgrades in the region that could affect interconnection 
requests; \336\ lists of potential upgrades that would be needed to 
export power to other regions or that would allow the transmission 
provider to increase injection capacity at each substation; \337\ more 
granular load growth data, defined by region, which could be combined 
with existing and planned generation and congestion to view anticipated 
system changes; \338\ and the share that all generating facilities 
contribute to a network upgrade along with their share of allocated 
costs.\339\ Tesla requests information that would particularly 
developers of non-synchronous generating facilities to decide what 
project controls might be best suited for a given point of 
interconnection, including: the number of generating facilities and 
power control devices (including series compensation systems, static 
synchronous compensator devices and other power control devices) that 
are two busses away from the given point of interconnection; the 
circuit breaker short circuit ratings of the nearest substation; and 
the maximum and minimum fault current in megavolt amperes (MVA) at the 
given point of interconnection.\340\
---------------------------------------------------------------------------

    \320\ NOPR, 179 FERC ] 61,194 at P 51.
    \321\ Ameren Initial Comments at 5; Bonneville Initial Comments 
at 7; Clean Energy Buyers Initial Comments at 7-8; MISO Initial 
Comments at 25 (agreeing that the five data points are sufficient 
but adding that, if the first is provided, then prospective 
interconnection customers can calculate the other four).
    \322\ Public Interest Organizations Initial Comments at 19-20.
    \323\ Public Interest Organizations Reply Comments at 11-12 
(citing 16 U.S.C. 824(a); Nat'l Ass'n for Advancement of Colored 
People v. FPC, 425 U.S. 662, 669-670 (1976); Executive Order 13985, 
``Executive Order on Advancing Racial Equity and Support for 
Underserved Communities Through the Federal Government'' (Jan. 20, 
2021)); see also Navajo Utility Initial Comments at 9.
    \324\ SEIA Initial Comments at 6.
    \325\ AES Initial Comments at 5-7; Hannon Armstrong Initial 
Comments at 2; Pattern Energy Initial Comments at 23; Public 
Interest Organizations Initial Comments at 19.
    \326\ AEP Initial Comments at 13; Clean Energy Associations 
Initial Comments at 12; Pine Gate Initial Comments at 14.
    \327\ Ameren Initial Comments at 6; R Street Initial Comments at 
10.
    \328\ Pattern Energy Initial Comments at 23.
    \329\ NextEra Initial Comments at 11.
    \330\ AES Initial Comments at 6; Pattern Energy Initial Comments 
at 23; Pine Gate Initial Comments at 14; SEIA Reply Comments at 4.
    \331\ AES Initial Comments at 5; Pine Gate Initial Comments at 
14; SEIA Reply Comments at 5.
    \332\ AES Initial Comments at 5; SEIA Reply Comments at 5.
    \333\ AES Initial Comments at 5; SEIA Reply Comments at 5.
    \334\ Pattern Energy Group Initial Comments at 23; SEIA Reply 
Comments at 5.
    \335\ Bonneville Initial Comments at 5; Eversource Initial 
Comments at 11.
    \336\ [Oslash]rsted Initial Comments at 7; Pattern Energy 
Initial Comments at 23; Public Interest Organizations Initial 
Comments at 19; SEIA Reply Comments at 5.
    \337\ Clean Energy Associations Initial Comments at 13; Public 
Interest Organizations Initial Comments at 20-21.
    \338\ Google Initial Comments at 6, 14.
    \339\ AES Initial Comments at 5-7, 13-14.
    \340\ Tesla Initial Comments at 7.
---------------------------------------------------------------------------

    112. Several commenters highlight that additional information 
regarding transmission system conditions, such as previous cluster 
studies and models, posted in a secure way subject to CEII processes, 
would allow interconnection customers to conduct their own initial 
analyses of system conditions and desirable points of 
interconnection.\341\ SoCal Edison states that, alternatively, the 
transmission providers could identify areas where new generation is 
desired, guided by state processes identifying the locations that can 
accommodate additional generation currently or locations intended for 
types of generation sought state policy.\342\
---------------------------------------------------------------------------

    \341\ ACE-NY Initial Comments at 11; AES Initial Comments at 5; 
Clean Energy States Alliance Initial Comments at 4; CREA and NewSun 
Initial Comments at 47; ENGIE Initial Comments at 3; NextEra Reply 
Comments at 9; PJM Initial Comments at 7; PPL Initial Comments at 9; 
SEIA Reply Comments at 4.
    \342\ SoCal Edison Initial Comments at 14-15.
---------------------------------------------------------------------------

    113. Some commenters oppose these requests for additional metrics. 
Dominion notes that tracking and providing the information requested by 
Public Interest Organizations, including documenting the study process, 
providing enhanced interconnection queue tracking, and metrics on 
constraints that cause bottlenecks, would be burdensome, taking 
engineers' time, slowing down the cluster study process, and diverting 
resources.\343\ EEI and WIRES contend that certain information on 
transmission line design, such as circuit type, conductor type, and 
pole type, would be overly burdensome and offer little benefit, adding 
that this information could invite potential disputes or be used to 
threaten to the reliability of the transmission system or for 
commercial gain if the information is not subject to confidentiality 
protections.\344\ EEI also asserts that any additional information 
beyond that proposed in the NOPR would complicate the interconnection 
process by adding another potential area of dispute and risks potential 
``backseat driving'' by the interconnection customer, while the 
transmission provider is responsible for performing and standing by its 
study results.\345\
---------------------------------------------------------------------------

    \343\ Dominion Reply Comments at 8.
    \344\ EEI Reply Comments at 9-10; WIRES Reply Comments at 5-6.
    \345\ EEI Reply Comments at 9-10.
---------------------------------------------------------------------------

    114. Some commenters disagree as to the appropriate level of 
granularity of the required metrics. SEIA and ENGIE support the NOPR 
proposal to require transmission providers to post bus-level 
interconnection capacity constraints.\346\ Dominion disagrees, arguing 
that requiring capacity constraint information to be provided at the 
bus-level is outside the scope of the NOPR and would not necessarily be 
useful in a networked system where injection at one bus will affect the 
capability at other buses and significant additional power flow 
analysis would be required to determine these values at each bus.\347\ 
According to Dominion, information about bus-level interconnection 
capacity constraints makes more sense where the system is radial in 
nature and injection capability at one bus is not dependent on 
contingencies or injections at another bus. Eversource adds that bus 
level information will not provide significant benefits because it may 
be too simplistic if it is not based on N-1 conditions or if it fails 
to incorporate stability considerations.\348\ Public Interest 
Organizations state that many utilities provide hosting capacity 
information on their websites at the distribution level in heatmaps or 
tables, in particular to help distributed solar interconnection 
customers, and this information is required by states and updated 
regularly.\349\ Public Interest Organizations ask the Commission to 
require analogous hosting capacity information to be provided by 
transmission providers for all potential generation locations with 
exemptions for urban substations where there is limited potential for 
generation development. PJM requests that, rather than requiring that 
all buses be made available in a large RTO/ISO, a transmission provider 
should be allowed to screen and only present the majority of the 
feasible points of interconnection.\350\ As an alternative to providing 
information at every bus, Tri-State states that a transmission provider 
could post the most recent cluster study to provide information for the 
buses that were studied as opposed to studying all buses on the system, 
while also making clear that the heatmap does not reflect 
interconnection requests in neighboring systems.\351\ Similarly, 
Bonneville argues that cluster studies would not provide the 
incremental injection capacity at each bus on the transmission 
provider's system, which would warrant a separate study, and therefore, 
transmission providers should be afforded flexibility to provide this 
capacity information as it becomes available.\352\
---------------------------------------------------------------------------

    \346\ ENGIE Initial Comments at 2-3; SEIA Initial Comments at 5.
    \347\ Dominion Reply Comments at 8-9.
    \348\ Eversource Initial Comments at 11.
    \349\ Public Interest Organizations Initial Comments at 20 
(citing National Renewable Energy Laboratory, Advanced Hosting 
Capacity Analysis, https://www.nrel.gov/solar/market-research-analysis/advanced-hosting-capacity-analysis.html).
    \350\ PJM Initial Comments at 48-49.
    \351\ Tri-State Initial Comments at 8.
    \352\ Bonneville Initial Comments at 6-7.
---------------------------------------------------------------------------

    115. Some commenters argue that the proposed heatmap is not an 
ideal way to present public interconnection information. For instance, 
Illinois Commission states that it is not immediately evident what 
information maps posted to an RTO/ISO website would reflect.\353\ For 
example, Illinois Commission questions whether

[[Page 61037]]

congestion maps would reflect present congestion or congestion that 
might arise after generating facilities interconnect. Fervo Energy 
states that additional research might be needed to determine the most 
useful informational suite.\354\ Clean Energy Associations proposes, 
and SEIA supports, that two maps, one for Energy Resource 
Interconnection Service (ERIS) and one for capacity or NRIS, should be 
made available where appropriate, and notes that in ISO-NE overlapping 
impact analysis is used to determine eligibility for capacity 
NRIS.\355\ Finally, Clean Energy Associations and ISO-NE recommend that 
the Commission consider allowing information to be qualitative, such 
that, rather than a ``hosting map,'' transmission providers could post 
a map and accompanying report regarding system conditions at various 
points on the transmission system.\356\
---------------------------------------------------------------------------

    \353\ Illinois Commission Initial Comments at 6.
    \354\ Fervo Energy Reply Comments at 3.
    \355\ Clean Energy Associations Initial Comments at 12; SEIA 
Reply Comments at 5.
    \356\ Clean Energy Associations Reply Comments at 3; ISO-NE 
Initial Comments at 17.
---------------------------------------------------------------------------

(2) Security of Critical Information
    116. Several commenters express concern that the NOPR's proposed 
heatmap and/or metrics may create a security risk \357\ by, among other 
things, indicating areas where transmission is heavily loaded and more 
vulnerable to interference.\358\ In particular, LADWP and Bonneville 
express concerns over sharing distribution factor and MW impact, which 
they believe could identify highly stressed transmission lines, as well 
as concerns with identifying the line locations, which are not 
currently provided publicly.\359\ LADWP further expresses concern with 
CEII issues that may arise from publicly releasing a table of metrics 
regarding the estimated impact of a potential generating facility.\360\
---------------------------------------------------------------------------

    \357\ EEI Reply Comments at 9-10; Indicated PJM TOs Initial 
Comments at 15; LADWP Initial Comments at 3; NRECA Initial Comments 
at 16-17; PacifiCorp Initial Comments at 16; PPL Initial Comments at 
8; SoCal Edison Initial Comments at 13-14; WIRES Reply Comments at 
5-6.
    \358\ LADWP Initial Comments at 3; PacifiCorp Initial Comments 
at 16; PPL Initial Comments at 8.
    \359\ Bonneville Initial Comments at 6; LADWP Initial Comments 
at 3.
    \360\ LADWP Initial Comments at 3.
---------------------------------------------------------------------------

    117. Other commenters counter that the security risks associated 
with the NOPR proposal are reasonable or non-existent. For example, 
Pacific Northwest Utilities and Puget Sound states that the purpose of 
the heatmap is to provide an overview of interconnection capacity, 
which is unlikely to implicate CEII, and thus the risk of unrestricted 
critical infrastructure information should be low.\361\ Indicated PJM 
TOs and PPL state that a visual map with limited information, excluding 
reliability constraints or other particular information that could be 
used to identify vulnerabilities, could be made public without security 
concerns and highlight PJM as a good example of this.\362\ Xcel states 
that it does not have security concerns about posting estimated 
injection capacity but that some of the more detailed information 
should be limited.\363\ MISO states that it is currently unaware of any 
security concerns associated with the proposal.\364\
---------------------------------------------------------------------------

    \361\ Pacific Northwest Utilities Initial Comments at 15; Puget 
Sound Initial Comments at 6-7.
    \362\ Indicated PJM TOs Initial Comments at 14-15; PPL Initial 
Comments at 8-9.
    \363\ Xcel Initial Comments at 22.
    \364\ MISO Initial Comments at 27.
---------------------------------------------------------------------------

    118. While SoCal Edison and Southern assert that there should be no 
requirement on transmission providers to make public or display any 
CEII or confidential information,\365\ other commenters contend that 
the CEII label should not be used to unreasonably impede 
interconnection customers' access to interconnection information 
necessary to understand the cost and other impacts of locating their 
projects in different areas of the transmission system.\366\ Some 
commenters recommend that the Commission require transmission providers 
to make CEII data available only to interconnection customers who meet 
restricted access requirements, such as through a secure portal or 
subject to a confidentiality agreement.\367\ Pattern Energy asks that 
this information be made available through a cost-free process that 
takes no longer than two weeks,\368\ and Pine Gate adds that the 
retrieval of this information should not require background checks, as 
required by certain transmission providers.\369\ EEI suggests that 
transmission providers should have the discretion to identify sensitive 
information that should be withheld.\370\ Clean Energy States add that 
the Commission may want to limit access to permitted users, controlling 
the copying and dissemination of data, or take other security 
measures.\371\
---------------------------------------------------------------------------

    \365\ SoCal Edison Initial Comments at 14; Southern Initial 
Comments 28.
    \366\ CESA Reply Comments at 4; Google Reply Comments at 7; 
Pattern Energy Initial Comments at 24.
    \367\ Google Reply Comments at 7; Indicated PJM TOs Initial 
Comments at 15; ISO-NE Initial Comments at 17; NRECA Initial 
Comments at 16; Pattern Energy Initial Comments at 24; SEIA Initial 
Comments at 6; SEIA Reply Comments at 5.
    \368\ Pattern Energy Initial Comments at 24.
    \369\ Pine Gate Initial Comments at 14.
    \370\ EEI Initial Comments at 13.
    \371\ Clean Energy States Initial Comments at 5.
---------------------------------------------------------------------------

(3) Miscellaneous
    119. SEIA requests that the Commission require transmission 
providers to use the most recent available study models as well as the 
most recently completed system impact study in creating their data 
results.\372\
---------------------------------------------------------------------------

    \372\ SEIA Initial Comments at 6.
---------------------------------------------------------------------------

    120. A few commenters express concern with the proposal to require 
updated information 30 days after the completion of each cluster study 
and restudy and instead request that the Commission allow for regional 
flexibility on the timing of updates.\373\ MISO states that, as 
written, the NOPR proposal would require it to update the tool 
available to help interconnection customers pre-screen for potential 
points of interconnection each time a regional system impact study is 
issued, which would be numerous times during a calendar year due to the 
configuration of MISO's transmission system.\374\ PJM states that it is 
not feasible for an RTO/ISO as large as PJM to update an interactive 
public interconnection information tool within 30 days after completing 
a cluster restudy.\375\ PJM states that, once the tool includes light 
load results, it will be uploading four to six datasets a year with 
each dataset including millions of points of interconnection flowgate 
records, which may eventually not be feasible to maintain from a 
storage perspective. According to El Paso Electric, the interconnection 
queue changes often as interconnection customers withdraw their 
requests and therefore transmission providers should not be required to 
update capacity line estimates monthly because the burden on staff 
could increase interconnection study delays.\376\ Tri-State explains 
that only a subset of buses and lines are studied in each cluster 
study, so to require an estimate of the injection capacity at every bus 
in each cluster study to be posted within 30 days would greatly 
increase the scope and cost and would likely have a negative impact on 
the time to complete the study and cause rates to increase.\377\
---------------------------------------------------------------------------

    \373\ Bonneville Initial Comments at 8; El Paso Electric Initial 
Comments at 7; MISO Initial Comments at 26; Pacific Northwest 
Utilities Initial Comments at 14; PJM Initial Comments at 49; Tri-
State Initial Comments at 7.
    \374\ MISO Initial Comments at 26-27.
    \375\ PJM Initial Comments at 49.
    \376\ El Paso Electric Initial Comments at 7.
    \377\ Tri-State Initial Comments at 7.
---------------------------------------------------------------------------

    121. On the other hand, [Oslash]rsted notes that any system 
representation needs to

[[Page 61038]]

be frequently updated to be useful and avoid the risk of becoming out-
of-date,\378\ and Public Interest Organizations state that hosting 
capacity data should be updated at least quarterly.\379\ Environmental 
Defense Fund argues that the public interconnection information should 
be updated immediately at the end of each cluster request window so 
that interconnection customers using that information are informed of 
generating facilities being studied that may impact transmission 
capacity.\380\
---------------------------------------------------------------------------

    \378\ [Oslash]rsted Initial Comments at 6.
    \379\ Public Interest Organizations Initial Comments at 20.
    \380\ Environmental Defense Fund Initial Comments at 3.
---------------------------------------------------------------------------

(4) Requests for Flexibility
    122. Several commenters request flexibility from the Commission 
with respect to the particular information included in a potential 
heatmap.\381\ Dominion asserts that the proposal is overly prescriptive 
and that the Commission should focus on the goal itself rather than 
uniformity.\382\ Clean Energy Associations state that the heatmaps may 
need to be tailored to the services offered by a particular 
transmission provider, because their services are not uniform.\383\ 
Several commenters claim that flexibility will help ensure that the 
information provided is useful and understandable, and will place a 
reasonable level of burden on transmission providers.\384\ MISO states 
that flexibility is reasonable given the burden on transmission 
providers of maintaining a heatmap tool relative to the limited value 
of frequent updates given that few interconnection customers use this 
tool and its inability to include future queued projects that will be 
relevant to the prospective interconnection customer.\385\ Bonneville 
also argues that flexibility is needed to ensure consistency with 
security requirements.\386\ On the other hand, Cypress Creek asserts 
that, as a broad consideration, the particular types of information to 
be made transparent that are valuable should be determined by the 
Commission in consultation with market participants who are best 
positioned to identify information relevant to financing and 
constructing new projects.\387\
---------------------------------------------------------------------------

    \381\ Avangrid Initial Comments at 21-22; Bonneville Initial 
Comments at 6-8; Dominion Initial Comments at 14; MISO Initial 
Comments at 27; NY Commission and NYSERDA Initial Comments at 8; 
NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial 
Comments at 14; PJM Initial Comments at 48; Puget Sound Initial 
Comments at 6; SEIA Initial Comments at 6; Southern Initial Comments 
at 28; SPP Initial Comments at 4; WAPA Initial Comments at 7-8.
    \382\ Dominion Initial Comments at 13.
    \383\ Clean Energy Associations Initial Comments at 12.
    \384\ Avangrid Initial Comments at 21-22; Bonneville Initial 
Comments at 6-8; Cypress Creek Initial Comments at 14; MISO Initial 
Comments at 27; NY Commission and NYSERDA Initial Comments at 7-8; 
NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial 
Comments at 14; WAPA Initial Comments at 8.
    \385\ MISO Initial Comments at 26-27.
    \386\ Bonneville Initial Comments at 6.
    \387\ Cypress Creek Initial Comments at 14.
---------------------------------------------------------------------------

    123. Several commenters ask for flexibility in the way information 
is shared. SEIA states that whether the data are in a map or other 
format is not as important as the product itself.\388\ NYTOs expect 
that flexibility would allow regions to adopt some form of the virtual 
tool as long as it is clear that the information is illustrative, non-
binding, and subject to change.\389\ NRECA states that smaller 
generation and transmission cooperatives may be able to just post a 
table with bus names and injection capability and present the same 
useful information in a more economical way.\390\ NV Energy states 
that, if it were to post to its OASIS the CAISO locational marginal 
price map with a link to CAISO's OASIS to provide a list of interchange 
limits and interchange schedules, this would be just as valuable as a 
map for its own transmission system.\391\
---------------------------------------------------------------------------

    \388\ SEIA Initial Comments at 6.
    \389\ NYTOs Initial Comments at 9.
    \390\ NRECA Initial Comments at 16.
    \391\ NV Energy Initial Comments at 10.
---------------------------------------------------------------------------

    124. Some commenters argue that transmission providers that already 
provide public interconnection information should have flexibility to 
use their existing systems to comply.\392\ However, Environmental 
Defense Fund avers that this flexibility should not extend to 
transmission providers who, prior to the NOPR, were without a 
substantial public interconnection information system, because they 
have no sunk costs related to public interconnection information 
systems.\393\
---------------------------------------------------------------------------

    \392\ Environmental Defense Fund Reply Comments at 4; OMS 
Initial Comments at 6.
    \393\ Environmental Defense Fund Reply Comments at 4.
---------------------------------------------------------------------------

    125. Several commenters express concern that heatmaps would be 
technically difficult to implement outside of RTOs/ISOs and ask the 
Commission to provide non-RTO/ISO regions with flexibility in how they 
comply with the mapping tool.\394\ Tri-State states that, in non-RTO/
ISO regions, it is common for multiple transmission providers to use a 
single substation, making injection capacity dependent on 
interconnection requests in neighboring interconnection queues and 
their associated study assumptions.\395\ Tri-State, therefore, 
encourages the Commission to permit variations among heatmaps, adding 
that entities in non-RTOs/ISOs should not be required to study every 
bus.\396\
---------------------------------------------------------------------------

    \394\ Dominion Initial Comments at 12-14; NRECA Initial Comments 
at 16; NV Energy Initial Comments at 10; PPL Initial Comments at 9; 
Puget Sound Initial Comments at 5-6; Tri-State Initial Comments at 
8.
    \395\ Tri-State Initial Comments at 8.
    \396\ Id.; see also Eversource Initial Comments at 11.
---------------------------------------------------------------------------

    126. Xcel recommends that the Commission consider applying the 
requirement only in RTO/ISO regions or granting non-RTO/ISO 
transmission providers sufficient time, such as two years, to 
comply.\397\ WAPA asks the Commission to first require data 
visualization by larger utilities, wait approximately 18 months after 
implementation, and then measure the benefits of interactive tools 
produced by larger utilities, giving stakeholders a chance to comment 
before extending the heatmap requirement.\398\
---------------------------------------------------------------------------

    \397\ Xcel Initial Comments at 22.
    \398\ WAPA Initial Comments at 8.
---------------------------------------------------------------------------

    127. On the other hand, some commenters expressly argue that 
uniformity should be required inside and outside of RTO/ISO 
regions.\399\ Google states that such publicly available information 
would begin to address the critical information advantage that 
transmission owners have over independent power producers, particularly 
in non-RTO/ISO regions.\400\ R Street notes that non-RTO/ISO regions 
may have additional challenges in implementing such a tool but states 
that this should not eliminate their requirement to do so and those 
regions could be granted extra implementation time.\401\
---------------------------------------------------------------------------

    \399\ Environmental Defense Fund Reply Comments at 3; Fervo 
Energy Reply Comments at 3; Google Initial Comments at 6; R Street 
Initial Comments at 10.
    \400\ Google Reply Comments at 6.
    \401\ R Street Initial Comments at 10.
---------------------------------------------------------------------------

(d) Requests for Clarification or Technical Conference
    128. Several commenters seek clarification on the information 
transmission providers are required to present in the heatmap, use of 
that information, who has the responsibility of presenting the 
information, timing of updating that information and recovery of costs 
for providing this information. PJM asks that the Commission clarify 
that an interactive visual congestion map could comply, instead of 
requiring its specific form.\402\
---------------------------------------------------------------------------

    \402\ PJM Initial Comments at 48.
---------------------------------------------------------------------------

    129. APPA-LPPC ask the Commission to clarify that it is not 
proposing that

[[Page 61039]]

transmission providers be required to conduct any individualized 
analyses or take any action in response to particular prospective 
interconnection customers' use of the interactive tools.\403\
---------------------------------------------------------------------------

    \403\ APPA-LPPC Initial Comments at 13-14.
---------------------------------------------------------------------------

    130. Some commenters request that the Commission make clear that 
the public information is published only as a guide and not as a 
binding or definitive statement of available interconnection capacity 
or costs.\404\ Xcel asks the Commission to clarify that transmission 
providers have no liability associated with the posting of public 
information.\405\ EEI urges the Commission to make clear that 
interconnection customers that rely exclusively on this information, 
including these maps, do so at their own risk.\406\
---------------------------------------------------------------------------

    \404\ AECI Initial Comments at 5; AEE Initial Comments at 9; AEP 
Initial Comments at 13; Ameren Initial Comment at 6; CAISO Initial 
Comments at 8; Duke Southeast Utilities Initial Comments at 6-7; EEI 
Initial Comments at 12-13; National Grid Initial Comments at 8-9; 
New York State Department Initial Comments at 8; NYISO Initial 
Comments at 17; NYTOs Initial Comments at 9.
    \405\ Xcel Initial Comments at 22.
    \406\ EEI Initial Comments at 13.
---------------------------------------------------------------------------

    131. Eversource asks that the Commission clarify that ``no 
information would be required to be made available before the 
conclusion of the first cluster study.'' \407\
---------------------------------------------------------------------------

    \407\ Eversource Initial Comments at 11.
---------------------------------------------------------------------------

    132. Dominion seeks clarification that, in an RTO/ISO context, the 
proposed requirements to maintain a visual representation would apply 
to the RTO/ISO, and not additionally to individual transmission 
owners.\408\
---------------------------------------------------------------------------

    \408\ Dominion Initial Comments at 14.
---------------------------------------------------------------------------

    133. Several commenters request clarification on how the public 
information proposal will be funded.\409\ Some commenters assert that a 
user-pays model is the only appropriate funding mechanism because not 
all interconnection customers will use the public information tools, 
and the transmission provider or their customers should not be required 
to pay for work that only benefits some.\410\ Tri-State asserts that it 
might increase the $5,000 application fee to cover the significant 
heatmap costs.\411\
---------------------------------------------------------------------------

    \409\ National Grid Initial Comments at 8; PacifiCorp Initial 
Comments at 14; Tri-State Initial Comments at 7-8.
    \410\ National Grid Initial Comments at 8; PacifiCorp Initial 
Comments at 14.
    \411\ Tri-State Initial Comments at 8.
---------------------------------------------------------------------------

    134. AEP, Tesla, and ACORE ask the Commission to initiate a 
proceeding and hold a technical conference to, among other things, 
identify useful information tools that could be feasibly developed, 
establish uniform and transparent study assumptions, share best 
practices, and help less sophisticated interconnection customers learn 
to use available tools and information to lessen their own risk before 
entering an interconnection queue.\412\
---------------------------------------------------------------------------

    \412\ ACORE Reply Comments at 3, AEP Initial Comments at 13, 15; 
Tesla Initial Comments at 6.
---------------------------------------------------------------------------

iii. Commission Determination
    135. We adopt, without modification, the NOPR proposal to revise 
pro forma LGIP section 6.4, now section 6.1, to require transmission 
providers to publicly post available information pertaining to 
generator interconnection (i.e., public interconnection information or 
a heatmap). We require transmission providers to update the heatmap 
within 30 calendar days after the completion of each cluster study and 
cluster restudy. Such heatmaps must be calculated under N-1 conditions 
and studied based on the power flow model of the transmission system 
with the transfer simulated from each point of interconnection to the 
whole transmission provider's footprint (to approximate NRIS), and with 
the incremental capacity at each point of interconnection decremented 
by the existing and queued generation at that location (based on the 
existing or requested interconnection service limit of such 
generation). We require transmission providers to provide the following 
information as outputs at each point of interconnection: (1) the 
distribution factor; (2) the MW impact (based on the proposed project 
size and the distribution factor); (3) the percentage impact on each 
impacted transmission facility (based on the MW values of the proposed 
project and the facility rating); (4) the percentage of power flow on 
each impacted transmission facility before the proposed project; and 
(5) the percentage power flow on each impacted transmission facility 
after the injection of the proposed project.
    136. We find that the benefit of providing further transparency to 
interconnection customers about potential points of interconnection 
outweighs the added administrative burden to transmission providers. 
Commenters generally support supplementing the existing publicly 
available interconnection information and note their broad support for 
the NOPR proposal.\413\ Many commenters further assert that the heatmap 
will provide valuable information to interconnection customers before 
they enter the interconnection queue,\414\ and as SEIA explains, 
interconnection customers currently lack substantial information prior 
to entering the interconnection queue, which is valuable in determining 
whether to proceed with a proposed generating facility.\415\ In 
particular, the information that we require transmission providers to 
provide to prospective interconnection customers will allow such 
interconnection customers to learn about available interconnection 
capacity as well as other metrics that reflect the impact of the 
addition of a proposed generating facility to the transmission 
provider's transmission system at a particular point of 
interconnection. Such information may allow a prospective 
interconnection customer to estimate expected congestion,\416\ and, in 
turn, to assess likely network upgrades triggered by a proposed 
generating facility or the possibility of curtailment of a proposed 
generating facility.
---------------------------------------------------------------------------

    \413\ ACE-NY Initial Comments at 11; AES Initial Comments at 3; 
Affected Interconnection Customers Initial Comments at 30; APPA-LPPC 
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial 
Comments at 7; Clean Energy Associations Initial Comments at 12; 
Clean Energy Buyers Initial Comments at 6-7; Colorado Commission 
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA 
and NewSun Initial Comments at 44-45; Duke Southeast Utilities 
Initial Comments at 6; Environmental Defense Fund Initial Comments 
at 3; Environmental Defense Fund Reply Comments at 2-3; ELCON 
Initial Comments at 4; ENGIE Initial Comments at 2; Evergreen Action 
Initial Comments at 3; Fervo Energy Initial Comments at 2; Google 
Initial Comments at 14; Google Reply Comments at 6; Illinois 
Commission Initial Comments at 6; Interwest Initial Comments at 7; 
New Jersey Commission Initial Comments at 11-12; Northwest and 
Intermountain Initial Comments at 9-10; NY Commission and NYSERDA 
Initial Comments at 8; [Oslash]rsted Initial Comments at 7; Pattern 
Energy Initial Comments at 23; Pine Gate Initial Comments at 13; 
Public Interest Organizations Initial Comments at 18-19; R Street 
Initial Comments at 8, 10; R Street Reply Comments at 2; Southern 
Initial Comments at 28; Tesla Initial Comments at 6-7; Vistra 
Initial Comments at 1, 4.
    \414\ Alliant Energy Initial Comments at 5; Clean Energy 
Associations Initial Comments at 12; CREA and NewSun Initial 
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6; 
EEI Initial Comments at 12-13; ELCON Initial Comments at 6; ENGIE 
Initial Comments at 2; Evergreen Action Initial Comments at 3; Fervo 
Energy Initial Comments at 2-3; Google Initial Comments at 4; 
Illinois Commission Initial Comments at 6; Indicated PJM TOs Initial 
Comments at 14; Indicated PJM TOs Reply Comments 6; ISO-NE Initial 
Comments at 26-27; New Jersey Commission Initial Comments at 12; NY 
Commission and NYSERDA Initial Comments at 8; Ohio Commission 
Consumer Advocate Initial Comments at 7; Pacific Northwest Utilities 
Initial Comments at 13; SEIA Initial Comments at 5.
    \415\ SEIA Initial Comments at 6.
    \416\ Google Initial Comments at 14.
---------------------------------------------------------------------------

    137. With access to this type of information, a prospective 
interconnection customer will be able to better assess the viability of 
a proposed generating facility before it submits an interconnection 
request and therefore may be able to submit fewer exploratory

[[Page 61040]]

and unviable interconnection requests. We believe that, by reducing the 
number of speculative interconnection requests, this reform will reduce 
the delays caused by restudies triggered by interconnection request 
withdrawals and overcrowded interconnection queues.\417\ We believe 
that this information is also beneficial in the cluster study context, 
contrary to some commenters' concerns regarding the availability of 
information about the composition of the cluster and the effect of the 
other proposed generating facilities in the cluster. In fact, 
interconnection customers will be able to evaluate the viability of 
their proposed generating facility in the context of a cluster by using 
the publicly posted information as a baseline and incorporating the 
cluster information that transmission providers are required to post, 
during the customer engagement window, per new pro forma LGIP section 
3.4.5 (Customer Engagement Window). Further, the heatmap requirement 
will standardize the information available to interconnection customers 
across regions and such standardization will provide interconnection 
customers with consistency as they assess the viability of proposed 
generating facilities, including where to site them, across 
regions.\418\ Despite MISO's assertion that interconnection customers 
typically use their own tools to conduct analyses, as opposed to MISO's 
heatmap, several commenters identify MISO's heatmap tool as an example 
of a transmission provider posting generator interconnection 
information that is useful for prospective interconnection 
customers.\419\ Therefore, we continue to find that it is important to 
make similar information available to prospective interconnection 
customers across the country to ensure comparable access to information 
and the above mentioned resultant benefits of such information for the 
interconnection process.
---------------------------------------------------------------------------

    \417\ See CESA Initial Comments at 9; CESA Reply Comments at 3; 
Consumers Energy Initial Comments at 3; CREA and NewSun Initial 
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6; 
Environmental Defense Fund Initial Comments at 3; EEI Initial 
Comments at 12-13; ELCON Initial Comments at 6; Evergreen Action 
Initial Comments at 3; Google Initial Comments at 14; Illinois 
Commission Initial Comments at 6-7; New Jersey Commission Initial 
Comments at 12; NY Commission and NYSERDA Initial Comments at 8; 
Pacific Northwest Utilities Initial Comments at 13; SEIA Initial 
Comments at 5.
    \418\ See, e.g., Alliant Energy Initial Comments at 5; Clean 
Energy Associations Initial Comments at 12.
    \419\ ACE-NY Initial Comments at 11; AES Initial Comments at 3; 
Affected Interconnection Customers Initial Comments at 30; APPA-LPPC 
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial 
Comments at 7; Clean Energy Associations Initial Comments at 12; 
Clean Energy Buyers Initial Comments at 6-7; Colorado Commission 
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA 
and NewSun Initial Comments at 44-45; Duke Southeast Utilities 
Initial Comments at 6; Environmental Defense Fund Initial Comments 
at 3; ELCON Initial Comments at 4; ENGIE Initial Comments at 2; 
Evergreen Action Initial Comments at 3; Fervo Energy Initial 
Comments at 2; Google Initial Comments at 14; Google Reply Comments 
at 6; Illinois Commission Initial Comments at 6; Interwest Initial 
Comments at 7; New Jersey Commission Initial Comments at 11-12; 
Northwest and Intermountain Initial Comments at 9-10; NY Commission 
and NYSERDA Initial Comments at 8; [Oslash]rsted Initial Comments at 
7; Pattern Energy Initial Comments at 23; Pine Gate Initial Comments 
at 13; Public Interest Organizations Initial Comments at 18-19; R 
Street Initial Comments at 8, 10; Southern Initial Comments at 28; 
Tesla Initial Comments at 6-7; Vistra Initial Comments at 1, 4.
---------------------------------------------------------------------------

    138. Some commenters assert that the NOPR proposal is not useful 
\420\ in part because it does not provide sufficient detail and may not 
correspond with future study conditions,\421\ its usefulness depends on 
its implementation,\422\ and it is unlikely to address cost uncertainty 
challenges.\423\ In response to such objections, we find that the 
public interconnection information requirements we adopt in this final 
rule will provide further transparency of interconnection conditions, 
but, as we have acknowledged above, will remain non-binding and 
therefore cannot provide cost certainty. We recognize that this 
requirement does not provide real-time transmission system information, 
but we find that this information is valuable to prospective 
interconnection customers before they enter the interconnection queue.
---------------------------------------------------------------------------

    \420\ Dominion Initial Comments at 13; Idaho Power Initial 
Comments at 3; ISO-NE Initial Comments at 17; NextEra Initial 
Comments at 12; New York State Department Initial Comments at 8; 
NYISO Initial Comments at 17; Omaha Public Power Initial Comments at 
4; PacifiCorp Initial Comments at 14.
    \421\ Dominion Initial Comments at 13; New York State Department 
Initial Comments at 8; Omaha Public Power Initial Comments at 4.
    \422\ Indicated PJM TOs Initial Comments at 14; New York State 
Department Initial Comments at 8; NYTOs Initial Comments at 9; SPP 
Initial Comments at 4.
    \423\ AEE Initial Comments at 9; Cypress Creek Initial Comments 
at 13.
---------------------------------------------------------------------------

    139. We disagree with commenters that assert that the NOPR proposal 
is overly burdensome.\424\ By moving the pro forma LGIP from a serial 
to a cluster study process, the reforms adopted in this final rule will 
reduce the number of studies and restudies performed by transmission 
providers, therefore reducing the burden on both transmission providers 
and their staff. In addition, as commenters assert, and we agree, the 
information posting and interactive capability we require in this final 
rule could feasibly be implemented with available industry system 
simulation tools.\425\ We also agree with Clean Energy Associations 
that providing these data in a standardized format should be a 
``relatively low-impact'' requirement for transmission providers.\426\ 
This appears to be consistent with comments from Dominion that suggests 
that the majority of the burden associated with complying with this 
reform will be through an up-front financial commitment in new 
software, rather than ongoing costs.\427\ Having made such software 
commitments, though, transmission providers should be able to automate 
much of the heatmap development, without significant commitments of 
staff or resources. In doing so, we expect the ongoing costs of 
maintaining such a heatmap to be relatively low. Moreover, because 
transmission providers must use the most recent cluster study or 
cluster restudy to populate the heatmap, they will not face the burden 
of individualized analyses, which addresses the concern raised by some 
commenters.\428\
---------------------------------------------------------------------------

    \424\ Dominion Initial Comments at 13; National Grid Initial 
Comments at 8; New York State Department Initial Comments at 8; 
NextEra Initial Comments at 12; Omaha Public Power Initial Comments 
at 4; Pacific Northwest Utilities Initial Comments at 14; PPL 
Initial Comments at 9; Tri-State Initial Comments at 4; WAPA Initial 
Comments at 7.
    \425\ APPA-LPPC Initial Comments at 13; Pennsylvania Commission 
Initial Comments at 13, which explains that transmission providers 
are already implementing these tools further illustrates the point: 
heatmaps will not likely cause further delay in already-stressed 
queues.
    \426\ Clean Energy Associations Initial Comments at 23-13; see 
also ACORE Reply Comments at 3 (stating that collaboration to 
increase automation of interconnection studies is a best practice 
that could be adopted elsewhere).
    \427\ Dominion Initial Comments at 12.
    \428\ See APPA-LPPC Initial Comments at 13-14.
---------------------------------------------------------------------------

    140. We adopt the requirement for transmission providers to update 
the heatmaps within 30 calendar days after the completion of each 
cluster study and cluster restudy. We recognize the need to balance the 
burden of a specific update frequency with the value of ensuring 
uniform, up-to-date information that can inform prospective 
interconnection customers evaluating whether to enter the next cluster. 
While some commenters support the timeline proposed in the NOPR,\429\ 
others argue that it is overly burdensome or, given the division of 
their footprint into regions that have different timelines, would 
trigger frequent updates. We find that the requirements we adopt here

[[Page 61041]]

establish an appropriate period of time because, as discussed above, 
once the necessary software is in place, updating the heatmap after the 
completion of a study is expected to be largely automated without 
significant commitments of staff or resources. As the record 
demonstrates, such heatmaps can be implemented with available industry 
system simulation tools \430\ and with a standardized format that 
causes the burden to be a ``relatively low-impact'' requirement for 
transmission providers,\431\ once transmission providers have invested 
in new software.\432\
---------------------------------------------------------------------------

    \429\ Environmental Defense Fund Initial Comments at 3; 
[Oslash]rsted Initial Comments at 6; Public Interest Organizations 
Initial Comments at 20.
    \430\ APPA-LPPC Initial Comments at 13-14; Pennsylvania 
Commission Initial Comments at 13.
    \431\ Clean Energy Associations Initial Comments at 23-13; see 
also ACORE Reply Comments at 3 (stating that collaboration to 
increase automation of interconnection studies is a best practice 
that could be adopted elsewhere).
    \432\ Dominion Initial Comments at 12.
---------------------------------------------------------------------------

    141. In response to Eversource, which asks the Commission to 
clarify that the heatmap would not be required to be made available 
before the first cluster study concludes,\433\ we agree and further 
clarify that the heatmap would not be required to be made available 
until after the transition period. In response to El Paso Electric's 
comments regarding the burden of a monthly update,\434\ we clarify that 
the heatmaps must be updated within 30 calendar days after the 
completion of each cluster study and cluster restudy, not on a cycle of 
every 30 calendar days.
---------------------------------------------------------------------------

    \433\ Eversource Initial Comments at 11.
    \434\ El Paso Electric Initial Comments at 7.
---------------------------------------------------------------------------

    142. In response to comments from PJM, Bonneville, and Tri-State 
requesting flexibility for the posting of information for points of 
interconnection that have yet to be studied,\435\ we clarify that 
transmission providers need to provide updates only for anything that 
has changed in the most recent cluster study or restudy after the first 
cluster study after the Commission-approved effective date of the 
transmission provider's filing in compliance with this final rule. 
Requiring transmission providers to study each potential point of 
interconnection, rather than just those requested in each cluster, 
would expand the scope of this requirement. In turn, requiring such 
expanded studies would be inconsistent with ensuring that 
interconnection customers are able to interconnect in a reliable, 
efficient, transparent, and timely manner. In response to PJM, which 
states that transmission providers should be allowed to use prescreened 
datasets that capture a majority of the feasible points of 
interconnection that remove existing generator buses on the low side of 
the generator step-up unit, rather than using all buses to populate the 
heatmap,\436\ we agree that the heatmap may not differ significantly 
between the existing generating facility's point of interconnection on 
the low voltage side of the generating facility's step-up unit and the 
high voltage side of the step-up unit. If that is the case, this final 
rule provides transmission providers with the flexibility to populate 
the heatmap with only the high side of the step-up unit.
---------------------------------------------------------------------------

    \435\ Bonneville Initial Comments at 6; PJM Initial Comments at 
48-49; Tri-State Initial Comments at 8.
    \436\ PJM Initial Comments at 48-49.
---------------------------------------------------------------------------

    143. In response to comments arguing that the Commission has failed 
to demonstrate that information already made available is 
inadequate,\437\ we disagree. The heatmap requirement is distinct from 
information that transmission providers are already required to 
provide. The existing pro forma LGIP requires transmission providers to 
post the interconnection models and assumptions on OASIS or a password-
protected website. But the information that we require to be posted in 
compliance with this final rule is the output of such models and 
assumptions. We believe that publicly posting such resulting output is 
necessary to aid prospective interconnection customers in their 
decision-making prior to entering the interconnection queue. While 
interconnection customers, on their own or through the hiring of 
consultants, may be capable of performing studies with information 
already published by transmission providers to arrive at information 
similar to that required as part of this final rule, we believe that 
making high-level information more easily accessible to all prospective 
interconnection customers is needed to remedy unjust and unreasonable 
Commission-jurisdictional rates. While Order No. 845 and FERC Form 715 
do require certain, more detailed information to be filed with the 
Commission and/or posted on OASIS or a password-protected website,\438\ 
access to this information has not addressed the problem of speculative 
interconnection requests that we aim to remedy with several reforms 
adopted in this final rule.
---------------------------------------------------------------------------

    \437\ APPA-LPPC Initial Comments at 9; Duke Southeast Utilities 
Initial Comments at 6-7; Idaho Power Initial Comments at 3; New York 
State Department Initial Comments at 8; NV Energy Initial Comments 
at 10; NYISO Initial Comments at 17; Ohio Commission Consumer 
Advocate Initial Comments at 6-7; PacifiCorp Initial Comments at 14-
15; PG&E Initial Comments at 9-10; SoCal Edison Initial Comments at 
14.
    \438\ Order No. 845, 163 FERC ] 61,043 at P 236.
---------------------------------------------------------------------------

    144. We recognize the need to balance security concerns with the 
benefits of additional transparency. While some commenters express 
security-related concerns with the NOPR proposal,\439\ as discussed 
below, we are not modifying the Commission's CEII procedures,\440\ 
which we believe are sufficient to address security concerns raised in 
comments. Some commenters state that publicly posting information that 
indicates areas of transmission congestion or constraints is a risk as 
these areas are more vulnerable. We are not persuaded by these concerns 
and note that location-specific congestion information is already 
publicly available in RTO/ISO markets. Moreover, the Commission's 
regulations already provide that, upon request, transmission providers 
must make available all data used to calculate available transfer 
capability, total transfer capability, capacity benefit margin, and 
transmission reliability margin for any constrained posted paths 
publicly available (including the limiting element(s) and the cause of 
the limit (e.g., thermal, voltage, stability)).\441\ Additionally, we 
find these concerns to be speculative, particularly in light of the 
fact that MISO already provides similar information over a large area. 
Rather, we agree with those commenters that do not believe that the 
NOPR proposal introduces additional security concerns.\442\
---------------------------------------------------------------------------

    \439\ Bonneville Initial Comments at 6; Indicated PJM TOs 
Initial Comments at 15; LADWP Initial Comments at 3; NRECA Initial 
Comments at 16-17; PacifiCorp Initial Comments at 16; PPL Initial 
Comments at 8; SoCal Edison Initial Comments at 13-14.
    \440\ 18 CFR 388.113 (2022), which govern ``the procedures for 
submitting, designating, handling, sharing, and disseminating [CEII] 
submitted to or generated by the Commission'' (emphasis added).
    \441\ 18 CFR 37.6(b)(2) (2022).
    \442\ MISO Initial Comments at 27.
---------------------------------------------------------------------------

    145. In response to concerns from PPL and LADWP regarding the 
distribution factor analysis being made public,\443\ we are not 
persuaded and find these concerns to be speculative as well. MISO has 
long made distribution factors publicly available and states it is 
currently unaware of any security concerns associated with the 
proposal.\444\ As such, there is no evidence in the record to suggest 
this posting has raised any concerns in the past. Moreover, we observe 
that the distribution factor analyses informing the heatmaps are the 
result of multi-year forward projections that inevitably

[[Page 61042]]

diverge from actual, real-time conditions, mitigating any potential 
concerns with publicly posting this information.
---------------------------------------------------------------------------

    \443\ LADWP Initial Comments at 3; PPL Initial Comments at 8-9.
    \444\ MISO Initial Comments at 27.
---------------------------------------------------------------------------

    146. We are similarly unpersuaded by potential data confidentiality 
concerns.\445\ As with distribution factors, we find such concerns to 
be speculative and contrary to the experience of MISO, which, for the 
last several years, has already provided this information 
publicly,\446\ as well as contrary to the statements of commenters that 
support the NOPR proposal and do not raise data confidentiality 
concerns.\447\
---------------------------------------------------------------------------

    \445\ Bonneville Initial Comments at 6; PPL Initial Comments at 
9.
    \446\ Rod Walton, MISO Introduces New Generation Interconnection 
Online Tool, Power and Engineering (May 19, 2020), at https://www.power-eng.com/om/miso-introduces-new-generation-interconnection-online-tool/#gref.
    \447\ Affected Interconnection Customers Initial Comments at 30; 
AES Initial Comments at 3; ACE-NY Initial Comments at 11; APPA-LPPC 
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial 
Comments at 7; Clean Energy Associations Initial Comments at 12; 
Clean Energy Buyers Initial Comments at 7-8; Colorado Commission 
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA 
and NewSun Initial Comments at 44-45; Duke Southeast Utilities 
Initial Comments at 6; Environmental Defense Fund Initial Comments 
at 3; ELCON Initial Comments at 4; ENGIE Initial Comments at 2; 
Evergreen Action Initial Comments at 3; Fervo Energy Initial 
Comments at 2; Google Initial Comments at 14; Google Reply Comments 
at 6; Interwest Initial Comments at 7; Illinois Commission Initial 
Comments at 6; New Jersey Commission Initial Comments at 11-12; NY 
Commission and NYSERDA Initial Comments at 8; Northwest and 
Intermountain Initial Comments at 9-10; [Oslash]rsted Initial 
Comments at 7; Pine Gate Initial Comments at 13; Public Interest 
Organizations Initial Comments at 18-19; R Street Initial Comments 
at 8, 10; Southern Initial Comments at 28; Tesla Initial Comments at 
6-7; Vistra Initial Comments at 1,4.
---------------------------------------------------------------------------

    147. We provide further clarification in response to comments 
regarding the scope of analysis and assumptions which must provide the 
basis for the heatmaps. In response to comments from Public Interest 
Organizations,\448\ we decline to specifically require the heatmap to 
be studied at high load conditions. Instead, we reiterate that such 
heatmap should be based on the power flow model of the cluster study or 
restudy. While such cluster studies are often simulated at high load 
conditions, we understand that transmission providers typically conduct 
interconnection studies by studying a variety of situations. As such, 
we clarify that the information posted, for consistency and 
actionability, must not only be based on the cluster studies, but also 
must reflect the most limiting result of each of these situations 
studied.
---------------------------------------------------------------------------

    \448\ Public Interest Organizations Initial Comments at 20.
---------------------------------------------------------------------------

    148. We find that it is necessary for the heatmaps to reflect N-1 
conditions because transmission systems are operated to withstand N-1 
contingencies. To the extent that such information was not calculated 
under N-1 conditions, the results would not be useful or sufficiently 
actionable to potential interconnection customers. As Eversource 
asserts, point of interconnection level information would be too 
simplistic if it is based only on N-0 conditions and would not provide 
prospective interconnection customers with the information necessary to 
select viable points of interconnection.\449\ Similarly, we find that 
it is necessary for such posted information to approximate NRIS because 
such level of interconnection service is generally subject to more 
stringent requirements and therefore, reflecting this type of service 
will cover both types of interconnection requests, whether they are 
NRIS or ERIS.\450\ Similar to information calculated under only N-0 
conditions, to the extent such a heatmap was not calculated to 
approximate NRIS, the results would not be useful or sufficiently 
actionable to a significant portion of interconnection customers.
---------------------------------------------------------------------------

    \449\ Eversource Initial Comments at 11.
    \450\ Specifically, the pro forma LGIP defines NRIS service as 
``an Interconnection Service that allows the Interconnection 
Customer to integrate its Large Generating Facility with the 
Transmission Provider's Transmission System (1) in a manner 
comparable to that in which the Transmission Provider integrates its 
generating facilities to serve native load customers; or (2) in an 
RTO or ISO with market-based congestion management, in the same 
manner as Network Resources. Network Resource Interconnection 
Service in and of itself does not convey transmission service.'' Pro 
forma LGIP section 1. Whereas, the pro forma LGIP defines ERIS as 
``an Interconnection Service that allows the Interconnection 
Customer to connect its Generating Facility to the Transmission 
Provider's Transmission System to be eligible to deliver the 
Generating Facility's electric output using the existing firm or 
nonfirm capacity of the Transmission Provider's Transmission System 
on an as available basis. Energy Resource Interconnection Service in 
and of itself does not convey transmission service.'' Id. (emphasis 
added).
---------------------------------------------------------------------------

    149. In response to comments from AES,\451\ we decline to require 
the heatmaps to include a five-year outlook of available 
interconnection capacity. The purpose of the heatmaps is to provide 
potential interconnection customers an idea of the amount of 
interconnection capacity available at the conclusion of each cluster 
study or restudy. Because we are requiring transmission providers to 
consider pending generating facilities when collating the information 
to make public, interconnection customers will be aware of some of the 
future conditions on the transmission system. Further, any requirement 
to produce forecasts would place an additional burden on transmission 
providers that we find would outweigh its usefulness to interconnection 
customers.
---------------------------------------------------------------------------

    \451\ AES Initial Comments at 5-7.
---------------------------------------------------------------------------

    150. In response to comments from Alliant Energy and Clean Energy 
Associations arguing that the assumptions used to produce the heatmap 
should be made clear to users,\452\ we find that the assumptions used 
to produce the heatmap should be consistent with those used in the 
interconnection cluster studies. As those assumptions are already 
required to be publicly posted, along with the models themselves,\453\ 
the assumptions used to produce the heatmap will be publicly posted via 
these preexisting requirements.
---------------------------------------------------------------------------

    \452\ Alliant Energy Initial Comments at 5; Clean Energy 
Associations Initial Comments at 12-13.
    \453\ Order No. 845, 163 FERC ] 61,043 at P 236; pro Forma LGIP 
section 2.3.
---------------------------------------------------------------------------

    151. Tri-State describes difficulties associated with multiple 
transmission providers that inhabit a single substation. In such 
situations, we clarify that transmission providers must populate the 
required heatmaps using the results from their interconnection studies. 
In response to the Illinois Commission, we clarify that the heatmaps 
must represent potential congestion that might result after a 
generating facility interconnects, not present congestion values. The 
heatmap must reflect the base case assumptions from the most recent 
cluster study or cluster restudy. Such studies are not intended to 
analyze current operational conditions.
    152. We next respond to specific objections raised regarding the 
heatmaps' required level of granularity and scope, requested 
flexibilities regarding alternatives to the adopted reform, and 
clarifications regarding which transmission providers are required to 
provide heatmaps, whether heatmaps are non-binding, and how costs 
related to the heatmaps requirement are to be recovered. We decline to 
alter the level of granularity of the heatmaps from that proposed in 
the NOPR. As Ameren and MISO attest,\454\ the five data points proposed 
in the NOPR are reasonable and sufficient to provide a high-level 
comparison between several points of interconnection, and therefore to 
satisfy the goals of this reform.
---------------------------------------------------------------------------

    \454\ Ameren Initial Comments at 5; Bonneville Initial Comments 
at 7; Clean Energy Buyers Initial Comments at 7-8; MISO Initial 
Comments at 25.

---------------------------------------------------------------------------

[[Page 61043]]

    153. Similarly, consistent with support from ENGIE and SEIA,\455\ 
we adopt the scope of the heatmap requirement proposed in the NOPR, 
which is the amount of point of interconnection-level interconnection 
capacity available to be injected at each point of interconnection. We 
decline to expand the scope of the reporting. We believe that the scope 
of information that we require transmission providers to publicly post 
appropriately balances the burdens on transmission providers associated 
with providing this information with the benefits that might be 
realized by prospective interconnection customers of having ready 
access to this information. In response to Dominion, which argues that 
point of interconnection-level information may not necessarily be 
useful because, in a networked system, injection at one point of 
interconnection will affect the capability at other points of 
interconnection,\456\ we agree that injections at one location affect 
capabilities at other locations. Because the information provided by 
the transmission provider accounts for full transmission system 
conditions, interconnection customers should have the information they 
need to approximate the impact of their potential generating facility 
on the transmission system. For example, interconnection customers will 
know if they are proposing to interconnect near constrained regions 
even if those constraints are not necessarily at the proposed point of 
interconnection.
---------------------------------------------------------------------------

    \455\ ENGIE Initial Comments at 2-3; SEIA Initial Comments at 5.
    \456\ Dominion Reply Comments at 8-9.
---------------------------------------------------------------------------

    154. We decline to require transmission providers to provide 
additional interconnection information metrics, as requested by some 
commenters.\457\ While we are supportive of increased transparency, we 
are not persuaded that the benefits of such information would outweigh 
the burden of tabulating and posting such information.
---------------------------------------------------------------------------

    \457\ AEP Initial Comments at 13; AES Initial Comments at 5-7; 
Bonneville Initial Comments at 5; Clean Energy Associations Initial 
Comments at 12-13; CREA and NewSun Initial Comments at 43-44; ENGIE 
Initial Comments at 3; Eversource Initial Comments at 11; Google 
Initial Comments at 6, 14; Hannon Armstrong Initial Comments at 2; 
Pattern Energy Initial Comments at 23; Pine Gate Initial Comments at 
14; Public Interest Organizations Reply Comments at 11-12; SEIA 
Initial Comments at 6; SoCal Edison Initial Comments at 14-15; Tesla 
Initial Comments at 7.
---------------------------------------------------------------------------

    155. In response to ISO-NE, we decline to require that the heatmap 
be qualitative only.\458\ We find that providing information only 
qualitatively would not provide interconnection customers information 
they could use to adequately mitigate risks such as obtaining site 
control and providing significant deposits to the transmission provider 
in order to enter the interconnection queue. Thus, providing only 
qualitative information would be insufficient to address the lack of 
information available to interconnection customers prior to entering 
the interconnection queue, which leads to speculative interconnection 
requests and the problems identified in the need for reform section 
above.
---------------------------------------------------------------------------

    \458\ Eversource Initial Comments at 11.
---------------------------------------------------------------------------

    156. In response to requests for flexibility for transmission 
providers to identify and post alternative heatmaps,\459\ we decline to 
grant such additional flexibility. In this final rule, we establish a 
set of required information that transmission providers must publicly 
provide. We believe that this level of information is what is needed to 
address the lack of information available to interconnection customers 
prior to entering the interconnection queue, and therefore remedy the 
unjust and unreasonable Commission-jurisdictional rates discussed in 
section II of this final rule. We therefore disagree that the proposal 
is overly prescriptive,\460\ as we believe that the required 
information is necessary to adequately inform prospective 
interconnection customers. While we establish a set of required 
information, in response to comments from Clean Energy Associations 
that the heatmap may need to be tailored to the services offered by a 
particular transmission provider,\461\ and comments from Bonneville 
that flexibility would allow transmission providers to determine 
whether a different methodology would more clearly identify 
interconnection capability for interconnection customers,\462\ we note 
that if transmission providers find value in providing additional or 
different information, they may propose such variations on compliance.
---------------------------------------------------------------------------

    \459\ Avangrid Initial Comments at 21-22; Bonneville Initial 
Comments at 6-8; Clean Energy Associations Initial Comments at 12; 
Dominion Initial Comments at 14; MISO Initial Comments at 27; NY 
Commission and NYSERDA Initial Comments at 8; NYTOs Initial Comments 
at 8; Pacific Northwest Utilities Initial Comments at 14; PJM 
Initial Comments at 48; Puget Sound Initial Comments at 6; SEIA 
Initial Comments at 6; Southern Initial Comments at 28; WAPA Initial 
Comments at 7-8.
    \460\ Dominion Initial Comments at 13.
    \461\ Clean Energy Associations Initial Comments at 12.
    \462\ Bonneville Initial Comments at 7-8.
---------------------------------------------------------------------------

    157. While we acknowledge that, as a result of the relative 
interconnection queue sizes and load levels, many transmission 
providers may have heatmaps that indicate negative interconnection 
capacity and thereby would simply be ``red,'' \463\ we agree with R 
Street that providing a visual representation of available 
interconnection capacity is a best practice and should be required 
nationwide.\464\ Moreover, we find that there is value in providing an 
all ``red'' heatmap, as such information will demonstrate to 
prospective interconnection customers the potential and likely network 
upgrade-related consequences associated with interconnecting. In other 
words, an all ``red'' heatmap sends a valuable signal to 
interconnection customers regarding where proposed generating 
facilities may be more or less economic to interconnect prior to 
entering the interconnection queue.
---------------------------------------------------------------------------

    \463\ See PacifiCorp Initial Comments at 15.
    \464\ See R Street Initial Comments at 10.
---------------------------------------------------------------------------

    158. Not only is there value in requiring this information from all 
transmission providers, we are not persuaded that the burden is so 
great as to outweigh the benefits for non-RTO/ISO transmission 
providers and for smaller transmission providers.\465\ We acknowledge 
that RTOs/ISOs are operationally different from their non-RTO/ISO 
counterparts and that RTOs/ISOs are often more technologically 
advanced, but the requirement is to reproduce interconnection studies 
and publish the results in a heatmap. No commenter attests that 
existing interconnection studies in non-RTO/ISO regions fail to 
evaluate point of interconnection-level interconnection injection 
capability. Moreover, we find that by publicly reproducing the results 
of existing interconnection studies, the heatmaps will address the need 
for additional interconnection information that exists in both RTOs/
ISOs and non-RTOs/ISOs. In other words, we find that there are unjust 
and unreasonable Commission-jurisdictional rates stemming from the lack 
of this information for prospective interconnection customers both 
within and outside of RTOs/ISOs and that this problem must be remedied. 
Additionally, as Environmental Defense Fund comments, at least one 
other relatively small transmission owner posts an interactive capacity 
heatmap for its distribution system comparable to

[[Page 61044]]

that required by this final rule.\466\ Thus, contrary to comments from 
PPL,\467\ we find that smaller transmission providers are able to 
provide this information to prospective interconnection customers and 
that the benefits outweigh the burdens.
---------------------------------------------------------------------------

    \465\ Dominion Initial Comments at 12; NRECA Initial Comments at 
16; NV Energy Initial Comments at 10; PPL Initial Comments at 9; 
Puget Sound Initial Comments at 5-6; Tri-State Initial Comments at 
7-8.
    \466\ Environmental Defense Fund Reply Comments at 3-4 (citing 
Central Hudson Gas & Electric Corp., Solar PV Hosting Capacity Map, 
https://www.cenhud.com/en/my-energy/distributed-generation/solar-pv-hc-map/).
    \467\ PPL Initial Comments at 9.
---------------------------------------------------------------------------

    159. In response to comments from the NY Commission and NYSERDA 
asking for flexibility to ensure that the information is accessible and 
understandable,\468\ we do not think that such flexibility is needed--
we specifically require the information to be contained within an 
interactive map and posted on transmission providers' websites for this 
purpose. Contrary to comments from NV Energy,\469\ we find that the 
interactive map is necessary to ensure accessibility and 
understandability. Absent the map, potential interconnection customers 
would need to separately map injection points of interconnection to 
specific locations.
---------------------------------------------------------------------------

    \468\ NY Commission and NYSERDA Initial Comments at 7.
    \469\ NV Energy Initial Comments at 10.
---------------------------------------------------------------------------

    160. In response to comments from PJM and NV Energy requesting 
flexibility for transmission providers, in lieu of the heatmap, to post 
congestion information and a link to OASIS with interchange limits and 
schedules, we decline to grant such flexibility. We find that there are 
meaningful differences between the results of planning studies, such as 
those used in the interconnection process, and operational data, like 
congestion and interchange schedules. Interconnection studies are 
generally conducted at a specific high-stress point in time for 
injection at a specific point of interconnection to determine flows 
across the whole transmission system, while operational data are simply 
the accumulation of real-time and/or day-ahead results. Thus, posting 
such operational data would only introduce timing differences and could 
not substitute for the deliverability analyses conducted in the 
interconnection processes.
    161. In response to NYTOs, we clarify that the information 
displayed in the heatmap will be illustrative, non-binding, and subject 
to change.\470\ We agree with Tri-State's statement that transmission 
providers must also caveat that the results do not account for affected 
system impacts. As we have acknowledged, one primary driver of the 
available interconnection capacity is the composition of the 
interconnection customer's cluster, and the heatmap cannot reflect 
those additional interconnection requests prior to the end of the 
customer request window.
---------------------------------------------------------------------------

    \470\ NYTOs Initial Comments at 9.
---------------------------------------------------------------------------

    162. In response to requests to clarify the funding mechanism 
associated with the heatmap requirement,\471\ we clarify that 
transmission providers, not interconnection customers, are responsible 
for paying for costs associated with posting the relevant heatmaps 
required in pro forma LGIP section 6.1. However, we note that, to the 
extent such costs are properly recoverable in transmission rates 
consistent with existing Commission accounting and ratemaking policy, 
such rate treatment is appropriate, and this final rule does not 
preclude such treatment. We find that this reform will improve overall 
interconnection queue efficiency to the benefit of transmission 
customers, consistent with Commission policy.\472\
---------------------------------------------------------------------------

    \471\ National Grid Initial Comments at 8; PacifiCorp Initial 
Comments at 14; Tri-State Initial Comments at 7-8.
    \472\ Order No. 845, 163 FERC ] 61,043 at P 37.
---------------------------------------------------------------------------

    163. In response to Dominion, which requests clarification in the 
RTO/ISO context,\473\ we clarify that within an RTO/ISO, the heatmap 
requirement applies to the RTO/ISO, rather than to an individual 
transmission owner in an RTO/ISO. Thus, transmission owners in RTOs/
ISOs are not required to separately post their own visual 
representations and results.
---------------------------------------------------------------------------

    \473\ Dominion Initial Comments at 14.
---------------------------------------------------------------------------

    164. Finally, in response to concerns from WAPA about Federal power 
marketing agencies having defined budgets and appropriations,\474\ we 
note that transmission providers may explain specific circumstances on 
compliance and justify why any deviations are either ``consistent with 
or superior to'' the pro forma LGIP or merit an independent entity 
variation in the context of RTOs/ISOs.
---------------------------------------------------------------------------

    \474\ WAPA Initial Comments at 7-8.
---------------------------------------------------------------------------

2. Cluster Study Process
a. Need for Reform and Interconnection Study Procedures
i. NOPR Proposal
    165. To remedy what may now be an unjust and unreasonable 
interconnection process, the Commission proposed to eliminate the 
serial first-come, first-served study process in the pro forma LGIP and 
instead require transmission providers to use a first-ready, first-
served cluster study process.\475\ The Commission explained that under 
a first-ready, first-served cluster study process, transmission 
providers would perform larger interconnection studies encompassing 
numerous proposed generating facilities, rather than separate studies 
for each individual interconnection request. Under the NOPR proposal, 
transmission providers would perform a single cluster study and cluster 
restudy each year, the particulars of which are further discussed 
below.
---------------------------------------------------------------------------

    \475\ NOPR, 179 FERC ] 61,194 at P 64.
---------------------------------------------------------------------------

ii. Comments
    166. Many commenters support the elimination of the serial study 
process and the use of the proposed cluster study process.\476\ Several 
commenters assert that the proposed cluster study process will increase 
efficiency in the interconnection process by diminishing delays and 
backlogs in processing

[[Page 61045]]

interconnection queues.\477\ Several commenters also believe that the 
proposed cluster study process will result in fewer interconnection 
request withdrawals \478\ and will discourage speculative 
interconnection requests.\479\ Some commenters assert that, from the 
interconnection customer's perspective, the proposed cluster study 
process provides more certainty on timing and cost.\480\ Several 
commenters state that they have already implemented some of the 
proposed cluster study process reforms.\481\
---------------------------------------------------------------------------

    \476\ ACE-NY Initial Comments at 2; ACORE Initial Comments at 4; 
AEE Initial Comments at 10; AEE Reply Comments at 8; AEP Reply 
Comments at 3-4; AES Initial Comments at 9; Amazon Initial Comments 
at 2-3; Ameren Initial Comments at 6; APPA-LPPC Initial Comments at 
14; Apple Initial Comments at 1; APS Initial Comments at 6; Avangrid 
Initial Comments at 10, 11; Avangrid Reply Comments at 4; Bonneville 
Initial Comments at 3; CAISO Initial Comments at 8; Clean Energy 
Associations Initial Comments at 19; Clean Energy Buyers Initial 
Comments at 8; Clean Energy States Initial Comments at 5; Colorado 
Commission Initial Comments at 8; Cypress Creek Initial Comments at 
12; Dominion Initial Comments at 14; Duke Southeast Utilities 
Initial Comments at 1; Environmental Defense Fund Reply Comments at 
6; EEI Initial Comments at 2, 5; EEI Reply Comments at 4-5; El Paso 
Electric Initial Comments at 4; NERC Initial Comments at 26; Enel 
Initial Comments at 11; EPSA Initial Comments at 5-6; Evergreen 
Action Initial Comments at 3; Eversource Initial Comments at 12; 
Fervo Energy Initial Comments at 3; Fervo Energy Reply Comments at 
3; Idaho Power Initial Comments at 1, 4; Illinois Commission Initial 
Comments at 7; Indicated PJM TOs Initial Comments at 10; Iowa 
Commission Initial Comments at 3; ISO-NE Initial Comments at 19; 
MISO Initial Comments at 28; NARUC Initial Comments at 6; National 
Grid Initial Comments at 3-4; Navajo Utility Initial Comments at 12; 
NESCOE Initial Comments at 9; NextEra Initial Comments at 13; 
Northwest and Intermountain Initial Comments at 2; NV Energy Initial 
Comments at 4; NY Commission and NYSERDA Initial Comments at 5; 
NYISO Initial Comments at 10-11; NYTOs Initial Comments at 7; Ohio 
Commission Consumer Advocate Initial Comments at 7; Omaha Public 
Power Initial Comments at 4; OMS Initial Comments at 7; OPSI Initial 
Comments at 3-4; [Oslash]rsted Initial Comments at 7; OSPA Reply 
Comments at 15; Pacific Northwest Utilities Initial Comments at 1; 
Pennsylvania Commission Initial Comments at 5-6; Pine Gate Initial 
Comments at 14; PJM Initial Comments at 16; Public Interest 
Organizations Initial Comments at 25; Puget Sound Initial Comments 
at 4, 5; R Street Initial Comments at 8; SDG&E Initial Comments at 
2; SEIA Initial Comments at 7; SoCal Edison Initial Comments at 3; 
State Agencies Initial Comments at 2, 12; Tesla Initial Comments at 
1; Tri-State Initial Comments at 3; U.S. Chamber of Commerce Initial 
Comments at 6; UMPA Initial Comments at 2; WAPA Initial Comments at 
8; WIRES Initial Comments at 5.
    \477\ AEP Initial Comments at 16; Amazon Initial Comments at 2-
3; Apple Initial Comments at 1; Consumers Energy Initial Comments at 
4; Environmental Defense Fund Initial Comments at 5; EEI Initial 
Comments at 2, 5; ELCON Initial Comments at 2, 8; EPSA Initial 
Comments at 10; NV Energy Initial Comments at 4; Ohio Commission 
Consumer Advocate Initial Comments at 8; Pennsylvania Commission 
Initial Comments at 5-6; Pine Gate Initial Comments at 14; Public 
Interest Organizations Initial Comments at 25; SEIA Initial Comments 
at 7; WIRES Initial Comments at 6.
    \478\ AEP Initial Comments at 16; Dominion Initial Comments at 
14; ELCON Initial Comments at 9; EPSA Initial Comments at 7; Ohio 
Commission Consumer Advocate Initial Comments at 8; SEIA Initial 
Comments at 7.
    \479\ Clean Energy States Initial Comments at 5; Colorado 
Commission Initial Comments at 8; ELCON Initial Comments at 9; EPSA 
Initial Comments at 6; SoCal Edison Initial Comments at 3-4.
    \480\ Avangrid Initial Comments at 11; Dominion Initial Comments 
at 14.
    \481\ APS Initial Comments at 6; Duke Southeast Utilities 
Initial Comments at 2; MISO Initial Comments at 28; PacifiCorp 
Initial Comments at 16; SPP Initial Comments at 5.
---------------------------------------------------------------------------

    167. Dominion states that another benefit of moving to the proposed 
cluster study process is that, if a proposed generating facility is not 
ready for its cluster study, it can join the next cluster rather than 
losing its interconnection queue position as occurs in a serial study 
process.\482\ Dominion asserts that, as a result, the proposed cluster 
study process removes the incentive for an interconnection customer to 
``reserve a spot in line'' for a proposed generating facility is not 
yet viable. Ohio Commission Consumer Advocate believes that larger 
interconnection studies encompassing numerous proposed generating 
facilities would be especially beneficial for interconnection customers 
with multiple proposed generating facilities in close geographical 
proximity.\483\ Avangrid believes that applying this concept to more 
regions will lead to a more guided and proactive build-out of new 
generation and required transmission upgrades.\484\
---------------------------------------------------------------------------

    \482\ Dominion Initial Comments at 15.
    \483\ Ohio Commission Consumer Advocate Initial Comments at 8.
    \484\ Avangrid Initial Comments at 11.
---------------------------------------------------------------------------

    168. Several commenters argue that the proposed cluster study 
process will foster renewable resource development and aid in meeting 
national and/or state clean energy and carbon emissions reduction 
goals.\485\ Puget Sound states that over the past year, it has seen 
unprecedented numbers of interconnection requests in response to the 
resource solicitation process and a demand for new renewable energy 
sources.\486\ Puget Sound adds that it has experienced a backlogged 
interconnection queue, entry of speculative interconnection requests, 
and uncertainty for interconnection customers relying on higher-queued 
interconnection requests to complete the interconnection process for 
their proposed generating facilities to be feasible. Clean Energy 
States assert that, because wind and solar projects can be relatively 
small, clustering should help smaller projects share the cost of 
interconnection studies and upgrades, thereby providing them a viable 
path through the interconnection process.\487\
---------------------------------------------------------------------------

    \485\ Apple Initial Comments at 1; Navajo Utility Initial 
Comments at 12; SoCal Edison Initial Comments at 4; State Agencies 
Initial Comments at 12.
    \486\ Puget Sound Initial Comments at 4-5.
    \487\ Clean Energy States Initial Comments at 5.
---------------------------------------------------------------------------

    169. Some commenters support the use of the proposed cluster study 
process, so long as it is coupled with additional requirements, some of 
which the Commission proposed in the NOPR.\488\ AEE recommends that the 
Commission consider further reforms to harmonize study assumptions and 
more closely link generator interconnection and long-term regional 
transmission planning processes.\489\ R Street states that the 
Commission should consider an interconnection study approach that uses 
transparent, realistic study assumptions.\490\ Clean Energy 
Associations argue that certain conservative assumptions--such as NERC 
standard TPL-001's extreme contingency cases--can lead to the 
identification of unreasonably large and costly upgrades.\491\ Clean 
Energy Associations also assert that the Commission should make clear 
in its final rule whether moving from a serial study process to a 
cluster study process should or should not be accompanied by any change 
in the interconnection standards and assumptions used in those 
studies.\492\ Ameren generally supports the proposal to move to a 
first-ready, first-served cluster study process, but argues that this 
move without other reforms is unlikely to clear the interconnection 
queue backlog.\493\ NERC states that its support for cluster studies is 
predicated on parallel enhancements for model validation with actual 
installed equipment and a true-up prior to interconnection.\494\
---------------------------------------------------------------------------

    \488\ AEP Initial Comments at 6, 16; Ameren Initial Comments at 
6; Cypress Creek Initial Comments at 12; CREA and NewSun Initial 
Comments at 10, attach. A; CREA and NewSun Reply Comments at 8; Enel 
Initial Comments at 11; Eversource Initial Comments at 13; Invenergy 
Initial Comments at ii; NRECA Initial Comments at 8, 18; PPL Initial 
Comments at 10; SoCal Edison Initial Comments at 4.
    \489\ AEE Initial Comments at 10.
    \490\ R Street Reply Comments at 2.
    \491\ Clean Energy Associations Initial Comments at 28.
    \492\ Id. at 21.
    \493\ Ameren Initial Comments at 6.
    \494\ NERC Initial Comments at 26.
---------------------------------------------------------------------------

    170. Other commenters express some concern with the move to the 
proposed cluster study process. For example, Enel states that cluster 
studies increase interdependence between interconnection requests, with 
a greater likelihood that multiple interconnection customers are 
responsible for a single network upgrade, which creates a paradigm 
where one interconnection customer's actions, such as withdrawing from 
the interconnection queue, can have drastic impacts on many other 
interconnection customers.\495\ Enel also asserts that, while the 
proposed cluster study process has some benefits, recent cluster 
studies are resulting in significant regional transmission constraints 
with very high associated network upgrade costs and long construction 
schedules. Enel contends that the proposed cluster study process can 
still reduce interdependency and succeed if there are much smaller, 
more local, regional groupings of interconnection requests in cluster 
studies and lower minimum impact thresholds for determining network 
upgrades. Enel says the Commission should adopt these two practices if 
it adopts the proposed cluster study process.
---------------------------------------------------------------------------

    \495\ Enel Initial Comments at 12-13.
---------------------------------------------------------------------------

    171. Some commenters note that, where the demand for generator 
interconnection significantly exceeds the available supply of 
interconnection access, the NOPR's proposed cluster study process and 
interconnection queue management reforms alone may be insufficient to 
address the backlog of interconnection requests.\496\ Other commenters 
assert that under these circumstances, some form of interconnection 
request prioritization may be needed to effectively allocate scarce 
interconnection access to the lowest-cost or highest-value proposed 
generating facilities.\497\
---------------------------------------------------------------------------

    \496\ AEE Reply Comments at 8; Cypress Creek Initial Comments at 
12.
    \497\ NARUC Initial Comments at 11-12; Western Regulators 
Initial Comments at 1.

---------------------------------------------------------------------------

[[Page 61046]]

    172. Several commenters state that, while they support the use of 
the proposed cluster study process, the Commission should allow 
variation among transmission providers in the makeup of the study 
process.\498\ Some commenters argue that regional variations should be 
permitted, especially where transmission providers have already 
implemented a first-ready, first-served cluster study process.\499\ 
Environmental Defense Fund, on the other hand, argues that the 
Commission should provide limited flexibility for transmission 
providers to demonstrate in their compliance filing that a preexisting 
cluster study process is substantially similar to the process 
established in the Commission's final rule.\500\
---------------------------------------------------------------------------

    \498\ AEP Initial Comments at 16; APPA-LPPC Initial Comments at 
14; Avangrid Initial Comments at 10; Dominion Initial Comments at 
14; EEI Initial Comments at 5; Eversource Initial Comments at 13; 
NARUC Initial Comments at 6-7; NEPOOL Initial Comments at 14; NRECA 
Initial Comments at 18-19; Omaha Public Power Initial Comments at 4; 
OMS Initial Comments at 8.
    \499\ AEP Initial Comments at 16; APPA-LPPC Initial Comments at 
14; Idaho Power Initial Comments at 4; Indicated PJM TOs Initial 
Comments at 10-11, 16; MISO Initial Comments at 31-32; NextEra Reply 
Comments at 7; NYISO Initial Comments at 10-11; Pacific Northwest 
Utilities Initial Comments at 2; SoCal Edison Initial Comments at 4; 
U.S. Chamber of Commerce Initial Comments at 6-7; WIRES Initial 
Comments at 6-7.
    \500\ Environmental Defense Fund Reply Comments at 7.
---------------------------------------------------------------------------

    173. Pacific Northwest Utilities and CREA and NewSun urge the 
Commission to allow flexibility for transmission providers to design 
the cluster study process to implement either a single-phase or two-
phase cluster study process.\501\ Pacific Northwest Utilities contend 
that requiring full commercial readiness in a single-phase study 
process, as proposed in the NOPR, significantly restricts an 
interconnection customer's ability to enter the interconnection 
queue.\502\ Pacific Northwest Utilities argue that a two-phase approach 
provides greater accessibility to some interconnection customers by not 
requiring commercial readiness for entry into the first phase. 
According to Pacific Northwest Utilities, this is because all 
interconnection customers who have attained site control will have 
information about the network upgrades needed to meet the 
interconnection requirements of the cluster and the expected cost 
responsibility for each interconnection customer in the cluster. 
Pacific Northwest Utilities aver that this information reduces the 
potential for interconnection customers to withdraw from phase two and, 
therefore, should reduce the need for additional restudies that might 
slow or stall the interconnection process.
---------------------------------------------------------------------------

    \501\ CREA and NewSun Reply Comments at 12-13; Pacific Northwest 
Utilities Initial Comments at 6, 8-9.
    \502\ Pacific Northwest Utilities Initial Comments at 7-8.
---------------------------------------------------------------------------

    174. Some commenters argue that it may not be appropriate to 
mandate the proposed cluster study process for every transmission 
provider as cluster studies can be complex, expensive, and not the most 
efficient or necessary approach for all proposed generating facilities 
or circumstances.\503\ Some commenters generally support the use of 
cluster studies if transmission providers retain discretion to use the 
existing serial study process.\504\ Vermont Electric and Vermont 
Transco notes that not all interconnection requests need to be studied 
in a cluster format, and that this has frequently been the situation in 
New England, where interconnection queue bottlenecks have historically 
been locational and driven by state clean energy procurement 
efforts.\505\ ISO-NE requests that the Commission consider a more 
targeted approach for clusters triggered by geographic or electric 
proximity among interconnection requests, rather than a blanket 
clustering process for all interconnection requests.\506\ Instead of 
mandating a clustering in all regions, ISO-NE contends that the 
Commission consider the expanded use of clustering in areas with larger 
concentrations of proposed generating facilities, while allowing use of 
serial studies for customers seeking to interconnect in areas with low 
activity, where serial studies could proceed relatively quickly.
---------------------------------------------------------------------------

    \503\ SPP Initial Comments at 5.
    \504\ AECI Initial Comments at 5; AEP Reply Comments at 4; 
Avangrid Reply Comments at 4-5; CREA and NewSun Initial Comments at 
44; ELCON Initial Comments at 9; NextEra Initial Comments at 15; 
Southern Initial Comments at 6; Vermont Electric and Vermont Transco 
Initial Comments at 2-3.
    \505\ Vermont Electric and Vermont Transco Initial Comments at 
2.
    \506\ ISO-NE Initial Comments at 24.
---------------------------------------------------------------------------

    175. National Grid asks for clarification as to whether the 
proposed cluster study process encompasses energy or capacity 
interconnection service requests, or both.\507\
---------------------------------------------------------------------------

    \507\ National Grid Initial Comments at 16.
---------------------------------------------------------------------------

    176. Some commenters contend that the Commission should encourage 
relevant state entities to consider the efficient coordination of their 
state-jurisdictional interconnection process with Commission-
jurisdictional interconnection processes.\508\ Avangrid argues that 
sizable distributed energy resources should be aggregated and included 
in the broader cluster study of large and small Commission-
jurisdictional generating facilities. Pine Gate suggests the Commission 
require transmission providers, on compliance, to ``document how they 
will ensure that any serial processes for state-jurisdictional 
interconnection agreements will interact with the required cluster 
study process'' and explain how the interconnection queue position of 
qualifying facilities (QFs) will not be prejudiced by the transition to 
a cluster study process.\509\
---------------------------------------------------------------------------

    \508\ Avangrid Initial Comments at 12.
    \509\ Pine Gate Initial Comments at 15.
---------------------------------------------------------------------------

iii. Commission Determination
    177. We adopt the NOPR proposal to revise the pro forma LGIP and 
pro forma LGIA to make cluster studies the required interconnection 
study method. We find that the move from the serial study process in 
the pro forma LGIP to the proposed cluster study process, alongside the 
other reforms adopted in the final rule, will remedy the unjust and 
unreasonable rates discussed in section II of this final rule. 
Specifically, we believe that this reform will help remedy the problems 
of the existing interconnection process for large generating facilities 
in several ways. First, the cluster study process will increase 
efficiency because transmission providers can perform larger 
interconnection studies encompassing many proposed generating 
facilities, rather than separate studies for each individual 
interconnection customer.\510\ The cluster study process will provide 
greater certainty to interconnection customers, regarding both the 
timing of studies and the magnitude of network upgrade costs. Coupled 
with the increased financial commitments and requirements to enter the 
interconnection queue, such as a demonstration of site control, as 
discussed further below, the cluster study process will also 
disincentivize interconnection customers from submitting 
interconnection requests for speculative generating facilities and 
ensure that ready, more viable proposed

[[Page 61047]]

generating facilities can proceed through the study process.\511\ We 
also expect that the cluster study process will result in fewer 
withdrawals because conducting a single cluster study and cluster 
restudy will minimize delays that arise from proposed generating 
facility interdependencies under the existing serial study process, in 
which lower-queued interconnection customers can strategically and 
monetarily benefit from network upgrades and associated costs borne 
earlier in the interconnection process by higher-queued interconnection 
customers. We further expect that the cluster study process will 
minimize the risk of cascading restudies when an interconnection 
customer withdraws.\512\
---------------------------------------------------------------------------

    \510\ NOPR, 179 FERC ] 61,194 at P64; May Joint Task Force Tr. 
46:15-19 (Clifford Rechtschaffen) (stating that CAISO's cluster 
process has been helpful and important for improving interconnection 
queue processing and that clustering ``is a best practice and should 
be promoted''); EEI Initial Comments at 2,5; ELCON Initial Comments 
at 2,8; EPSA Initial Comments at 6; Idaho Power Initial Comments at 
4; Indicated PJM TOs Initial Comments at 10; Pennsylvania Commission 
Initial Comments at 5-6; see also May Joint Task Force Tr. 43:25-
44:4 (Riley Allen) (``Clustering helps the system to the benefit 
ultimately of ratepayers. New England has been relying on 
(explaining that clustering has two goals: minimizing the study time 
and minimizing the first mover disadvantage by sharing costs among 
those resources that need the same upgrades).
    \511\ ELCON Initial Comments at 9; EPSA Initial Comments at 6; 
NYTOs Initial Comments at 7; Ohio Commission Consumer Advocate 
Initial Comments at 8; SoCal Edison Initial Comments at 4; State 
Agencies Initial Comments at 12.
    \512\ Cypress Creek Initial Comments at 12; Dominion Initial 
Comments at 14; SEIA Initial Comments at 7.
---------------------------------------------------------------------------

    178. We are not persuaded by Enel's request that the Commission 
adopt smaller, more local regional groupings of proposed generating 
facilities in interconnection studies and lower minimum impact 
thresholds for determining upgrades.\513\ We find the record 
insufficient to support these additional requirements. We also decline 
requests to allow transmission providers to either continue to use a 
serial study process or to create a parallel serial study process \514\ 
because, as discussed further below, we find that establishing in the 
pro forma LGIP a separate interconnection process outside the cluster 
study process could detract from transmission providers' efforts to 
efficiently process cluster studies, and would be insufficient to 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner.
---------------------------------------------------------------------------

    \513\ Enel Initial Comments at 13.
    \514\ AECI Initial Comments at 5; AEP Reply Comments at 4; 
Avangrid Reply Comments at 4-5; CREA and NewSun Initial Comments at 
44; ELCON Initial Comments at 9; SPP Initial Comments at 5; Vermont 
Electric and Vermont Transco Initial Comments at 2-3.
---------------------------------------------------------------------------

    179. In response to requests to allow variation in how clusters are 
formed,\515\ we emphasize that the reforms to the pro forma LGIP 
adopted in this final rule do not prescribe how transmission providers 
should form clusters.
---------------------------------------------------------------------------

    \515\ Clean Energy States Initial Comments at 10; CREA and 
NewSun Reply Comments at 12-13; Pacific Northwest Utilities Initial 
Comments at 6-9; R Street Initial Comments at 11.
---------------------------------------------------------------------------

    180. In response to National Grid,\516\ we decline to clarify 
whether the proposed cluster study process encompasses energy or 
capacity interconnection service requests. ``Energy interconnection 
requests'' and ``capacity interconnection requests'' are not defined 
terms in the pro forma LGIP, and we decline to define them here. We do 
not believe that such detail is needed for transmission providers to 
implement the reforms adopted herein.
---------------------------------------------------------------------------

    \516\ National Grid Initial Comments at 16.
---------------------------------------------------------------------------

    181. In response to Avangrid,\517\ we encourage relevant state 
entities to consider the efficient coordination of their state-
jurisdictional interconnection processes with Commission-jurisdictional 
interconnection processes.
---------------------------------------------------------------------------

    \517\ Avangrid Initial Comments at 12.
---------------------------------------------------------------------------

    182. In response to requests to create some form of generating 
facility prioritization,\518\ we are neither persuaded that such 
prioritization is needed, nor do we have an adequate record to dictate 
how generating facility prioritization should be implemented in a just, 
reasonable, and not unduly discriminatory or preferential manner.
---------------------------------------------------------------------------

    \518\ AEE Reply Comments at 8; Cypress Creek Initial Comments at 
12; NARUC Initial Comments at 11-12; Western Regulators Initial 
Comments at 1.
---------------------------------------------------------------------------

    183. Finally, we decline to adopt the following proposals advocated 
by some commenters because they are outside the scope of this 
proceeding: (1) AEE's request that the Commission consider further 
reforms to more closely link generator interconnection and long-term 
regional transmission planning process; \519\ (2) Cypress Creek's 
request to require transmission providers to allow interconnection 
customers to seek energy-only injection as a default and provide a 
subsequent process (needed to address capacity-market constructs) by 
which an interconnection customer can add firm rights; \520\ (3) Pine 
Gate's suggestion for the Commission to require transmission providers 
to document on compliance how they will ensure that any serial study 
processes for state-jurisdictional interconnection agreements will 
interact with the required cluster study process and explain how the 
interconnection queue position of QFs will not be prejudiced by the 
transition to a cluster study process; \521\ and (4) AEE's and Clean 
Energy Associations' request that the Commission also harmonize study 
standards and assumptions.\522\ We find that these proposals are 
outside the scope of this proceeding as the Commission did not propose 
specific reforms on these issues, and we find an inadequate record to 
fully consider or adopt these requested changes.
---------------------------------------------------------------------------

    \519\ AEE Initial Comments at 10.
    \520\ Cypress Creek Initial Comments at 8-9.
    \521\ Pine Gate Initial Comments at 15.
    \522\ AEE Initial Comments at 10; Clean Energy Associations 
Initial Comments at 21, 28.
---------------------------------------------------------------------------

b. Defined Terms in the Pro Forma LGIP and Pro Forma LGIA
i. NOPR Proposal
    184. In the NOPR, the Commission proposed to add several new 
defined terms (such as cluster, cluster study process, and cluster 
request window) and to revise several defined terms (such as stand 
alone network upgrade and material modification) in section 1 of the 
pro forma LGIP and article 1 of the pro forma LGIA.\523\
---------------------------------------------------------------------------

    \523\ NOPR, 179 FERC ] 61,194 at P 65.
---------------------------------------------------------------------------

ii. Comments
    185. Starting with the proposed definition of stand alone network 
upgrade, a few commenters support the Commission's proposal.\524\ Tri-
State suggests adding to the definition of stand alone network upgrade 
that a transmission provider's interconnection facilities may be shared 
by more than one generating facility in a given cluster study, 
including a co-located resource.\525\
---------------------------------------------------------------------------

    \524\ Ameren Initial Comments at 9; MISO Initial Comments at 32.
    \525\ Tri-State Initial Comments at 25.
---------------------------------------------------------------------------

    186. Other commenters oppose the proposed revisions to the 
definition of stand alone network upgrade. Clean Energy Associations 
argue that the proposal to modify the definition of stand alone network 
upgrade to restrict it to those needed only for a single 
interconnection customer is problematic and counterproductive.\526\ 
Clean Energy Associations contend that allowing interconnection 
customers the right to self-build interconnection facilities and stand 
alone network upgrades since Order No. 845 has served as a welcome 
relief valve to transmission providers' lengthy construction timelines, 
giving customers increased control of both the time and cost for 
building these upgrades. As an alternative, Clean Energy Associations 
suggest an approach similar to ISO-NE's for network upgrades that are 
needed for multiple interconnections where an independently developed 
elective network upgrade, if selected by all of the interconnection 
customers in the cluster that require the network upgrade, can take the 
place of the incumbent-built cluster enabling network upgrade.
---------------------------------------------------------------------------

    \526\ Clean Energy Associations Initial Comments at 22-23.
---------------------------------------------------------------------------

    187. Pine Gate states that in its experience, after Order No. 845,

[[Page 61048]]

transmission providers have taken a very narrow view of the facilities 
that constitute stand alone network upgrades, and thus the potential 
for interconnection customers to exercise the option to build has not 
been fully realized.\527\ Pine Gate asserts that the proposed change 
would further restrict the opportunity for interconnection customers to 
exercise the option to build, exacerbate construction delays, and 
result in a lack of competition to construct stand alone network 
upgrades, ultimately harming consumers. Pine Gate therefore recommends 
that the Commission not modify the definition of stand alone network 
upgrade as proposed and instead grant the interconnection customer with 
the largest projected impact on a potential stand alone network upgrade 
facility the ability to elect the option to build with priority falling 
to each interconnection customer based on the next largest impact on 
the stand alone network upgrades.
---------------------------------------------------------------------------

    \527\ Pine Gate Initial Comments at 63-64 (citing Comments of 
Pine Gate, Docket No. RM21-17-000, at 9-10 (filed Oct. 12, 2021); 
Order No. 2003, 104 FERC ] 61,103 at PP 85, 353).
---------------------------------------------------------------------------

    188. Enel argues that the Commission should not adopt the proposed 
substantive revisions to the definition of stand alone network upgrades 
and should instead expand the definition of stand alone network 
upgrades to include upgrades to an existing transmission facility which 
involves a transmission line or substation being entirely rebuilt.\528\ 
Enel offers suggestions for implementing a third-party option that 
would give interconnection customers more control over the cost and 
schedule of larger network upgrades, resolving a frequent barrier to 
bringing needed generating facilities online. To that end, Enel states 
that pro forma LGIA article 5.1 could be modified to specify that the 
option to build is only eligible for stand alone network upgrades 
funded by a single interconnection customer, while the proposed third-
party option could be used for all stand alone network upgrades, 
including line and substation rebuilds.
---------------------------------------------------------------------------

    \528\ Enel Initial Comments at 55-56.
---------------------------------------------------------------------------

    189. Moving to the proposed definition of material modification, 
some commenters support the Commission's proposal.\529\ [Oslash]rsted 
urges the Commission to ensure that under the newly proposed definition 
of material modification, any changes to a proposed generating facility 
that occur on the generating facility side of the point of 
interconnection that do not result in changes to the electrical output 
at the point of interconnection or the electrical characteristics of 
the generating facility's interconnection: (1) will not be deemed to be 
a material modification; and (2) will not result in the termination of 
the interconnection customer's queue position.\530\
---------------------------------------------------------------------------

    \529\ Ameren Initial Comments at 9; MISO Initial Comments at 32.
    \530\ [Oslash]rsted Initial Comments at 8.
---------------------------------------------------------------------------

    190. Ameren suggests that the Commission consider clarifying the 
proposed definition of material modification, so that cost and timing 
are factors to be considered in addition to when the transmission 
provider determines changes to the point of interconnection are 
otherwise material (e.g., from an electrical standpoint).\531\ Ameren 
states that the Commission may want to consider whether the change 
should only be triggered by a change to the point of interconnection or 
whether a change to the inverters or other pieces of equipment in the 
interconnecting generating facility, which could require other 
upgrades, should also result in the determination of a material 
modification.
---------------------------------------------------------------------------

    \531\ Ameren Initial Comments at 9.
---------------------------------------------------------------------------

    191. EPSA asks the Commission to be clearer in determining a 
standard definition of a material modification.\532\ EPSA argues that, 
at minimum, the Commission should direct each RTO/ISO or each NERC 
region to establish clear criteria for the evaluation of material 
modifications.
---------------------------------------------------------------------------

    \532\ EPSA Initial Comments at 13.
---------------------------------------------------------------------------

iii. Commission Determination
    192. We adopt the proposed revisions to section 1 of the pro forma 
LGIP and article 1 of the pro forma LGIA to revise and add several 
defined terms. Specifically, we adopt the proposed revisions to the 
definition of stand alone network upgrade to clarify that, for a 
network upgrade to be eligible for treatment as a stand alone network 
upgrade, the network upgrade must be required for only one 
interconnection customer and must meet the other existing requirements 
in the definition of stand alone network upgrade. We address further 
modifications to the definition of stand alone network upgrade below 
where discussing network upgrade cost allocation (section III.A.4.c of 
this final rule). We also adopt the proposed revisions to the 
definition of material modification, which account for the equal 
interconnection queue position of proposed generating facilities that 
are part of the same cluster. We also modify the NOPR proposal to 
define interconnection facilities study report.
    193. With respect to the definition of stand alone network upgrade, 
in response to Clean Energy Associations' concerns, we note that we do 
not remove the right to self-build interconnection facilities and stand 
alone network upgrades established in Order No. 845. Rather, we are 
explicitly maintaining the status quo, which is to say that, under the 
existing pro forma LGIP, there is no potential for a stand alone 
network upgrade to be shared by more than one interconnection customer. 
With the revision proposed in the NOPR and adopted here, we are 
ensuring that within the structure of a cluster study process adopted 
in this final rule, stand alone network upgrades continue to be defined 
as only those required for a single interconnection customer, and 
therefore the option to build is only available for a single 
interconnection customer. Were we to not adopt this revision, multiple 
interconnection customers could potentially attempt to construct the 
same stand alone network upgrades, leading to confusion and potentially 
lengthy negotiations and/or disputes regarding which interconnection 
customer had the right to construct the stand alone network upgrade. 
Additionally, with regard to Clean Energy Associations' request that 
the Commission consider an approach similar to ISO-NE's for certain 
upgrades that are needed for multiple interconnections, we decline to 
adopt this approach because it is outside the scope of this proceeding. 
We are not proposing in this proceeding to modify the pro forma LGIP to 
address the cost responsibility and division of work between 
interconnection customers that may share cost allocation for stand 
alone network upgrades.
    194. Similarly, Tri-State, Pine Gate, and Enel argue that the 
Commission should expand the definition of stand alone network upgrade, 
thereby expanding the right of interconnection customers to build 
certain network upgrades. These requests are outside the scope of this 
proceeding, which is not proposing to modify the scope of 
interconnection customers' option to build certain stand alone network 
upgrades but rather is only revising definitions insofar as is 
necessary to implement reforms adopted elsewhere in this final rule. 
For the same reason, we decline to expand the definition of material 
modification, as [Oslash]rsted, Ameren, and EPSA request.\533\
---------------------------------------------------------------------------

    \533\ See Ameren Initial Comments at 9; EPSA Initial Comments at 
13; [Oslash]rsted Initial Comments at 8.

---------------------------------------------------------------------------

[[Page 61049]]

c. Definitive Point of Interconnection
i. NOPR Proposal
    195. In the NOPR, the Commission proposed to add new section 3.1.2 
to the pro forma LGIP and therein to require interconnection customers 
to select a definitive point of interconnection to be studied no later 
than the execution of the cluster study agreement. The Commission also 
proposed that, upon mutual agreement, the transmission provider may 
make reasonable changes to the requested point of interconnection to 
facilitate efficient generator interconnection of clustered 
interconnection requests at common points of interconnection.\534\
---------------------------------------------------------------------------

    \534\ NOPR, 179 FERC ] 61,194 at P 66.
---------------------------------------------------------------------------

ii. Comments
    196. MISO supports the Commission requiring the selection of a 
definitive point of interconnection when executing the cluster study 
agreement; however, MISO encourages the Commission to require the 
selection of a definitive point of interconnection even earlier, as 
part of the interconnection request.\535\ MISO notes that requiring an 
earlier selection of the definitive point of interconnection will 
assist in interconnection queue processing, as a transmission provider 
would not be able to begin modeling work if the interconnection 
customer is permitted to wait until a later point in time to select its 
definitive point of interconnection. MISO further argues that the 
definitive point of interconnection (even if subject to change) should 
be selected prior to any scoping meeting. MISO also supports the 
proposed language that limits the ability of the interconnection 
customer to change its point of interconnection after the submission of 
interconnection request.
---------------------------------------------------------------------------

    \535\ MISO Initial Comments at 33-34.
---------------------------------------------------------------------------

    197. Other commenters do not support the Commission's proposal to 
require a definitive point of interconnection when executing the 
cluster study agreement.\536\ ACE-NY supports making the demonstration 
of a feasible point of interconnection a requirement for a generating 
facility to move into the facilities study phase of the generator 
interconnection process.\537\
---------------------------------------------------------------------------

    \536\ ACE-NY Initial Comments at 3; CREA and NewSun Initial 
Comments at 47; Pine Gate Initial Comments at 15.
    \537\ ACE-NY Initial Comments at 3-4.
---------------------------------------------------------------------------

    198. Pine Gate and CREA and NewSun assert that the Commission 
should modify its proposal to permit interconnection customers to 
request alternative points of interconnection.\538\ Pine Gate argues 
that the Commission should permit interconnection customers to request 
a study of a primary and secondary point of interconnection within one 
or two electrical buses, then select a point of interconnection restudy 
after receiving initial cluster study results.\539\ Similarly, CREA and 
NewSun assert that the Commission should permit alternative points of 
interconnection, and collective points of interconnection for proposed 
generating facilities in a cluster (e.g., those that could connect to a 
single substation), to be proposed and studied, at least through the 
system impact study in order to obtain more complete cost 
information.\540\
---------------------------------------------------------------------------

    \538\ CREA and NewSun Initial Comments at 47-48; Pine Gate 
Initial Comments at 15-16.
    \539\ Pine Gate Initial Comments at 15-16.
    \540\ CREA and NewSun Initial Comments at 47-48.
---------------------------------------------------------------------------

    199. Enel suggests that, in the second paragraph of proposed 
section 3.1.2 of the pro forma LGIP, the Commission should change the 
word ``make'' to ``propose'' in the following quoted language: ``For 
purposes of clustering Interconnection Requests, Transmission Provider 
may make reasonable changes to the requested Point of 
Interconnection.'' \541\ Enel explains that this would clarify that any 
such changes can only be made with the consent of the interconnection 
customer, as specified in the proposed new final sentence to that 
paragraph.
---------------------------------------------------------------------------

    \541\ Enel Initial Comments at 82.
---------------------------------------------------------------------------

iii. Commission Determination
    200. We adopt the proposed section 3.1.2 of the pro forma LGIP 
insofar as it requires an interconnection customer to select a 
definitive point of interconnection to be studied when executing the 
cluster study agreement, with one modification discussed below.
    201. Requiring interconnection customers to select a definitive 
point of interconnection when executing the cluster study agreement 
allows the interconnection customer to submit its interconnection 
request with a proposed point of interconnection, participate in the 
scoping meeting during the customer engagement window, and receive 
feedback on its proposed point of interconnection. We believe that this 
strikes the right balance between allowing for flexibility and 
potential adjustments to the point of interconnection, based on 
discussion with the transmission provider and the transmission 
provider's detailed knowledge of its transmission system, and providing 
transmission providers with the information necessary to conduct the 
cluster study, thus reducing the potential for restudies that would be 
required if interconnection customers could change their points of 
interconnection later in the process.
    202. We decline to: (1) require that the definitive point of 
interconnection be selected earlier (e.g., as part of the 
interconnection request); \542\ (2) only require that the definitive 
point of interconnection be selected later (e.g., at the facilities 
study phase); \543\ or (3) permit interconnection customers to submit 
multiple alternative points of interconnection for study in a single 
interconnection request.\544\ We believe that requiring the selection 
of a definitive point of interconnection earlier in the cluster study 
process, as suggested by MISO, would deprive interconnection customers 
of information that could aid in their selection. Similarly, we believe 
that requiring the selection of a definitive point of interconnection 
after the cluster study, as suggested by ACE-NY, or allowing multiple 
points of interconnection to be studied before the interconnection 
customer is required to select the definitive point of interconnection, 
as suggested by Pine Gate and CREA and NewSun, fails to take into 
account the fact that, if an interconnection customer changes the 
definitive point of interconnection after the cluster study, it will 
likely impact the study results of the other interconnection customers 
in the cluster and could lead to restudies and delays. We do not 
believe that the alternatives suggested by commenters would remedy the 
unjust and unreasonable status quo described in section II of this 
final rule.
---------------------------------------------------------------------------

    \542\ See MISO Initial Comments at 33.
    \543\ See ACE-NY Initial Comments at 3-4.
    \544\ See CREA and NewSun Initial Comments at 47-48; Pine Gate 
Initial Comments at 15-16.
---------------------------------------------------------------------------

    203. Finally, we agree with Enel's suggestion to change the word 
``make'' to ``propose'' in pro forma LGIP section 3.1.2. We modify that 
section to state: ``For purposes of clustering Interconnection 
Requests, Transmission Provider may propose reasonable changes to the 
requested Point of Interconnection.'' \545\ We agree that this 
clarifies that any such changes can only be made with the consent of 
the interconnection customer.
---------------------------------------------------------------------------

    \545\ Enel Initial Comments at 82.
---------------------------------------------------------------------------

d. Cluster Request Window and Customer Engagement Window
i. NOPR Proposal
    204. In the NOPR, the Commission proposed to add new section 3.4.1 
(Cluster Request Window) to the pro forma LGIP to require 
interconnection

[[Page 61050]]

customers to submit an interconnection request during the cluster 
request window--a 45-calendar day period with the start date to be 
determined by each transmission provider (with the annual start date 
for the transmission provider's cluster request window included in its 
LGIP).\546\ The transmission provider would consider all 
interconnection requests accepted during this period to have equal 
queue priority for purposes of the cluster study. The Commission also 
proposed to add in pro forma LGIP section 3.1.1 (Initial Study Deposit) 
a non-refundable application fee of $5,000 to be submitted with the 
interconnection request. The Commission further proposed that 
interconnection customers must cure deficient interconnection requests 
within 10 business days after receipt of notice from the transmission 
provider, but no later than the close of the cluster request window.
---------------------------------------------------------------------------

    \546\ NOPR, 179 FERC ] 61,194 at P 67.
---------------------------------------------------------------------------

    205. The Commission also proposed to add new pro forma LGIP section 
3.4.5 (Customer Engagement Window), which provides that, following the 
close of the cluster request window, the transmission provider begins a 
30-calendar day customer engagement window.\547\ New pro forma LGIP 
section 3.4.5 also requires the transmission provider to post within 
the first 10 business days following the close of the cluster request 
window a list of interconnection requests for that cluster.
---------------------------------------------------------------------------

    \547\ Id.
---------------------------------------------------------------------------

ii. Comments
    206. Clean Energy Associations support the proposal to require 
interconnection customers to submit interconnection requests during the 
cluster request window.\548\ MISO supports the Commission requiring a 
definitive application deadline as part of the implementation of 
cluster studies, and equal interconnection queue priority for all 
interconnection requests submitted prior to that deadline, but does not 
see an intrinsic value in a defined application start time.\549\ MISO 
supports granting interconnection customers flexibility to submit an 
interconnection request earlier than the beginning of a cluster request 
window. Noting that, under proposed pro forma LGIP section 3.4.5, 
interconnection requests that are deemed valid during the customer 
engagement window are placed into the cluster study, Southern proposes 
that if an interconnection request is not deemed valid, the 
interconnection request should be withdrawn from the interconnection 
queue.\550\
---------------------------------------------------------------------------

    \548\ Clean Energy Associations Initial Comments at 19.
    \549\ MISO Initial Comments at 35 (noting that, under the MISO 
tariff, all interconnection requests received after the application 
deadline ``shall be applied towards the following Definitive 
Planning Phase cycle'') (citing MISO, FERC Electric Tariff, attach. 
X, section 3.3.1 (158.0.0)).
    \550\ Southern Initial Comments at 37.
---------------------------------------------------------------------------

    207. MISO expresses concern that the timelines listed in the 
customer engagement window for posting information are 
impractical.\551\ MISO asserts that the Commission should not require a 
posting so near to the close of the cluster request window because the 
transmission provider must devote its resources to reviewing the 
interconnection requests for deficiencies.\552\ MISO contends that this 
information would only be useful at this time to interconnection 
customers with speculative interconnection requests that may be trying 
to determine if their proposed generating facility is economically 
viable and that may be trying to identify a point of interconnection 
change to increase the viability of their interconnection requests.
---------------------------------------------------------------------------

    \551\ MISO Initial Comments at 36.
    \552\ Id. (stating that a majority of its interconnection 
requests are submitted on the last day of the application window, or 
two days prior at most).
---------------------------------------------------------------------------

    208. MISO argues that the Commission should not require any 
informational posting pertaining to an interconnection request prior to 
the interconnection customer's finalization of the interconnection 
request because a definitive point of interconnection has not yet been 
selected.\553\ MISO highlights that the proposed pro forma LGIP section 
3.4.5 requires the transmission provider's OASIS posting to include 
``(3) the station or transmission line where the interconnection will 
be made.'' \554\ However, MISO notes that an interconnection customer 
is not required to select a definitive point of interconnection until 
the end of the customer engagement window. As such, MISO contends that 
the posting requirement is impossible if the transmission provider is 
required to post the point of interconnection. MISO argues that the 
Commission should not require any posting until a reasonable period 
after the interconnection customer is required to select its definitive 
point of interconnection and the information is complete, such as when 
the customer engagement window is completed and cluster studies are 
about to begin.
---------------------------------------------------------------------------

    \553\ Id. at 36-37.
    \554\ Id. at 37.
---------------------------------------------------------------------------

    209. Regarding the makeup of the cluster, Clean Energy States 
assert that the cluster study process should allow for changes in the 
makeup of the cluster, and that the study process may identify ways to 
improve a cluster to provide better performance for the transmission 
system, such as by adding or subtracting certain interconnection 
requests from the cluster.\555\ Clean Energy States assert that a 
transmission provider should be able to modify the cluster in response 
to interconnection customer changes or study findings without 
threatening the interconnection customer's queue priority or paying 
penalties.
---------------------------------------------------------------------------

    \555\ Clean Energy States Initial Comments at 8-9.
---------------------------------------------------------------------------

    210. EPSA argues that the final rule should specify that 
transmission providers are required to work with interconnection 
customers during the customer engagement window and study agreement 
negotiation in a manner that is fair and equitable regarding the study 
models to be used, data verification, and stakeholder engagement--
regardless of the planning or procurement method used by the 
prospective interconnection customer.\556\
---------------------------------------------------------------------------

    \556\ EPSA Initial Comments at 7.
---------------------------------------------------------------------------

    211. Enel recommends that the Commission consolidate the 
interconnection request and cluster and facilities study agreements 
into a single study agreement to be submitted at the time of 
application.\557\ Enel also recommends that the Commission include 
language in the pro forma LGIP that provides that transmission 
providers will not post information about interconnection requests 
proceeding through or withdrawing from the interconnection queue until 
all interconnection requests submitted within a cluster request window 
successfully meet their milestone requirements to proceed, withdraw, or 
fail to cure their breach within the specific cure period.\558\
---------------------------------------------------------------------------

    \557\ Enel Initial Comments at 13.
    \558\ Id. at 48.
---------------------------------------------------------------------------

    212. Regarding the length of the cluster request window, some 
commenters support the proposed 45-calendar day time frame for the 
cluster request window.\559\ Although it supports the 45-calendar day 
time frame, Eversource suggests the Commission add more structure to 
this element of its proposal by establishing rules that enable 
potential interconnection customers to be informed of when the request 
windows

[[Page 61051]]

will be open and how to prepare to apply.\560\
---------------------------------------------------------------------------

    \559\ Eversource Initial Comments at 13; Clean Energy 
Associations Initial Comments at 19.
    \560\ Eversource Initial Comments at 13.
---------------------------------------------------------------------------

    213. Other commenters argue that the proposed 45-calendar day time 
frame for the cluster request window is too short and should be 
increased to 60 calendar days.\561\ ISO-NE states that, based on its 
experience implementing its forward capacity market process, each of 
the cluster study windows proposed in the NOPR should be extended to 
help ensure an efficient cluster study process.\562\ Pine Gate also 
argues that a longer cluster request window would reduce the burden on 
transmission providers by providing more time to administer their 
deficiency notice processes.\563\ Pine Gate explains that, for larger 
interconnection customers that may be developing numerous 
interconnection requests for multiple transmission providers, 
overlapping cluster request windows are likely. Additionally, Pine Gate 
contends that, as contemplated by the NOPR, it is likely that increased 
requirements and additional information for interconnection customers 
will be due at the time of interconnection queue entry (e.g., the 
complex modeling required to be submitted) and burdensome to 
accommodate in the proposed time frame.
---------------------------------------------------------------------------

    \561\ ISO-NE Initial Comments at 22-23; Pine Gate Initial 
Comments at 16; PJM Initial Comments at 19-20.
    \562\ ISO-NE Initial Comments at 22. ISO-NE requests that the 
Commission consider the following windows for the cluster study 
process: (i) cluster request window--60 calendar days; (ii) customer 
engagement window--90 calendar days; (iii) cluster study--270 to 365 
calendar days (depending on the size of a given cluster); (iv) 
cluster restudy--150 calendar days; and (v) facilities study--90 to 
180 calendar days. Id. at 23.
    \563\ Pine Gate Initial Comments at 16.
---------------------------------------------------------------------------

    214. On the other hand, some commenters argue that a shorter 
cluster request window is appropriate. CAISO argues that longer cluster 
request windows result in low quality requests because interconnection 
customers have more time within the window to fix their 
submissions.\564\ CAISO contends that its use of a shorter 15-day 
interconnection request completeness window followed by a longer 
validation and scoping meeting window have significantly improved 
interconnection request quality and the speed with which CAISO 
processes requests.\565\ Similarly, Tri-State recommends that the 
cluster request window be shortened because, based on its experience, 
most interconnection requests submitted in the cluster request window 
are received the last two days of the request window.\566\
---------------------------------------------------------------------------

    \564\ CAISO Initial Comments at 9.
    \565\ Id. (citing CAISO, CAISO Tariff, app. DD, sections 3.5.1, 
3.5.2.2 (16.0.0); id. section 6.1.2 (21.0.0)).
    \566\ Tri-State states that during its 2022 definitive 
interconnection system impact study request window, 75% of the 
interconnection requests were received during the last two days of 
the request window, and 50% of the interconnection requests were 
received in the last two days of the 2021 definitive interconnection 
system impact study request window. Id. at 10.
---------------------------------------------------------------------------

    215. Regarding the requirement for correcting deficiencies in the 
proposed pro forma LGIP section 3.4.4 (Deficiencies in Interconnection 
Request), Tri-State argues that requiring interconnection customers to 
provide any requested information within 10 business days after 
receiving notice of deficiencies in the interconnection request, but no 
later than the close of the cluster request window, does not take into 
account that most requests are not submitted until the last day of the 
cluster request window.\567\
---------------------------------------------------------------------------

    \567\ Tri-State Initial Comments at 27.
---------------------------------------------------------------------------

    216. Regarding the number of cluster request windows opened each 
year, a couple of commenters argue that there should be more than one 
cluster request window per year.\568\ Clean Energy States assert that, 
because presumably there will be fewer generator interconnection 
studies to be done, transmission providers should provide opportunities 
more frequently (e.g., quarterly) for interconnection customers to 
submit interconnection requests.\569\ Environmental Defense Fund argues 
that the Commission should require that the cluster request windows 
occur bi-annually, rather than once a year, to reduce the delay caused 
by missing a cluster request window while still covering a large enough 
time period that a number of interconnection requests will be included 
in each cluster.\570\
---------------------------------------------------------------------------

    \568\ Clean Energy States Initial Comments at 9; Environmental 
Defense Fund Initial Comments at 4.
    \569\ Clean Energy States Initial Comments at 9.
    \570\ Environmental Defense Fund Initial Comments at 4.
---------------------------------------------------------------------------

    217. Southern generally agrees with the Commission that a cluster 
study process, including the individual facilities study, should be 
completed within a year, but recommends eliminating unnecessary delays, 
such as multiple, overlapping clusters, by only permitting one cluster 
study at a time (i.e., that a new cluster should not commence until the 
previous cluster has been completed).\571\ According to Southern, under 
this format, an annual cluster study can be performed because the 
previous cluster study process has been completed. Southern asserts 
that overlapping cluster study processes will not help end 
interconnection queue backlogs and uncertainty, but rather add to them.
---------------------------------------------------------------------------

    \571\ Southern Initial Comments at 23-24.
---------------------------------------------------------------------------

    218. Regarding the length of the customer engagement window, Clean 
Energy Associations support the proposed 30-calendar day time frame for 
the customer engagement window as a baseline.\572\ A number of 
commenters argue that the proposed 30-calendar day customer engagement 
window is too short and recommend a longer window.\573\ Duke Southeast 
Utilities argue that, based on experience with Duke Carolinas 
Utilities' cluster study process, which includes a 60-calendar day 
customer engagement window, the proposed 30-calendar day customer 
engagement window may not provide sufficient time to facilitate robust 
engagement.\574\ Duke Southeast Utilities therefore urge the Commission 
to adopt a 60-calendar day customer engagement window. Xcel describes 
PSCo's recent interconnection queue reform, which extended the customer 
engagement window to 95 calendar days to allow interconnection 
customers additional time to reevaluate their readiness in a way that 
includes other customers.\575\
---------------------------------------------------------------------------

    \572\ Clean Energy Associations Initial Comments at 19.
    \573\ APS Initial Comments at 10-11; CAISO Initial Comments at 
8, 10-11; Duke Southeast Utilities Comments at 8; ISO-NE Initial 
Comments at 23; Tri-State Initial Comments at 9-10; PJM Initial 
Comments at 20.
    \574\ Duke Southeast Utilities Initial Comments at 8.
    \575\ Xcel Initial Comments at 21 (citing Pub. Serv. Co. of 
Colo., Docket No. ER22-2087-000 (Aug. 9, 2022) (delegated order)).
---------------------------------------------------------------------------

    219. ISO-NE suggests a 90-calendar day customer engagement 
window.\576\ In addition, ISO-NE suggests that the Commission clarify 
that transmission providers may withdraw interconnection requests for 
which the models and data do not meet the requirements following the 
customer engagement window in order to improve efficiency. ISO-NE 
further asks that the Commission recognize the role of the 
participating transmission owners in performance of interconnection 
studies and build time into the cluster study time frames that accounts 
for this coordination.
---------------------------------------------------------------------------

    \576\ ISO-NE Initial Comments at 23.
---------------------------------------------------------------------------

    220. Indicated PJM TOs argue that there should be a 30-calendar day 
window after the date that the cluster request window closes, and 
between the time the transmission provider posts the interconnection 
cases for the cluster study and the cluster study commences, during 
which interconnection customers qualified to receive CEII information 
have the opportunity to conduct their own studies with the transmission 
provider's base case and

[[Page 61052]]

the new interconnection service requests. Indicated PJM TOs assert that 
during this time, interconnection customers should be able to withdraw 
their interconnection request with minimal financial impact.\577\
---------------------------------------------------------------------------

    \577\ Indicated PJM TOs Reply Comments at 6-7.
---------------------------------------------------------------------------

    221. APS states that multiple customers requesting individual 
scoping meetings could place a significant burden on the transmission 
provider to schedule several meetings under a condensed time frame if 
the customer engagement window remains 30 calendar days.\578\ For 
example, APS states that, assuming all notifications of valid 
interconnection requests are made by the time the customer engagement 
window starts, the interconnection customer has 15 business days to 
request an individual meeting and, if an interconnection customer uses 
all 15 business days, that is a minimum 21 calendar days out of the 
total 30 calendar days of the overall customer engagement window. APS 
contends that this leaves nine calendar days at most (i.e., no more 
than seven business days) to schedule an individual customer meeting, 
which could be less if there are holidays occurring within the customer 
engagement window.
---------------------------------------------------------------------------

    \578\ APS Initial Comments at 10.
---------------------------------------------------------------------------

    222. Similarly, Tri-State argues that the proposed 30-day customer 
engagement window is not sufficient to meet the purpose of the customer 
engagement window and recommends it be extended to allow adequate time 
to cure deficiencies and hold individual scoping meetings.\579\ Tri-
State argues that a 75-day customer engagement window would give 
interconnection customers an opportunity to: (1) assess the viability 
of their proposed generating facilities before committing to the 
interconnection process and subjecting themselves to a withdrawal 
penalty; and (2) cure deficiencies in their interconnection 
requests.\580\
---------------------------------------------------------------------------

    \579\ Tri-State Initial Comments at 9, 10.
    \580\ Id. at 9.
---------------------------------------------------------------------------

iii. Commission Determination
    223. We adopt the proposed new pro forma LGIP section 3.4.1 
(Cluster Request Window), which provides that interconnection customers 
must submit an interconnection request during a specified period--the 
cluster request window--a 45-calendar day period with the start date to 
be determined by each transmission provider. We also adopt the non-
refundable $5,000 application fee required to be submitted with the 
interconnection request.\581\ We also adopt the requirement that 
interconnection customers provide requested information within 10 
business days of receiving an interconnection request deficiency notice 
but no later than the close of the cluster request window, as proposed 
and adopted in new pro forma LGIP section 3.4.4 (Deficiencies in 
Interconnection Request), but we modify that section to clarify the 
timeline for curing deficiencies. We modify the proposed new pro forma 
LGIP section 3.4.5 (Customer Engagement Window) and extend the customer 
engagement window from 30 days to 60 calendar days.
---------------------------------------------------------------------------

    \581\ We note that the application fee is separate from the 
initial study deposit, commercial readiness deposit, and deposit in 
lieu of site control.
---------------------------------------------------------------------------

    224. To ensure clarity for both interconnection customers and 
transmission providers, based on the record, we believe that 45 
calendar days is a sufficient window to adequately notify prospective 
interconnection customers of the formation of a new cluster but not so 
long as to delay the processing of the interconnection queue.
    225. Contrary to commenters' assertions, we are not persuaded to 
extend the cluster request window. We do not believe that more time is 
needed for transmission providers to work with interconnection 
customers that submitted invalid interconnection requests to cure 
deficiencies, particularly given the limit we adopt on the time for 
such additional information to be submitted by interconnection 
customers, and because the start date of the cluster request window 
will be included in the transmission provider's LGIP for prospective 
interconnection customers. We similarly do not believe that shortening 
the cluster request window would result in fewer ``low quality'' 
interconnection requests, as CAISO argues. Given the package of reforms 
adopted in this final rule, we expect fewer speculative interconnection 
requests and that interconnection customers will be more likely as a 
result of this final rule to submit interconnection requests for 
proposed generating facilities that they believe are viable and ready 
to move forward in the interconnection process.
    226. As for Tri-State's concern about the requirement for 
correcting deficiencies in new pro forma LGIP section 3.4.4 
(Deficiencies in Interconnection Request),\582\ we clarify that the 10-
business day window is the maximum time allowed to submit a response. 
This means that an interconnection customer that submits its 
interconnection request more than 10 business days before the close of 
the cluster request window will have a full 10 business days to submit 
a response, whereas an interconnection customer that does not submit 
its interconnection request until less than 10 business days before the 
close of the cluster request window will have however many days remain 
in the cluster request window to respond to any deficiencies. 
Accordingly, we modify pro forma LGIP section 3.4.4 to provide that if 
the interconnection customer does not respond before the deadline: (1) 
the interconnection request is immediately deemed withdrawn (without 
the cure period provided under pro forma LGIP section 3.7); (2) the 
application fee is forfeited to the transmission provider; and (3) 
because the cluster study has not commenced, the study deposit and 
commercial readiness deposit are returned to the interconnection 
customer.
---------------------------------------------------------------------------

    \582\ Tri-State Initial Comments at 27.
---------------------------------------------------------------------------

    227. We decline to adopt revisions to the pro forma LGIP to require 
biannual or quarterly cluster study windows, as suggested by Clean 
Energy States and Environmental Defense Fund. Based on the record, we 
are not convinced that mandating multiple cluster request windows per 
year will result in a more efficient cluster study process, especially 
considering the various sizes of transmission provider footprints and 
interconnection queues. As we adopt an annual cluster study process, an 
annual cluster request window will allow transmission providers to 
dedicate resources to the cluster request window only once per year, 
dedicating their resources to the remainder of the cluster study 
process for the rest of the year. We also are not convinced by 
Environmental Defense Fund's concern with interconnection customers 
missing a cluster request window, as the date of the start of the 
cluster request window will be in each transmission provider's LGIP, 
providing sufficient notice for prospective interconnection customers 
to prepare required application materials accordingly. We do not 
believe that additional rules are needed to govern how transmission 
providers will inform interconnection customers about the cluster 
request window.
    228. We disagree with Southern's suggestion that the cluster study 
process should only permit transmission providers to conduct one 
cluster study at a time (i.e., eliminating the possibility of 
conducting multiple cluster studies at any time). Prohibiting the 
transmission provider from conducting overlapping cluster studies, in 
the instance where it is necessary to process cluster subgroups or to 
process delayed studies, would delay the interconnection process for 
interconnection customers. We therefore find that this suggestion

[[Page 61053]]

would contribute to more backlogs and uncertainty, as delays to any 
cluster study would significantly delay cluster studies for all 
remaining interconnection requests in an interconnection queue and 
would be insufficient to ensure that interconnection customers are able 
to interconnect to the transmission system in a reliable, efficient, 
transparent, and timely manner. Transmission providers with the 
capacity to conduct multiple cluster studies at a given time should be 
permitted to do so to facilitate more effective and efficient 
interconnection processes.
    229. In response to MISO's concern about posting requirements close 
to the conclusion of the cluster request window, we reiterate that we 
are extending the length of the customer engagement window from the 
proposed 30 calendar days to 60 calendar days, which will allow 
transmission providers a total of 60 calendar days from the close of 
the cluster request window to post the list of interconnection requests 
for that cluster.
    230. MISO argues that the Commission should not require any OASIS 
posting prior to the interconnection customer's finalization of the 
interconnection request because a definitive point of interconnection 
would have not yet been selected.\583\ While we recognize MISO's 
concern about transmission providers posting interconnection request 
information on OASIS that may later change, we find that providing as 
much information as possible to interconnection customers early in the 
customer engagement window provides important transparency to improve 
interconnection queue processing. Providing information about other 
interconnection requests that may be studied within the same cluster to 
interconnection customers considering whether to execute a cluster 
study agreement and to continue with the cluster, may help them 
determine the viability of their proposed generating facilities, making 
it less likely that interconnection customers will withdraw later in 
the cluster study process, triggering delays and restudies and the 
associated problems discussed in section II of this final rule.
---------------------------------------------------------------------------

    \583\ MISO Initial Comments at 36-37.
---------------------------------------------------------------------------

    231. We disagree with Clean Energy States' assertion that a cluster 
should be able to be modified in response to interconnection customer 
changes or study findings without threatening the interconnection 
customer's relative queue priority or paying penalties.\584\ Any 
interconnection customer that submits a valid interconnection request 
during the customer request window will become part of the cluster, if 
the interconnection customer chooses to execute a cluster study 
agreement by the end of the customer engagement window. The 
transmission provider may not modify the makeup of the cluster or pick 
and choose which interconnection customers to keep in the cluster in 
the way Clean Energy States describes. We also note that 
interconnection customers can request a modification assessment 
pursuant to section 4.4 of the pro forma LGIP.
---------------------------------------------------------------------------

    \584\ Clean Energy States Initial Comments at 9.
---------------------------------------------------------------------------

    232. Regarding the customer engagement window, we adopt the NOPR 
proposal to add a new section 3.4.5 (Customer Engagement Window) to the 
pro forma LGIP, which provides that, following the close of the cluster 
request window, the transmission provider begins a customer engagement 
window. Additionally, we modify the proposal to extend the customer 
engagement window from 30 calendar days, as proposed, to 60 calendar 
days. Under this provision, the transmission provider must post new 
cluster information on OASIS with details of each interconnection 
request for that cluster, including information on the amount of 
interconnection service and the location of the proposed generating 
facility, within the first 10 business days of the customer engagement 
window. While we extend the customer engagement window from 30 calendar 
to 60 calendar days, we retain the proposed 10 business day deadline by 
which the transmission provider must post new cluster information on 
OASIS. We find that it is more beneficial for interconnection customers 
to have this information as early as possible, such that they are able 
to assess the composition of the cluster and make informed choices 
moving forward with their interconnection requests earlier rather than 
later in the customer engagement window. Further, during the customer 
engagement window, an interconnection customer may withdraw its 
interconnection request without penalty.
    233. We extend the customer engagement window to 60 calendar days 
in response to numerous commenters' arguments that 30 calendar days is 
insufficient to adequately engage with interconnection customers in a 
cluster, including based on experience implementing a similar cluster 
study process to that we require as part of this final rule.\585\ By 
extending the customer engagement window, we provide transmission 
providers with additional time to conduct individual meetings with 
interconnection customers that submitted interconnection requests 
within the cluster request window, lessening the burden on transmission 
providers, particularly larger transmission providers such as RTOs/
ISOs.\586\ At the same time, we provide interconnection customers with 
more time to consider information collected during this period of 
engagement with the transmission provider--including the makeup of the 
cluster--and assess the continued viability of their proposed 
generating facilities before withdrawal of the interconnection request 
will incur a penalty. For example, the interconnection customer can 
assess the expected costs of potential network upgrades and the impact 
of those costs on the viability of its proposed generating facility in 
the context of the size and location of other interconnection requests 
in the cluster. Interconnection customers will have 46 calendar days to 
consider the posted information (which must be posted within 10 
business days after the start of the customer engagement window). Not 
only will this longer time period for interconnection customers to 
consider whether to withdraw their interconnection requests prior to 
the start of the cluster study save interconnection customers' 
resources by avoiding future penalties, but it will also result in more 
efficient interconnection queue processing with fewer withdrawals later 
in the cluster study process--withdrawals that can trigger restudies 
and cause the problems discussed in section II of this final rule.
---------------------------------------------------------------------------

    \585\ Duke Southeast Utilities Initial Comments at 8; PJM 
Initial Comments at 20; Xcel Initial Comments at 21 (citing Pub. 
Serv. Co. of Colo., Docket No. ER22-2087-000 (Aug. 9, 2022) 
(delegated order)).
    \586\ PJM Initial Comments at 20; ISO-NE Initial Comments at 23.
---------------------------------------------------------------------------

    234. We reject Southern's suggestion that if an interconnection 
request is not deemed valid,\587\ the interconnection request should be 
withdrawn from the interconnection queue. Under new section 3.4.5 of 
the pro forma LGIP, any interconnection requests not deemed valid at 
the close of the customer engagement window will not be included in the 
cluster. This provision is designed to ensure that interconnection 
customers and transmission providers have sufficient time to conduct 
scoping meetings and to discuss and comprehensively evaluate whether 
interconnection requests are fully valid during the customer engagement 
window. We find that

[[Page 61054]]

forced withdrawals prior to the close of the customer engagement window 
could result in potentially valid interconnection requests being 
rejected prior to allowing for interconnection customers and 
transmission providers to discuss alternative interconnection options, 
exchange information that could impact such options, and conduct due 
diligence informed by information discussed during the customer 
engagement window per the provisions set forth in new pro forma LGIP 
section 3.4.6 detailing scoping meetings.
---------------------------------------------------------------------------

    \587\ Southern Initial Comments at 37.
---------------------------------------------------------------------------

    235. In response to EPSA,\588\ we note that transmission providers 
and interconnection customers should always work in a manner that is 
fair and nondiscriminatory, including during the customer engagement 
window and study agreement negotiation.
---------------------------------------------------------------------------

    \588\ EPSA Initial Comments at 7.
---------------------------------------------------------------------------

    236. We decline to adopt MISO's suggestion that transmission 
providers allow interconnection customers to submit an interconnection 
request prior to the beginning of the cluster request window. We note 
that the cluster request window is specifically designed to structure 
when transmission providers should expect interconnection customers to 
submit interconnection requests for assessment. We find that allowing 
interconnection request submission prior to the cluster request window 
may be burdensome to transmission providers, who would have to dedicate 
staff and resources towards assessing the viability of interconnection 
requests before the designated request window opening, instead of 
concentrating their resources towards the prior stage of the 
interconnection process.
    237. We agree with Enel's recommendation that the Commission 
include language in the pro forma LGIP that, in the cluster study 
process, the transmission provider will not post detailed information 
about interconnection requests proceeding or withdrawing until all 
interconnection requests successfully meet their milestone requirements 
to proceed, withdraw, or fail to cure their breach within the specific 
cure period. We note that transmission providers are required to post 
this information at the conclusion of the cluster request window, at 
which point interconnection customers must provide significant 
requirements to proceed. We find that maintaining confidentiality early 
in the customer engagement window stage is appropriate to reduce 
opportunities for developers to gain competitive advantage over others 
before interconnection requests have been finalized and accepted by the 
transmission provider. We therefore adopt the following modification to 
section 3.4.5 of the pro forma LGIP (addition in italics): ``Within ten 
(10) Business Days after the close of the Cluster Request Window, 
Transmission Provider shall post on its OASIS site a list of 
Interconnection Requests for that Cluster. The list shall identify, for 
each anonymized Interconnection Request[s]: (1) the requested amount of 
Interconnection Service; (2) the location by county and state; (3) the 
station or transmission line or lines where the interconnection will be 
made; (4) the projected In-Service Date; (5) the type of 
Interconnection Service requested; and (6) the type of Generating 
Facility or Facilities to be constructed, including fuel types, such as 
wind, natural gas, coal, or solar. The transmission provider must 
ensure that project information is anonymized and does not reveal the 
identity or commercial information of interconnection customers with 
submitted requests.'' Further, as discussed below, we modify section 
3.4.6 of the pro forma LGIP to require that transmission providers 
exercise the use of non-disclosure agreements to maintain 
confidentiality of identifying or commercially sensitive information 
for all other interconnection customers in a group scoping meeting.
e. Scoping Meeting
i. NOPR Proposal
    238. In the NOPR, the Commission proposed to renumber and revise 
section 3.4.4 of the pro forma LGIP as section 3.4.6 to provide that, 
during the proposed customer engagement window, transmission providers 
must hold a scoping meeting with all interconnection customers whose 
valid interconnection requests were received in that cluster request 
window.\589\ Revised section 3.4.6 of the pro forma LGIP would also 
require transmission providers to hold individual customer-specific 
scoping meetings, at the interconnection customer's request, which must 
be requested by no later than 15 business days after the close of the 
cluster request window.
---------------------------------------------------------------------------

    \589\ NOPR, 179 FERC ] 61,194 at P 68.
---------------------------------------------------------------------------

ii. Comments
    239. MISO supports the Commission requiring individual customer-
specific scoping meetings only when requested by interconnection 
customers.\590\ APS agrees that a single scoping meeting with all 
interconnection customers in the cluster during the customer engagement 
window is beneficial to transmission providers and eases the burden of 
scheduling individual meetings with all parties. However, APS has 
concerns about security and confidentiality.\591\ APS notes that, 
currently, each interconnection customer in the interconnection queue 
is provided a queue number that becomes the only identifying 
information posted publicly. APS requests that the Commission provide 
clarity on whether the requirements to treat additional information as 
confidential no longer apply or if there is a form of good utility 
practice as it pertains to holding a single scoping meeting without 
revealing the identities of the other interconnection customers 
involved and some examples thereof.
---------------------------------------------------------------------------

    \590\ MISO Initial Comments at 35-36.
    \591\ APS Initial Comments at 10.
---------------------------------------------------------------------------

    240. MISO expresses concern that the timelines listed in the 
customer engagement window for posting information are impractical. 
MISO asserts that the Commission should not require a posting so near 
the close of the request window because the transmission provider must 
devote its resources to reviewing the interconnection requests for 
deficiencies.\592\
---------------------------------------------------------------------------

    \592\ MISO Initial Comments at 36.
---------------------------------------------------------------------------

    241. Enel and AEE argue that the Commission should also require 
transmission providers and transmission owners to hold individual, 
customer-specific scoping meetings at the request of the 
interconnection customer before the customer commits to entering the 
cluster.\593\ Enel states that an individual pre-interconnection queue 
scoping meeting would be an opportunity for the interconnection 
customer to ask basic questions that can help inform economically 
significant decisions an interconnection customer faces in deciding to 
enter the interconnection queue.\594\ As an alternative to requiring a 
pre-interconnection queue meeting, Enel suggests that the Commission 
could require transmission providers to maintain an electronic inbox 
where prospective interconnection customers could submit 
interconnection-related questions and be guaranteed a response in time 
to inform decisions on entering the interconnection queue.
---------------------------------------------------------------------------

    \593\ AEE Initial Comments at 10; Enel Initial Comments at 10.
    \594\ Enel Initial Comments at 10.
---------------------------------------------------------------------------

    242. PJM believes that ``grouping kick off meetings'' will reduce 
the burden on transmission owners and providers of scheduling and 
participating in hundreds of meetings, and the burden on 
interconnection customers of waiting

[[Page 61055]]

for their meeting to be scheduled.\595\ PJM requests clarification that 
a transmission provider may group requests for this customer engagement 
window unless an interconnection customer requests otherwise.
---------------------------------------------------------------------------

    \595\ PJM Initial Comments at 20-21.
---------------------------------------------------------------------------

    243. Tri-State asks the Commission to consider providing only one 
week to schedule the requested individual customer-specific scoping 
meeting if the interconnection customer does not request a scoping 
meeting until the fifteenth business day.\596\
---------------------------------------------------------------------------

    \596\ Tri-State Initial Comments at 27.
---------------------------------------------------------------------------

    244. Noting the difficulty of coordinating in-person scoping 
meetings, SEIA requests that the Commission clarify that both 
generating facility-specific and cluster scoping meetings must provide 
the option for interconnection customers to attend via teleconference, 
which is currently not available in all regions.\597\ Enel suggests 
that, for all scoping meetings, the Commission should require 
transmission owners, not just interconnection customers and 
transmission providers, to attend; otherwise, Enel continues, there 
could be crucial questions that the transmission provider may not be 
able to answer.\598\
---------------------------------------------------------------------------

    \597\ SEIA Initial Comments at 8.
    \598\ Enel Initial Comments at 11.
---------------------------------------------------------------------------

iii. Commission Determination
    245. We adopt, in part, the proposed revisions to section 3.4.6 of 
the pro forma LGIP, and therefore require that, during the customer 
engagement window, transmission providers hold a scoping meeting with 
all interconnection customers whose interconnection requests were 
received in that cluster request window. We decline to adopt the NOPR 
proposal to require transmission providers to hold individual customer-
specific scoping meetings at the interconnection customer's request.
    246. These revisions to the pro forma LGIP align the timing and 
purpose of scoping meetings between transmission providers and 
interconnection customers with the adoption of the cluster study 
process in this final rule. We do not believe that providing the option 
for interconnection customers to request an individual customer-
specific scoping meeting is necessary to ensure that interconnection 
customer-specific questions are answered as interconnection customers 
consider whether to remain in the interconnection queue for the cluster 
study or to withdraw their interconnection request. We find that this 
requirement would be comparatively inefficient and burdensome for 
transmission providers, leading to potentially significant 
interconnection delays. We thus find that this requirement would be 
inconsistent with the goal to ensure that interconnection customers are 
able to interconnect to the transmission system in a reliable, 
efficient, transparent, and timely manner. We find that the cluster-
wide scoping meeting is an appropriate forum in which all 
interconnection customers can direct questions to transmission 
providers in an efficient manner without delaying the cluster process 
with unnecessarily time-consuming individual scoping meetings.
    247. We agree with APS' concerns pertaining to good utility 
practices \599\ for security and confidentiality regarding the 
disclosure of potentially sensitive commercial information during the 
cluster scoping meeting that will include numerous interconnection 
customers in the cluster.\600\ We therefore modify section 3.4.6 of the 
pro forma LGIP to require that transmission providers use non-
disclosure agreements to maintain confidentiality of identifying or 
commercially sensitive information for all other interconnection 
customers in a group scoping meeting until the close of the customer 
engagement window.
---------------------------------------------------------------------------

    \599\ Good utility practice means ``any of the practices, 
methods and acts engaged in or approved by a significant portion of 
the electric industry during the relevant time period, or any of the 
practices, methods and acts which, in the exercise of reasonable 
judgment in light of the facts known at the time the decision was 
made, could have been expected to accomplish the desired result at a 
reasonable cost consistent with good business practices, 
reliability, safety and expedition. Good utility practice is not 
intended to be limited to the optimum practice, method, or act to 
the exclusion of all others, but rather to be acceptable practices, 
methods, or acts generally accepted in the region.'' See pro forma 
LGIP section 1 (Definitions).
    \600\ APS Initial Comments at 10.
---------------------------------------------------------------------------

    248. In response to Enel and AEE,\601\ we will not modify the pro 
forma LGIP to require transmission providers to hold individual 
interconnection customer-specific scoping meetings at the request of 
the interconnection customer before the interconnection customer 
commits to entering the cluster. As discussed above, we decline to 
adopt a requirement that transmission providers conduct individual 
interconnection customer scoping meetings. Additionally, as discussed 
above,\602\ we adopt the heatmap requirement, which will assist 
interconnection customers prior to entering the interconnection queue 
in evaluating the viability of their proposed generating facilities, 
and we are also permitting interconnection customers to withdraw from 
the interconnection queue without penalty prior to the close of the 
customer engagement window. With these reforms, we do not believe that 
pre-interconnection queue scoping meetings should be required to ensure 
just and reasonable rates.
---------------------------------------------------------------------------

    \601\ AEE Initial Comments at 10; Enel Initial Comments at 10.
    \602\ See supra section III.A.1.c.
---------------------------------------------------------------------------

    249. In response to MISO's concern about posting requirements close 
to the conclusion of the cluster request window,\603\ we find that 
allowing transmission providers a total of 10 business days from the 
close of the cluster request window to post the required list of 
interconnection requests for that cluster is a reasonable amount of 
time.
---------------------------------------------------------------------------

    \603\ MISO Initial Comments at 36.
---------------------------------------------------------------------------

    250. In response to SEIA,\604\ we decline to modify the pro forma 
LGIP to require transmission providers to include an option for 
interconnection customers to attend via teleconference for cluster-wide 
scoping meetings. We do not believe that such level of logistical 
specification governing how transmission providers choose to conduct 
scoping meetings with interconnection customers is needed in the pro 
forma LGIP.
---------------------------------------------------------------------------

    \604\ SEIA Initial Comments at 8.
---------------------------------------------------------------------------

    251. In response to Enel,\605\ we decline to modify the pro forma 
LGIP to require transmission owners, not just interconnection customers 
and transmission providers, to attend scoping meetings. The pro forma 
LGIP contemplates that the transmission owner and transmission provider 
may be the same entity, except in the case of an RTO/ISO, in which case 
the transmission owner does not have operational control of the 
facilities and does not perform cluster studies. In the case of an RTO/
ISO, only the entity that independently administers the cluster study 
is required to attend the scoping meeting.
---------------------------------------------------------------------------

    \605\ Enel Initial Comments at 11.
---------------------------------------------------------------------------

f. Posting of Metrics for Cluster Study Processing Time and Restudy 
Processing Time
i. NOPR Proposal
    252. In the NOPR, the Commission proposed to revise the 
requirements included in section 3.5.2 of the pro forma LGIP to post 
metrics for interconnection feasibility study processing time and 
system impact study processing time, to instead require transmission 
providers to post metrics for cluster study processing time and

[[Page 61056]]

cluster restudy processing time.\606\ The Commission also proposed to 
require transmission providers to post the time from when the 
transmission provider received a valid interconnection request to the 
completion of the cluster study, cluster restudy, and facilities study.
---------------------------------------------------------------------------

    \606\ NOPR, 179 FERC ] 61,194 at P 69.
---------------------------------------------------------------------------

    253. Specifically, in section 3.5.2.1 of the pro forma LGIP, the 
Commission proposed requiring that transmission providers must post the 
number of interconnection requests that had cluster studies completed 
within the transmission provider's coordinated region during the 
reporting quarter that were completed more than 150 calendar days after 
the close of the customer engagement window. Similarly, in section 
3.5.2.2 of the pro forma LGIP, the Commission proposed requiring that 
transmission providers must post the number of interconnection requests 
that had cluster restudies completed within the transmission provider's 
coordinated region during the reporting quarter that were completed 
more than 150 calendar days after the transmission provider's receipt 
of the interconnection customer's executed cluster restudy agreement.
    254. In section 6.4 of the pro forma LGIP, the Commission proposed 
that transmission providers publicly post new metrics requirements on 
their websites pertaining to various technical specifications for, and 
impacts of, potential generating facilities on the transmission 
provider's transmission system, requiring that these metrics must be 
updated on the transmission provider's website ``within 30 days after 
the completion of each Cluster Study and Cluster Restudy period.'' 
\607\
---------------------------------------------------------------------------

    \607\ Proposed pro forma LGIP section 6.4.
---------------------------------------------------------------------------

ii. Comments
    255. Clean Energy Associations support the proposal to require the 
posting of metrics for cluster study processing time and cluster 
restudy processing time, starting from when the transmission provider 
received a valid interconnection request.\608\ Clean Energy 
Associations further argue that these reports should also identify the 
level of accuracy of these studies relative to final costs.
---------------------------------------------------------------------------

    \608\ Clean Energy Associations Initial Comments at 20-21.
---------------------------------------------------------------------------

    256. While supportive of the use of metrics that reflect cluster 
study and cluster restudy processing time, some commenters do not 
support measuring these metrics from the date that the transmission 
provider received the interconnection request.\609\ APS argues that 
this seems contradictory to the NOPR proposal that the 150-day timeline 
to process cluster study requests begins at the end of the customer 
engagement window.\610\ MISO asserts that for study metrics to be a 
useful measurement of whether a transmission provider is meeting its 
tariff deadlines, the start date used in the metrics must reflect when 
studies actually commence.\611\ MISO notes that an interconnection 
customer may choose to submit its interconnection request weeks ahead 
of the cluster request window deadline and that the time between that 
deadline and study commencement is variable.\612\ MISO urges the 
Commission to allow RTOs/ISOs flexibility to maintain metrics that 
reflect their tariff deadlines, especially where the RTO/ISO already 
has a Commission-approved cluster study process.
---------------------------------------------------------------------------

    \609\ APS Initial Comments at 9; MISO Initial Comments at 37.
    \610\ APS Initial Comments at 9.
    \611\ MISO Initial Comments at 38.
    \612\ Id. (submitting MISO's tariff as an example).
---------------------------------------------------------------------------

    257. Ameren contends that if the Commission retains the proposal to 
require the posting of the time from when the transmission provider 
received a valid interconnection request to the completion of the 
cluster study, cluster restudy, and facilities study, it should clarify 
that in the context of an RTO/ISO, ``complete'' refers to the final 
sign-off by the RTO/ISO.\613\ Ameren asserts that transmission owners 
within an RTO/ISO may act on behalf of the RTO/ISO transmission 
provider for purposes of certain studies; however, it is the RTO/ISO 
and not the transmission owner that decides when a study is complete.
---------------------------------------------------------------------------

    \613\ Ameren Initial Comments at 10-11.
---------------------------------------------------------------------------

    258. In section 6.4 of the pro forma LGIP, regarding the proposed 
requirement that ``[t]hese metrics must be updated within 30 days after 
the completion of each Cluster Study and Cluster Re-study period[,]'' 
Enel recommends that the word ``period'' should be deleted. Enel argues 
that the trigger should be the completion of the studies 
themselves.\614\
---------------------------------------------------------------------------

    \614\ Enel Initial Comments at 83.
---------------------------------------------------------------------------

iii. Commission Determination
    259. We adopt the proposed revisions to section 3.5.2 of the pro 
forma LGIP to require transmission providers to post metrics for 
cluster study processing time and cluster restudy processing time, 
including the number of cluster studies completed within 150 calendar 
days of the close of the customer engagement window. We modify section 
3.5.2.2 of the pro forma LGIP as proposed in the NOPR to be consistent 
with the new requirement adopted in section 7.5 of the pro forma LGIP 
that cluster restudies should be completed within 150 calendar days of 
the transmission provider notifying interconnection customers in the 
cluster and that a cluster restudy is required. The requirement to post 
these metrics replaces the existing requirement to post metrics for 
interconnection feasibility study processing time and system impact 
study processing time, which were relevant for the serial study process 
but are no longer relevant for the cluster study process required by 
this final rule. We therefore believe that these revisions are 
necessary to implement the change from a serial study process to the 
cluster study process.
    260. As for the point at which to begin measuring the metrics, 
several commenters argue against using the date on which the 
transmission provider received the interconnection requests. We clarify 
that sections 3.5.2.1 and 3.5.2.2 of the pro forma LGIP adopted in this 
final rule establish that these metrics must be measured from the close 
of the customer engagement window for the cluster study processing time 
metric and from when transmission provider notifies interconnection 
customers in the cluster that a cluster restudy is needed for the 
cluster restudy processing time metric. We find that these are 
appropriate start dates from which to calculate the metrics because 
they reflect when the respective studies are to actually commence.\615\ 
We decline to grant additional flexibility to maintain metrics and 
associated timelines for those metrics, as urged by MISO.\616\
---------------------------------------------------------------------------

    \615\ APS Initial Comments at 9; MISO Initial Comments at 37-38.
    \616\ MISO Initial Comments at 38.
---------------------------------------------------------------------------

    261. Regarding Clean Energy Associations' suggestion that the 
metrics also identify the level of accuracy of studies relative to 
final costs,\617\ we decline to adopt this suggestion. For one, it is 
unclear to what final costs Clean Energy Associations is referring to. 
Additionally, the metrics that we require transmission providers to 
post as part of this final rule focus on the timing of interconnection 
studies and not on the accuracy of cost estimates. The metrics are 
intended, as described in Order No. 845, to provide needed transparency 
``to allow interconnection customers to develop informed expectations 
about how long the

[[Page 61057]]

interconnection study portion of the process actually takes.'' \618\
---------------------------------------------------------------------------

    \617\ Clean Energy Associations Initial Comments at 21.
    \618\ Order No. 845, 163 FERC ] 61,043 at P 307.
---------------------------------------------------------------------------

    262. We decline to adopt Ameren's suggestion to base the 150-
calendar day cluster study deadline on the RTO/ISO's completion of the 
cluster study rather than the transmission owner's completion because 
the deadlines are applicable to the transmission provider and such a 
clarification is unnecessary to be added to the pro forma LGIP.
    263. We agree with Enel's suggestion to modify proposed pro forma 
LGIP section 6.4--now pro forma LGIP section 6.1--by deleting 
``period'' because, as Enel explains, this would more concisely convey 
that the metrics should be updated following the completion of the 
studies themselves.\619\
---------------------------------------------------------------------------

    \619\ Enel Initial Comments at 83.
---------------------------------------------------------------------------

g. Interconnection Request Evaluation Process
i. NOPR Proposal
    264. In the NOPR, the Commission proposed several changes to pro 
forma LGIP section 4, renamed ``interconnection request evaluation 
process'' from ``queue position.'' First, the Commission proposed to 
rename and revise section 4.1 of the pro forma LGIP as ``queue 
position'' and added two new proposed sections: (1) section 4.1.1 
(Assignment of Queue Position), which provides that queue position will 
be based on the time and date that the transmission provider receives 
all items required under section 3.4 (Valid Interconnection Request) 
and that there is no queue priority for interconnection customers that 
opted for informational interconnection studies; and (2) section 4.1.2 
(Higher Queue Position), which provides that all interconnection 
requests studied in a single cluster shall be considered to have equal 
queue priority, but clusters initiated earlier in time shall be 
considered to have a higher queue position than clusters initiated 
later in time.\620\
---------------------------------------------------------------------------

    \620\ NOPR, 179 FERC ] 61,194 at P 70.
---------------------------------------------------------------------------

    265. The Commission also proposed to remove from section 4.2 of the 
pro forma LGIP the provisions allowing transmission providers to study 
interconnection requests serially and the requirement for transmission 
providers to provide 180 calendar days' advance notice before opening a 
cluster window.\621\ The Commission also proposed to rename section 4.2 
of the pro forma LGIP ``general study process,'' and revise it to 
require transmission providers to perform interconnection studies 
within the cluster study process.
---------------------------------------------------------------------------

    \621\ Id. P 72.
---------------------------------------------------------------------------

    266. In the NOPR, the Commission also proposed changes to the 
material modification provisions in section 4.4 (Modification) of the 
pro forma LGIP to provide that moving a point of interconnection shall 
result in a loss of interconnection queue position if it is deemed a 
material modification by the transmission provider. Additionally, 
proposed additions to pro forma LGIP section 4.4 require that any 
identified changes to a planned interconnection, proposed by an 
interconnection customer or the transmission provider, must be 
acceptable to any impacted interconnection customer in the same 
cluster, and such acceptance is not to be unreasonably withheld.\622\ 
The Commission noted that the interconnection customer may decide to 
forego the requested change that constitutes a material modification 
and retain its existing queue position.\623\
---------------------------------------------------------------------------

    \622\ Proposed pro forma LGIP section 4.4.
    \623\ NOPR, 179 FERC ] 61,194 at P 71.
---------------------------------------------------------------------------

    267. Further, the Commission proposed to revise section 4.4.1 of 
the pro forma LGIP to make clear that: (1) the modifications previously 
permitted prior to return of the executed system impact study agreement 
are now permitted to be made prior to return of the executed cluster 
study agreement; and (2) for generating plant increases, the 
incremental increase will be studied with the next cluster study for 
purposes of cost allocation and study analysis.\624\ Pro forma LGIP 
section 4.4.1 also explicitly permits specific modifications prior to 
the interconnection customer's return of the executed cluster study 
agreement to the transmission provider, including: (a) a decrease of up 
to 60 percent of electrical output (MW) of the proposed project, 
through either a decrease in plant size or a decrease in 
interconnection service level; (b) modifying the technical parameters 
associated with the generating facility technology or step up 
transformer; and (c) modifying the interconnection configuration.
---------------------------------------------------------------------------

    \624\ Id. P 73.
---------------------------------------------------------------------------

ii. Comments
    268. With regards to the proposed changes to section 4.1 (Queue 
Position), Tri-State questions whether the proposed definition of queue 
position includes surplus interconnection requests.\625\ Xcel argues, 
and EEI agrees, that the Commission should modify the proposal to 
clarify that queue position or queue priority is based on 
interconnection request readiness and not on the date and time the 
interconnection request is submitted.\626\
---------------------------------------------------------------------------

    \625\ Tri-State Initial Comments at 25.
    \626\ EEI Reply Comments at 5; Xcel Initial Comments at 9 n.12.
---------------------------------------------------------------------------

    269. CAISO asserts that it is unclear what losing a queue position 
means in a cluster-based study (e.g., being withdrawn from the 
interconnection queue or moving to a lower interconnection queue 
position), but also contends that no specification or reform is 
necessary because interconnection customers will simply withdraw the 
modification every time if it is found to be material.\627\ CAISO 
argues that the Commission should either remove the ``option'' to lose 
an interconnection queue position when a proposed modification is found 
to be material, or clarify what replaces the interconnection queue 
position when it is lost.
---------------------------------------------------------------------------

    \627\ CAISO Initial Comments at 11-12.
---------------------------------------------------------------------------

    270. Clean Energy States argue that, in addition to the ``signs of 
commercial progress'' proposed by the Commission, clusters should be 
prioritized for study based on a number of other transparent and 
quantifiable factors, such as alignment with state policy (e.g., 
participation in procurement actions), and benefits to low-income, 
environmentally impacted, and ``energy communities'' as defined under 
the Inflation Reduction Act, state policies, and the Justice40 
Initiative.\628\ Clean Energy States assert that clusters could further 
be prioritized for development by how well the combined cluster meets 
transmission system needs, with preference for interconnection 
agreements given to those that result in the lowest cost upgrades, have 
the most attractive operational profile, or deliver the best 
reliability improvements.
---------------------------------------------------------------------------

    \628\ Clean Energy States Initial Comments at 8.
---------------------------------------------------------------------------

    271. Regarding the proposed changes to pro forma LGIP section 4.4 
(Modifications), Enel argues that the Commission should remove the 
proposed language requiring the acceptance of ``any impacted 
Interconnection Customer in the same Cluster'' to modify an 
interconnection request.\629\ Enel asserts that this requirement not 
only will be challenging to facilitate (especially in large clusters) 
but is also a redundant and unnecessary hurdle that could result in 
anticompetitive behavior. If the Commission keeps this language, to 
avoid uncertainty regarding the application of this provision, Enel 
proposes to replace this language with ``any Interconnection Customer 
in the same Cluster whose interconnection would be delayed or whose

[[Page 61058]]

interconnection-related costs would be increased as a result of the 
identified changes.'' \630\
---------------------------------------------------------------------------

    \629\ Enel Initial Comments at 19-20.
    \630\ Id. at 83.
---------------------------------------------------------------------------

    272. A few commenters argue that the Commission should consider 
changes to the material modification process such that only certain 
modifications trigger a restudy.\631\ Clean Energy Associations 
recommend that the Commission modify the current material modification 
definition to clearly state that certain changes are presumptively 
immaterial, such as changing solar modules or turbines, adding storage 
capacity, or making minor adjustments to inverter performance. Clean 
Energy Associations argue that this presumption should be in place so 
long as planned export and import capacity remains the same.\632\ Clean 
Energy Associations also support the concept of expedited, limited 
studies for project modifications, provided that: (1) an expedited 
approach does not change the level of interconnection service; (2) 
there is no impact on cost or timing of an interconnection request that 
is lower- or equally queued; and (3) it does not cause any reliability 
concern. Additionally, Pattern Energy asserts that, in its experience, 
transmission providers apply widely disparate standards where even de 
minimis impacts--timing or financial--can be determined to be material, 
which Pattern Energy believes is unreasonable and unduly discriminatory 
in light of the dynamic nature of the generator interconnection 
processes.\633\ Pattern Energy argues that, absent severe delay, timing 
delay should not be factored into materiality. Pattern Energy suggests 
instead that materiality be tied to financial impact on a proposed 
generating facility (or group of proposed generating facilities).
---------------------------------------------------------------------------

    \631\ AEP Initial Comments at 18; Clean Energy Associations 
Initial Comments at 42; Pattern Energy Initial Comments at 17; PPL 
Initial Comments at 11.
    \632\ Clean Energy Associations Initial Comments at 42.
    \633\ Pattern Energy Initial Comments at 16-17.
---------------------------------------------------------------------------

    273. With regard to modifications under proposed pro forma LGIP 
section 4.4.1, MISO supports the proposed revisions to avoid proposed 
project service level increasing \634\ and other changes disrupting 
cluster studies that are in progress or delaying the negotiation and 
execution timelines for the LGIA.\635\
---------------------------------------------------------------------------

    \634\ We understand MISO to be referring to the NOPR proposal 
that clarified that for plant increases, the incremental increase 
will be studied with the next cluster study for purposes of cost 
allocation and study analysis.
    \635\ MISO Initial Comments at 39.
---------------------------------------------------------------------------

    274. Enel recommends that the Commission modify the proposed pro 
forma LGIP section 4.4.1 language to give interconnection customers 
flexibility in the initial stages of interconnection studies, 
otherwise, it argues that, interconnection customers are more likely to 
work around the rules by submitting multiple smaller interconnection 
requests to retain size flexibility after seeing their initial results, 
which is more administratively burdensome for transmission providers 
and leads to its own form of inefficiency as size reductions come in 
the form of withdrawals at any point in the process rather than being 
limited to partial reductions prior to entering the cluster 
restudy.\636\
---------------------------------------------------------------------------

    \636\ Enel Initial Comments at 16-17 (proposing the section be 
revised to read: ``Prior to the deadline to return the milestones 
listed in Section 7.5 of this LGIP to proceed into the initial 
Cluster Re-study, modifications permitted. . . .'').
---------------------------------------------------------------------------

    275. CREA and NewSun argue that the Commission should explicitly 
permit interconnection customers to modify their interconnection 
requests to reduce or eliminate the assignment of network upgrade or 
stand alone network upgrade costs associated with a proposed generating 
facility after receipt of the first cluster-level interconnection 
study.\637\ CREA and NewSun argue that interconnection customers should 
be permitted to modify their proposed generating facilities to avoid 
impacts on the transmission system that trigger network upgrades by, 
for example, reducing their capacity or installing devices that will 
limit their output during critical periods.\638\ CREA and NewSun state 
that the existing pro forma LGIP allows an interconnection customer to 
downsize its interconnection capacity up to 60% upon receipt of the 
first interconnection study (i.e., the feasibility study) and before 
progressing to the second study (i.e., the system impact study).\639\ 
CREA and NewSun state that, in contrast, the NOPR proposes to only 
allow downsizing to occur before receipt of the first cluster system 
impact study and, as a result, the opportunity to downsize the 
interconnection request to tailor the facility to the available 
capacity identified in the first useful interconnection study would be 
lost. Therefore, CREA and NewSun argue that the Commission should 
revise the NOPR proposal to ensure that a reasonable amount of 
downsizing (e.g., 60%) is permitted after receipt of the first cluster-
level interconnection study.\640\
---------------------------------------------------------------------------

    \637\ CREA and NewSun Initial Comments at 45-47.
    \638\ Id. at 46.
    \639\ Id. (citing NOPR, 179 FERC ] 61,194 at app. B (proposed 
pro forma LGIP section 4.4.1)).
    \640\ Id. at 47.
---------------------------------------------------------------------------

iii. Commission Determination
    276. We adopt the proposed revisions to pro forma LGIP section 4.1 
(Queue Position), section 4.2 (General Study Process), and section 
4.4.1, and we modify the proposed definition of queue position and the 
proposed revisions to the material modification provisions in section 
4.4 (Modification). These are discussed below.
    277. First, we adopt the proposed revisions to section 4.1 of the 
pro forma LGIP (Queue Position), which reflect the impact of the 
adoption of the proposed cluster study process in this final rule on 
queue position assignments. These revisions provide that transmission 
providers must assign queue positions based on the date and time of 
receipt of a valid interconnection request, but all interconnection 
customers that submit interconnection requests within a cluster request 
window must be considered equally queued. Clusters initiated earlier in 
time must have a higher queue position than clusters initiated later in 
time. Under the existing serial study process in the pro forma LGIP, 
queue position had a greater effect on an interconnection customer, for 
instance, in the allocation of network upgrade costs. By contrast, 
network upgrade costs within a cluster will not be allocated by queue 
position; rather, as discussed below, network upgrade costs within a 
cluster must be allocated generally through a proportional impact 
method among the interconnection customers in the cluster. Given the 
nature of the cluster study process, including the nature of the cost 
allocation for network upgrades, it is appropriate for all 
interconnection customers in a cluster to be considered equally queued.
    278. Second, we adopt the proposal to remove from section 4.2 of 
the pro forma LGIP the provisions allowing transmission providers to 
study interconnection requests serially and the requirement for 
transmission providers to provide 180 days' advance notice before 
opening a cluster window. We also adopt the proposal to rename section 
4.2 of the pro forma LGIP ``General Study Process'' and revise it to 
require transmission providers to perform interconnection studies 
within the cluster study process. These revisions are necessary to 
implement the cluster study process required by this final rule.
    279. As requested by Tri-State, we clarify that the definition of 
queue

[[Page 61059]]

position is not relevant to surplus interconnection requests, which are 
processed outside of the normal interconnection queue, as further 
discussed in section III.A.2.n below.
    280. We also maintain the language in the pro forma LGIP that 
moving a point of interconnection in a way that is deemed a material 
modification will impact an interconnection customer's queue position, 
but we clarify the meaning of this in the context of the cluster study 
process. Specifically, if moving a point of interconnection is deemed 
by the transmission provider to be a material modification to the 
interconnection request, and the interconnection customer chooses to 
proceed with the proposed modification, the interconnection request 
will be deemed withdrawn and the interconnection customer must re-enter 
the interconnection queue with a new interconnection request, if it 
desires to proceed to interconnect. To avoid being deemed withdrawn, 
the interconnection customer may choose not to move its point of 
interconnection and to instead remain in the same cluster with the 
original interconnection request, and, thus, in the same queue 
position.
    281. In response to CREA and NewSun, we do not opine on whether 
moving a point of interconnection within a cluster will be a material 
modification. Instead, we leave the determination as to whether it is 
deemed a material modification to the transmission provider, as in the 
existing process for determining whether a proposed modification is 
material.
    282. We decline to adopt Clean Energy States' suggestion that, in 
addition to the ``signs of commercial progress'' proposed by the 
Commission, clusters should be prioritized for study based on other 
transparent and quantifiable factors.\641\ Clean Energy States neither 
provides sufficient rationale or detail regarding such factors by which 
clusters would be prioritized by transmission providers, nor explains 
how such prioritization criteria would be determined. We note that the 
Commission did not propose alternative factors for consideration. 
Additionally, we note that the record lacks adequate discussion in 
favor of such prioritization mechanisms or such ``factors'' for the 
Commission to consider adopting in this final rule.
---------------------------------------------------------------------------

    \641\ Clean Energy States Initial Comments at 8.
---------------------------------------------------------------------------

    283. Third, we modify the proposed definition of queue position in 
the pro forma LGIP and LGIA to provide that queue position is 
established pursuant to section 4.1 of the pro forma LGIP. Fourth, we 
modify the proposed revisions to the material modification provisions 
in section 4.4 (Modification) of the pro forma LGIP. We adopt the 
language that provides that moving a point of interconnection shall 
result in a loss of queue position if it is deemed a material 
modification by the transmission provider, for the reasons discussed 
above. At the same time, we modify the proposed revisions to remove the 
requirement to obtain the approval of ``any impacted Interconnection 
Customer in the same Cluster.'' \642\ We are persuaded by Enel's 
argument that this proposed language in pro forma LGIP section 4.4 
should be struck for two reasons. First, we find this language 
unnecessary because the point of interconnection could be changed only 
if the transmission provider had deemed it to not be a material 
modification to the interconnection request. Through this requirement, 
the transmission provider's analysis ensures that the change will not 
have a material impact on the cost or timing of another interconnection 
request in the cluster. Second, although the proposal included the 
language ``such acceptance not to be unreasonably withheld,'' we are 
still concerned about the potential for anticompetitive behavior to the 
extent that other interconnection customers in the cluster could refuse 
to accept the point of interconnection change to limit competition. The 
interconnection customers within a cluster will be competitors in the 
wholesale markets in many, if not all, respects. To ensure competitive 
market outcomes, they should not be provided an undue opportunity to 
affect the advancement or the costs for a proposed generating facility 
of one of their competitors.
---------------------------------------------------------------------------

    \642\ Proposed pro forma LGIP section 4.4.
---------------------------------------------------------------------------

    284. A number of commenters argue that the Commission should 
consider changes to the material modification process such that only 
certain modifications trigger a restudy.\643\ We decline to adopt any 
of the suggested revisions to the material modification provisions and 
restudy triggers in the pro forma LGIP. We did not propose changes 
suggested by commenters and do not find the need to adopt such changes 
to the material modification provisions to ensure just and reasonable 
rates. We believe that the list of permitted modifications in section 
4.4 of the pro forma LGIP is appropriate because they allow 
interconnection customers a degree of flexibility with respect to 
generating facility size, interconnection service level, and specific 
generating facility technology that appropriately balances the high 
burden to enter the interconnection queue and the lengthy duration of 
the interconnection queue, during which external factors may change, 
including the introduction of new technology that interconnection 
customers may wish to incorporate into their generating facility 
design.
---------------------------------------------------------------------------

    \643\ AEP Initial Comments at 18; Clean Energy Associations 
Initial Comments at 42; Pattern Energy Initial Comments at 17; PPL 
Initial Comments at 11.
---------------------------------------------------------------------------

    285. Finally, we adopt the proposed revisions to section 4.4.1 of 
the pro forma LGIP to make clear that: (1) the modifications previously 
permitted prior to the return of the executed system impact study 
agreement are now permitted to be made prior to return of the executed 
cluster study agreement; and (2) for plant increases, the incremental 
increase will be studied with the next cluster study for purposes of 
cost allocation and study analysis. We believe that these revisions are 
needed to implement the cluster study process adopted to ensure that 
interconnection customers are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner. 
Notably, we believe that prior to the return of the executed cluster 
study agreement is the appropriate time to permit the modifications 
previously permitted prior to the return of the executed system impact 
study agreement because these represent approximately the same point of 
the interconnection process in a serial study process versus a cluster 
study process. For plant increases, we find that it is appropriate to 
exclude increases to proposed generating facility size from the cluster 
study that is ongoing as any increase to size may create the need for 
restudies. By moving the increase to the subsequent cluster, the 
interconnection customer can still pursue its requested addition, 
albeit on a delayed schedule.
    286. We decline to adopt Enel's alternative proposed language that 
would allow the same modifications permitted to be made prior to the 
executed cluster study agreement to also be permitted before a cluster 
restudy. This would not only represent a significant change from the 
existing modification language in pro forma LGIP section 4.4.1, but 
allowing such modifications at the cluster restudy stage could 
negatively affect the integrity of the cluster and cause further 
restudies, which would not ensure that interconnection customers are 
able to interconnect to the transmission system in a reliable, 
efficient, transparent, and timely manner.

[[Page 61060]]

    287. We also decline to adopt the revisions suggested by CREA and 
NewSun that would explicitly permit interconnection customers to modify 
their interconnection requests to reduce or eliminate the assignment of 
network upgrade or stand alone network upgrade costs associated with a 
proposed generating facility after receipt of the first cluster-level 
interconnection study. The ``loss'' of the opportunity for 
interconnection customers to downsize the interconnection request to 
tailor the facility to the available capacity identified in the first 
useful interconnection study \644\ reflects the nature of moving from a 
serial study process, with an initial, high-level feasibility study, to 
a cluster study process, with the benefit of a customer engagement 
window, potential for shared cost allocation, and lower likelihood of 
cascading restudies. Moreover, providing interconnection customers an 
opportunity to reduce the size of their proposed generating facilities 
after the cluster study would undercut the increased certainty and 
efficiency that are key benefits of the shift to a cluster study 
process. With the adoption of clusters, a reduction in size that may 
eliminate one interconnection customer's cost responsibility for a 
network upgrade could affect other interconnection customers in the 
cluster, either by increasing their costs or requiring a different 
network upgrade. This type of uncertainty could lead to further 
reductions, withdrawals, and restudies, and would be insufficient to 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner. We note, however, that interconnection customers may request a 
material modification assessment under section 4.4 of the pro forma 
LGIP for reductions and that if those reductions are found to not be 
material, the interconnection customer may proceed with them without a 
loss of queue position.
---------------------------------------------------------------------------

    \644\ CREA and NewSun Initial Comments at 46.
---------------------------------------------------------------------------

h. Fewer Than Three Year Extension to Commercial Operation Date
i. NOPR Proposal
    288. Currently, if an interconnection customer's generating 
facility is delayed by fewer than three years, the pro forma LGIP 
states that such extensions are not material and shall be handled 
through construction sequencing. However, the pro forma LGIP does not 
state the starting point for this fewer than three-year period. In the 
NOPR, the Commission proposed to revise section 4.4.5 of the pro forma 
LGIP, which currently allows an extension of less than three cumulative 
years of the generating facility's commercial operation date, to 
require that the commercial operation date reflected in the initial 
interconnection request be used in calculating the permissible fewer 
than three-year extension.\645\
---------------------------------------------------------------------------

    \645\ NOPR, 179 FERC ] 61,194 at P 71.
---------------------------------------------------------------------------

ii. Comments
    289. Several commenters contend that the commercial operation dates 
set out in the executed LGIA, rather than the date in the initial 
interconnection request, are generally more accurate \646\ and provide 
more certainty when established at the end of the interconnection study 
process as they would include the schedule estimates for network 
upgrades,\647\ and the interconnection customer may have greater 
control over pursuing its development timeline.\648\
---------------------------------------------------------------------------

    \646\ Invenergy Initial Comments at 34; [Oslash]rsted Initial 
Comments at 8; Pine Gate Initial Comments at 65.
    \647\ [Oslash]rsted Initial Comments at 8.
    \648\ Invenergy Initial Comments at 34.
---------------------------------------------------------------------------

    290. Invenergy argues that, because assigned upgrades necessary for 
interconnection can require more than three years for construction, it 
would be reasonable to permit a greater extension right of five years 
from the date set out in the LGIA.\649\ Enel also argues that the 
Commission should grant a longer extension of time if the transmission 
provider's studies are delayed or if more time is required to build 
network upgrades because these circumstances are beyond the 
interconnection customer's control.\650\ Enel also recommends requiring 
the transmission provider to grant a day-for-day delay to the 
originally requested commercial operation date for any delays in the 
study process relative to the LGIP deadlines as well as due 
consideration for network upgrades that require more than 18 months to 
design, procure, and construct.
---------------------------------------------------------------------------

    \649\ Id.
    \650\ Enel Initial Comments at 18-19.
---------------------------------------------------------------------------

    291. Ameren and PPL assert that continuing to provide a three-year 
extension of the commercial operation date would allow projects to move 
forward when they are not ready or viable.\651\ APS believes that 
limiting the ability to suspend interconnection requests or extend the 
commercial operation date to instances of force majeure, including 
where a customer demonstrates specific timeline obstructions such as 
permit issuance or supply chain delays, is more in line with the 
proposals in the NOPR.\652\
---------------------------------------------------------------------------

    \651\ Ameren Initial Comments at 10; PPL Initial Comments at 11.
    \652\ APS Initial Comments at 7-8 (citing Midcontinent Indep. 
Transmission Sys. Operator, Inc., 120 FERC ] 61,293, at PP 23, 27 
(2007)).
---------------------------------------------------------------------------

    292. NV Energy seeks clarification on how long an interconnection 
customer may extend its commercial operation date because the pro forma 
LGIP allows seven to 10 years from the initial interconnection request 
to construct.\653\ NV Energy requests clarification on how the three-
year suspension clause in the pro forma LGIA plays into the timeline 
for the commercial operation date. Pine Gate argues that any extension 
period from the commercial operation date be subject to the overall 
seven-year time period for achieving commercial operation.\654\ 
Invenergy argues that the Commission should also make clear that the 
limits on the initial proposed in-service date that can be specified in 
an interconnection request to no more than seven years beyond the 
interconnection request date, does not limit the ability to take 
advantage of commercial operation date extensions that are otherwise 
provided under the pro forma LGIP or an LGIA.\655\ For example, some 
transmission owners have taken the position that, when exercising a 
suspension right, if the suspension would result in an in-service date 
greater than seven years after the date specified in the 
interconnection request, the interconnection customer cannot use its 
full suspension period. Invenergy asserts that the Commission has 
already clarified that the interconnection request limitation on 
proposed in-service dates is applicable only for the purpose of 
limiting the date requested at the application stage, and does not 
limit in-service dates that extend beyond that period as a result of 
other factors, which would include transmission owner delay, exercise 
of suspension, and here, additional commercial operation date 
extensions.\656\ Invenergy also states that the Commission should 
clarify that its revisions to pro forma LGIP section

[[Page 61061]]

4.4.5 are in addition to, and do not limit, an interconnection 
customer's suspension rights under its interconnection agreement.\657\
---------------------------------------------------------------------------

    \653\ NV Energy Initial Comments at 5-6. NV Energy states that 
it currently has several customers that requested to move well 
beyond the three-year time frame and that most of its 
interconnection customers use the full seven to 10-year window. Id. 
at 6.
    \654\ Pine Gate Initial Comments at 65. Pine Gate also 
reiterates its comments on the ANOPR, stating that the Commission 
should expand the interconnection customer's option to build. Id. at 
63 (citing Comments of Pine Gate, Docket No. RM21-17-000, at 9-10 
(filed Oct. 12, 2021) (citing Order No. 2003, 104 FERC ] 61,103 at 
PP 85, 353)).
    \655\ Invenergy Initial Comments at 35 (citing pro forma LGIP 
section 3.4.1 and pro forma LGIA art. 5.16).
    \656\ Id. (citing Midcontinent Indep. Sys. Operator, Inc., 150 
FERC ] 61,180, at P 23 (2015)).
    \657\ Id. at 34.
---------------------------------------------------------------------------

iii. Commission Determination
    293. We adopt the proposed revisions to section 4.4.5 of the pro 
forma LGIP that require that interconnection customers receive an 
extension of fewer than three cumulative years of the generating 
facility's commercial operation date without requiring them to request 
such an extension from the transmission provider. In response to 
commenters' concerns, however, we modify our proposal to clarify that 
the commercial operation date reflected in the initial interconnection 
request shall be used in calculating the permissible fewer than three-
year extension until the interconnection customer executes, or requests 
the unexecuted filing of, an LGIA. Once the interconnection customer 
has executed an LGIA or requested that the LGIA be filed unexecuted, 
the commercial operation date established in the LGIA shall be the date 
from which the up to three cumulative years is calculated.
    294. At the time the pro forma LGIP was adopted, the 
interconnection process was considerably shorter than it is now; the 
delays and sizeable interconnection queues facing transmission 
providers create a situation where many interconnection customers use 
this up to three-year period to ensure that their proposed generating 
facilities reach commercial operation. Furthermore, the length of the 
interconnection queues is such that at the time an interconnection 
customer enters the queue, it may have little idea of how long it will 
spend in the interconnection queue before commencement of the 
construction of its generating facility and required interconnection 
facilities and network upgrades. Thus, we agree with Invenergy, 
[Oslash]rsted, and Pine Gate, and we modify our proposal to require the 
up to three-year period to commence from the commercial operation date 
established in the interconnection customer's LGIA once the LGIA is 
executed or the interconnection customer has requested that it be filed 
unexecuted with the Commission.
    295. We decline commenters' requests to revise the actual length of 
the permissible extension of a proposed generating facility's 
commercial operation date. The Commission did not propose to change the 
length of the permissible extension in the NOPR, and we lack an 
adequate record that the existing up to three-year extension is unjust 
and unreasonable.
    296. Commenters request clarification \658\ of how the changes to 
pro forma LGIP section 4.4.5 adopted in this final rule affect other 
provisions such as pro forma LGIP section 3.4.2 and pro forma LGIA 
article 5.16, which provide for extensions of the in-service date or 
suspension of construction.\659\ We reiterate that the revisions to 
section 4.4.5 of the pro forma LGIP adopted in this final rule 
establish only the starting point for the less than three-year 
extension to the commercial operation date. The Commission did not 
propose in the NOPR, and we do not adopt in this final rule, changes to 
the extension of in-service date provisions in pro forma LGIP section 
3.4.2, or to the suspension provision in pro forma LGIA article 5.16.
---------------------------------------------------------------------------

    \658\ Invenergy Initial Comments at 35; NV Energy Initial 
Comments at 5-6.
    \659\ Specifically, pro forma LGIP section 3.4.2 (previously pro 
forma LGIP section 3.4.1) provides that the expected in-service date 
of the new generating facility or increase in capacity of the 
existing generating facility shall not exceed seven years, but may 
be extended up to 10 years upon mutual agreement of the transmission 
provider and interconnection customer. Pro forma LGIA article 5.16 
provides the interconnection customer the right to suspend work by 
the transmission provider associated with the construction and 
installation of transmission provider's interconnection facilities 
and/or network upgrades for up to three years, at which time the 
LGIA would be deemed terminated.
---------------------------------------------------------------------------

i. Cluster Study Provisions (Pro Forma LGIP Sections 6, 7)
i. NOPR Proposal
    297. As part of the proposed revisions to the pro forma LGIP, the 
NOPR proposed to replace section 6 (Interconnection Feasibility Study) 
with the new requirements to publicly post interconnection information, 
i.e., the ``heatmap'' as discussed above in section III.A.1.c, thereby 
removing the entirety of the feasibility study from the pro forma 
LGIP.\660\ Furthermore, in the NOPR, the Commission proposed to rename 
pro forma LGIP section 7 from ``interconnection system impact study'' 
to ``cluster study.'' \661\ The Commission proposed revisions to pro 
forma LGIP section 7.1 (Cluster Study Agreement) to state that the 
transmission provider must tender to each interconnection customer that 
submitted a valid interconnection request a cluster study agreement no 
later than five business days after the close of the cluster request 
window.\662\ The Commission proposed revisions to pro forma LGIP 
section 7.2 (Execution of Cluster Study Agreement) to state that if the 
interconnection customer does not provide technical data when it 
delivers the cluster study agreement, the transmission provider must 
notify the interconnection customer of the deficiency within five 
business days, and the interconnection customer must cure the 
deficiency within 10 business days of receipt of the notice.\663\ The 
Commission proposed revisions to pro forma LGIP section 7.3 (Scope of 
Cluster Study Agreement) to make clear that the stability analysis, 
power flow analysis, and short circuit analysis previously conducted 
under the feasibility and system impact studies would be conducted on a 
clustered basis.\664\ The Commission also proposed changes to pro forma 
LGIP section 7.3 to make clear that, for purposes of determining 
necessary interconnection facilities and network upgrades, the cluster 
study shall use the level of interconnection service requested by 
interconnection customers in the cluster, except where the transmission 
provider otherwise determines that it must study the full generating 
facility capacity due to safety or reliability concerns. The Commission 
proposed revisions to pro forma LGIP section 7.4 (Cluster Study 
Procedures) to state that, within 10 business days of simultaneously 
furnishing a cluster study report and a draft facilities study 
agreement to each interconnection customer within the cluster and 
posting such report on OASIS, the transmission provider shall convene 
an open meeting to discuss the study results and shall, upon request, 
make itself available to meet with individual interconnection customers 
after the report is provided.\665\ Pro forma LGIP section 7.4 also 
states that the transmission provider must complete the cluster study 
within 150 calendar days. The Commission proposed revisions to pro 
forma LGIP section 7.5 (Cluster Study Restudies) to state that the 
interconnection customer must provide, within 20 calendar days after 
the cluster study report meeting, a study deposit, demonstration of 
site control, and a commercial readiness demonstration. Pro forma LGIP 
section 7.5 also states that the transmission provider must complete 
the cluster restudy within 150 calendar days and delineates the steps 
the transmission provider must take when a restudy is required or not 
required.\666\
---------------------------------------------------------------------------

    \660\ Proposed pro forma LGIP section 6.
    \661\ NOPR, 179 FERC ] 61,194 at P 74.
    \662\ Proposed pro forma LGIP section 7.1.
    \663\ Id. at section 7.2.
    \664\ Id. at section 7.3.
    \665\ Id. at section 7.4.
    \666\ Id. at section 7.5.

---------------------------------------------------------------------------

[[Page 61062]]

ii. Comments
    298. MISO supports the deletion of section 6 of the pro forma LGIP 
and the removal of the feasibility study from the pro forma LGIP.\667\
---------------------------------------------------------------------------

    \667\ MISO Initial Comments at 40.
---------------------------------------------------------------------------

    299. In reference to the proposed revisions to section 7.1 (Cluster 
Study Agreement) of the pro forma LGIP, Tri-State stresses that five 
business days is a tight time frame to tender a valid cluster study 
agreement to each interconnection customer that submitted a valid 
interconnection request and argues that this timeline is not feasible 
for transmission providers with greater than 50 interconnection 
requests submitted in a cluster request window.\668\
---------------------------------------------------------------------------

    \668\ Tri-State Initial Comments at 31.
---------------------------------------------------------------------------

    300. In reference to the proposed revisions to section 7.2 of the 
pro forma LGIP, Tri-State asserts that the Commission needs to confirm 
or reiterate that the interconnection request is considered withdrawn 
if the interconnection customer does not cure a deficiency identified 
by the transmission provider.\669\
---------------------------------------------------------------------------

    \669\ Id.
---------------------------------------------------------------------------

    301. In reference to the proposed revisions to section 7.3 (Scope 
of Cluster Study) of the pro forma LGIP, Tri-State asks the Commission 
to add language to address situations with studies pending completion 
of higher-queued project cluster studies.\670\
---------------------------------------------------------------------------

    \670\ Id.
---------------------------------------------------------------------------

    302. Enel proposes an alternative method for performing the cluster 
study and restudy to the NOPR proposal.\671\ Enel states that if the 
Commission wants to retain the full scope of analyses in the cluster 
study, the Commission could require draft power flow analyses to be 
provided to interconnection customers part way through the cluster 
study. Enel explains that interconnection customers could be granted 
the right to reduce interconnection service amounts and make other 
changes pursuant to pro forma LGIP section 4.4.1 following receipt of 
these results. Enel states that the transmission provider would repeat 
the power flow analyses until the queue stabilized, with the motivation 
for interconnection customers to make changes in a timely way being 
driven by knowledge that once the latter portion of the studies 
started, the interconnection customer would lose this flexibility.
---------------------------------------------------------------------------

    \671\ Enel Initial Comments at 17.
---------------------------------------------------------------------------

    303. In the list of requirements to proceed to the cluster restudy 
in proposed revisions to section 7.5 of the pro forma LGIP, Enel 
proposes to add ``(d) election of project changes as permitted by LGIP 
section 4.4.1.'' \672\
---------------------------------------------------------------------------

    \672\ Id.
---------------------------------------------------------------------------

    304. In the proposed revisions to section 7.5 of the pro forma 
LGIP, Enel suggests removing item (2), which states that if there are 
no changes to the composition of the cluster, a cluster restudy is not 
required, because it claims that the cluster restudy would always be 
required, at least in part, to add short circuit and stability 
analyses.
    305. With regard to the 150-day cluster study deadline, some 
commenters generally support the proposed 150-day deadline to complete 
the cluster study.\673\ Enel recommends a reduction in the scope and 
schedule of the cluster study to only include power flow analysis and a 
short circuit ratio test (to test grid strength and flag potential 
inverter instability issues) and suggests that this initial cluster 
study be completed in 90 days instead of 150 days.\674\ Enel contends 
that, the availability of some information from this first study, 
interconnection customers retain more flexibility up to the point of 
committing to the initial cluster restudy, which allows interconnection 
customers to optimize the characteristics of their proposed generating 
facilities, most notably the amount of ERIS and NRIS interconnection 
service requested, in response to the results of the study. Enel argues 
that early flexibility for optimization of proposed generating 
facilities is better than forcing interconnection customers to withdraw 
and re-enter the interconnection queue, is less disruptive, and does 
not add a year of delay to an interconnection customer completing the 
interconnection process.
---------------------------------------------------------------------------

    \673\ AEE Initial Comments at 33; Clean Energy Associations 
Initial Comments at 20-21; Consumers Energy Initial Comments at 4.
    \674\ Enel Initial Comments at 15-16.
---------------------------------------------------------------------------

    306. A number of commenters argue that the proposed 150-day 
deadline to complete the initial cluster study may be, or is, too short 
and recommend a longer study window.\675\ A few commenters also argue 
that the study timelines are too short, given the proposal to eliminate 
the reasonable efforts standard and impose penalties on transmission 
providers that miss those deadlines.\676\ National Grid asserts that 
the proposed 150-day deadline may be ``unreasonably condensed'' and 
could result in a decline in the quality of the studies, which could 
lead to delays.\677\ Specifically, National Grid claims that rushing 
the issuance of the cluster study could lead to later amendments or 
corrections to certain engineering requirements or cost estimates, that 
in turn may lead to later-stage interconnection request withdrawals.
---------------------------------------------------------------------------

    \675\ APS Initial Comments at 8; AES Initial Comments at 9; ISO-
NE Initial Comments at 23; National Grid Initial Comments at 13-14; 
Tri-State Initial Comments at 10.
    \676\ Dominion Initial Comments at 18; Tri-State Initial 
Comments at 4.
    \677\ National Grid Initial Comments at 13-14.
---------------------------------------------------------------------------

    307. Tri-State notes that it currently implements a 270-day system 
impact study period, specifically 150 days for phase 1 (power flow, 
short circuit, reactive capability) and 120 days for phase 2 (short 
circuit, transient stability), and has yet to miss a study 
deadline.\678\ Tri-State argues that this time frame allows for a 
thorough study process, including coordination with neighboring systems 
and the correction of errors found in interconnection customers' 
modeling data.
---------------------------------------------------------------------------

    \678\ Tri-State Initial Comments at 10.
---------------------------------------------------------------------------

    308. AES contends that cluster study timelines should be tailored 
to the types of studies being completed at each stage of the respective 
cluster.\679\ For example, AES states that steady state analysis takes 
less time to complete than dynamic analysis, meaning that a longer time 
frame should be afforded for dynamic analysis in the cluster study 
process. Accordingly, AES recommends that the Commission adopt a 150-
day general study timeline for cluster studies and restudies (system 
impact study-steady state, and short-circuit analysis performed) and a 
200-day timeline for facilities studies (dynamic analysis performed).
---------------------------------------------------------------------------

    \679\ AES Initial Comments at 9.
---------------------------------------------------------------------------

    309. APS requests that the Commission extend the initial study time 
frame to 180 days to provide meaningful studies identifying feasible 
proposed generating facilities, explaining that the APS transmission 
system is situated in such a way that many interconnections are at 
jointly owned facilities that require reviews and sign-off from 
multiple owners, including non-jurisdictional entities.\680\ APS argues 
that 180 days is more prudent for initial studies, with the exception 
of specific criteria such as jointly owned facilities, Western 
Electricity Coordinating Council (WECC) rated paths, and federally 
owned and Tribal lands, for which studies take significantly longer 
despite good faith efforts.
---------------------------------------------------------------------------

    \680\ APS Initial Comments at 8-9.
---------------------------------------------------------------------------

    310. NYTOs and National Grid argue that the proposal is not clear 
on which specific steps would be included in the 150-day time frame for 
the initial cluster study and argue that certain additional special 
studies that a transmission

[[Page 61063]]

provider may need to perform should not be subject to a 150-day time 
frame.\681\ NYTOs state that it is unclear when the clock starts for 
the proposed 150-day cluster study deadline and how the scope of the 
work can be reasonably limited to comply with the 150-day 
deadline.\682\ NYTOs argue that transmission providers and transmission 
owners should be afforded the flexibility to provide clarifications and 
supporting details on compliance.
---------------------------------------------------------------------------

    \681\ National Grid Initial Comments at 15; NYTOs Initial 
Comments at 15.
    \682\ NYTOs Initial Comments at 15.
---------------------------------------------------------------------------

    311. Similarly, National Grid notes that certain RTO/ISO 
interconnection processes require special supplemental studies in 
addition to general system impact studies and that, while the NOPR 
recognizes that these studies may be required to ensure reliable 
interconnection of new generating facilities, it does not address 
whether such studies must be conducted within the proposed 150-day 
cluster study window or could be conducted outside of this window.\683\ 
National Grid argues that the time to complete such special studies 
should not be included in the NOPR's proposed 150-day cluster study 
window and that the final rule should allow regions to adjust their 
overall interconnection timelines to accommodate such region-specific 
studies and take into consideration the time required to develop system 
models. Finally, National Grid states that the NOPR does not address 
whether the 150-day cluster study window includes the time required to 
develop system models and base case data for the cluster study.
---------------------------------------------------------------------------

    \683\ National Grid Initial Comments at 15.
---------------------------------------------------------------------------

    312. Several commenters recommend that the Commission provide 
transmission providers with flexibility to specify study 
timelines.\684\
---------------------------------------------------------------------------

    \684\ AEP Initial Comments at 17-18; APPA-LPPC Initial Comments 
at 21; Avangrid Initial Comments at 13; Bonneville Initial Comments 
at 16; CAISO Initial Comments at 11; Dominion Initial Comments at 
16-17; Indicated PJM TOs Reply Comments at 39; ISO-NE Initial 
Comments at 35-37; NYISO Initial Comments at 29, 33; NY Commission 
and NYSERDA Initial Comments at 5; NYTOs Initial Comments at 14; 
SEIA Reply Comments at 6.
---------------------------------------------------------------------------

    313. Regarding the 150-day cluster restudy deadline, several 
commenters agree that the 150-day deadline is reasonable for a cluster 
restudy.\685\ Other commenters oppose the 150-day deadline. Bonneville 
argues that the proposed requirement to conduct a cluster restudy 
within 150 days is unworkable because the complexity of the cluster 
restudy would vary and directly impact the completion timeline.\686\ 
Therefore, Bonneville seeks a longer time frame.
---------------------------------------------------------------------------

    \685\ AES Initial Comment at 11; APS Initial Comments at 8; ISO-
NE Initial Comments at 23.
    \686\ Bonneville Initial Comments at 9.
---------------------------------------------------------------------------

    314. On the other hand, several commenters argue that the deadline 
to conduct a cluster restudy should be shorter.\687\ AES recommends 
that the Commission instead require transmission providers to include 
restudies and model rebuilds between cluster study phases, and to 
require that the timeline for such model rebuilds and restudies cannot 
be greater than 90 days.\688\ Enel similarly asserts that if the 
Commission leaves the cluster study timeline at 150 days and does not 
change the study scope, the timeline for cluster restudies should be 90 
days.\689\
---------------------------------------------------------------------------

    \687\ AEE Initial Comments at 33; Clean Energy Associations 
Initial Comments at 42; Cypress Creek Initial Comments at 18.
    \688\ AES Initial Comments at 11.
    \689\ Enel Initial Comments at 83.
---------------------------------------------------------------------------

    315. A few commenters argue that a 30-day window per restudy is 
more reasonable because network models are already built, and therefore 
substantially fewer staff resources should be required than for the 
initial study.\690\ Cypress Creek adds that a shorter restudy window 
will also help avoid potential delays in a cluster study process in 
which multiple restudies are required.\691\ AEE also recommends that 
the Commission limit interconnection restudy timelines to 30 days, 
arguing that this will encourage transmission providers to treat 
customers in interconnection restudy with the same urgency as customers 
in the initial interconnection study, eliminating the possibility of 
asymmetric treatment of interconnection customers and alleviating 
interconnection queue congestion by moving those interconnection 
customers that have been in the interconnection queue the longest to 
study completion.\692\
---------------------------------------------------------------------------

    \690\ AEE Reply Comments at 11-12; Clean Energy Associations 
Initial Comments at 42; Cypress Creek Initial Comments at 18; SEIA 
Initial Comments at 8.
    \691\ Cypress Creek Initial Comments at 18.
    \692\ AEE Initial Comments at 33.
---------------------------------------------------------------------------

iii. Commission Determination
    316. We adopt the proposed deletion of the feasibility study as 
effectuated by the replacement of the current section 6 
(Interconnection Feasibility Study) of the pro forma LGIP with the new 
heatmap requirements, as discussed in section III.A.1.c. The move from 
a serial interconnection process to the new cluster study process, 
coupled with the Commission's heatmap requirements, render the 
feasibility study redundant at best and an unnecessary burden on 
transmission provider resources. As discussed in section III.A.1.c, 
above, we find that the publicly available information required by this 
final rule will provide the appropriate level of pre-interconnection 
queue information for interconnection customers to make informed 
choices.
    317. We also adopt, with one modification, the proposed revisions 
to section 7 of the pro forma LGIP that rename it ``cluster study'' 
instead of ``interconnection system impact study,'' which set out the 
requirements and scope of the cluster study agreement, as well as the 
cluster study and restudy procedures. These revisions reflect the 
adoption of the cluster study process set forth in this final rule by 
making clear that the interconnection studies that transmission 
providers previously performed as part of the serial system impact 
studies (i.e., stability analysis, power flow analysis, and short 
circuit analysis) must now be conducted on a clustered basis. As 
discussed further in section III.A.6 of this final rule, pro forma LGIP 
section 7.5 is modified to remove the requirement to provide an initial 
study deposit that would have been applied towards the cost of the 
cluster study process.
    318. We are not persuaded by Tri-State's concern that five business 
days after the close of the cluster request window is too short a time 
frame for a transmission provider to tender a cluster study agreement 
to each interconnection customer. Transmission providers may start to 
prepare cluster study agreements before the close of the cluster 
request window, as the overall terms and conditions of the cluster 
study agreement are standardized so that a transmission provider need 
not engage in rewriting each agreement before tendering a draft to the 
interconnection customer.
    319. In response to Tri-State's comments concerning section 7.2 of 
the pro forma LGIP, we confirm that an interconnection request is 
considered withdrawn if the interconnection customer does not cure 
deficiencies identified by the transmission provider. We note that 
under new section 3.4.4 of the pro forma LGIP, if a transmission 
provider identifies that an interconnection customer's technical data 
are incomplete or contain errors, both parties must ``work 
expeditiously and in good faith to remedy such issues,'' but the 
failure by the interconnection customer to provide the missing data or 
correct data errors will be treated as a withdrawal and dealt with 
under pro forma LGIP section 3.7 (Withdrawal).
    320. In reference to Tri-State's comments on the proposed revisions 
to

[[Page 61064]]

section 7.3 of the pro forma LGIP, we decline to add language to 
address situations with studies pending completion of higher-queued 
project cluster studies because Tri-State's comments are unclear as to 
what additional language may be needed.
    321. We decline to adopt the alternative methods to perform cluster 
studies and restudies suggested by Enel. The current pro forma LGIP 
does not prescribe particular study methods and instead provides 
discretion to transmission providers to determine the particular 
methods of study appropriate for their transmission systems. We do not, 
based on the record in this proceeding, find a basis to determine that 
existing study methods are unjust, unreasonable, and unduly 
discriminatory or preferential. We also decline to add Enel's suggested 
section (d) to section 7.5 of the pro forma LGIP. Pro forma LGIP 
section 4.4.1 contains the modifications permitted to an 
interconnection request prior to the return of an executed cluster 
study agreement, which predates any potential cluster restudy. We 
further note that the record does not support Enel's modification 
request.
    322. We decline to adopt the provision requiring transmission 
providers to hold cluster study report meetings with individual 
customers as proposed in section 7.4 of the pro forma LGIP. We find 
that the individual meetings would be unnecessary, and that individual 
customers should utilize the group cluster study report meeting as a 
more efficient forum in which to address any questions or concerns 
pertaining to the cluster study report. We also find that requiring 
transmission providers to conduct individual meetings would impose 
unnecessarily burdensome additional requirements on transmission 
providers and would be insufficient to ensure that interconnection 
customers are able to interconnect to the transmission system in a 
reliable, efficient, transparent, and timely manner.
    323. Also, we decline to remove proposed section 7.5(2) of the pro 
forma LGIP, as suggested by Enel. Contrary to Enel's claim, pro forma 
LGIP section 7.3 establishes that the cluster study will consist of 
short circuit and stability analyses; therefore, we disagree with Enel 
that a cluster restudy will be needed in all cases to perform the short 
circuit and stability analyses. Section 7.5(2) states that if there are 
no changes to the composition of the cluster, a cluster restudy is not 
required. We find that this is appropriate as it prevents the 
transmission provider from performing an unnecessary restudy if no 
conditions have changed after the first cluster study. This will 
increase efficiency, free up the transmission provider's resources to 
perform other studies, and increase the speed of interconnection, 
ensuring that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner.
    324. Based on the record, we find that a 150-calendar day cluster 
study deadline provides a sufficient time to allow transmission 
providers to perform the stability analyses, power flow analyses, and 
short circuit analyses required in the cluster study process for 
complex clusters consisting of numerous interconnection requests. We 
find that the 150-calendar day time frame balances providing 
transmission providers with sufficient time to perform these technical 
cluster studies while providing certainty about the timeline for the 
interconnection process and ensuring that cluster studies progress in a 
timely manner. We note that depending on the cluster size, cluster 
studies may not always consume the entire 150 calendar days, and if a 
cluster study is complete prior to this deadline, transmission 
providers have flexibility to provide the cluster study report at that 
time prior to the deadline indicated in its LGIP and commence any 
necessary restudies or move to the facilities study phase. We also note 
that if a transmission provider progresses to the next study phase 
prior to the deadline indicated in its LGIP, the transmission provider 
must post any changes on its website or OASIS.
    325. We disagree with Enel's suggestion to reduce the scope and 
schedule of the cluster study in the proposed pro forma LGIP. The 
cluster study represents the first time the interconnection customer 
will obtain information about its potential interconnection costs. At 
this point, interconnection customers will have to make significant 
financial decisions about whether to remain in the interconnection 
queue. The information provided in the cluster study report will likely 
dictate that decision, and we find that the scope of the study is 
appropriate to allow interconnection customers to make these types of 
decisions and evaluate whether they will face significant risk. Given 
that we decline to reduce the scope of the study, we find Enel's 
request to reduce the timeline overly restrictive. Enel's proposal 
would create significant burden on transmission providers to perform 
complex studies in an even shorter timeline, and we therefore decline 
to adopt it.
    326. We also disagree with commenters that argue that the 150-
calendar day time frame to complete the cluster study is too short. As 
discussed above, numerous commenters agree with the Commission's 
conclusion that the significant interconnection queue backlogs create 
uncertainty and risk in bringing new generating facilities online, 
rendering Commission-jurisdictional rates unjust and unreasonable. 
While we have extended the timeline from that provided in the 
individual serial study process, we believe that 150 calendar days is a 
reasonable extension to account for the more complex study. We also 
note that transmission providers will be conducting only one 
interconnection study, or at most a small number of interconnection 
studies, at a time, allowing them to devote more resources to 
completing the studies in a timely manner. Thus, on balance, we believe 
that 150 calendar days represents an appropriate and reasonable 
timeline on which transmission providers must complete initial cluster 
studies.
    327. We disagree with NYTOs that it is not clear as to when the 
clock starts for the proposed 150-calendar day cluster study deadline, 
as proposed pro forma LGIP section 7.3 contains this information (150 
calendar days from the close of the customer engagement window). We 
also disagree with NYTOs' statement that it is not clear how the scope 
of the work can be reasonably limited to comply with the 150-calendar 
day deadline, as we are not proposing to limit the scope of work 
necessary to effectively run a cluster study. As discussed above, we 
find that the 150-calendar day cluster study deadline, combined with 
the fewer necessary studies, provides a reasonable amount of time to 
allow transmission providers to perform the required studies.
    328. In response to National Grid's concern that some RTO/ISO 
interconnection processes require supplemental studies and that these 
studies should not be required to be conducted within the 150-calendar 
day cluster study window, we decline to modify the pro forma LGIP to 
provide for more time for such studies. We also clarify for National 
Grid that the 150-calendar day deadline includes the time required to 
develop system models and base case data for the cluster study.
    329. Regarding the 150-calendar day cluster restudy deadline, we 
agree with commenters that the proposed 150-calendar day deadline is 
reasonable for a cluster restudy. We acknowledge that some commenters 
argue that 150 calendar days is too short, while others argue that it 
is too long. On balance, we

[[Page 61065]]

find that 150 calendar days is a just and reasonable time frame for 
purposes of the pro forma LGIP that allows transmission providers to 
conduct potentially complex restudies for instances in which larger 
clusters experience multiple withdrawals and/or modifications.
    330. In response to commenters' arguments that a 150-calendar day 
restudy deadline is too long, we note that if transmission providers 
complete the cluster restudy prior to the full 150-calendar day period 
elapsing, transmission providers may move to the facilities study stage 
at that time. As such, the adopted 150-calendar day cluster restudy 
time frame accommodates more complex instances of cluster restudies 
while still allowing flexibility for transmission providers to move 
forward without waiting for the deadline to pass if the restudy does 
not take the full 150 calendar days.
    331. Additionally, we decline to adopt suggestions to allow 
transmission providers flexibility to set their own study 
deadlines,\693\ which would undermine the purpose of ensuring that 
transmission providers complete interconnection studies by standard 
deadlines prescribed by their tariffs and would thus be insufficient to 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner.
---------------------------------------------------------------------------

    \693\ AEP Initial Comments at 17-18; APPA-LPPC Initial Comments 
at 21; Avangrid Initial Comments at 13; Bonneville Initial Comments 
at 16; CAISO Initial Comments at 11; Dominion Initial Comments at 
16-17; Indicated PJM TOs Reply Comments at 39; ISO-NE Initial 
Comments at 35-37; NYISO Initial Comments at 29, 33; NY Commission 
and NYSERDA at 5; NYTOs Initial Comments at 14; SEIA Reply Comments 
at 6.
---------------------------------------------------------------------------

j. Restudies Triggered by Higher- or Equally Queued Generating Facility
i. NOPR Proposal
    332. In the NOPR, the Commission proposed to revise section 8.5 
(Restudy) of the pro forma LGIP to make clear that restudies can be 
triggered by a higher- or equally queued interconnection request 
withdrawing from the interconnection queue or modification of a higher- 
or equally queued interconnection request pursuant to section 4.4 
(Modifications) of the pro forma LGIP.\694\
---------------------------------------------------------------------------

    \694\ NOPR, 179 FERC ] 61,194 at P 75.
---------------------------------------------------------------------------

ii. Comments
    333. Shell argues the withdrawal of an interconnection request 
should not automatically trigger a cluster restudy, and instead the 
Commission should consider a process and cost allocation method that 
creates a ``secondary market'' to replace a proposed generating 
facility that withdraws with another generating facility in the same 
location or nearby.\695\ CREA and NewSun agree with Shell's suggestion 
to allow interconnection customers to step in and assume the rights of 
any interconnection customer that withdraws its interconnection 
request.\696\ Similarly, R Street argues that the cluster study process 
should not impede the transfer of interconnection request 
``ownership,'' as, according to R Street, allowing parties to trade 
will help ensure an efficient balance between generation additions and 
transmission interconnection costs.\697\
---------------------------------------------------------------------------

    \695\ Shell Initial Comments, app. A at i.
    \696\ CREA and NewSun Reply Comments at 10.
    \697\ R Street Initial Comments at 11.
---------------------------------------------------------------------------

    334. MISO seeks clarification on the trigger for restudies. MISO 
states that its understanding is that any modification during its study 
process that is found to be material would not be allowed.\698\ 
Further, MISO contends that allowing a material modification to impact 
an equally queued interconnection customer seems to be inconsistent 
with the Commission's proposal to modify the definition of material 
modification.\699\ Therefore, MISO argues that there should not be a 
need for a restudy due to such modification. MISO asserts that the 
Commission should not allow modifications during the study process that 
materially impact other interconnection customers and may require 
restudies.
---------------------------------------------------------------------------

    \698\ MISO Initial Comments at 40.
    \699\ Id. (referencing NOPR, 179 FERC ] 61,194 at P 65).
---------------------------------------------------------------------------

iii. Commission Determination
    335. We adopt the proposed revisions to section 8.5 of the pro 
forma LGIP to make clear that restudies can be triggered by a 
withdrawal or modification by a higher- or equally queued 
interconnection request. First, we clarify that the ``modification'' we 
refer to in this section must be explicitly permitted under pro forma 
LGIP section 4.4. Any other modification that triggered a restudy would 
be found to be material and would not be allowed, as it would affect 
the cost and/or timing of the other customers in the interconnection 
queue by necessitating a restudy. Next, we find that restudies may be 
triggered if there is either a withdrawal or a modification explicitly 
permitted under pro forma LGIP section 4.4. Changes to the composition 
of the cluster often require the transmission provider to restudy the 
entire cluster to ensure that all network upgrades and the associated 
costs are still needed. Finally, we find that stating that restudy may 
be required due to the withdrawal or modification of a higher- or 
equally queued interconnection request, rather than requiring that a 
restudy must occur, provides the transmission provider with flexibility 
to assess whether the restudy is necessary. If the transmission 
provider is able to move forward without performing a full restudy, 
that is a preferable outcome in terms of interconnection queue 
efficiency, as the transmission provider can maintain the study 
milestones already achieved and maintain progress towards completion 
and operation for generating facilities in the cluster, as opposed to 
dedicating significant additional time required to restart and conduct 
the study process over again when it may not be necessary or beneficial 
to do so.
    336. In response to Shell, CREA and NewSun, and R Street, we 
decline to consider modifications to the pro forma LGIP to create a 
``secondary market'' process that would allow one generating facility 
to replace a similarly situated one that withdraws from the 
interconnection queue, where that withdrawal would otherwise trigger a 
restudy. The Commission did not propose such a process in the NOPR, and 
we do not have a sufficient record to consider adopting such a process 
in this final rule.
    337. In response to MISO, we clarify that material modifications 
are defined in section 1 of the pro forma LGIP as modifications that 
have a material impact on the cost or timing of any interconnection 
request with an equal or later queue position. Under section 4.4.3 of 
the pro forma LGIP, if an interconnection customer chooses to move 
forward with the modification that has been deemed material by the 
transmission provider, the interconnection customer will lose its queue 
position and must proceed with a new interconnection request if 
desired. However, we note that certain modifications as listed in pro 
forma LGIP sections 4.4.1, 4.4.2, and 4.4.5 are permitted regardless of 
their impact on other interconnection customers.
k. Timing of LGIA Tender, Execution, and Filing
i. NOPR Proposal
    338. In the NOPR, the Commission proposed to revise sections 11.1 
(Tender) and 11.3 (Execution and Filing) of the pro forma LGIP, which 
include provisions related to the tender, execution, and filing of the 
LGIA, to incorporate a 60 calendar-day

[[Page 61066]]

negotiation period and to incorporate the site control demonstrations 
and LGIA deposit provisions included in proposed section 3 of the pro 
forma LGIP.\700\
---------------------------------------------------------------------------

    \700\ NOPR, 179 FERC ] 61,194 at P 76.
---------------------------------------------------------------------------

ii. Comments
    339. Enel states that many transmission providers and 
interconnection customers are confused as to how to interpret pro forma 
LGIP sections 11.1 and 11.2 in relation to each other, and Enel thus 
recommends that the Commission revise and simplify sections 11.1 and 
11.2 of the pro forma LGIP to provide more clarity.\701\ Enel argues 
that additional changes are needed to address common delays in 
completion of the final facilities study report; delays in a 
transmission provider issuing the draft LGIA; and delays in the 
transmission provider executing the LGIA after receiving the 
interconnection customer's signature and milestones, and subsequently 
proposes targeted revisions to pro forma LGIP sections 11.1 and 11.2 to 
provide additional time for interconnection customers to review and 
negotiate LGIAs.\702\
---------------------------------------------------------------------------

    \701\ Enel Initial Comments at 13-14.
    \702\ Id. at 14-15.
---------------------------------------------------------------------------

    340. Tri-State notes that section 11.3 of the pro forma LGIP is 
unclear when it states that the ``Transmission Provider must not 
suspend the LGIA'' until the interconnection customer meets the tariff 
requirements because it is the interconnection customer that has the 
ability to suspend a proposed generating facility.\703\
---------------------------------------------------------------------------

    \703\ Tri-State Initial Comments at 32.
---------------------------------------------------------------------------

    341. APS requests that the Commission be more prescriptive on what 
is considered reasonable evidence of achieving development milestones 
when executing an LGIA in the same manner that the Commission defines 
commercial readiness milestones in order to avoid subjectivity and 
potential disagreements regarding what is considered ``reasonable.'' 
\704\ APS also asserts that the reference to simultaneous submission of 
the interconnection customer-executed LGIA and the continued 
demonstration of site control is duplicative and unnecessary if an 
interconnection customer demonstrates site control at the time an 
interconnection request is made.
---------------------------------------------------------------------------

    \704\ ASP Initial Comments at 7.
---------------------------------------------------------------------------

    342. Hydropower Commenters contend that the Commission should 
provide additional time for payment of interconnection costs after the 
interconnection process is complete.\705\ Hydropower Commenters assert 
that once a transmission provider delivers the interconnection 
agreement and construction agreement to the interconnection customer, 
the interconnection customer has only 60 days to execute the agreements 
and 15 business days after receipt of the signed agreements to 
demonstrate site control or post a non-refundable additional security 
deposit to cover the interconnection costs. Hydropower Commenters argue 
that, because the end of the study process may occur long before a 
proposed generating facility is fully funded, and the interconnection 
customer risks losing its queue position if it does not execute the 
agreements, the Commission should extend this period to at least one 
year so the interconnection customer has time to secure funding and 
avoids having to restart the interconnection process.
---------------------------------------------------------------------------

    \705\ Hydropower Commenters Initial Comments at 18.
---------------------------------------------------------------------------

    343. NV Energy similarly suggests changes to the NOPR proposal to 
allow interconnection customers that request a transmission provider to 
file an unexecuted LGIA to satisfy these requirements within 15 days of 
the Commission issuing an order. NV Energy states that the proposed 
extra time between receiving a draft LGIA and having to satisfy these 
requirements creates an undue preferential advantage for those 
interconnection customers that request unexecuted LGIAs to be filed at 
the Commission and could delay the interconnection process for 
others.\706\ To address this issue, NV Energy suggests that 
interconnection customers who choose to have their unexecuted LGIAs 
filed with the Commission should be required to submit their data to 
the transmission provider by the day after the filing of the LGIA.
---------------------------------------------------------------------------

    \706\ NV Energy Initial Comments at 20.
---------------------------------------------------------------------------

iii. Commission Determination
    344. We adopt, in part, and modify, in part, the proposal to revise 
sections 11.1 and 11.3 of the pro forma LGIP, regarding the tendering, 
execution, and filing of the LGIA, to incorporate a 60-calendar day 
negotiation period and to incorporate the site control demonstrations 
and LGIA deposit provisions included in proposed section 3 of the pro 
forma LGIP. We find that the revisions to section 11.1 of the pro forma 
LGIP that we adopt herein clarify the process of tendering an LGIA and 
the revisions to section 11.3 of the pro forma LGIP that we adopt 
herein incorporate the site control and LGIA deposit provisions adopted 
elsewhere in this final rule.
    345. We do not adopt the proposed revisions to pro forma LGIP 
section 11.3 that reference the commercial readiness demonstration 
provisions of proposed section 8.1 of the pro forma LGIP because we are 
not adopting those provisions, as discussed below in section III.A.6.
    346. We modify the proposed revisions to pro forma LGIP section 
11.3, as requested by Tri-State, because we agree that the proposal was 
unclear when it stated that ``Transmission Provider must not suspend 
the LGIA under LGIA article 5.16'' until the interconnection customer 
meets certain tariff requirements. We modify pro forma LGIP section 
11.3 to instead state: ``Interconnection Customer may not request to 
suspend its LGIA under LGIA Article 5.16 until Interconnection 
Customer'' meets certain tariff requirements. This reflects the fact 
that it is the interconnection customer, not the transmission provider, 
that has the right to suspend the LGIA.
    347. We also modify proposed section 11.3 of the pro forma LGIP in 
response to NV Energy's concerns about favoring interconnection 
customers that request a transmission provider to file an unexecuted 
LGIA. We agree that the proposal has the potential to encourage more 
filings of unexecuted LGIAs simply to delay the due date for submission 
of deposits, evidence of site control, and milestone progress data. We 
therefore modify the proposal such that interconnection customers that 
request a transmission provider to file an unexecuted LGIA must satisfy 
these submission requirements within 10 business days after the date of 
the filing of the unexecuted LGIA with the Commission.
    348. We decline to make further modifications to the proposal 
beyond those discussed above. Enel has neither explained why pro forma 
LGIP sections 11.1, as revised by this final rule, and 11.2, cause an 
unjust and unreasonable result for interconnection customers, nor has 
it explained why changes to the negotiation process between 
transmission providers and interconnection customers are needed at this 
time.
    349. Similarly, we decline APS' request that the Commission be 
``more prescriptive'' on what is considered reasonable evidence of 
achieving development milestones when executing an LGIA. We believe 
that the requirement that interconnection customers provide reasonable 
evidence is sufficient to ensure just and reasonable rates without 
imposing detailed requirements surrounding the meaning of 
``reasonable.'' There is inadequate record to demonstrate a more 
prescriptive approach is needed.

[[Page 61067]]

For example, development milestones generally involve the execution of 
contracts or applications for permits.
    350. We also decline to adopt Hydropower Commenters' request to 
modify the pro forma LGIP to provide additional time for payment of 
interconnection costs after the conclusion of the interconnection study 
process. The pro forma LGIP, as modified by this final rule, requires 
transmission providers to give interconnection customers ample notice 
of costs and the timing that costs are due as part of the 
interconnection process so that interconnection customers can secure 
funding for a proposed generating facility. We are unpersuaded that 
interconnection customers should have additional time beyond that 
already provided, especially given the number of generating facilities 
that have been developed using the existing process and the added 
transparency that we adopt in this final rule that will only serve to 
improve the ability of interconnection customers to secure financing.
l. Cluster Subgroups
i. NOPR Proposal
    351. In the NOPR, the Commission sought comment on whether to 
require transmission providers to conduct cluster studies on subgroups 
of interconnection customers based on areas of geographic and electric 
relevance, and, if so, whether to adopt provisions governing how 
cluster areas should be formed to ensure that cluster areas are formed 
in a transparent and not unduly discriminatory manner.\707\
---------------------------------------------------------------------------

    \707\ NOPR, 179 FERC ] 61,194 at P 77.
---------------------------------------------------------------------------

ii. Comments
    352. A number of commenters support permitting transmission 
providers to study clusters in subgroups based on geographic or 
electrical relevance,\708\ but some argue that clustering projects in 
subgroups should not be required.\709\
---------------------------------------------------------------------------

    \708\ APS Initial Comments at 9; ClearPath Initial Comments at 
7; NARUC Initial Comments at 6; NextEra Initial Comments at 14-15; 
[Oslash]rsted Initial Comments at 8; PacifiCorp Initial Comments at 
17; Pennsylvania Commission Initial Comments at 8.
    \709\ APS Initial Comments at 9; Indicated PJM TOs Initial 
Comments at 18; NextEra Initial Comments at 15; PJM Initial Comments 
at 22.
---------------------------------------------------------------------------

    353. Several entities argue that clustering around subgroups of 
geographic or electrical relevance is a reasonable approach, 
particularly for transmission providers with a large or fragmented 
footprint.\710\ Some commenters argue that creating sub-clusters may 
not make sense for transmission providers with small footprints.\711\ 
Several commenters argue that transmission providers should have 
flexibility in deciding whether to form subgroups of interconnection 
customers because geographic and electric relevance will vary with each 
cluster study.\712\ Similarly, some commenters contend that the 
Commission should not mandate studying subgroups based on geographic 
and electric relevance, and that the efficacy of this approach should 
instead first be evaluated through experience.\713\
---------------------------------------------------------------------------

    \710\ Illinois Commission Initial Comments at 5; NextEra Initial 
Comments at 14-15; PacifiCorp Initial Comments at 18; Pennsylvania 
Commission Initial Comments at 8.
    \711\ NRECA Initial Comments at 19; Tri-State Initial Comments 
at 11.
    \712\ Bonneville Initial Comments at 8-9; ClearPath Initial 
Comments at 8; ENGIE Reply Comments at 2; Fervo Energy Reply Comment 
at 4; Indicated PJM TOs Initial Comments at 18; SEIA Reply Comments 
at 6.
    \713\ AES Initial Comments at 10; PJM Initial Comments at 22.
---------------------------------------------------------------------------

    354. PacifiCorp notes that using cluster study areas allows it to 
assess and more efficiently allocate the costs of network upgrades to 
requesters triggering the improvements and protect interconnection 
customers in different clusters from bearing the cost of network 
upgrades triggered by interconnection customers in different parts of 
PacifiCorp's system, thereby facilitating more expedient processing of 
all the cluster studies.\714\ PacifiCorp asserts that its ability to 
create cluster areas where appropriate is a critical feature of its 
cluster study process, adding that cluster areas can facilitate 
expedient processing of interconnection requests that might otherwise 
be delayed due to restudies or other study complications.\715\
---------------------------------------------------------------------------

    \714\ PacifiCorp Initial Comments at 18-19.
    \715\ Id. at 17.
---------------------------------------------------------------------------

    355. On the other hand, Pattern Energy asserts that designating 
subregions may result in separate geographic regions bearing a 
disproportionate share of network upgrade costs that provide regional 
benefits and should be subject to regional cost allocations.\716\ 
Pattern Energy notes that it is also important for the transmission 
provider to review subregional cluster study results and determine 
whether inter-cluster network upgrades would better serve the needs of 
the subregional clusters during each planning cycle. Illinois 
Commission asserts that interconnection requests that are near one 
another might have a greater impact on each other, and subgroups could 
ease the study process, but any subgroup process should not compromise 
cost or timing efficiency gains that the clustering process is meant to 
address.\717\ OPSI argues that to reduce the ``first mover 
disadvantage'' most effectively, the Commission should continue to 
analyze and further explain in any final rule whether a region-wide, 
annual cluster in a large region like PJM could benefit from better 
defined subclusters.\718\ OPSI asserts that the Commission should 
further evaluate methods to ensure that clusters facilitate 
identification of shared network upgrades by grouping generating 
facilities based on areas of geographic and electrical relevance.
---------------------------------------------------------------------------

    \716\ Pattern Energy Initial Comments at 16.
    \717\ Illinois Commission Initial Comments at 5.
    \718\ OPSI Initial Comments at 4.
---------------------------------------------------------------------------

    356. Avangrid contends that the open call cluster request window 
should have geographic distinctions, but that if the open call results 
in only one interconnection request in a particular area of the system 
electrically, this interconnection should be able to undergo a process 
reminiscent of current serial study processes in a parallel track if it 
will influence, or be influenced by, the broader cluster study 
process.\719\
---------------------------------------------------------------------------

    \719\ Avangrid Initial Comments at 12.
---------------------------------------------------------------------------

    357. Some commenters argue that the Commission should set forth 
specific mandates to transmission providers on how cluster areas should 
be formed.\720\ CREA and NewSun argue that clear mandates would prevent 
transmission providers from subgrouping as a means to engage in anti-
competitive conduct (e.g., assigning the utility's own generation to 
subgroups with lower congestion or network upgrade costs).\721\ 
Similarly, Fervo Energy contends that the Commission should adopt 
provisions governing how cluster areas should be formed to ensure that 
clusters are formed in a transparent and not unduly discriminatory 
manner.\722\
---------------------------------------------------------------------------

    \720\ CREA and NewSun Initial Comments at 48-49; Environmental 
Defense Fund Reply Comments at 7-8; Fervo Energy Initial Comments at 
3.
    \721\ CREA and NewSun Initial Comments at 48-49.
    \722\ Fervo Energy Initial Comments at 3.
---------------------------------------------------------------------------

    358. Other commenters argue that the Commission should provide 
flexibility by creating a general framework for defining cluster study 
subgroups appropriate for their own regions, rather than a specific set 
of requirements.\723\

[[Page 61068]]

Some commenters further contend that transmission providers have 
extensive knowledge of their own transmission systems,\724\ and the 
particular interconnection requests that should and should not be 
included within a cluster based on their system's geography, electric 
configuration, or other relevant factors.\725\
---------------------------------------------------------------------------

    \723\ APS Initial Comments at 9; Clean Energy Associations 
Initial Comments at 20; ClearPath Initial Comments at 8; EEI Initial 
Comments at 5; Eversource Initial Comments at 13-14; LADWP Initial 
Comments at 3; Longroad Energy Initial Comments at 10; MISO Initial 
Comments at 41-42; New York State Department Initial Comments at 5-
6; Pattern Energy Initial Comments at 15; PacifiCorp Initial 
Comments at 18; PPL Initial Comments at 10; R Street Initial 
Comments at 11; Tri-State Initial Comments at 11; U.S. Chamber of 
Commerce Initial Comments at 7; Xcel Initial Comments at 23.
    \724\ Shell Initial Comments, app. A at i; Tri-State Initial 
Comments at 11.
    \725\ U.S. Chamber of Commerce Initial Comments at 7.
---------------------------------------------------------------------------

    A number of commenters suggest that transmission providers develop 
subgroup criteria with stakeholder input.\726\
---------------------------------------------------------------------------

    \726\ Interwest Initial Comments at 14; MISO Initial Comments at 
42; Northwest and Intermountain Initial Comments at 7; Pattern 
Energy Initial Comments at 15-16; PacifiCorp Initial Comments at 18 
(citing PacifiCorp, Transmission OATT and Service Agmts, Part 
IV.42.4(a) (5.0.0)); Shell Initial Comments, app. A at i.
---------------------------------------------------------------------------

    359. Other commenters argue that the Commission should allow 
variation in how transmission providers form clusters. For example, R 
Street argues that the Commission should refrain from being too 
prescriptive regarding how cluster areas are defined, and instead 
require that transmission providers publish their cluster definitions 
well in advance of the request window for interconnection 
requests.\727\ Clean Energy States believe that allowing 
interconnection customers to create their own clusters would result in 
an internal vetting of proposed generating facilities in the cluster 
and negotiation about how costs and penalties will be managed.\728\ 
Regarding how clusters should be defined, several commenters provide 
suggestions for subgroup criteria beyond geographic proximity or 
electrical relevance.\729\ PPL suggests cluster formation be based on 
geographic or electrical proximity only and that interconnection 
customers should not be separated based on fuel type.\730\ Energy 
Keepers asserts that, when utilities are considering cluster studies on 
subgroups of interconnection customers, those clusters should be based 
on location.\731\ Clean Energy Associations, Vistra, and ENGIE assert 
that cluster studies should evaluate subgroups of projects based on 
electric proximity to one another.\732\ Further, ENGIE agrees that 
distribution factors should not be the sole indicator of electrical 
proximity as there are other factors around which subgroups might 
appropriately be grouped.\733\
---------------------------------------------------------------------------

    \727\ R Street Initial Comments at 11.
    \728\ Clean Energy States Initial Comments at 10.
    \729\ Id. at 5; Fervo Energy Initial Comments at 3; Interwest 
Initial Comments at 13-14; Longroad Energy Initial Comments at 10; 
Pattern Energy Initial Comments at 15-16; Pennsylvania Commission 
Initial Comments at 6.
    \730\ PPL Initial Comments at 10.
    \731\ Energy Keepers Initial Comments at 4.
    \732\ Clean Energy Associations Initial Comments at 20; ENGIE 
Reply Comments at 2; Vistra Initial Comments at 2.
    \733\ ENGIE Reply Comments at 2.
---------------------------------------------------------------------------

    360. Xcel argues that it is not necessary to create ``separate'' 
clusters for electrically distinct regions, noting that PSCo separates 
interconnection requests into ``study pockets'' based on geographic/
electrical separation but studies all the interconnection requests in a 
single cluster.\734\
---------------------------------------------------------------------------

    \734\ Xcel Initial Comments at 23.
---------------------------------------------------------------------------

    361. Clean Energy Associations assert that the Commission should 
make clear whether a cluster study must identify the upgrades required 
in order to interconnect every interconnection request in whole, or 
whether it might identify upgrades that would be sufficient for only a 
subset of the interconnection requests; if the latter, Clean Energy 
Associations continue, the Commission should establish a pro forma 
process for determining which requests might proceed with those initial 
upgrades.\735\ Clean Energy Associations claim that transmission 
development is a ``lumpy'' process, and in some cases there can be 
``breakpoints'' where adding one more generating facility can result in 
a significant per-unit cost increase compared to the interconnection 
costs that could have been achieved for a subset of the interconnection 
requests up to that point. Clean Energy Associations state that, in the 
current ISO-NE cluster study process, ISO-NE attempts to identify such 
breakpoints and fills each cluster up to that level, with remaining 
requests able to either withdraw or proceed into the next cluster 
study. Some commenters contend that studies should include or consider 
including breakpoints, which can provide helpful information to inform 
interconnection customers' next steps.\736\
---------------------------------------------------------------------------

    \735\ Clean Energy Associations Initial Comments at 26.
    \736\ Id. at 26-27; SEIA Reply Comments at 6.
---------------------------------------------------------------------------

    362. Finally, several commenters encourage transparency and request 
that any subgrouping criteria be publicly posted or filed by 
transmission providers or RTOs/ISOs.\737\
---------------------------------------------------------------------------

    \737\ ENGIE Reply Comments at 2; Fervo Energy Initial Comments 
at 3; Fervo Energy Reply Comments at 4; [Oslash]rsted Initial 
Comments at 8; R Street Initial Comments at 11; Tri-State Initial 
Comments at 11.
---------------------------------------------------------------------------

iii. Commission Determination
    363. We will neither require transmission providers to conduct 
cluster studies on subgroups of interconnection customers based on 
areas of geographic and electric relevance, nor adopt provisions 
governing how cluster subgroup areas should be formed. However, we 
adopt revisions to section 7.4 of the pro forma LGIP to permit 
transmission providers to use subgroups in their cluster study process 
if they so choose. To the extent a transmission provider chooses to use 
subgroups, it must include provisions in its pro forma LGIP in its 
tariff that state that it will use subgroups. We further modify section 
7.4 of the pro forma LGIP to require that the criteria used to define 
subgroups be publicly posted on a publicly accessible website. We 
believe that publicly sharing these criteria is important to ensure 
adequate transparency and to safeguard against the potential for undue 
discrimination in the design and implementation of cluster subgroups.
    364. We agree with commenters that support permitting transmission 
providers to study clusters in subgroups based on geographic or 
electrical relevance but argue that clustering projects in subgroups 
should not be required. We believe that there may be benefits to 
studying clusters in subgroups in certain circumstances, and therefore 
we do not want to preclude transmission providers from proposing such a 
process on compliance. At the same time, based on the record, we do not 
believe that requiring subgroups for all transmission providers is 
appropriate. In some instances, the administrative burden of defining 
and separately studying subgroups may not outweigh the benefits.
    365. Consistent with our decision to not require transmission 
providers to conduct cluster studies on subgroups of interconnection 
customers, we decline to adopt provisions governing how clusters should 
be formed. Rather, we believe it more appropriate to allow transmission 
providers to determine how to define subclusters appropriate for their 
regions, taking into consideration their system geography, electrical 
configuration, and other relevant factors.\738\
---------------------------------------------------------------------------

    \738\ Clean Energy Associations Initial Comments at 20; 
ClearPath Initial Comments at 8; EEI Initial Comments at 5; 
Eversource Initial Comments at 13-14; LADWP Initial Comments at 3; 
Longroad Energy Initial Comments at 10; MISO Initial Comments at 41-
42; New York State Department Initial Comments at 5-6; PacifiCorp 
Initial Comments at 18; Pattern Energy Initial Comments at 15; PPL 
Initial Comments at 10; Shell Initial Comments, app. A at i; Tri-
State Initial Comments at 11; U.S. Chamber of Commerce Initial 
Comments at 7.

---------------------------------------------------------------------------

[[Page 61069]]

    366. Regarding concerns raised by Pattern Energy and others about 
the use of subgroups resulting in a disproportionate allocation of 
network upgrade costs, we note that if a transmission provider opts to 
study in subgroups, it cannot change how it allocates network upgrade 
costs. That is, it must follow the requirement adopted in this final 
rule to use a proportional impact method to allocate system network 
upgrade costs among all interconnection customers in the cluster 
regardless of subgroup, as discussed further below. Because 
transmission providers will be using a proportional impact method to 
allocate system network upgrade costs, regardless of whether 
interconnection customers are studied in subgroups, we believe 
subgroups would not change an interconnection customer's potential cost 
allocation. An interconnection customer with an impact on a network 
upgrade would be allocated its portion of the cost of that network 
upgrade regardless of whether its request was studied in a subgroup 
with another interconnection customer allocated a different portion of 
that network upgrade.
m. Restudy
i. NOPR Proposal
    367. In the NOPR, the Commission sought comment on whether to 
specify in the pro forma LGIP how cluster studies must be rerun after 
restudy is triggered or whether there are provisions the Commission 
could adopt to improve the efficacy of the restudy process, such as 
preventing excessive restudy by limiting the transmission provider to 
two restudies per month within the 150-calendar day cluster restudy 
period.\739\
---------------------------------------------------------------------------

    \739\ NOPR, 179 FERC ] 61,194 at P 78.
---------------------------------------------------------------------------

ii. Comments
    368. Eversource recommends that the Commission adopt detailed 
restudy rules.\740\ Pine Gate suggests that the Commission provide 
guidance on when the need for a restudy is triggered, as even minimal 
changes can trigger long and costly restudies.\741\ Pine Gate 
recommends that the Commission: (1) furnish criteria to be used by 
transmission providers in determining whether a restudy is required; 
(2) require transmission providers to limit the scope of restudies if 
only a local impact is anticipated; (3) require transmission providers 
to publish restudy criteria, determinations, and scoping as resources 
for interconnection customers; (4) permit interconnection customers to 
send engineering analyses applying the transmission provider's 
published criteria, which could be used by the transmission provider to 
help decide whether to conduct a restudy, thereby reducing the 
transmission providers' burden; and (5) not require every cluster 
participant to submit additional study deposits until the transmission 
provider determines the need for and scope of any restudy and affected 
cluster participants are notified. Pattern Energy believes that 
transmission providers should be required to develop expedited modeling 
processes to evaluate whether the withdrawal of an interconnection 
request or other allowed modification may cause a full restudy.\742\ 
Pattern Energy argues that such a requirement would allow 
interconnection customers to make better informed decisions about 
withdrawing or modifying interconnection requests.
---------------------------------------------------------------------------

    \740\ Eversource Initial Comments at 14.
    \741\ Pine Gate Initial Comments at 62-63.
    \742\ Pattern Energy Initial Comments at 17.
---------------------------------------------------------------------------

    369. Conversely, a number of commenters recommend that the 
Commission provide flexibility to transmission providers and not adopt 
overly prescriptive requirements specifying how cluster studies must be 
rerun after a restudy is triggered.\743\ MISO encourages the Commission 
to grant maximum flexibility to transmission providers regarding the 
necessity of restudies and the scope of restudies as the situations 
that give rise to restudies are varied and unique.\744\ PJM states that 
it finds acceptable the NOPR's proposal requiring transmission 
providers to specify in their tariffs how cluster studies must be 
rerun, but suggests the Commission avoid being overly prescriptive 
regarding restudies.\745\ Xcel recommends that the Commission not 
propose additional prescriptive requirements on how restudies must be 
performed, but suggests that if there are multiple clusters impacted, 
where each cluster only has ``ready'' projects, the transmission 
provider may combine the clusters into a single cluster for a single 
restudy instead of restudying multiple clusters.\746\
---------------------------------------------------------------------------

    \743\ Bonneville Initial Comments at 9; EEI Initial Comments at 
5; Idaho Power Initial Comments at 4; MISO Initial Comments at 43; 
NYISO Initial Comments at 12; PacifiCorp Initial Comments at 19; PJM 
Initial Comments at 22-23; Xcel Initial Comments at 24.
    \744\ MISO Initial Comments at 43.
    \745\ PJM Initial Comments at 22-23.
    \746\ Xcel Initial Comments at 24.
---------------------------------------------------------------------------

    370. Some commenters support limiting the number of restudies a 
transmission provider may perform within a restudy period.\747\ Ameren 
states that limiting the number of restudies to two within the 150-day 
cluster restudy period seems reasonable, given the size of the many 
interconnection queues and the reported uncertainty of interconnection 
customers in the queue.\748\ Ohio Commission Consumer Advocate concurs 
that conducting a single cluster study and cluster restudy annually may 
reduce the risk of cascading restudies occurring if an interconnection 
customer withdraws from the interconnection queue.\749\
---------------------------------------------------------------------------

    \747\ Ameren Initial Comments at 8; Clean Energy Associations 
Initial Comments at 42; Cypress Creek Initial Comments at 18; Ohio 
Commission Consumer Advocate Initial Comments at 8; Southern Initial 
Comments at 24.
    \748\ Ameren Initial Comments at 8.
    \749\ Ohio Commission Consumer Advocate Initial Comments at 8.
---------------------------------------------------------------------------

    371. A few commenters argue that the Commission should address the 
lack of any limit on restudy requests, stating that this issue is a 
known shortcoming that results in essentially unlimited time and 
resource obligations for interconnection customers.\750\ Southern 
expresses concern that the proposed pro forma LGIP language allows for 
multiple restudies, which would interfere with a one-year timeline 
maximum.\751\
---------------------------------------------------------------------------

    \750\ Clean Energy Associations Initial Comments at 42; Cypress 
Creek Initial Comments at 18 (citing PJM Manual 14A at 26).
    \751\ Southern Initial Comments at 24.
---------------------------------------------------------------------------

    372. A number of commenters do not support a set limit on the 
number of restudies a transmission provider may perform.\752\ 
Bonneville asserts that efforts to prevent excessive restudies (e.g., 
limit of two per month) could be overly prescriptive.\753\ Bonneville 
argues that transmission providers should be afforded the flexibility 
to determine and publish the timing of any restudy, and limits thereto, 
on their OASIS sites to help to facilitate transparency and ensure 
timelines are attainable. NextEra states that experience has shown that 
having a defined and limited number of restudies, such as in MISO's 
three-phase process, can help limit the duration of the study 
process.\754\ However, NextEra contends that it would be too 
restrictive for the Commission to dictate exactly how transmission 
providers should limit the number of restudies, and argues that the 
final rule should instead require that each transmission provider

[[Page 61070]]

propose to the Commission on compliance what rules or processes it will 
use to ensure there is not an undefined and unpredictable number of 
restudies, e.g., whether it will have a fixed number of scheduled 
restudies or some other method to limit the number of restudies and 
associated potential delays. PacifiCorp notes that, because restudies 
are typically triggered through a withdrawal or modification of an 
interconnection request, the transmission provider is responding to 
changes, typically outside of its control, that warrant a restudy and 
undertaking efforts to complete the restudy as efficiently as 
possible.\755\
---------------------------------------------------------------------------

    \752\ Bonneville Initial Comments at 9; MISO Initial Comments at 
42, 43; NextEra Initial Comments at 15; PacifiCorp Initial Comments 
at 20; PJM Initial Comments at 23; Tri-State Initial Comments at 11.
    \753\ Bonneville Initial Comments at 9.
    \754\ NextEra Initial Comments at 15.
    \755\ PacifiCorp Initial Comments at 19.
---------------------------------------------------------------------------

    373. Idaho Power requests clarification surrounding the single 
cluster and cluster restudy process and the suggested limitation of 
allowing only two restudies per month within the 150-day cluster 
restudy period.\756\ Idaho Power states, for example, an entity may 
have three cluster areas requiring three cluster studies, and 
withdrawals from those studies may require more than two simultaneous 
cluster restudies in the same month to prevent delay of any one cluster 
restudy.
---------------------------------------------------------------------------

    \756\ Idaho Power Initial Comments at 4.
---------------------------------------------------------------------------

iii. Commission Determination
    374. We decline to modify the pro forma LGIP to specify how a 
transmission provider conducts cluster restudies and when it must 
conduct a cluster restudy. We find persuasive the arguments of several 
commenters that the Commission allow transmission providers flexibility 
on how and whether to conduct a restudy and the scope and frequency of 
any restudies. The transmission provider is best positioned to 
determine when and how to conduct a restudy, including the scope and 
frequency of restudies, because it determines the need for the 
restudies to maintain the reliability of the transmission system.\757\ 
We agree with commenters like MISO and Xcel that different events can 
trigger restudies, and transmission providers are in the best position 
to determine whether an event warrants a restudy, and if so, what the 
scope of that restudy should be (for example, whether a new study is 
required, or whether only a modification as to certain model data and a 
reanalysis is required).\758\
---------------------------------------------------------------------------

    \757\ National Glossary of Terms Used in NERC Reliability 
Standards, https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
    \758\ MISO Initial Comments at 43; Xcel Initial Comments at 24.
---------------------------------------------------------------------------

    375. As to frequency of restudies, we also agree with PacifiCorp 
that because restudies are typically triggered through a withdrawal of 
an interconnection request, the transmission provider is responding to 
changes, typically outside of its control, that warrant a restudy, and 
thus limiting the number of restudies could hinder the ability of a 
transmission provider to undertake efforts to complete a restudy as 
efficiently as possible.\759\ Because we are not modifying the pro 
forma LGIP to specify how cluster studies must be rerun after restudy 
is triggered, we will also not limit the transmission provider to two 
restudies per month within the 150-calendar day cluster restudy period. 
We agree with commenters like Bonneville, NextEra, and PacifiCorp that 
it would be too restrictive for the Commission to dictate exactly how 
transmission providers should limit the number of restudies.\760\
---------------------------------------------------------------------------

    \759\ PacifiCorp Initial Comments at 19.
    \760\ Id.; Bonneville Initial Comments at 9; NextEra Initial 
Comments at 15.
---------------------------------------------------------------------------

    376. Regarding Idaho Power's request for clarification on the 
suggested limitation of allowing only two restudies per month within 
the 150-calendar day cluster restudy period,\761\ because we are not 
adopting a limit of two restudies per month within the restudy period, 
Idaho Power's clarification request is moot.
---------------------------------------------------------------------------

    \761\ Idaho Power Initial Comments at 4.
---------------------------------------------------------------------------

n. Exceptions to the Cluster Study Process
i. NOPR Proposal
    377. In the NOPR, the Commission sought comment on whether there 
should be an option in the pro forma LGIP for transmission providers to 
process some interconnection requests outside of the annual cluster 
study process, and if so, in what circumstances and on what time frame 
(for completion of the study), and on what priority compared to any 
active clusters.\762\
---------------------------------------------------------------------------

    \762\ NOPR, 179 FERC ] 61,194 at P 79.
---------------------------------------------------------------------------

ii. Comments
    378. Several parties generally support an option in the pro forma 
LGIP for some interconnection requests to be processed outside of the 
annual cluster study process,\763\ with some commenters supporting such 
an option only under specific circumstances.\764\ For example, 
[Oslash]rsted argues that such an option could be beneficial in the 
case of a stand alone network upgrade built to serve a single 
interconnection customer that will not impact the cluster.\765\ Some 
commenters suggest establishing a separate process outside of the 
cluster study process to expedite certain interconnection 
requests.\766\ Several commenters contend that an option to study 
interconnection requests outside of clusters would be particularly 
beneficial as more renewable generating facilities are added to the 
resource mix.\767\ Two commenters support exceptions for replacement 
resources specifically.\768\ A few commenters argue that the Commission 
should allow transmission providers to separately or individually study 
certain interconnection requests that are not geographically or 
electrically relevant to other interconnection requests in the 
interconnection queue.\769\
---------------------------------------------------------------------------

    \763\ AES Initial Comments at 10; Fervo Energy Initial Comments 
at 3; [Oslash]rsted Initial Comments at 9; Tri-State Initial 
Comments at 11.
    \764\ AEP Initial Comments at 19, 42; APPA-LPPC Initial Comments 
at 15; Clean Energy Associations Initial Comments at 21; CREA and 
NewSun Initial Comments at 49; Energy Keepers Initial Comments at 4-
5; Eversource Initial Comments at 14; Iowa Commission Initial 
Comments at 3; Northwest and Intermountain Initial Comments at 7; 
UMPA Initial Comments at 3-4; Xcel Initial Comments at 24.
    \765\ [Oslash]rsted Initial Comments at 9.
    \766\ Clean Energy Associations Initial Comments at 21; Iowa 
Commission Initial Comments at 4; Navajo Utility Initial Comments at 
13; UMPA Initial Comments at 4.
    \767\ AEP Initial Comments at 19-20; Clean Energy Associations 
Initial Comments at 21; ENGIE Reply Comments at 2; Iowa Commission 
Initial Comments at 4.
    \768\ AEP Initial Comments at 19; Clean Energy Associations 
Initial Comments at 21.
    \769\ Energy Keepers Initial Comments at 4-5; Eversource Initial 
Comments at 14.
---------------------------------------------------------------------------

    379. Additionally, APPA-LPPC request that the Commission recognize 
that there are transmission providers, principally in rural communities 
or where the transmission system provides limited opportunities for 
advantageous interconnections, where there are too few interconnection 
requests to justify a cluster study approach.\770\ In these cases, 
APPA-LPPC recommend that the Commission provide for a self-executing 
``opt out,'' permitting the transmission providers to continue to study 
interconnection requests on a serial basis.
---------------------------------------------------------------------------

    \770\ APPA-LPPC Initial Comments at 14-15.
---------------------------------------------------------------------------

    380. Northwest and Intermountain recommend a limited exception to 
the cluster study process requirement to allow existing interconnection 
customers seeking to make changes to their proposed generating 
facilities to be processed outside of the cluster study process where 
the proposed change had no demonstrable incremental impact on the 
transmission system.\771\
---------------------------------------------------------------------------

    \771\ Northwest and Intermountain Initial Comments at 7-8.
---------------------------------------------------------------------------

    381. Xcel argues that proposed generating facilities needed to 
serve load should be allowed to be processed

[[Page 61071]]

outside of the annual cluster study process.\772\ AEP argues that 
transmission providers with a reserve margin obligation must have the 
ability to prioritize the interconnection of needed capacity in the 
interconnection process.\773\
---------------------------------------------------------------------------

    \772\ Xcel Initial Comments at 24.
    \773\ AEP Initial Comments at 42.
---------------------------------------------------------------------------

    382. Iowa Commission argues that state commissions should have the 
ability to require studies outside of annual cluster studies, which 
would help increase the availability of needed generation for resource 
adequacy and maintain local reliability needs, particularly as large 
intermittent generating facilities are interconnecting to the system at 
a rapid pace.\774\ Iowa Commission explains that such studies could 
potentially address increased transmission system stability and also 
minimize future transmission costs because of the ``transient nature'' 
of some load and resource changes.
---------------------------------------------------------------------------

    \774\ Iowa Commission Initial Comments at 4.
---------------------------------------------------------------------------

    383. Similarly, UMPA contends that the Commission should require a 
process outside of the annual cluster study process to expedite 
interconnection requests that are beyond the exploration phase and 
ready for development.\775\ UMPA explains that some load serving 
entities search for potential resources to meet their integrated 
resource plan based on a request for proposal or certain competitive 
criteria, but are then confronted with a choice among proposed 
generating facilities that meet the criteria but are lower in the 
interconnection queue, or proposed generating facilities that do not 
satisfy the criteria, but are higher in the interconnection queue. 
Therefore, UMPA argues that it would be helpful to a load serving 
entity with a development-ready generating facility to be able to enter 
into a parallel process outside of the annual cluster study process in 
order to expedite an interconnection request.
---------------------------------------------------------------------------

    \775\ UMPA Initial Comments at 3-4.
---------------------------------------------------------------------------

    384. AEP also suggests that RTOs/ISOs that have consolidated their 
small and large generator interconnection procedures into a single 
generator interconnection procedure should be permitted to propose that 
all or some smaller-sized generating facilities, such as 20 MW or 
smaller generating facilities, would be ``too small'' to need to be 
included in the cluster.\776\
---------------------------------------------------------------------------

    \776\ AEP Initial Comments at 19.
---------------------------------------------------------------------------

    385. Other commenters believe that any exceptions to the cluster 
study process requirement should be very limited.\777\ NRECA asserts 
that if the final rule provides for any interconnection requests to be 
processed outside the annual cluster study process, it should be 
limited to a narrow category of interconnection requests, such as 
emergency replacements of failed equipment driven by near-term 
reliability needs.\778\ MISO asserts that there should be very limited 
exceptions, explaining that it has limited its non-queue 
interconnection requests to those that are associated with existing 
generating facilities that do not seek to add new or additional 
interconnection service, or small interconnection requests.\779\ 
Outside of those limited exceptions, MISO states that it does not 
support processing any other interconnection requests outside of the 
interconnection queue.\780\
---------------------------------------------------------------------------

    \777\ ENGIE Initial Comments at 3; MISO Initial Comments at 44; 
NRECA Initial Comments at 19-20.
    \778\ NRECA Initial Comments at 20.
    \779\ MISO Initial Comments at 44. MISO states that these 
limited exceptions are Surplus Interconnection Requests (MISO, FERC 
Electric Tariff, attach. X, section 3.2.3 (158.0.0)), a request for 
Generating Facility Replacement (MISO, FERC Electric Tariff, attach. 
X, section 3.7 (158.0.0)), and Fast Track Processing that is 
available to Small Generating Facilities under 5 MW (MISO, FERC 
Electric Tariff, attach. X, art. 14 (158.0.0)). Id. n.100.
    \780\ Id. at 44.
---------------------------------------------------------------------------

    386. ENGIE recommends that exceptions be limited to requests that 
``need[ ] to be studied outside of the cluster process, e.g., 
transmission planning and state or public policy issues.'' \781\ ENGIE 
states that it is possible that there may be other exceptions made in 
emergency situations, in which case, the granting of exceptions should 
be very limited in scope, subject to transparent criteria, and the 
rationale made publicly available. ENGIE further recommends that every 
interconnection request, including emergency requests, enter through 
the cluster request window, but that an emergency request be 
accelerated if it meets the pre-determined and publicly available 
requirements.
---------------------------------------------------------------------------

    \781\ ENGIE Initial Comments at 3.
---------------------------------------------------------------------------

    387. A number of commenters oppose an option to process 
interconnection requests outside of the annual cluster study 
process.\782\ A few parties argue that maintaining an option to process 
interconnection requests outside of the annual cluster study process 
would likely create an administrative burden for transmission providers 
without a clear benefit.\783\ Some commenters assert that processing 
certain interconnection requests outside of the interconnection queue 
could increase the time needed to complete the cluster studies or could 
increase restudies.\784\
---------------------------------------------------------------------------

    \782\ Bonneville Initial Comments at 9; Enel Initial Comments at 
19; PacifiCorp Initial Comments at 21; PJM Initial Comments at 23; 
PPL Initial Comments at 12.
    \783\ Enel Initial Comments at 19; PacifiCorp Initial Comments 
at 21; PJM Initial Comments at 23.
    \784\ Bonneville Initial Comments at 9; Enel Initial Comments at 
19; NRECA Initial Comments at 20.
---------------------------------------------------------------------------

    388. Some commenters express concern that such an option could 
become overly used or abused.\785\ Enel asserts that if interconnection 
requests could be accepted for processing outside the annual cluster 
study process, especially on an individual basis, there would be a high 
degree of interest because this would allow interconnection customers 
to avoid being allocated the costs of regional upgrades that result 
from many cluster studies.\786\ Bonneville asserts that permitting an 
interconnection request to be processed outside of the annual cluster 
study process would create a ``perverse incentive'' for some 
interconnection customers to forgo the cluster study process to avoid 
cluster study requirements.\787\
---------------------------------------------------------------------------

    \785\ Bonneville Initial Comments at 9-10; Enel Initial Comments 
at 19; MISO Initial Comments at 44; NRECA Initial Comments at 20.
    \786\ Enel Initial Comments at 19.
    \787\ Bonneville Initial Comments at 9-10.
---------------------------------------------------------------------------

    389. OMS states that it has considered the benefits of some sort of 
a ``fast-lane process'' for resources that are more ``certain,'' like 
those that have received all necessary permits and regulatory 
approvals.\788\ OMS states that use of such a mechanism may be 
important or necessary in the future to address reliability concerns, 
but OMS explains that it is neutral on the proposal because bypassing 
the interconnection queue invites a myriad of potential unintended 
consequences that might not outweigh the value OMS otherwise envisions 
in this type of mechanism.
---------------------------------------------------------------------------

    \788\ OMS Initial Comments at 8.
---------------------------------------------------------------------------

    390. PacifiCorp states that the Commission's proposal on this topic 
is not clear.\789\ PacifiCorp states that, if the NOPR refers to an 
interconnection customer's ability to request surplus or provisional 
interconnection service or an informational interconnection study, 
PacifiCorp supports maintaining these options. However, PacifiCorp 
requests the Commission clarify that requests for such service will be 
evaluated in the order that completed interconnection requests are 
received. PacifiCorp states that it does not currently support 
expanding non-cluster service and study offerings.
---------------------------------------------------------------------------

    \789\ PacifiCorp Initial Comments at 21.

---------------------------------------------------------------------------

[[Page 61072]]

    391. Regarding under what time frame and at what priority 
interconnection requests should be studied outside of the cluster study 
process, as compared to any active clusters, Fervo Energy recommends a 
270-day time frame for completion of the study with secondary priority 
to the active cluster studies.\790\
---------------------------------------------------------------------------

    \790\ Fervo Energy Initial Comments at 3.
---------------------------------------------------------------------------

iii. Commission Determination
    392. We decline to include an additional option in the pro forma 
LGIP for transmission providers to process some interconnection 
requests outside the annual cluster study process adopted in this final 
rule. We find that establishing in the pro forma LGIP a separate 
interconnection process outside the cluster study process could detract 
from transmission providers' efforts to efficiently process cluster 
studies--a point persuasively argued by commenters.\791\ A separate set 
of interconnection studies outside of the cluster study process could 
cause transmission providers to divert resources away from cluster 
studies and cluster restudies. Such diversion could hinder the 
transmission provider from meeting the cluster study and cluster 
restudy deadlines adopted in this final rule, which would be 
insufficient to ensure that interconnection customers are able to 
interconnect to the transmission system in a reliable, efficient, 
transparent, and timely manner. We also find that such an option in the 
pro forma LGIP would be too open-ended, as it would leave a significant 
amount of discretion to the transmission provider to create new study 
processes for processing any types of interconnection requests it 
chooses outside the cluster study process and could therefore result in 
a separate but unduly discriminatory interconnection process. We 
further find that establishing such an open-ended option in the pro 
forma LGIP could create an incentive for some interconnection customers 
to forgo the cluster study process, which could increase the time and 
resources needed for transmission providers to complete the cluster 
studies or could increase restudies.\792\
---------------------------------------------------------------------------

    \791\ Bonneville Initial Comments at 9; Enel Initial Comments at 
19; NRECA Initial Comments at 20; PacifiCorp Initial Comments at 21; 
PJM Initial Comments at 23.
    \792\ Bonneville Initial Comments at 9-10; Enel Initial Comments 
at 19; MISO Initial Comments at 44; NRECA Initial Comments at 20; 
PJM Initial Comments at 23.
---------------------------------------------------------------------------

    393. A number of commenters see benefits to establishing an option 
in the pro forma LGIP for particular types of interconnection requests 
to be processed outside of the annual cluster study process, such as 
for generator replacement, projects ready for development, emergency 
replacements, for certain special circumstances, or for transmission 
providers who have too few interconnection requests to justify a 
cluster study approach.\793\ However, we are not persuaded that 
establishing such processes in the pro forma LGIP is necessary to 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner. We believe that processing such one-off interconnection 
requests will be needed less often under the cluster study process 
adopted in this final rule, and therefore, any benefits that exist to 
processing some interconnection requests outside a transmission 
provider's interconnection process may be outweighed by the benefit of 
allowing transmission providers to conduct cluster studies efficiently 
without diverting resources to a separate set of studies.
---------------------------------------------------------------------------

    \793\ AEP Initial Comments at 19; APPA-LPPC Initial Comments at 
14-15; Clean Energy Associations Initial Comments at 21; Energy 
Keepers Initial Comments at 4-5; Navajo Utility Initial Comments at 
13; NRECA Initial Comments at 19-20; UMPA Initial Comments at 3-4.
---------------------------------------------------------------------------

    394. In response to the Iowa Commission's argument that state 
commissions should be able to require studies outside of annual cluster 
studies, we similarly find that any such studies would divert a 
transmission provider's resources away from conducting the cluster 
studies and cluster restudies.
    395. Regarding AEP's suggestion that those RTOs/ISOs that have 
consolidated their small and large generator interconnection procedures 
should be permitted to propose that all or some smaller-sized 
generating facilities would be ``too small'' to be included in the 
cluster, we note that the Commission did not propose the cluster study 
process for small generating facilities subject to the pro forma SGIP.
    396. Finally, because we are not revising the pro forma LGIP to add 
a new option for some interconnection requests to be processed outside 
of the annual cluster study process, we find moot those comments on the 
time frame and priority of interconnection requests studied outside of 
the cluster study process.\794\ In response to PacifiCorp,\795\ we 
clarify that requests for surplus interconnection service, or an 
optional interconnection study, will continue to be processed as 
received and outside of the cluster study process, and that this does 
not entail an expansion of non-cluster service and study offerings.
---------------------------------------------------------------------------

    \794\ Fervo Energy Initial Comments at 3; Tri-State Initial 
Comments at 12; Xcel Initial Comments at 24-25.
    \795\ PacifiCorp Initial Comments at 21.
---------------------------------------------------------------------------

o. Other Comments
i. Comments
    397. Some entities recommend automation or standardization of the 
interconnection queue process and studies.\796\ NextEra states that the 
proposed cluster study process time frame requires significant 
information technology and personnel resources.\797\ NextEra argues 
that, despite the lack of such a proposal in the NOPR, automation of 
the interconnection queue process and studies is likely the key to 
compressing interconnection process timelines. NextEra encourages the 
Commission to convene a technical conference or other process to focus 
on the root causes of interconnection study delays as well as the 
potential to accelerate the interconnection queue process through 
enhanced automation.
---------------------------------------------------------------------------

    \796\ ACORE Initial Comments at 4-5; Clean Energy Associations 
Initial Comments at 26; NextEra Initial Comments at 13.
    \797\ NextEra Initial Comments at 13-14.
---------------------------------------------------------------------------

    398. Several commenters argue that the Commission should require 
transmission providers to provide more cost information to 
interconnection customers throughout the interconnection process.\798\ 
Clean Energy Associations and SEIA argue that cluster studies should 
also ensure that interim cost information is made available to 
interconnection customers so that they can make more informed decisions 
earlier in the interconnection process, which will in turn lead to a 
more efficient interconnection process overall.\799\ Clean Energy 
Associations argue that as part of the cluster studies provided to 
interconnection customers prior to their receiving facilities studies, 
the Commission should require transmission providers to provide 
interconnection customers with cost estimates for the upgrades required 
if they were to request ERIS or NRIS (or long-term firm transmission 
service), respectively--and coupled with minimum thresholds for 
materiality (such as distribution factor) and transparency regarding 
how these costs are derived (detailing the assumptions and criteria 
that will be used).\800\ Clean Energy Associations also suggest that 
the Commission should provide concrete direction regarding how

[[Page 61073]]

differing service types should be studied, and what outcome an 
interconnection customer should receive for making the necessary 
transmission system improvements to obtain that interconnection 
service.\801\ AEE similarly believes that additional reforms are needed 
to bring more transparency and predictability to interconnection costs, 
and without this transparency and predictability, interconnection 
customers face continued risks of unjust and unreasonable 
interconnection study results that derail or delay interconnection 
requests and cause increased costs.\802\
---------------------------------------------------------------------------

    \798\ ACE-NY Initial Comments at 4; Clean Energy Associations 
Initial Comments at 20; Enel Initial Comments at 18; SEIA Initial 
Comments at 8.
    \799\ Clean Energy Associations Initial Comments at 20; SEIA 
Initial Comments at 8.
    \800\ Clean Energy Associations Initial Comments at 27.
    \801\ Id. at 29.
    \802\ AEE Initial Comments at 12.
---------------------------------------------------------------------------

    399. Affected Interconnection Customers state that the Commission 
should permit interconnection customers to use independent studies to 
demonstrate whether the request for limited interconnection service 
would result in stability, short circuit, thermal, and/or voltage 
issues, if the transmission provider or transmission owner is unable to 
complete the studies on time.\803\ Affected Interconnection Customers 
argue that allowing interconnection customers to use any available 
resources to conduct these studies would enable already built 
interconnection facilities to flow power onto the system, as long as 
studies show that such interim services will not harm the system.
---------------------------------------------------------------------------

    \803\ Affected Interconnection Customers Initial Comments at 21.
---------------------------------------------------------------------------

    400. Clean Energy Associations ask that in a final rule, the 
Commission adopt a cost threshold (in terms of the anticipated upgrade 
cost relative to distribution factor) beyond which upgrades should be 
evaluated in the next near-term transmission planning process. 
Similarly, Clean Energy Associations argue that cumulative congestion 
issues should also be addressed via the transmission planning 
process.\804\
---------------------------------------------------------------------------

    \804\ Clean Energy Associations Initial Comments at 29.
---------------------------------------------------------------------------

ii. Commission Determination
    401. We decline to adopt the remainder of the proposals advocated 
for in the comments regarding our requirement for transmission 
providers to use a cluster study process. We decline to adopt three of 
these proposals because they are outside the scope of the NOPR: (1) 
NextEra's request to require or standardize automated processing of 
interconnection requests; \805\ (2) Clean Energy Associations' argument 
that the Commission should adopt a cost threshold beyond which upgrades 
should be evaluated in the next near-term transmission planning 
process; \806\ and (3) Clean Energy Associations' argument that the 
Commission should provide concrete direction regarding how differing 
service types should be studied, and what outcome an interconnection 
customer should receive for making the necessary transmission system 
improvements to obtain that interconnection service.\807\
---------------------------------------------------------------------------

    \805\ NextEra Initial Comments at 14. We also decline to convene 
a technical conference to explore the causes of interconnection 
study delays and the potential to accelerate the interconnection 
queue process through enhanced automation. As discussed above, we 
have adequate record of the causes of interconnection study delays 
to fashion a remedy with the combination of reforms we adopt in this 
final rule.
    \806\ Clean Energy Associations Initial Comments at 29.
    \807\ Id.
---------------------------------------------------------------------------

    402. Regarding Affected Interconnection Customers' arguments 
discussing the use of independent studies, we note that interconnection 
customers can use independent resources during the interconnection 
process. However, the results of independent studies will not be 
binding on transmission providers, as the use of studies conducted by 
an interconnection customer cannot ensure that the cluster study 
process results in a just, reasonable, and not unduly discriminatory or 
preferential outcome for all interconnection customers in the cluster. 
In addition, transmission providers must be able to conduct the 
necessary studies to maintain the reliability of their transmission 
system.
    403. We will not require transmission providers to provide 
additional cost information to interconnection customers that is not 
already required to be provided pursuant to the pro forma LGIP, as 
modified by this final rule. For example, revised pro forma LGIP 
sections 3.4.5 (Customer Engagement Window) and 8.1 (Interconnection 
Facilities Study Agreement) require the transmission provider to 
provide the interconnection customer with a good faith estimate of the 
costs of the cluster study and the interconnection facility study, 
respectively. Similarly, revised pro forma LGIP sections 7.3 (Scope of 
Cluster Study) and 8.2 (Scope of Interconnection Facilities Study) 
require the transmission provider to provide cost estimates for 
interconnection facilities and network upgrades. It is unclear what 
other ``interim cost information'' \808\ Clean Energy Associations want 
transmission providers to provide, nor the value of such information 
vis-[agrave]-vis the burden on transmission providers to develop it.
---------------------------------------------------------------------------

    \808\ Id. at 20.
---------------------------------------------------------------------------

    404. Clean Energy Associations argue that as part of the cluster 
studies provided to interconnection customers prior to receiving 
facilities studies, the Commission should require transmission 
providers to provide interconnection customers with cost estimates for 
the upgrades required if they were to request ERIS or NRIS. Section 3.2 
of the pro forma LGIP provides that an interconnection customer 
requesting NRIS may also request that it be concurrently studied for 
ERIS, up to the point when the facility study agreement is executed. As 
the pro forma LGIP already provides interconnection customers the 
ability to have both ERIS and NRIS studied concurrently, we find Clean 
Energy Associations' request moot.
3. Allocation of Cluster Study Costs
a. NOPR Proposal
    405. In the NOPR, the Commission proposed to require transmission 
providers to allocate the shared costs of cluster studies as follows: 
90% of the applicable study costs allocated pro rata to interconnection 
customers based on requested MWs included in the applicable cluster, 
and 10% of the applicable study costs allocated per capita to 
interconnection customers based on the number of interconnection 
requests included in the applicable cluster.\809\ The Commission 
preliminarily found that this allocation of the costs of cluster 
studies would result in just and reasonable Commission-jurisdictional 
rates because it appropriately recognizes that the MW size of a cluster 
has a dramatic impact on the cost of studying the cluster, while also 
recognizing that the number of interconnection requests included in the 
cluster also impacts the cost of studying the cluster, but to a lesser 
degree. The Commission sought comment on whether a different cost 
allocation approach may be appropriate or whether each transmission 
provider should be provided additional flexibility to propose a cost 
allocation approach on compliance with any final rule.\810\
---------------------------------------------------------------------------

    \809\ NOPR, 179 FERC ] 61,194 at P 82.
    \810\ Id. P 83.
---------------------------------------------------------------------------

b. Comments
i. Comments in Support
    406. Multiple commenters support the proposal.\811\ Clean Energy 
Buyers note

[[Page 61074]]

that certainty and consistency in cost allocation for interconnection 
studies will be helpful for interconnection customers that site 
generating facilities in more than one region.\812\ Idaho Power adds 
that a uniform cost allocation would prevent interconnection customers 
from ``shopping around'' for the best price for larger generating 
facility locations.\813\ Duke Southeast Utilities note that Duke 
Carolinas Utilities' currently effective LGIP/LGIA contains the same 
90/10 cost allocation, which it states provides a balanced and 
equitable study cost allocation based on the Commission's cost 
causation principle.\814\ Duke Southeast Utilities assert that the 
proposed allocation aligns with study deposits that would be submitted 
based on varying assumptions around the number and size of 
interconnection requests submitted into the cluster study process.
---------------------------------------------------------------------------

    \811\ Clean Energy Buyers Initial Comments at 8; Consumers 
Energy Initial Comments at 4; Cypress Creek Initial Comments at 19; 
Duke Southeast Utilities Initial Comments at 8-9; Enel Initial 
Comments at 20; Fervo Energy Initial Comments at 3; Idaho Power 
Initial Comments at 5; Interwest Initial Comments at 5; Public 
Interest Organizations Initial Comments at 31; R Street Initial 
Comments at 11; Tri-State Initial Comments at 3, 12.
    \812\ Clean Energy Buyers Initial Comments at 8-9.
    \813\ Idaho Power Initial Comments at 5.
    \814\ Duke Southeast Utilities Initial Comments at 8-9.
---------------------------------------------------------------------------

ii. Comments in Opposition
    407. Several commenters oppose the proposal. For instance, National 
Grid and NRECA argue that any predetermined study cost allocation 
method will produce results that do not comport with cost 
causation.\815\ National Grid gives the example of a 20 MW generating 
facility that has unique or complex engineering features at a 
particular point of interconnection that may require considerably more 
time to conduct a study than a much larger 100 MW generating facility; 
in this situation, according to National Grid, the 90/10 cost 
allocation methodology proposed in the NOPR would not align with cost 
causation, a problem that would be exacerbated if the interconnection 
customer withdraws the interconnection request.\816\ National Grid 
asserts that a predetermined cost allocation risks undermining 
competitive pressures in the interconnection process, which it states 
should be retained to the maximum extent possible consistent with 
revisions to mitigate the existing interconnection queue 
inefficiencies. Similarly, Xcel and NextEra argue that the size of the 
interconnection request does not impact the study costs by a 9:1 ratio 
compared to the number of interconnection requests, noting that the 
size of the interconnection request does not materially impact the time 
to add the generating facility to the model or time to design the 
interconnecting substation.\817\ NRECA adds that the Commission has not 
produced data showing the fixed costs of processing an interconnection 
request or a precise linear correlation between generating facility 
size and study costs.\818\ rPlus argues that the proposed 90/10 cost 
allocation is ``unduly discriminatory toward pumped storage, and wholly 
disincentivizes large capacity projects.'' \819\ rPlus argues that the 
assertion that the MW size of a cluster study is significantly more 
impactful on the cost and effort required to perform the study is 
incorrect. rPlus states that the number of interconnection requests and 
the cluster size are both burdensome for the study process, as each 
generating facility requires its own project management, technical 
review, study implementation, and deliverability assessment.\820\ SDG&E 
and SoCal Edison agree that a 90/10 cost allocation would 
inappropriately burden larger generating facilities with higher study 
costs, as the level of effort to study an interconnection request is 
driven more by complexity around the point of interconnection and is 
not strongly correlated to the size of the generating facility.\821\
---------------------------------------------------------------------------

    \815\ National Grid Initial Comments at 16; NRECA Initial 
Comments at 8.
    \816\ National Grid Initial Comments at 16-17.
    \817\ NextEra Initial Comments at 16; Xcel Initial Comments at 
25.
    \818\ NRECA Initial Comments at 21.
    \819\ rPlus Initial Comments at 5.
    \820\ Id.; Hydropower Commenters Initial Comments at 27.
    \821\ SDG&E Initial Comments at 7; SoCal Edison Initial Comments 
at 15.
---------------------------------------------------------------------------

iii. Alternatives and Requests for Flexibility
    408. Several commenters put forth alternatives to the NOPR 
proposal. For instance, some commenters generally contend that 
transmission providers should allocate study costs based on the 
proposed generating facility's impact on the overall study, measured by 
the time and resources expended on a particular generating facility 
within the study.\822\ National Grid asserts that this process would be 
consistent with the current serial study approach, which directly 
correlates cost responsibility to cost causation.\823\ AES argues that 
the final rule's cost allocation framework should reflect the reality 
that study costs are not only a function of generating facility size, 
but also the location of the generating facility and the degree to 
which that location is constrained.\824\
---------------------------------------------------------------------------

    \822\ AES Initial Comments at 12; Clean Energy Associations 
Initial Comments at 23; National Grid Initial Comments at 17.
    \823\ National Grid Initial Comments at 17.
    \824\ AES Initial Comments at 12.
---------------------------------------------------------------------------

    409. Several commenters argue that the Commission should allocate 
cluster study costs based solely on the number of interconnection 
requests in the cluster.\825\ Ameren and SDG&E state that, in their 
experience, study costs are not based on the size of the proposed 
generating facilities.\826\ In contrast, Fervo Energy argues against 
allocating study costs evenly to all interconnection customers within a 
cluster, asserting that it is ``not at all clear'' how this proposal is 
just and reasonable, as it strays away from allocating costs on a pro 
rata basis based on requested MWs.\827\
---------------------------------------------------------------------------

    \825\ Ameren Initial Comments at 11; SDG&E Initial Comments at 
7; SoCal Edison Initial Comments at 15-16.
    \826\ Ameren Initial Comments at 11; SDG&E Initial Comments at 
7.
    \827\ Fervo Energy Reply Comments at 4.
---------------------------------------------------------------------------

    410. CAISO argues that the proposal appears arbitrary and 
capricious because the Commission does not adequately explain the basis 
for the 90% to 10% ratio.\828\ CAISO asserts that the 10% allocation is 
so small as to be de minimis, yet it still increases the administrative 
burden to allocate the cluster study costs. CAISO argues that it would 
be much simpler and easier if transmission providers simply allocated 
all cluster study costs based on the MW capacity alone.
---------------------------------------------------------------------------

    \828\ CAISO Initial Comments at 12.
---------------------------------------------------------------------------

    411. Enel argues that there are study phases where it would be more 
appropriate to assign study costs to individual interconnection 
requests, ``such as the [f]acilities [s]tudy for upgrades assigned to 
only a single customer.'' \829\ Enel argues that a 90/10 study cost 
split may disproportionately exclude very small generating facilities 
which still require modeling from study cost responsibility, and 
suggests that a minimum MW size be assumed, such as was used to set the 
minimum study deposit in proposed pro forma LGIP section 3.1.1.1.
---------------------------------------------------------------------------

    \829\ Enel Initial Comments at 20.
---------------------------------------------------------------------------

    412. Several commenters argue for a cost allocation of 50% of the 
study costs based on requested MW and 50% based on the number of 
interconnection requests in the cluster.\830\ NextEra states that, 
based on its experience, it takes comparable time and effort to study a 
small proposed generating facility as a large one.\831\ NextEra and 
SoCal Edison argue that allocating study costs based

[[Page 61075]]

mostly on the MW size would likely cause some cross-subsidies from 
interconnection customers submitting large proposed generating 
facilities to those submitting smaller ones.\832\ SEIA notes that the 
MW size of the cluster may be artificially inflated when certain 
interconnection customers submit multiple exploratory requests, and 
recommends a 50/50 cost allocation to deter such requests.\833\ SEIA 
argues that, similar to CAISO's study cost allocation, the Commission 
should structure the cost allocation so that interconnection customers 
with multiple interconnection requests are responsible for a greater 
share of the study costs.\834\
---------------------------------------------------------------------------

    \830\ Hydropower Commenters Initial Comments at 26-27; NextEra 
Initial Comments at 16; Pattern Energy Initial Comments at 18-19; 
rPlus Initial Comments at 5; SEIA Initial Comments at 9-10.
    \831\ NextEra Initial Comments at 16.
    \832\ Id.; SoCal Edison Initial Comments at 15-16.
    \833\ SEIA Initial Comments at 10.
    \834\ Id. (citing Cal. Indep. Sys. Operator, Inc., 140 FERC ] 
61,070, at P 4 (2012)).
---------------------------------------------------------------------------

    413. Clean Energy Associations add that cluster studies should be 
conducted in subgroups based on electrical relevance, and that study 
costs related to each subgroup should be tracked independently and 
allocated only among those interconnection customers within that 
subgroup.\835\
---------------------------------------------------------------------------

    \835\ Clean Energy Associations Initial Comments at 23.
---------------------------------------------------------------------------

    414. Multiple commenters argue that the Commission should not 
impose a specific cluster study cost allocation, but instead allow 
transmission providers flexibility in proposing their own cost 
allocation methods.\836\ For example, APPA-LPPC argue that the use of a 
``one-size-fits-all'' approach may result in unreasonable results in 
certain circumstances.\837\ APPA-LPPC assert that weighting the 
allocation of cluster study costs based on MWs may unfairly burden 
interconnection customers proposing large generating facilities in 
regions where a cluster is likely to include a large number of 
relatively small proposed generating facilities and a small number of 
large proposed generating facilities because study costs do not 
necessarily track linearly with generating facility size.
---------------------------------------------------------------------------

    \836\ AES Initial Comments at 12; Ameren Initial Comments at 11; 
APPA-LPPC Initial Comments at 3; Bonneville Initial Comments at 10; 
Clean Energy Associations Initial Comments at 24; Dominion Initial 
Comments at 19; Indicated PJM TOs Initial Comments at 18-19; ISO-NE 
Initial Comments at 25; MISO Initial Comments at 45; National Grid 
Initial Comments at 16; NextEra Initial Comments at 16-17; NRECA 
Initial Comments at 8; NYISO Initial Comments at 13; Omaha Public 
Power Initial Comments at 5; [Oslash]rsted Initial Comments at 9; 
Pattern Energy Initial Comments at 19; PPL Initial Comments at 12; R 
Street Initial Comments at 11; SEIA Initial Comments at 10; Xcel 
Initial Comments at 25.
    \837\ APPA-LPPC Initial Comments at 16.
---------------------------------------------------------------------------

    415. Several commenters argue that RTOs/ISOs should be able to 
retain their existing cluster study cost allocations, where applicable, 
because those cost allocations accomplish the purpose of the 
Commission's proposal to equitably allocate study costs among 
interconnection customers.\838\
---------------------------------------------------------------------------

    \838\ Dominion Initial Comments at 19; Indicated PJM TOs Initial 
Comments at 18-19; ISO-NE Initial Comments at 25; MISO Initial 
Comments at 45; NYISO Initial Comments at 14; Omaha Public Power 
Initial Comments at 5; PJM Initial Comments at 35; SPP Initial 
Comments at 7. In response, Fervo Energy cautions against permitting 
transmission providers too much flexibility, arguing that this opens 
the door for undue discrimination against interconnection customers. 
Fervo Energy Reply Comments at 4.
---------------------------------------------------------------------------

c. Commission Determination
    416. We adopt the NOPR proposal, with modification, to revise 
section 13.3 (Obligation for Study Costs) of the pro forma LGIP to 
allow each transmission provider to propose its own study cost 
allocation ratio for allocating the shared costs of cluster studies 
between a per capita basis and pro rata by MW, provided that: between 
10% and 50% of study costs must be allocated on a per capita basis, 
with the remainder (between 90% and 50%) allocated pro rata by MW. 
Under this revised provision, a transmission provider may propose to 
retain its existing study cost allocation ratio if it falls within this 
range and meets the requirements of this final rule.
    417. We are persuaded by comments arguing that it is appropriate to 
allow transmission providers a degree of flexibility in proposing on 
compliance the method for allocating study costs in their tariff to 
adapt to their specific regional circumstances and help avoid 
unreasonable outcomes. Some commenters assert that the NOPR-proposed 
90%-10% allocation could in some instances unduly burden larger 
generating facilities, such as when a cluster includes a large number 
of interconnection requests representing relatively small generating 
facilities and a small number of large generating facilities.\839\ 
Conversely, other commenters caution that straying too far from the 
NOPR proposal for a 90%-10% allocation could disproportionately burden 
smaller generating facilities, given the role that size may play in 
determining study costs.\840\ Accordingly, we believe that granting 
transmission providers the flexibility to propose in their tariff the 
study cost allocation appropriate to their region, within the limits 
detailed above, strikes a better balance than the NOPR proposal.
---------------------------------------------------------------------------

    \839\ APPA-LPPC Initial Comments at 16.
    \840\ Fervo Energy Reply Comments at 4-5.
---------------------------------------------------------------------------

    418. The revised study cost allocation requirements that we adopt 
in this final rule recognize that cluster study costs are impacted by 
both the number of interconnection requests in a cluster and the size 
of the proposed generating facilities in each cluster. We find that 
requiring transmission providers to allocate between 10% and 50% of 
cluster study costs on a per capita basis is just and reasonable 
because it ensures that interconnection customers that propose smaller 
generating facilities or submit multiple interconnection requests to 
explore different interconnection scenarios for a single proposed 
generator adequately contribute to study costs, particularly given that 
some study costs are incurred independent of the MW size of a specific 
proposed generating facility in a cluster.\841\ Further, we agree with 
commenters that observe that not all study costs track linearly with 
generating facility size because there are other factors, such as the 
point of interconnection selected, that can lead to increasingly 
complex studies and correspondingly higher study costs.\842\ We believe 
that the per capita component of the study cost allocation requirements 
addresses this fact. Requiring a per capita component also ensures that 
an interconnection customer that proposes a large generating facility 
in a cluster of many smaller generating facilities will not bear a 
disproportionate amount of the study costs. We likewise find that 
requiring transmission providers to allocate between 50% and 90% of 
study costs on a pro rata by MW basis prevents a disproportionate 
amount of study costs from being allocated to interconnection customers 
that propose smaller generating facilities in the cluster. The pro rata 
by MW component reflects the fact that, to a significant extent, study 
costs correlate to the total MW size of the cluster. In general, even 
if the number of interconnection requests in each cluster remains 
constant, we expect that a cluster of 10,000 MW will be significantly 
more costly to study than a cluster of 100 MW.\843\ Accordingly, 
requiring that a substantial share of study costs is allocated based on 
each generating facility's contribution to the total MW size of the 
cluster study ensures consistency with cost causation principles.
---------------------------------------------------------------------------

    \841\ SDG&E Initial Comments at 7; SoCal Edison Initial Comments 
at 15.
    \842\ AES Initial Comments at 12; APPA-LPPC Initial Comments at 
16; NRECA Initial Comments at 21.
    \843\ Fervo Initial Comments at 4.
---------------------------------------------------------------------------

    419. We disagree with CAISO that the Commission should require the

[[Page 61076]]

allocation of all cluster study costs based on the MW capacity because 
allocating 10% of study costs on a per capita basis is de minimis and 
not worth the administrative burden. First, this final rule now allows 
transmission providers to allocate up to 50% of costs on a per capita 
basis. Even if a transmission provider chooses to allocate only 10% of 
study costs on a per capita basis, as explained above, we believe that 
this is an important component that is needed to ensure that study 
costs are allocated in a manner that is at least roughly commensurate 
with estimated benefits (i.e., consistent with cost causation). We are 
unpersuaded that the administrative burden associated with allocating a 
potentially small fraction of the study costs among interconnection 
customers in a cluster outweighs the benefits, particularly given that 
nothing in the record demonstrates that those administrative costs are 
significant.
    420. In response to commenters' arguments in favor of a uniform 
study cost allocation method across regions, we find that the benefits 
of allowing transmission providers flexibility to tailor their study 
cost allocation to the specific circumstances of their region outweigh 
the benefits of uniformity cited by commenters, such as consistency and 
preventing ``shopping around.'' We believe that the guardrails that we 
provide in this final rule will ensure just, reasonable, and not unduly 
discriminatory or preferential rates while at the same time addressing 
concerns with the different characteristics of regions. We urge 
stakeholders to engage with transmission providers as part of the 
compliance process as the transmission providers develop their proposed 
study cost allocations.
    421. In response to National Grid, AES, and Clean Energy 
Associations' comments arguing that costs should be allocated based on 
individual calculations of the actual time and resources expended on a 
particular interconnection request, we find that such individual 
calculations would not only increase the administrative burden on 
transmission providers, but also would offer little benefit given the 
cluster study context, which requires transmission providers to 
evaluate multiple interconnection requests simultaneously.\844\ We are 
also unconvinced that a transmission provider could accurately perform 
such calculations because, as explained above, some study costs are 
unrelated to an individual interconnection request and are instead 
incurred as a matter of course as part of studying a cluster of 
interconnection requests.
---------------------------------------------------------------------------

    \844\ AES Initial Comments at 12; Clean Energy Associations 
Initial Comments at 23; National Grid Initial Comments at 17.
---------------------------------------------------------------------------

4. Allocation of Cluster Network Upgrade Costs
a. NOPR Proposal
    422. In the NOPR, the Commission proposed to require transmission 
providers to allocate network upgrade costs to interconnection 
customers within a cluster using a proportional impact method.\845\ The 
Commission also proposed to add the defined term proportional impact 
method to the pro forma LGIP and require transmission providers to 
revise their LGIPs to include the specific technical parameters and 
thresholds of their method for cost allocation. The Commission also 
proposed to require transmission providers to allocate the costs of 
transmission provider's interconnection facilities equally among all 
interconnection customers sharing use of the transmission provider's 
interconnection facilities. The Commission sought comment on: (1) 
whether there are specific types of analyses that the Commission should 
require transmission providers to use to determine the proportional 
impact attributed to an interconnection request, including the benefits 
and drawbacks of any proposed approach; (2) whether there are specific 
types of analyses that the Commission should prohibit because they are 
known to be inaccurate, provide undue discretion to the transmission 
provider, or could otherwise be problematic; (3) whether alternative 
methods to allocate the costs of network upgrades within a cluster, 
such as the proportional capacity method, can be sufficiently accurate 
in certain instances, in a manner consistent with or superior to the 
proposed method; and (4) whether there are some circumstances where the 
proportional capacity method would not be appropriate, such as 
circumstances where there may be potential for discriminatory 
treatment.\846\
---------------------------------------------------------------------------

    \845\ NOPR, 179 FERC ] 61,194 at P 88.
    \846\ Id. P 89.
---------------------------------------------------------------------------

b. Comments
i. General Comments
    423. Several commenters support the proposal.\847\ These commenters 
state that the proposed proportional impact cost allocation method is 
widely used, both by RTOs/ISOs and non-RTO/ISO transmission 
providers,\848\ and ensures that each interconnection customer 
contributes to the cost of network upgrades in proportion to its impact 
on the transmission system.\849\ These commenters assert that other 
options (such as a proportional capacity or a pro rata allocation per 
interconnection request) would be more likely to shift a 
disproportionate share of network upgrade costs to smaller generating 
facilities, which may have less impact on the transmission system.\850\ 
Bonneville and Interwest argue that the proportional impact method 
could also reduce the incentive for interconnection customers to submit 
multiple speculative requests and reduce the amount of cascading 
withdrawals and restudies.\851\ ELCON contends that, should any one 
proposed generating facility in the cluster have an outsized impact on 
the transmission system compared to other proposed generating 
facilities in the cluster, those other proposed generating facilities 
should be protected from exorbitant network upgrade costs to 
accommodate a proposed generating facility that may not be suitably 
located.\852\ CAISO adds

[[Page 61077]]

that it has used distribution factor analysis without controversy.\853\
---------------------------------------------------------------------------

    \847\ ACORE Initial Comments at 8; Ameren Initial Comments at 
12; Avangrid Initial Comments at 31; Cypress Creek Initial Comments 
at 19; Eversource Initial Comments at 15; Fervo Energy Initial 
Comments at 3; Interwest Initial Comments at 16-17; Invenergy 
Initial Comments at 21; NEPOOL Initial Comments at 15; New Jersey 
Commission Initial Comments at 15; Northwest and Intermountain 
Initial Comments at 8; NYTOs Initial Comments at 16; Omaha Public 
Power Initial Comments at 5; Pennsylvania Commission Initial 
Comments at 8-9.
    \848\ For example, several transmission providers support the 
Commission's proposal, and state that they already use a 
proportional impact method or distribution factor analysis. CAISO 
Initial Comments at 13; ISO-NE Initial Comments at 25; MISO Initial 
Comments at 46-47; NYISO Initial Comments at 14; PJM Initial 
Comments at 36; SoCal Edison Initial Comments at 16; Tri-State 
Initial Comments at 12.
    \849\ ACORE Initial Comments at 8; Ameren Initial Comments at 
12; Avangrid Initial Comments at 31; Cypress Creek Initial Comments 
at 19; Eversource Initial Comments at 15; Fervo Energy Initial 
Comments at 3; Interwest Initial Comments at 16-17; Invenergy 
Initial Comments at 21; NEPOOL Initial Comments at 15; New Jersey 
Commission Initial Comments at 15; Northwest and Intermountain 
Initial Comments at 8; NYTOs Initial Comments at 16; Omaha Public 
Power Initial Comments at 5; Pennsylvania Commission Initial 
Comments at 8-9.
    \850\ ACORE Initial Comments at 8; Ameren Initial Comments at 
12; Avangrid Initial Comments at 31; Cypress Creek Initial Comments 
at 19, Eversource Initial Comments at 15; Fervo Energy Initial 
Comments at 3, Interwest Initial Comments at 16-17; Invenergy 
Initial Comments at 21; NEPOOL Initial Comments at 15; New Jersey 
Commission Initial Comments at 15; Northwest and Intermountain 
Initial Comments at 8; NYTOs Initial Comments at 16; Omaha Public 
Power Initial Comments at 5; Pennsylvania Commission Initial 
Comments at 8-9.
    \851\ Bonneville Initial Comments at 10; Interwest Initial 
Comments at 17.
    \852\ ELCON Initial Comments at 9.
    \853\ CAISO Initial Comments at 13.
---------------------------------------------------------------------------

    424. NRECA states that it interprets this proposal to implement--
and not modify, weaken, or permit deviations from--the Commission's 
established policy that transmission costs, including network upgrade 
costs, must be allocated in a manner at least reasonably commensurate 
with estimated benefits.\854\ NRECA states that, based on that 
interpretation of the NOPR's proposal, NRECA believes this method is 
fair to both interconnection customers and transmission providers and 
helps ensure that the costs to implement an interconnection request are 
allocated reasonably commensurate with cost causation and expected 
benefits. NRECA states that the proportional impact method is also 
reasonably transparent and relatively easy for transmission providers 
to implement, explain, and defend.
---------------------------------------------------------------------------

    \854\ NRECA Initial Comments at 22.
---------------------------------------------------------------------------

    425. In response to the Commission's request for comment on whether 
there are circumstances in which the proportional capacity method would 
be appropriate, some commenters argue that the proportional capacity 
method is never appropriate and should be expressly prohibited for 
clusters.\855\ MISO argues that network upgrade cost allocation methods 
that only consider installed capacity without considering the network 
topology do not consider the full picture of what an interconnection 
customer's responsibility for the network upgrade costs should be.\856\ 
Pennsylvania Commission asserts that large generating facilities would 
continue to bear high network upgrade costs and would have an incentive 
to interconnect wisely, while small generating facilities, which are 
becoming the norm in interconnection queues, would not.\857\ 
Pennsylvania Commission contends that this would create a subsidy 
whereby large generating facilities pay a share of unnecessary network 
upgrade costs caused by poor siting of smaller generating 
facilities.\858\ Longroad Energy illustrates this point by noting that 
one of its generating facilities was recently allocated nearly $10 
million under the proportional capacity method based solely on the 
generating facility's size, despite the fact that relevant 
interconnection studies firmly established that its generating 
facility, while large, actually reduced the identified overload.\859\
---------------------------------------------------------------------------

    \855\ Longroad Energy Initial Comments at 9; MISO Initial 
Comments at 45-46; NRECA Initial Comments at 22; Pennsylvania 
Commission Initial Comments at 9.
    \856\ MISO Initial Comments at 45-46.
    \857\ Pennsylvania Commission Initial Comments at 9.
    \858\ Id.; see also NRECA Initial Comments at 22.
    \859\ Longroad Energy Initial Comments at 9.
---------------------------------------------------------------------------

    426. NV Energy urges the Commission to reconsider the application 
of pro rata allocation of network upgrade costs over using the 
proportional impact method.\860\ NV Energy contends that the 
proportional impact method could negatively impact interconnection 
customers due to the time and risk of reallocations required by 
restudies.\861\ NV Energy argues that assigned network upgrade costs 
could change dramatically if a cluster participant withdraws from the 
interconnection queue and requires a restudy, potentially resulting in 
each participant's cost allocation changing.\862\ NV Energy asserts 
that in addition to disintegrating cost reassurance for the 
interconnection customer, performing studies using the proportional 
impact method defeats the purpose of completing cluster studies where 
each interconnection customer in the cluster has the same 
interconnection queue position and that this method will require the 
transmission provider to review each interconnection request within the 
cluster individually to assign the proportional impact.
---------------------------------------------------------------------------

    \860\ NV Energy Initial Comments at 12.
    \861\ Id.; PacifiCorp Reply Comments at 3.
    \862\ NV Energy Initial Comments at 12.
---------------------------------------------------------------------------

    427. NV Energy contends that using the proportional impact method 
to allocate the costs of network upgrades resulting from cluster 
studies will be burdensome in application because of the volume of 
interconnection requests being studied and the large number of network 
upgrades identified in each study.\863\ NV Energy states that, under a 
proportional capacity method, when an interconnection customer 
withdraws and the same network upgrades are deemed necessary, the 
transmission provider could simply reallocate a pro rata share to the 
remaining interconnection customers and expedite the study; however, in 
the case of the proportional impact method, the transmission provider 
would need to complete a full restudy to review each generating 
facility's impact on the system.
---------------------------------------------------------------------------

    \863\ Id.
---------------------------------------------------------------------------

    428. According to NV Energy, this issue is further exacerbated when 
a network upgrade becomes a shared network upgrade with another cluster 
and the proportional impact is expanded to include additional 
interconnection customers.\864\ NV Energy states that, not only would 
the restudy be required for the lower-queued cluster based on the 
withdrawal, but also the concurrently queued cluster to modify the 
network upgrade cost allocation. NV Energy also argues that, without a 
consistent proportional impact cost allocation amongst transmission 
providers, there is risk that this could lead to disputes at the 
Commission from interconnection customers, which would lead to 
increased costs and delays.
---------------------------------------------------------------------------

    \864\ Id. at 13.
---------------------------------------------------------------------------

    429. PacifiCorp strongly opposes the proportional impact method to 
allocate network upgrade costs.\865\ PacifiCorp argues that the 
Commission has not made a transmission provider-specific finding that 
the proportional capacity method, approved for PacifiCorp by the 
Commission in May 2020,\866\ is no longer just and reasonable. 
PacifiCorp contends that transmission providers should be permitted to 
use proportional capacity-based network upgrade cost allocation 
methods.\867\ PacifiCorp claims that the proportional capacity method 
it uses is informed by three additional mechanisms within the cluster 
study process, all of which work in tandem to ensure that costs are 
appropriately allocated: (1) the use of electrically or geographically 
relevant subregions; (2) iterative studies that consider ERIS network 
upgrades prior to NRIS requests; and (3) a floor of 1% of total MW 
within a cluster, under which interconnection requests will be deemed 
not to contribute to the network upgrades identified in the cluster 
study.\868\
---------------------------------------------------------------------------

    \865\ PacifiCorp Initial Comments at 23.
    \866\ PacifiCorp, 171 FERC ] 61,112 (2020).
    \867\ PacifiCorp Initial Comments at 22, 26.
    \868\ Id. at 23-24.
---------------------------------------------------------------------------

    430. PacifiCorp states that the proportional capacity method also 
assists it in completing cluster studies and restudies on a timely 
basis, and minimizes disputes.\869\ PacifiCorp argues that, in sharp 
contrast, the proportional impact method involves a complex analysis 
that, in addition to being excessively time consuming, will result in 
disputes, both of which will put substantial pressure on PacifiCorp's 
ability to meet study deadlines.\870\ Therefore, according to 
PacifiCorp, requiring use of the proportional impact method will be 
counterproductive to the Commission's intent of making processing of 
interconnection requests more efficient.
---------------------------------------------------------------------------

    \869\ Id.; PacifiCorp Reply Comments at 2.
    \870\ PacifiCorp Initial Comments at 24-25.
---------------------------------------------------------------------------

    431. PacifiCorp explains that the degree of contribution to a 
needed network upgrade can be very difficult to

[[Page 61078]]

determine depending on the size, number of interconnection requests, 
and location of proposed generating facilities in a cluster.\871\ 
PacifiCorp adds that a proportional impact method analysis is 
complicated further by the fact that all interconnection requests 
within a single cluster are considered equally queued. In addition, 
PacifiCorp argues that, given the size of its multi-state system and 
the thousands of MWs of interconnection requests entering the cluster 
study process each year,\872\ it is simply not possible to both perform 
a proportional impact method analysis on each interconnection request 
and complete the cluster study process within 150 calendar days.\873\
---------------------------------------------------------------------------

    \871\ Id. at 25.
    \872\ PacifiCorp states that during the most recent cluster 
study, which commenced in May 2022, PacifiCorp received around 40 
GW-worth of interconnection requests, which is more than three times 
PacifiCorp's peak system load.
    \873\ PacifiCorp Initial Comments at 25.
---------------------------------------------------------------------------

ii. Comments on Specific Proposal
(a) Specificity Regarding Technical Parameters and Thresholds
    432. Several commenters state that, if the Commission adopts its 
proposal for each transmission provider to revise its tariff to include 
its specific technical parameters and thresholds for the proportional 
impact method for network upgrade cost allocation, the Commission 
should at least consider guidance or principles for those technical 
parameters and thresholds.\874\ The same commenters ask that the 
Commission also require sufficient specificity to provide transparency 
and certainty for potential interconnection customers and to avoid 
disputes over cost allocation.
---------------------------------------------------------------------------

    \874\ Clean Energy Buyers Initial Comments at 9; Cypress Creek 
Initial Comments at 19; Invenergy Initial Comments at 21.
---------------------------------------------------------------------------

    433. EPSA and Vistra argue that the Commission should provide an 
opportunity for comments prior to moving to a final rule with more 
detailed parameters.\875\ Vistra contends that without such an 
opportunity, the Commission will have not provided sufficient 
notice.\876\ Vistra argues that adopting a final rule that contains 
only the very high-level requirement to allocate costs based on 
proportional impact method simply defers the Commission's determination 
on important implementation details to litigation over the individual 
compliance filings that will be submitted. Without sufficient detail, 
Vistra continues, the Commission will arguably need to accept any set 
of technical details as in compliance with the requirement to allocate 
network upgrade costs based on proportional impact.
---------------------------------------------------------------------------

    \875\ EPSA Initial Comments at 8; Vistra Initial Comments at 12-
13.
    \876\ Vistra Initial Comments at 13.
---------------------------------------------------------------------------

    434. PPL states that the NOPR did not address the allocation of 
network upgrade costs within a cluster after an interconnection 
customer withdraws.\877\ PPL states that, prior to the execution of an 
interconnection agreement by the interconnection customer(s), the 
Commission should provide that any interconnection facility and network 
upgrade costs previously allocated to the withdrawing interconnection 
customer be reallocated among the remaining interconnection customers 
in the cluster to prevent delays and allow the study process to 
proceed. PPL states that the Commission should allow for withdrawal to 
be treated as an event that allows the transmission provider to retain 
or call on the security provided by the withdrawing interconnection 
customer. PPL adds that the Commission should allow for an increase in 
the cost allocated to remaining interconnection customers in a cluster 
to account for the amount previously allocated to the withdrawing 
interconnection customer.
---------------------------------------------------------------------------

    \877\ PPL Initial Comments at 14.
---------------------------------------------------------------------------

(b) Tariff Requirement for Technical Details
    435. PJM states that, while it generally supports the requirement 
to describe the cost allocation method in the applicable tariff, the 
Commission should clarify that transmission providers may provide the 
detailed and specific technical information in business practice 
manuals rather than in tariffs.\878\ PJM states that these types of 
implementation details change from time to time and, consistent with 
Commission precedent, are appropriately addressed in the transmission 
provider's manuals. PJM asserts that mandating that these procedures be 
placed in the transmission provider's tariff, on the other hand, would 
require a transmission provider to submit an FPA section 205 filing 
every time the implementation details changed, which would be 
inefficient and burdensome.
---------------------------------------------------------------------------

    \878\ PJM Initial Comments at 37.
---------------------------------------------------------------------------

    436. In contrast, other commenters argue that these thresholds, and 
any associated procedures, should be codified in transmission 
providers' tariffs.\879\ AES explains that the thresholds used as part 
of the proportional impact method are important planning criteria, and 
constitute ``practices that affect rates and services significantly, 
that are realistically susceptible of specification and that are not so 
generally understood as to render recitation superfluous;'' 
accordingly, AES continues, they should be included in transmission 
providers' filed rates, and subject to review and approval by the 
Commission pursuant to section 205 of the FPA.\880\ Union of Concerned 
Scientists contends that the combination of issues that are expressed 
through network upgrade decisions and cost allocations for 
interconnection customers are arguably central to this rulemaking and 
the fulfillment of the competition amongst interconnection customers as 
a regulatory approach to setting wholesale energy prices and must be 
subject to notice and review, both initially and for any subsequent 
changes, through filings with the Commission.\881\
---------------------------------------------------------------------------

    \879\ AES Initial Comments at 8; Union of Concerned Scientists 
Reply Comments at 20.
    \880\ AES Initial Comments at 8 (citing Pub. Serv. Co. of Colo., 
67 FERC ] 61,371, at 62,267 (1994); Portland Gen. Elec. Co., 144 
FERC ] 61,087 (2013)).
    \881\ Union of Concerned Scientists Reply Comments at 20-21.
---------------------------------------------------------------------------

    437. Xcel states that the Commission should make clear that there 
are several just and reasonable approaches to allocating network 
upgrade costs to interconnection customers within a cluster.\882\ For 
example, states Xcel, if two generating facilities are connecting to a 
new a transmission line, a substation must be constructed. Xcel 
explains that, using some analysis, a larger generating facility might 
be considered to have a larger impact, but the respective size of the 
interconnection request did not have any impact on the cost or size of 
the substation needed. Xcel states that, for example, the cost of the 
substation is not different for a 100 MW and 500 MW generating facility 
or for two 300 MW generating facilities if they are interconnecting at 
the same voltage, and as a result, the cost of that substation should 
be allocated equally to both generating facilities. Xcel states that 
there could be a third generating facility (not directly connected to 
the substation) from which the power flows through the new substation, 
but it is not clear if the Commission is proposing that the 
interconnection customer proposing that third generating facility pays 
for a portion of the substation costs because its flows ``impact'' the 
substation. Xcel states that it does not generally support allocating 
network upgrade costs to interconnection customers simply because their 
proposed generating facilities have a flow impact if they are not 
causing the

[[Page 61079]]

need for the network upgrade under a ``but for'' evaluation.
---------------------------------------------------------------------------

    \882\ Xcel Initial Comments at 26.
---------------------------------------------------------------------------

    438. Invenergy states that, in the occasional circumstance where a 
point of interconnection is shared among more than one interconnection 
request within a cluster, which could involve new equipment that does 
not vary based on proportional impact, the associated costs at the 
point of interconnection (e.g., the substation) could be allocated on a 
pro rata basis.\883\ PacifiCorp states that the proportional impact 
method would not be necessary to account for costs that are agnostic to 
interconnection customer impacts, such as the need to construct a new 
substation to connect to a new transmission line regardless of whether 
one or several generating facilities are interconnecting.\884\
---------------------------------------------------------------------------

    \883\ Invenergy Initial Comments at 21-22.
    \884\ PacifiCorp Reply Comments at 2 (citing Xcel Initial 
Comments at 26 (describing how a proportional impact analysis is not 
necessary to allocate costs for a new station connecting to a 
transmission line, as ``[t]he cost of the station is not different 
for a 100 MW and 500 MW generator or for two 300 MW generators if 
they are interconnecting at the same voltage'')).
---------------------------------------------------------------------------

    439. Invenergy states that the NOPR could be read to permit each 
transmission provider to adopt different and possibly inconsistent 
analyses and that the Commission should be clear that it is requiring a 
proportional impact method for allocating network upgrade costs, just 
as the NOPR proposes to do with respect to shared network 
upgrades.\885\
---------------------------------------------------------------------------

    \885\ Invenergy Initial Comments at 21.
---------------------------------------------------------------------------

    440. Several commenters state that the final rule should require 
transmission providers to submit compliance filings that propose 
minimum distribution factor thresholds that will be used to evaluate 
NRIS and ERIS requests.\886\
---------------------------------------------------------------------------

    \886\ AEE Reply Comments at 10; AES Initial Comments at 8; 
Longroad Energy Initial Comments at 9; SEIA Initial Comments at 11.
---------------------------------------------------------------------------

(c) Requests for Flexibility
    441. Some commenters support the proportional capacity method only 
for certain network upgrades or limited circumstances.
    442. Tri-State states that it does not apply a proportional impact 
method to transient-stability-driven network upgrades, which cannot be 
measured using a proportional impact approach; rather, Tri-State uses a 
MW pro rata method approach when allocating the costs of transient-
stability-driven network upgrades.\887\ Longroad Energy states that, to 
the extent the Commission allows a transmission provider to use some 
method other than a flow-based proportional impact allocation for 
transient stability constraints, the transmission provider should be 
required to demonstrate that the alternative cost allocation method is 
based on sound engineering principles for the specific transient 
stability constraint observed in the studies.\888\
---------------------------------------------------------------------------

    \887\ PacifiCorp Reply Comments at 2; Tri-State Initial Comments 
at 12.
    \888\ Longroad Energy Initial Comments at 9.
---------------------------------------------------------------------------

    443. R Street states that allocating network upgrade costs based on 
proportional capacity is appropriate in situations where clusters are 
composed of similar types of generation.\889\ R Street asserts that the 
default should be that all thermal network upgrade cost allocations are 
based on proportional capacity. R Street states that this leaves open 
the possibility for transmission providers to allocate other types of 
network upgrade costs (voltage, transient stability, short circuit) 
using a different but predefined method.
---------------------------------------------------------------------------

    \889\ R Street Initial Comments at 12.
---------------------------------------------------------------------------

    444. Several commenters ask the Commission to provide flexibility 
for transmission providers to establish a cost allocation method for 
network upgrades, rather than mandating a prescriptive approach.\890\ 
PPL claims that such region-specific cost allocations are necessary to 
keep disputes from overwhelming the reform process the Commission 
anticipates.\891\ New York State Department asserts that any strict or 
limiting requirement for a specific cost allocation method may 
undermine and replace existing processes that work well.\892\ National 
Grid recommends that the Commission allow for consideration of the 
unique circumstances of a region, input from relevant stakeholders in 
the region, including the potential for regions to propose cost 
allocation methods that allow for broader allocation to load or 
transmission customers in addition to interconnection customers.\893\
---------------------------------------------------------------------------

    \890\ AES Initial Comments at 7; APPA-LPPC Initial Comments at 
16; Bonneville Initial Comments at 10; Dominion Initial Comments at 
19; Indicated PJM TOs Initial Comments at 20; ISO-NE Initial 
Comments at 25; MISO Initial Comments at 45; National Grid Initial 
Comments at 8; NEPOOL Initial Comments at 15; New York State 
Department Initial Comments at 8; NYISO Initial Comments at 15; PPL 
Initial Comments at 14.
    \891\ PPL Initial Comments at 14.
    \892\ New York State Department Initial Comments at 8-9.
    \893\ National Grid Initial Comments at 18.
---------------------------------------------------------------------------

    445. Dominion points out that courts and the Commission have long 
recognized that there is not one single just and reasonable method for 
establishing cost allocation.\894\ Dominion states that rather, cost 
allocation proposals are reviewed to determine whether they meet 
certain principles, chiefly that costs are allocated in a manner that 
is at least ``roughly commensurate'' with estimated benefits 
received.\895\ Accordingly, Dominion recommends that if the Commission 
imposes any requirements related to cost allocation, it simply retains 
a general definition of proportional impact method and is not overly 
prescriptive.\896\
---------------------------------------------------------------------------

    \894\ Dominion Initial Comments at 19, 21 (citing Entergy La., 
Inc. v. La. Pub. Serv. Comm'n, 539 U.S. 39, 50 (2003)).
    \895\ Id. at 19.
    \896\ Id. at 22.
---------------------------------------------------------------------------

iii. Requests for Clarification or Technical Conference
    446. Pattern Energy generally supports the application of the 
proportional impact method, subject to clarification on which form of 
distribution factor analysis the Commission is contemplating.\897\ 
Pattern Energy states that there are two types of distribution factors 
used to determine the impact of given power injection flows over a 
monitored facility: (1) power transfer distribution factor, which is 
the percentage of power that will flow on a specific monitored facility 
and does not consider outage/contingent facilities; and (2) outage 
transfer distribution factor, which is the percentage of power that 
will flow on a specific facility that does consider outage/contingent 
facilities. Pattern Energy states that the difference between the two 
distribution factors (i.e., the consideration of the outage/contingent 
facility) is important because power transfer distribution factor is 
usually more relevant for evaluating ``local impacts'' (e.g., 
generating facilities that are connecting in very close electrical 
proximity to a given monitored element), compared to outage transfer 
distribution factor, which captures impacts that may be more 
geographically and electrically distant from a given monitored 
facility. Pattern Energy asserts that the Commission should require 
outage transfer distribution factor to be the required distribution 
factor utilized in the proportional impact method for identifying 
impacts to constrained facilities and resultant cost allocation for 
network upgrades. Pattern Energy argues that outage transfer 
distribution factor is a better measure of power flows on the bulk-
power system, and, in turn, its use ensures that impacts to constrained 
facilities are properly mitigated by, and cost allocated to, the 
actual, full set of contributors and not just the nearby highest 
contributors.
---------------------------------------------------------------------------

    \897\ Pattern Energy Initial Comments at 11-12.
---------------------------------------------------------------------------

    447. Pine Gate contends that certain proposed enhancements to the 
NOPR

[[Page 61080]]

proposal would provide much needed certainty to interconnection 
customers and mitigate the systematic problem of interconnection queues 
being the primary mechanism by which needed transmission infrastructure 
is identified, developed, and constructed.\898\ Specifically, Pine Gate 
requests that the Commission make the following clarifications: (1) 
transmission providers are not permitted to allocate to interconnection 
customers network upgrade costs associated with preexisting operating 
conditions (such as overloads); (2) transmission providers are not 
permitted to allocate network upgrade costs to interconnection 
customers for loading that results from the simulation of conditions 
that do not reflect typical operating conditions; (3) transmission 
providers are required to use consistent, uniform thresholds to measure 
the impact on a specific transmission facility caused by an 
interconnection request and publish these thresholds, along with the 
corresponding scope of the resulting network upgrades; and (4) 
establish a 4% impact threshold for NRIS and a 20% impact threshold for 
ERIS, unless there is preexisting loading on the facility.\899\ Pine 
Gate further requests that the Commission provide transmission 
providers guidance on the scope of the network upgrade required to 
accommodate an interconnection request. Pine Gate states that, if a 
network upgrade benefits other types of customers, interconnection 
customers should receive transmission credits or other compensation if 
the additional transmission capacity created is used for market 
dispatch or by wholesale transmission customers.\900\ Pine Gate states 
that, if the Commission does not adopt Pine Gate's proposed 
enhancements as part of a final rule in this proceeding, then the 
Commission should establish a technical conference to explore these 
issues.
---------------------------------------------------------------------------

    \898\ Pine Gate Initial Comments at 16-17.
    \899\ Id. at 18-19.
    \900\ Id. at 20.
---------------------------------------------------------------------------

iv. Miscellaneous
    448. Pennsylvania Commission states that limiting the scope of each 
cluster to those interconnection customers most likely to share the 
same network upgrades may reduce the need for the proportional impact 
network upgrade cost allocation method.\901\ According to Pennsylvania 
Commission, instead of determining the degree to which interconnection 
requests cause specific network upgrades on the back end through cost 
allocation, clustering by electrical relevance may accomplish the same 
goal, making sure that interconnection customers are sharing the costs 
of network upgrades that they cause and from which they benefit. 
Pennsylvania Commission contends that the Commission should examine 
whether limiting the scope of a cluster or cost allocation, or a 
combination of both, is the best method to share costs among 
interconnection customers causing the same network upgrades.
---------------------------------------------------------------------------

    \901\ Pennsylvania Commission Initial Comments at 9.
---------------------------------------------------------------------------

    449. Several commenters state that the NOPR leaves unresolved the 
fundamental question of more equitably sharing network upgrade costs 
across all beneficiaries, including load.\902\ They argue, for example, 
that policies requiring interconnection customers to pay for 100% of 
network upgrade costs when the benefits of those upgrades are 
distributed among other system users (i.e., participant funding) causes 
interconnection customers to pay more than their appropriate share of 
the costs.\903\ In contrast, Ameren claims that it is appropriate for 
interconnection customers to bear responsibility for the cost of 
network upgrades required for their interconnection requests.\904\ 
Ameren argues that, to ensure the full costs of interconnection are 
identified and allocated, network upgrade costs associated with 
affected systems must also be included in cluster network upgrade cost 
allocation, and interconnection customers should be required to accept 
the assigned costs. Ohio Commission Consumer Advocate emphasizes that 
the Commission should not change the participant funding mechanisms in 
RTO/ISO markets,\905\ while PPL argues that the Commission should allow 
non-RTO/ISO transmission providers the option to propose allocating the 
costs of network upgrades to interconnection customers without credits 
as RTOs/ISOs do.\906\
---------------------------------------------------------------------------

    \902\ ACORE Initial Comments at 8-9; AEE Initial Comments at 14-
15; Interwest Initial Comments at 5; Northwest and Intermountain 
Initial Comments at 8; Public Interest Organizations Initial 
Comments at 31-33.
    \903\ AEE Initial Comments at 14 (citing Joint Supplemental 
Comments of American Clean Power Association, Advanced Energy 
Economy, and Solar Energy Industries Association, Docket No. RM21-
17-000, at 7-8 (filed June 1, 2022)).
    \904\ Ameren Initial Comments at 12.
    \905\ Ohio Commission Consumer Advocate Initial Comments at 9.
    \906\ PPL Initial Comments at 13.
---------------------------------------------------------------------------

    450. New York State Department and Shell argue that the Commission 
should discontinue the historical practice of allowing interconnection 
customers essentially free use of headroom on ratepayer-funded network 
facilities.\907\ New York State Department states that this occurs when 
transmission ratepayers fund upgrades to the transmission system that 
create headroom, from which interconnection customers later benefit 
without having to pay for access or use.\908\ In contrast, Invenergy 
asserts that the Commission needs to ensure that the transmission 
planning and interconnection models are consistent, so that 
interconnection customers are not required to pay for the cost of 
resolving overloads and other transmission system issues that exist 
without the proposed interconnection.\909\
---------------------------------------------------------------------------

    \907\ New York State Department Initial Comments at 9; Shell 
Reply Comments at 27-28.
    \908\ New York State Department Initial Comments at 9.
    \909\ Invenergy Initial Comments at 21.
---------------------------------------------------------------------------

    451. AEE encourages the Commission to ensure that its proposal 
increases cost transparency and establishes a pathway for 
interconnection customers to access accurate information about their 
network upgrade costs in a timely manner.\910\ For instance, AEE asks 
that the Commission also provide guidance regarding which party must 
pay if network upgrade costs significantly exceed estimates. AEE states 
that one approach to minimizing the construction time and cost of 
network upgrades, and consequently the interconnection process as a 
whole, is to provide a third-party construction option in the pro forma 
LGIA that would allow the interconnection customer to elect for stand 
alone network upgrades to be bid out and potentially built by third 
parties.\911\
---------------------------------------------------------------------------

    \910\ AEE Initial Comments at 15.
    \911\ Id. at 15-16 (citing Comments of AEE, Docket No. RM21-17-
000, at 47-49 (filed Oct. 12, 2021)).
---------------------------------------------------------------------------

    452. Pine Gate recommends that the Commission require transmission 
providers to analyze more holistically the other underlying needs 
driving identified network upgrades to the transmission system.\912\ 
Pine Gate states that the Commission should require transmission 
providers to only allocate to interconnection customers the costs 
associated with accelerating the construction of the upgrade to 
accommodate the interconnection customer's anticipated commercial 
operation date.\913\
---------------------------------------------------------------------------

    \912\ Pine Gate Initial Comments at 17.
    \913\ Id.; Fervo Energy Reply Comments at 5.
---------------------------------------------------------------------------

c. Commission Determination
    453. We adopt the NOPR proposal, with modifications, to add new 
proposed section 4.2.3, now section 4.2.1, to the pro forma LGIP to 
require transmission providers to allocate

[[Page 61081]]

network upgrade costs based on a proportional impact method.\914\ Based 
on the record, we modify the NOPR proposal and add definitions for 
substation network upgrades and system network upgrades in the pro 
forma LGIP and pro forma LGIA. In addition, we modify the definitions 
of proportional impact method and stand alone network upgrades proposed 
in the NOPR. We also modify proposed section 4.2.1 of the pro forma 
LGIP to require transmission providers to allocate the costs of network 
upgrades located at substations equally among each generating facility 
interconnecting to the same substation (i.e., on a per capita basis), 
and to revise the information that a transmission provider's tariff 
must include regarding the proportional impact method.
---------------------------------------------------------------------------

    \914\ ``Proportional Impact Method shall mean a technical 
analysis conducted by Transmission Provider to determine the degree 
to which each Generating Facility in the Cluster Study contributes 
to the need for a specific System Network Upgrade.'' Pro forma LGIP 
section 1.
---------------------------------------------------------------------------

    454. We also modify the requirement in proposed section 4.2.1 of 
the pro forma LGIP for transmission providers to directly assign the 
cost of shared transmission provider's interconnection facilities to 
interconnection customers on a per capita basis (i.e., on a per 
generating facility basis). Specifically, we modify proposed section 
4.2.1 of the pro forma LGIP to make the new provisions applicable to 
the interconnection customer's interconnection facilities as well as to 
the transmission provider's interconnection facilities. We also modify 
this section to provide that interconnection customers may agree to 
share interconnection facilities, and that the per capita allocation 
will apply only where interconnection customers agree to share 
interconnection facilities. We also modify this section to allow the 
interconnection customers that share interconnection facilities to 
choose a different cost sharing arrangement upon mutual agreement.
    455. We find that adopting the modified NOPR proposal will ensure 
just and reasonable rates as transmission providers transition to the 
cluster study process required by this final rule. We find that the 
cost allocation method adopted herein will allow transmission providers 
to allocate network upgrade costs among several interconnection 
customers that may benefit from (and cause the need for) certain 
network upgrades. We also find that allocating shared network upgrade 
costs among a cluster of interconnection customers will reduce the 
frequency of an individual interconnection customer being allocated the 
costs of a large network upgrade that benefits subsequent 
interconnection customers; reduce the incentive of interconnection 
customers to submit multiple speculative interconnection requests to 
avoid shouldering the cost of large network upgrades that may be 
triggered by a single interconnection customer in the existing serial 
study process; and reduce the number of cascading withdrawals and 
restudies, thereby improving the efficiency of the interconnection 
process and reducing interconnection queue processing delays.
    456. We conclude that a proportional impact method appropriately 
reflects the Commission's interconnection pricing policy for facilities 
designated as network upgrades needed for the interconnection of the 
cluster. However, we are persuaded to adopt a different cost allocation 
method for substations at the point of interconnection that are 
designated as network upgrades and needed only to facilitate the 
interconnection of certain generating facilities within the cluster 
seeking interconnection to the specific substation, as demonstrated by 
commenters.\915\
---------------------------------------------------------------------------

    \915\ Xcel Initial Comments at 26; Invenergy Initial Comments at 
21-22.
---------------------------------------------------------------------------

    457. In Order No. 2003, the Commission reasoned that ``it is 
appropriate for the Interconnection Customer to pay the initial full 
cost for Interconnection Facilities and Network Upgrades that would not 
be needed but for the interconnection'' (i.e., ``but for'' 
policy).\916\ Hence, under the serial study process in the existing pro 
forma LGIP, the transmission provider allocates network upgrade costs 
by assigning the initial full cost responsibility for all network 
upgrades identified in a study to a single interconnection customer 
that causes those upgrades. However, in transitioning to a cluster 
study process in this final rule, the Commission must establish a 
method for allocating network upgrade costs among all interconnection 
customers within a cluster. Based on the record in this proceeding, we 
find that a proportional impact method is the appropriate application 
of the Commission's interconnection pricing policy when allocating the 
costs of network upgrades needed for an entire cluster of proposed 
generating facilities because a proportional impact method allows 
transmission providers to assess a generating facility's individual 
contribution to the need for the network upgrades identified for the 
cluster. However, the need for substation network upgrades is only 
generated by a specific generating facility seeking interconnection at 
a specific substation and not by all the generating facilities in the 
cluster. It would be inconsistent with the Commission's interconnection 
pricing policy to allocate the costs of the substation network upgrades 
to interconnection customers in the cluster that are interconnecting at 
other substations because, in the case of a cluster of new 
interconnection requests, only the generating facilities 
interconnecting to the same substation generate the need for network 
upgrades at that substation.
---------------------------------------------------------------------------

    \916\ See id. P 694; Nev. Power Co., 182 FERC ] 61,048, at PP 
50-51 (2023) (describing the cost allocation requirements for 
network upgrades as the Commission's Order No. 2003 ``but for 
requirements'').
---------------------------------------------------------------------------

    458. As explained above, the cost of substation network upgrades 
must be initially allocated only to those interconnection customers 
seeking to interconnect at the same substation,\917\ while the cost of 
system network upgrades for all interconnection customers in a cluster 
must be initially allocated based on the technical analyses to be 
specified under the transmission provider's proportional impact method. 
To facilitate these differing cost allocation methods, we modify the 
definitions in section 1 of the pro forma LGIP and article 1 of the pro 
forma LGIA to distinguish substation network upgrades (including all 
switching stations) \918\ from system network upgrades.\919\ Using 
these definitions, we further modify the pro forma LGIP and pro forma 
LGIA to draw this distinction and to ensure that the costs for the two 
types of network upgrades are allocated consistent with the 
Commission's interconnection pricing policy, which establishes the 
principles for allocating the costs of network upgrades.
---------------------------------------------------------------------------

    \917\ For clarity, we note that we are referring to the 
transmission provider's substation immediately beyond the point of 
interconnection as defined in section 1 of the pro forma LGIP: 
``Point of Interconnection shall mean the point . . . where the 
interconnection facilities connect to the transmission provider's 
transmission system.'' Pro forma LGIP section 1 (Definitions).
    \918\ Substation network upgrades shall mean the network 
upgrades required at the substation located at the point of 
interconnection.
    \919\ System network upgrades shall mean the network upgrades 
required beyond the substation located at the point of 
interconnection.
---------------------------------------------------------------------------

    459. We note that we are not modifying the pro forma LGIP's 
definition of facilities needed beyond the point of interconnection as 
network upgrades; rather, we are providing greater specificity with 
regard to how the costs of the two distinct types of network upgrades 
identified within a

[[Page 61082]]

cluster study should be initially allocated. We find that this approach 
will also lead to greater transparency and ease of administering the 
cluster study process by establishing distinct guidelines for how the 
costs of the two types of network upgrades will be initially allocated 
within a cluster. Also, as commenters note, in instances where a point 
of interconnection is shared among more than one interconnection 
request within a cluster, the cost of the substation network upgrades 
is more directly impacted by the number of generating facilities 
proposing to interconnect there because the cost of the equipment used 
to interconnect generating facilities to substations does not vary 
based on the electrical characteristics of the interconnecting 
generating facilities (e.g., the MW size of the generating facility, 
fuel type, or services provided).
    460. To further implement this modification of the NOPR proposal, 
we modify the definition of stand alone network upgrades proposed in 
the NOPR to recognize that (1) a substation network upgrade may only be 
considered a stand alone network upgrade if it is needed to 
interconnect only one generating facility in the cluster and no other 
interconnection customer in that cluster is required to interconnect to 
the same substation network upgrades, and (2) the proportional impact 
analysis will be used in determining whether a system network upgrade 
is only needed for one generating facility in the cluster and can be 
considered a stand alone network upgrade. Our revisions also seek to 
prevent lengthy disputes over which interconnection customer has the 
right to exercise the option to build in instances where a network 
upgrade could qualify under the existing definition of a stand alone 
network upgrade, but the network upgrade is needed for multiple 
interconnection customers' generating facilities.
    461. Several commenters request that the Commission provide more 
specificity and guidance regarding the specific thresholds and metrics 
that transmission providers are expected to submit on compliance.\920\ 
In this final rule, we modify the proposed requirement in pro forma 
LGIP section 4.2.1 for transmission providers to revise their LGIPs on 
compliance to include specific thresholds and metrics. Instead, we 
direct transmission providers on compliance to provide tariff 
provisions that describe, for each type of system network upgrade that 
a transmission provider would identify in the cluster study process 
(e.g., voltage support network upgrades or short circuit network 
upgrades), how the costs of each system network upgrade type will be 
allocated among the interconnection customers within the cluster. 
Transmission providers' revisions on compliance must provide that costs 
for a discrete network upgrade identified in the cluster study process 
(e.g., reconductoring a portion of a transmission line to accommodate 
the interconnection of several generating facilities in the cluster) 
are allocated to only the interconnection customers in the cluster that 
are shown through technical analyses to contribute to the need for the 
discrete network upgrade. For example, the transmission provider must 
propose tariff provisions similar to the following: (1) voltage support 
related network upgrades shall be allocated using a voltage impact 
analysis, which will identify each generating facility's contribution 
to the voltage violation; (2) short circuit network upgrade costs 
within a cluster will be allocated based on the impact from each 
generating facility within the cluster, on the constrained facilities 
under the most constraining fault in the relevant study case(s); or (3) 
the estimated costs of short circuit related general reliability 
network upgrades identified through a cluster study shall be assigned 
to all interconnection requests in that group study pro rata on the 
basis of the short circuit duty contribution of each generating 
facility.
---------------------------------------------------------------------------

    \920\ Clean Energy Buyers Initial Comments at 9; Cypress Creek 
Initial Comments at 19; EPSA Initial Comments at 8; Invenergy 
Initial Comments at 21; Vistra Initial Comments at 12-13.
---------------------------------------------------------------------------

    462. PJM requests that the Commission clarify that transmission 
providers may provide the detailed and specific technical information 
in business practice manuals rather than in tariffs.\921\ In response, 
we find that, as noted above, transmission providers must provide 
tariff provisions that describe the method they will use for allocating 
costs of each type of network upgrade, but specific metrics and 
thresholds for implementing the allocation, or other specific technical 
information, may be included in business practice manuals, or publicly 
posted on the transmission provider's website. We agree with PJM that 
such details are appropriate for business practice manuals, consistent 
with Commission precedent applying the ``rule of reason'' to determine 
whether a detail should be included in a tariff or business practice 
manual. In particular, the technical information surrounding 
implementation of the proportional impact method by a particular 
transmission provider does not need to be included in the transmission 
provider's tariff under the rule of reason because these provisions are 
properly classified as implementation details that do not significantly 
affect rates, terms, and conditions of service.\922\
---------------------------------------------------------------------------

    \921\ PJM Initial Comments at 37.
    \922\ See, e.g., N.Y. Indep. Sys. Operator, Inc., 179 FERC ] 
61,102, at PP 105-114 (2022) (citing, inter alia, Energy Storage 
Ass'n v. PJM Interconnection, L.L.C., 162 FERC ] 61,296, at P 103 
(2018); City of Cleveland v. FERC, 773 F.2d, 1368, 1376-77 (D.C. 
Cir. 1985)).
---------------------------------------------------------------------------

    463. Several commenters request that the Commission direct 
transmission providers to use a specific type of proportional impact 
method or distribution factor analysis and apply minimum distribution 
factor thresholds that will be used to evaluate NRIS and ERIS 
requests.\923\ We are unpersuaded that such level of prescription is 
needed to ensure just, reasonable, and not unduly discriminatory or 
preferential rates. Instead, we believe that flexibility for 
transmission providers to develop such details as part of their 
compliance filings--and in their business practice manuals, where 
consistent with the rule of reason, as discussed above--is important to 
ensure that the proportional impact method used by each transmission 
provider reflects the characteristics of its region (e.g., types of 
network upgrade facilities identified in the region, or preferred 
analyses in the region for determining the share of the need for the 
specific network upgrade type). For the same reason, we decline to 
require transmission providers to use consistent, uniform thresholds to 
measure impact, as requested by Pine Gate.\924\
---------------------------------------------------------------------------

    \923\ AEE Reply Comments at 10; AES Initial Comments at 8; 
Invenergy Initial Comments at 21; Longroad Energy Initial Comments 
at 9; Pattern Energy Initial Comments at 11-12; Pine Gate Initial 
Comments at 16-19; SEIA Initial Comments at 11.
    \924\ Pine Gate Initial Comments at 19.
---------------------------------------------------------------------------

    464. Based on the record, we decline to require transmission 
providers to use the proportional capacity method to allocate the costs 
of all system network upgrades, given our decision to instead opt for 
the proportional impact method and because it reflects the Commission's 
interconnection pricing policy for facilities designated as network 
upgrades needed for the interconnection of the cluster. Nonetheless, we 
recognize that there may be a tradeoff between simplicity and accuracy 
when considering proportional capacity versus proportional impact for 
cost allocation for network upgrades. While we require transmission 
providers to allocate network upgrade costs based on a proportional 
impact method based on the record in this final rule, we

[[Page 61083]]

acknowledge that other allocation methods could potentially meet the 
consistent with or superior to standard or the independent entity 
variation standard if, among other things, they allocate network 
upgrade costs in a manner consistent with the Commission's 
interconnection pricing policy.
    465. We disagree with NV Energy and PacifiCorp's arguments that the 
proportional impact method carries unmanageable time, restudy, and 
reallocation risks.\925\ In response to concerns about restudy risk 
resulting from withdrawals, we note that the Commission's new cluster 
study process requires transmission providers to complete the process 
within 150 calendar days, which we believe is sufficiently long for 
transmission providers to be able to conduct the rounds of restudy and 
reallocation that are needed to achieve a stable interconnection queue 
and reduce the risk of further withdrawals before moving to the 
individual facilities studies. Further, the proportional impact method 
is currently used by most transmission providers that conduct cluster 
studies, and several of these transmission providers have adopted study 
timelines similar to what we adopt in this final rule.\926\
---------------------------------------------------------------------------

    \925\ NV Energy Initial Comments at 12; PacifiCorp Reply 
Comments at 3.
    \926\ See Dominion Energy S.C., Inc., Docket No. ER22-301-000 
(Dec. 28, 2021) (delegated order); Duke Energy Carolinas, LLC, 176 
FERC ] 61,075 (2021); Pub. Serv. Co. of Colo., 169 FERC ] 61,182 
(2019); Tri-State Generation & Transmission Ass'n, Inc., 173 FERC ] 
61,015 (2020).
---------------------------------------------------------------------------

    466. We disagree with claims from NV Energy and PacifiCorp that the 
proportional impact method must be conducted as if it were a serial 
study in that each interconnection request must be studied 
individually. When proposing a proportional impact method on 
compliance, transmission providers have many methods to choose from and 
should adopt a method that allows them to meet the timelines designated 
in the cluster study process. In response to PPL,\927\ we confirm that 
within the cluster study process, any network upgrade costs previously 
allocated to a withdrawing interconnection customer that are still 
required after the withdrawal may be reallocated among the remaining 
interconnection customers in the cluster based on the relevant cost 
allocation method applied to the network upgrade facility type.
---------------------------------------------------------------------------

    \927\ PPL Initial Comments at 14.
---------------------------------------------------------------------------

    467. Finally, several commenters suggest alternative reforms to the 
Commission's network upgrade cost allocation policies: (1) limit the 
use of cluster areas as an alternative to the proposed cost allocation 
method within a cluster; \928\ (2) change the interconnection pricing 
policy or participant funding regime (as allowed in certain RTOs/ISOs) 
to limit participant funding and/or require assessment of whether 
transmission customers benefit from and should pay for network 
upgrades; \929\ (3) establish a process to eliminate the use of 
headroom on network transmission facilities; \930\ and/or (4) provide a 
third-party construction option.\931\ We find these requests to be 
outside the scope of this proceeding and lacking in record support to 
adequately consider whether to adopt them in this final rule.
---------------------------------------------------------------------------

    \928\ Pennsylvania Commission Initial Comments at 9.
    \929\ ACORE Initial Comments at 8-9; AEE Initial Comments at 14-
15; Ameren Initial Comments at 12; Interwest Initial Comments at 5; 
Northwest and Intermountain Initial Comments at 8; Ohio Commission 
Consumer Advocate Initial Comments at 12; PPL Initial Comments at 
13; Public Interest Organizations Initial Comments at 31-33.
    \930\ New York State Department Initial Comments at 9; Shell 
Reply Comments at 27-28.
    \931\ AEE Initial Comments at 15.
---------------------------------------------------------------------------

5. Shared Network Upgrades
a. NOPR Proposal
    468. In the NOPR, the Commission preliminarily found that the 
absence of network upgrade cost sharing provisions in the pro forma 
LGIP may pose a barrier to entry to generation development.\932\ The 
Commission stated that absent cost sharing provisions among clusters, 
interconnection customers may significantly benefit from earlier-in-
time network upgrades but not share in the cost of those network 
upgrades in a manner that is roughly commensurate with benefits. The 
Commission therefore proposed to require transmission providers to 
allocate the costs of network upgrades between interconnection 
customers in an earlier cluster and interconnection customers in a 
subsequent cluster that benefit from the same network upgrade in a 
manner that is roughly commensurate with the benefits received.\933\ 
Specifically, the Commission proposed that when the transmission 
provider analyzes the network upgrades identified through its cluster 
study process, if a generating facility of an interconnection customer 
in a later cluster directly connects either to (1) a network upgrade in 
service for less than five years or (2) a substation where the network 
upgrade in service for less than five years terminates, then the 
transmission provider would be required to designate the network 
upgrade a shared network upgrade. Upon such a designation, the 
interconnection customer in the later cluster would be required to 
contribute a pro rata portion of the shared network upgrade's remaining 
undepreciated capital cost based on the impact the interconnection 
customer in the later cluster has on the network upgrade, as measured 
using the same method the transmission provider used to determine the 
impact of the interconnection customer(s) in the earlier cluster.
---------------------------------------------------------------------------

    \932\ NOPR, 179 FERC ] 61,194 at P 97.
    \933\ Id. P 98.
---------------------------------------------------------------------------

    469. The Commission proposed that if the new generating facility 
does not directly connect to the network upgrade, then the transmission 
provider would perform a power flow analysis with a two-step test to 
measure the lower-queued interconnection customer's use of and benefit 
from the network upgrade funded by interconnection customers from an 
earlier cluster. Under the first step, the transmission provider would 
determine if the impact of the interconnection customer in the later 
cluster exceeds five MW and exceeds one percent of the network 
upgrade's rating. Then, if those criteria are met, the transmission 
provider would determine if the lower-queued interconnection customer's 
impact either exceeds more than 5% of the network upgrade's facility 
rating or if the transmission distribution factor is greater than 20%. 
Finally, if either of these criteria were met, the transmission 
provider would be required to designate that network upgrade a shared 
network upgrade, and the interconnection customer in the later cluster 
would be responsible for a pro rata share of the network upgrade's 
remaining undepreciated capital cost based on the impact the 
interconnection customer in the later cluster has on the network 
upgrade, as measured using the same method the transmission provider 
used to determine the impact of the interconnection customer(s) from 
the earlier cluster.
    470. The Commission proposed to require the interconnection 
customer in the later cluster to pay the transmission provider for the 
interconnection customer's share of the shared network upgrade costs 
through a one-time lump sum, which the transmission provider would 
disburse to the appropriate interconnection customer(s) from the 
earlier cluster.\934\ The Commission also proposed that, where 
applicable, the interconnection customer from the earlier cluster or 
the relevant transmission provider would be required to assign 
transmission credits for the portion of the shared network

[[Page 61084]]

upgrade that the interconnection customer in the later cluster funded 
to the interconnection customer in the later cluster. Additionally, the 
Commission proposed to require that the interconnection customer in the 
later cluster not be required to pay for its share of the cost of the 
shared network upgrade until that shared network upgrade is in service. 
The Commission also proposed to require transmission providers to 
provide the list of shared network upgrades to interconnection 
customers in subsequent clusters at the conclusion of the cluster study 
and to list those network upgrades in the appendix of the relevant 
interconnection customer's LGIA. The Commission acknowledged that there 
could be scenarios where the network upgrade may be identified as both 
a shared network upgrade and a contingent facility; and, thus a 
designation of a network upgrade as a contingent facility does not 
preclude it from also being a shared network upgrade if the network 
upgrade meets the aforementioned criteria and passes the screens.\935\
---------------------------------------------------------------------------

    \934\ Id. P 99.
    \935\ Id. P 100.
---------------------------------------------------------------------------

b. Comments
i. Comments in Support
    471. Multiple commenters support the proposal.\936\ OMS states 
that, while cost sharing arrangements can be resource intensive and 
contentious, they can be crucial to facilitating an equitable 
interconnection process.\937\ NARUC states that the proposal is a 
logical extension of the cluster cost sharing concept and could spread 
costs over even more interconnection customers benefitting from network 
upgrades.\938\ A couple of commenters contend that the proposal will 
provide more certainty and result in fewer withdrawals, thus reducing 
associated restudies and study processing delays.\939\
---------------------------------------------------------------------------

    \936\ AES Initial Comments at 12; Avangrid Initial Comments at 
32; Bonneville Initial Comments at 11; Interwest Initial Comments at 
17; ISO-NE Initial Comments at 25; MISO Initial Comments at 47; 
NARUC Initial Comments at 9; National Grid Initial Comments at 19; 
NESCOE Initial Comments at 9-10; New Jersey Commission Initial 
Comments at 15-16; NYTOs Initial Comments at 17; SEIA Initial 
Comments at 12; Shell Initial Comments at 27; Vistra Initial 
Comments at 1; Xcel Initial Comments at 27.
    \937\ OMS Initial Comments at 9.
    \938\ NARUC Initial Comments at 9.
    \939\ New Jersey Commission Initial Comments at 16; Omaha Public 
Power Initial Comments at 5-6; SEIA Initial Comments at 2.
---------------------------------------------------------------------------

    472. Several commenters believe that the proposal will address the 
issue of ``first movers/free riders'' when interconnection customers in 
a later cluster study benefit from network upgrades assigned to 
interconnection customers in earlier clusters.\940\ Shell claims that 
avoiding first mover subsidization of free riders is particularly 
important for offshore wind interconnections because of the potential 
lack of onshore access points and, therefore, argues that the 
Commission should be open to non-traditional cost allocation methods 
when contemplating methods to mitigate first mover risk.\941\
---------------------------------------------------------------------------

    \940\ ELCON Initial Comments at 9; Longroad Energy Reply 
Comments at 13; Pattern Energy Initial Comments at 18; SEIA Initial 
Comments at 12; Shell Initial Comments at 27; Xcel Initial Comments 
at 27; Vistra Initial Comments at 4.
    \941\ Shell Initial Comments at 27.
---------------------------------------------------------------------------

    473. Additionally, some commenters believe that the proposal is 
consistent with the Commission's cost causation policy.\942\ Avangrid 
asserts that, when surplus transmission capacity created by a recent 
network upgrade is used by a later generating facility, the lower-
queued interconnection customer should share the costs in a way that is 
commensurate with benefits like those allocated using the original 
proportional impact method assessment.\943\
---------------------------------------------------------------------------

    \942\ Avangrid Initial Comments at 32; Omaha Public Power 
Initial Comments at 5-6; Vistra Initial Comments at 5.
    \943\ Avangrid Initial Comments at 32.
---------------------------------------------------------------------------

    474. Xcel does not believe the proposal will have a significant 
impact on the number of interconnection requests submitted but believes 
that it will reduce barriers to entry for all interconnection 
customers.\944\ Xcel believes that the proposal is appropriate where 
there is participant funding.
---------------------------------------------------------------------------

    \944\ Xcel Initial Comments at 48.
---------------------------------------------------------------------------

ii. Comments in Opposition
    475. Some commenters oppose the proposal.\945\ Several commenters 
assert that it will not yield many benefits and that the Commission 
should focus on other reforms that are more likely to reduce network 
upgrade costs and improve the equity of allocating them among 
beneficiaries.\946\ Dominion and Fervo Energy argue that 
interconnection customers in subsequent clusters do not ``cause'' the 
costs to be incurred, and to the extent the interconnection customers 
will benefit, they will contribute through their payment for 
transmission service.\947\
---------------------------------------------------------------------------

    \945\ APS Initial Comments at 11; Dominion Initial Comments at 
22, 28; Dominion Reply Comments at 17; Duke Southeast Utilities 
Initial Comments at 9; EEI Reply Comments at 12-13; Enel Initial 
Comments at 30; Indicated PJM TOs Initial Comments at 21; PacifiCorp 
Initial Comments at 27; Pennsylvania Commission Initial Comments at 
10; R Street Initial Comments 12; SPP Initial Comments at 8; U.S. 
Chamber of Commerce Initial Comments at 8.
    \946\ AEE Initial Comments at 16; Dominion Initial Comments at 
23-24; Dominion Reply Comments at 17; Enel Initial Comments at 30; 
EEI Reply Comments at 12; Eversource Initial Comments at 15; 
Indicated PJM TOs Reply Comments at 40; PacifiCorp Initial Comments 
at 29; Pennsylvania Commission Initial Comments at 10; Pine Gate 
Initial Comments at 20; SoCal Edison Initial Comments at 17; SPP 
Initial Comments at 8; U.S. Chamber of Commerce Initial Comments at 
8.
    \947\ Dominion Initial Comments at 23; Fervo Energy Reply 
Comments at 5-6.
---------------------------------------------------------------------------

    476. Other commenters believe that the implementation of the 
proposal will be administratively burdensome for transmission 
providers.\948\ A few commenters believe that the proposal will lead to 
increased disputes and FPA section 206 complaints at the Commission 
over cost allocation assignments.\949\
---------------------------------------------------------------------------

    \948\ AECI Initial Comments at 5; AEE Initial Comments at 16; 
APS Initial Comments at 11; CAISO Initial Comments at 15; Dominion 
Initial Comments at 23-24; Dominion Reply Comments at 17; Enel 
Initial Comments at 30; Indicated PJM TOs Initial Comments at 21-22; 
National Grid Initial Comments at 19; PacifiCorp Initial Comments at 
27, 29; Pine Gate Initial Comments at 22; PJM Initial Comments at 
37-38; R Street Initial Comments at 12; SPP Initial Comments at 8; 
U.S. Chamber of Commerce Initial Comments at 8.
    \949\ AECI Initial Comments at 5-6; Dominion Initial Comments at 
23-24; Dominion Reply Comments at 18; Duke Southeast Utilities 
Initial Comments at 10; Fervo Energy Reply Comments at 5; PacifiCorp 
Initial Comments at 28; PJM Initial Comments at 37-38.
---------------------------------------------------------------------------

    477. Several commenters express concern that the proposal will lead 
to interconnection study delays and/or restudies, which would undermine 
the NOPR's goal to reduce interconnection study processing 
timelines.\950\ A few commenters state that the proposal would require 
transmission providers to track all in-service network upgrades on the 
transmission system across all cluster studies over a five-year period, 
which they contend would be onerous or nearly impossible.\951\ The U.S. 
Chamber of Commerce claims that power flow studies conducted up to five 
years after the in-service date of non-adjacent network upgrades will 
inevitably fail to accurately divide the relevant interconnection costs 
among disparate-in-time interconnection customers due to the many 
coinciding yet unrelated system changes that will affect the outcomes 
of such analyses.\952\ PacifiCorp contends that this requirement would 
require transmission providers to track multiple requests for

[[Page 61085]]

each network upgrade on different timelines, the suspension or 
withdrawal of which could trigger cascading revaluations and 
corresponding LGIA amendments.\953\ Dominion contends that the NOPR's 
proposal would complicate reviews and require additional time-consuming 
analysis, which would only worsen for transmission providers with a 
high volume of interconnection requests, such as RTOs/ISOs.\954\
---------------------------------------------------------------------------

    \950\ CAISO Initial Comments at 13; Dominion Initial Comments at 
23; Dominion Reply Comments at 17; Indicated PJM TOs Reply Comments 
at 40; PacifiCorp Initial Comments at 27-28; Pennsylvania Commission 
Initial Comments at 10; SPP Initial Comments at 9.
    \951\ APS Initial Comments at 11-12; Dominion Initial Comments 
at 22; Dominion Reply Comments at 17; PacifiCorp Initial Comments at 
28; U.S. Chamber of Commerce Initial Comments at 8.
    \952\ U.S. Chamber of Commerce Initial Comments at 8.
    \953\ PacifiCorp Initial Comments at 28.
    \954\ Dominion Initial Comments at 23.
---------------------------------------------------------------------------

    478. Some commenters argue that the proposal will not create cost 
certainty for interconnection customers in earlier clusters when 
deciding whether to move forward with a generating facility because 
there would be no guarantee that an interconnection customer in a 
subsequent cluster would provide reimbursement.\955\ NextEra and PJM 
argue that a benefit of not sharing costs between clusters is that all 
the interconnection customers within a cluster simultaneously learn 
their network upgrade costs and associated cost responsibility, 
creating greater cost certainty.\956\
---------------------------------------------------------------------------

    \955\ AEE Initial Comments at 16; Clean Energy Associations 
Initial Comments at 25; Dominion Initial Comments at 23-24; EEI 
Initial Comments at 22; Enel Initial Comments at 30; Indicated PJM 
TOs Initial Comments at 22-23; Indicated PJM TOs Reply Comments at 
40; NARUC Initial Comments at 9; NextEra Initial Comments at 18; 
Pine Gate Initial Comments at 22; PJM Initial Comments at 38; U.S. 
Chamber of Commerce Initial Comments at 8; Xcel Initial Comments at 
48.
    \956\ NextEra Initial Comments at 18-19; PJM Initial Comments at 
38.
---------------------------------------------------------------------------

iii. Alternatives and Requests for Flexibility
    479. Several commenters recommend modifications to the 
proposal.\957\ A few recommend that the Commission implement a minimum 
threshold before a network upgrade would be evaluated as a potential 
shared network upgrade.\958\ MISO and Xcel state that changes will be 
necessary in RTO/ISO regions where a transmission owner may 
unilaterally provide upfront funding for network upgrades to integrate 
the cost allocation for such a funding mechanism with the shared 
network upgrade proposal.\959\ ENGIE recommends that the Commission set 
requirements in the interconnection process to identify interconnection 
facilities and network upgrades that are necessary to interconnect the 
generating facility, as well as network upgrades needed to mitigate 
local transmission constraints, and asserts that interconnection 
customers should not be responsible for the costs of distant and 
minimally impacted network upgrades.\960\ Xcel also contends that the 
interconnection customer in the subsequent cluster should enter into a 
multiparty facilities service agreement to reimburse the 
interconnection customers in the earlier cluster, rather than pay the 
proposed lump sum payment to the transmission provider.\961\ Pattern 
Energy recommends that the interconnection customer in the later 
cluster be required to repay the earlier interconnection customer at 
the time of execution of the subsequent interconnection customer's 
interconnection agreement, and not when the relevant shared network 
upgrades go into service.\962\
---------------------------------------------------------------------------

    \957\ Clean Energy Associations Initial Comments at 25-26; ENGIE 
Reply Comments at 3-4; MISO Initial Comments at 48-49; Pattern 
Energy Initial Comments at 18; Xcel Initial Comments at 29.
    \958\ ENGIE Reply Comments at 3-4; MISO Initial Comments at 48; 
R Street Initial Comments 12; Xcel Initial Comments at 29.
    \959\ MISO Initial Comments at 48-49; Xcel Initial Comments at 
29.
    \960\ ENGIE Reply Comments at 3-4.
    \961\ Xcel Initial Comments at 29.
    \962\ Pattern Energy Initial Comments at 18.
---------------------------------------------------------------------------

    480. A few commenters propose alternative methods for cost 
allocation for shared network upgrades.\963\ For instance, Xcel argues 
that the Commission should be clear that it will accept other proposals 
to determine if a network upgrade is shareable to subsequent 
interconnection requests.\964\
---------------------------------------------------------------------------

    \963\ Clean Energy Associations Initial Comments at 25; ENGIE 
Reply Comments at 3; Longroad Energy Reply Comments at 13; Pine Gate 
Initial Comments at 20, 23.
    \964\ Xcel Initial Comments at 28.
---------------------------------------------------------------------------

    481. Some commenters support regional flexibility for transmission 
providers to implement any shared network upgrade mechanism.\965\ For 
example, NESCOE suggests that allowing transmission providers, 
especially RTOs/ISOs, some flexibility in coordinating with their 
states on developing proposed approaches to sharing the costs 
associated with network upgrades funded by interconnection customers in 
earlier clusters could minimize the contentious nature of developing 
cost sharing arrangements.\966\
---------------------------------------------------------------------------

    \965\ Bonneville Initial Comments at 11; CAISO Initial Comments 
at 14; EEI Initial Comments at 22; Indicated PJM TOs Initial 
Comments at 21; Indicated PJM TOs Reply Comments at 40; National 
Grid Initial Comments at 19; NESCOE Initial Comments at 11; NESCOE 
Reply Comments at 7; NRECA Initial Comments at 9, 24; NYISO Initial 
Comments at 16; PJM Initial Comments at 37.
    \966\ NESCOE Initial Comments at 11.
---------------------------------------------------------------------------

    482. Other commenters recommend that the Commission not adopt the 
shared network upgrade proposal in non-RTO/ISO regions where 
interconnection customers provide upfront funds for the network 
upgrades and receive reimbursement through transmission credits from 
the transmission provider, plus interest (i.e., the interconnection 
pricing policy established in Order No. 2003).\967\ Pine Gate states 
that under the NOPR proposal, interconnection customers in later 
clusters would potentially reimburse interconnection customers in 
earlier clusters sooner than the transmission provider would have via 
transmission credits, but with the same result.\968\ Enel asserts that 
coupling shared network upgrades with transmission credits creates even 
more administrative complexity, as an interconnection customer in a 
later cluster providing funds to an interconnection customer in an 
earlier cluster would necessitate a partial transfer of transmission 
credits, potentially on a partially depreciated asset, which creates an 
extremely complex payment, reimbursement, and multiparty crediting 
system that would be administratively burdensome.\969\ Similarly, APS 
and Duke Southeast Utilities express concern over an additional 
complication in the event the earlier interconnection customer has 
already been fully reimbursed for the network upgrades through 
transmission credits.\970\ In contrast, Vistra contends that the shared 
network upgrade proposal will be beneficial in regions with 
transmission crediting as it will speed reimbursement relative to the 
status quo.\971\ Vistra claims that, when an overlap exists between the 
reimbursement of an interconnection customer through transmission 
credits and the reimbursement mechanism in this proposal, this proposal 
will appropriately charge interconnection customers in subsequent 
clusters.
---------------------------------------------------------------------------

    \967\ Duke Southeast Utilities Initial Comments at 10-11; Enel 
Initial Comments at 30; PacifiCorp Initial Comments at 26-28; Pine 
Gate Initial Comments at 22.
    \968\ Pine Gate Initial Comments at 22.
    \969\ Enel Initial Comments at 30.
    \970\ APS Initial Comments at 12; Duke Southeast Utilities 
Initial Comments at 10.
    \971\ Vistra Initial Comments at 5.
---------------------------------------------------------------------------

    483. Other commenters raise additional cost allocation concerns 
with the shared network upgrade proposal. Enel argues that, in markets 
where transmission credits do not apply, reimbursement for funding 
network upgrades is often granted in the form of congestion hedging 
mechanisms, and the repayment of network upgrade costs from a lower-
queued interconnection customer to a higher-queued interconnection 
customer could create the need for a partial transfer of these

[[Page 61086]]

congestion hedging rights.\972\ SDG&E cautions against allowing 
scenarios where an higher-queued interconnection customer with cost 
responsibility terminates an executed LGIA but the network upgrades are 
still needed for later interconnection customers, thus leaving the 
transmission provider as the backstop for financing the network 
upgrade.\973\ A few commenters argue that the Commission should limit 
its proposal to share network upgrade costs between clusters to areas 
whether interconnection customers are not already reimbursed for 
network upgrade costs.\974\
---------------------------------------------------------------------------

    \972\ Enel Initial Comments at 30.
    \973\ SDG&E Initial Comments at 6.
    \974\ CAISO Initial Comments at 13; SoCal Edison Initial 
Comments at 16.
---------------------------------------------------------------------------

    484. Several commenters note that some RTOs/ISOs have similar 
existing cost allocation mechanisms to the NOPR proposal and request 
that, in those instances, the Commission defer to those transmission 
providers when the existing mechanisms are accomplishing the final 
rule's objectives.\975\ On a similar note, PJM and Indicated PJM TOs 
request that the Commission not require PJM to implement cost sharing 
between its clusters.\976\
---------------------------------------------------------------------------

    \975\ Ameren Initial Comments at 13; APPA-LPPC Initial Comments 
at 17; ISO-NE Initial Comments at 26; MISO Initial Comments at 47-
48; NYISO Initial Comments at 15; NYTOs Initial Comments at 17; OMS 
Initial Comments at 9; SDG&E Initial Comments at 5.
    \976\ Indicated PJM TOs Initial Comments at 23; PJM Initial 
Comments at 37.
---------------------------------------------------------------------------

    485. Several commenters request various clarifications of the 
proposal and provide their thoughts on specific aspects.\977\
---------------------------------------------------------------------------

    \977\ APS Initial Comments at 11-12; Avangrid Initial Comments 
at 32-33; Clean Energy Associations Initial Comments at 25; Fervo 
Energy Initial Comments at 4; Fervo Energy Reply Comments at 4; 
LADWP Initial Comments at 4; Pattern Energy Initial Comments at 18; 
Pine Gate Initial Comments at 21-22; Tri-State Initial Comments at 
12, 34; Vistra Initial Comments at 5.
---------------------------------------------------------------------------

c. Commission Determination
    486. We decline to adopt the NOPR proposal to revise the pro forma 
LGIP and pro forma LGIA to implement shared network upgrades between 
interconnection customers in an earlier cluster and interconnection 
customers in a subsequent cluster. We find that the reforms adopted in 
this final rule that require transmission providers to allocate network 
upgrade costs to interconnection customers within the same cluster 
using a proportional impact method, as discussed above, will provide 
interconnection customers with more cost certainty during the 
interconnection process and will allow for sharing of network upgrade 
costs between interconnection customers that benefit from those network 
upgrades within the same cluster.
    487. The record demonstrates the complexity of the NOPR proposal 
and potentially significant administrative burdens associated with 
implementing it for at least some transmission providers, especially 
under the Commission's interconnection pricing policy. We agree with 
some commenters that adopting the proposal would not provide cost 
certainty to interconnection customers in earlier clusters at the point 
that they have to proceed in the interconnection process because they 
would lack certainty about potential reimbursement for network upgrades 
from interconnection customers in subsequent clusters.\978\ Thus, the 
NOPR proposal is unlikely to reduce barriers to generation development 
due to the absence of network upgrade cost sharing provisions. Further, 
the proposal may introduce burdens for lower-queued interconnection 
customers that could be faced with reimbursing a higher-queued 
interconnection customer for a new shared network upgrade cost late in 
the interconnection process. For these reasons, we decline to adopt 
this NOPR proposal.\979\
---------------------------------------------------------------------------

    \978\ AEE Initial Comments at 16; Clean Energy Associations 
Initial Comments at 25; Dominion Initial Comments at 23-24; EEI 
Initial Comments at 22; Enel Initial Comments at 30; Indicated PJM 
TOs Initial Comments at 22-23; Indicated PJM TOs Reply Comments at 
40; NARUC Initial Comments at 9; NextEra Initial Comments at 18; 
Pine Gate Initial Comments at 22; PJM Initial Comments at 38; U.S. 
Chamber of Commerce Initial Comments at 8; Xcel Initial Comments at 
48.
    \979\ We note that MISO, ISO-NE, and NYISO, which have 
independent entity variations to the Commission's crediting policy, 
have similar shared network upgrade mechanisms to the NOPR proposal. 
See Midwest Indep. Transmission Sys. Operator, Inc., 133 FERC ] 
61,221, at P 336 (2010); ISO New England Inc., 161 FERC ] 61,123, at 
PP 92-96 (2017); N.Y. Indep. Sys. Operator, Inc., 124 FERC ] 61,238, 
at P 34 (2008).
---------------------------------------------------------------------------

    488. We find that the final rule's reforms to conduct cluster 
studies and to allocate the costs of any assigned network upgrades to 
the cluster's interconnection customers on a proportional basis address 
the ``first mover/free rider'' issue.\980\ Under this final rule, a 
transmission provider must study interconnection customers in an 
earlier cluster study based on the transmission system at that time, 
and those interconnection customers will be assigned network upgrades 
that would not be needed but for their interconnection to the 
transmission system; then, the transmission provider will study 
interconnection customers in a subsequent cluster study based on the 
transmission system at that point in time, and those interconnection 
customers will be assigned any necessary network upgrades that would 
not be needed but for their interconnection to the transmission system. 
Further, we note that under the Commission's interconnection pricing 
policy, interconnection customers receive reimbursement for network 
upgrade costs, which helps to mitigate any ``first mover/free rider'' 
concerns because interconnection customers are reimbursed through 
transmission credits. In addition, we find that the aforementioned 
reforms to conduct cluster studies and use a proportional impact method 
to allocate the costs of network upgrades within a cluster will also 
address ``first mover/free rider'' concerns in regions with independent 
entity variations to the interconnection pricing policy.
---------------------------------------------------------------------------

    \980\ See ELCON Initial Comments at 9; Longroad Energy Reply 
Comments at 13; Pattern Energy Initial Comments at 18; SEIA Initial 
Comments at 12; Shell Initial Comments at 27; Vistra Initial 
Comments at 4; Xcel Initial Comments at 27.
---------------------------------------------------------------------------

    489. Because we decline to adopt this proposal, we do not respond 
to the requests for clarification or the requests for modifications to 
the NOPR proposal that would not address the reasons provided above for 
declining to adopt the NOPR proposal as a general matter.
6. Increased Financial Commitments and Readiness Requirements
    490. In the NOPR, the Commission stated that the pro forma LGIP 
allows an interconnection customer to proceed through the generator 
interconnection process without having shown evidence to the 
transmission provider of meaningful progress toward achieving 
commercial viability.\981\ The Commission stated its concern that, 
without requiring this type of evidence, interconnection customers will 
continue to submit multiple speculative interconnection requests and 
later withdraw those requests, triggering rounds of restudies. The 
Commission therefore proposed a set of reforms to adopt more stringent 
financial commitments and readiness requirements for interconnection 
customers to remain in the interconnection queue to discourage 
speculative interconnection requests and allow transmission providers 
to focus on processing viable interconnection requests and to better 
approximate the cost of the interconnection study process.\982\
---------------------------------------------------------------------------

    \981\ NOPR, 179 FERC ] 61,194 at P 102.
    \982\ Id. P 103.

---------------------------------------------------------------------------

[[Page 61087]]

a. Increased Study Deposits
i. NOPR Proposal
    491. In the NOPR, the Commission proposed to adopt the following 
study deposit framework in the pro forma LGIP: \983\
---------------------------------------------------------------------------

    \983\ Id. P 106.

------------------------------------------------------------------------
   Size of proposed generating facility
  associated with interconnection request         Amount of deposit
------------------------------------------------------------------------
> 20 MW < 80 MW...........................  $35,000 + $1,000/MW.
>= 80 MW < 200 MW.........................  $150,000.
>= 200 MW.................................  $250,000.
------------------------------------------------------------------------

    492. The Commission proposed to require transmission providers to 
collect this study deposit before each phase of the new first-ready, 
first-served cluster study process (i.e., cluster study, cluster 
restudy, and facilities study).\984\ The Commission proposed to require 
the interconnection customer to provide: (1) an initial study deposit 
along with its interconnection request, which will be used to pay for 
the cluster study; (2) the second study deposit of the same amount 
within 20 days of receiving the cluster study report from the 
transmission provider to cover the cost of any clustered restudies; and 
(3) the third study deposit of the same amount along with its executed 
facilities study agreement. The Commission explained that study 
deposits would be refundable, and that the transmission provider would 
refund any portion of the study deposits above the applicable study 
costs and withdrawal penalties once the interconnection customer 
executes the LGIA, requests the filing of an unexecuted LGIA and 
submits the corresponding payment discussed below, or withdraws from 
the interconnection queue. The Commission also proposed to delete 
section 8.1.1 of the pro forma LGIP to remove the requirement for 
transmission providers to invoice interconnection customers on a 
monthly basis for the work conducted on the facilities study.
---------------------------------------------------------------------------

    \984\ Id. P 107.
---------------------------------------------------------------------------

    493. The Commission sought comment on whether: (1) the proposed 
study deposit amounts accurately estimate the cost of conducting 
cluster studies; and (2) to adopt additional provisions or a different 
framework that would require larger proposed generating facilities to 
provide a higher deposit amount--such as a per MW framework.\985\
---------------------------------------------------------------------------

    \985\ Id. P 110.
---------------------------------------------------------------------------

ii. Comments
    494. Several commenters fully support the NOPR proposal to increase 
study deposits in order to support more effective interconnection queue 
management and reduce speculative interconnection requests.\986\
---------------------------------------------------------------------------

    \986\ AEP Initial Comments at 20; APPA-LPPC Initial Comments at 
18; CAISO Initial Comments at 15-16; Consumers Energy Initial 
Comments at 5; EEI Initial Comments at 6-7; NARUC Initial Comments 
at 10; NYTOs Initial Comments at 17; Pennsylvania Commission Initial 
Comments at 14; SoCal Edison Initial Comments at 5; U.S. Chamber of 
Commerce Initial Comments at 8; UMPA Initial Comments at 5; Vistra 
Initial Comments at 6.
---------------------------------------------------------------------------

    495. Other commenters express qualified support for the 
proposal.\987\ For example, ELCON, New York Commission and NYSERDA, and 
NextEra contend that it is important that such measures be carefully 
balanced so that they are not overly burdensome or discouraging to 
interconnection customers with legitimate proposed generating 
facilities that may be delayed for reasons out of their control.\988\ 
Clean Energy Associations do not oppose the heightened study deposit 
requirements, provided that they are paired with real predictability on 
the timing of studies and real certainty on the costs of network 
upgrades.\989\ CAISO argues that the Commission must raise study 
deposits significantly, and contends that it is illusory to argue that 
interconnection customers without significant capital can progress to 
commercial operation in today's hyper-competitive climate.\990\ PPL 
asserts that the Commission's proposed study deposits are likely on the 
low end of what is required to ensure proper ``skin in the game,'' but 
should work for many regions, including New England.\991\ Tri-State 
overall supports the proposed study deposit amounts but notes that 
interconnection customers proposing smaller generating facilities will 
end up paying a lower study deposit than what Tri-State is currently 
charging.\992\ ENGIE, MISO, and SPP would prefer to collect study 
deposits only once upon entry into the cluster, rather than at each 
stage of the cluster study process, to reduce administrative burden on 
them and the interconnection customers.\993\ MISO and Shell argue that 
limiting speculative interconnection requests and ensuring more 
concrete financial readiness would be better achieved by requiring a 
single study deposit at the initiation of the generator interconnection 
process.\994\ Shell urges the Commission to base that deposit on the 
generating facility's size.
---------------------------------------------------------------------------

    \987\ ACE-NY Initial Comments at 4; AES Initial Comments at 14; 
Ameren Initial Comments at 14; APPA-LPPC Initial Comments at 18; APS 
Initial Comments at 13; Avangrid Initial Comments at 16; Bonneville 
Initial Comments at 11; CESA Initial Comments at 8-9; Clean Energy 
Associations Initial Comments at 30; Cypress Creek Initial Comments 
at 20; Dominion Initial Comments at 24; EEI Initial Comments at 6; 
ELCON Initial Comments at 10; ENGIE Initial Comments at 4; 
Eversource Initial Comments at 16; Google Initial Comments at 20; 
Fervo Energy Initial Comments at 4; Idaho Power Initial Comments at 
6; ISO-NE Initial Comments at 27; MISO Initial Comments at 49; 
National Grid Initial Comments at 20; NESCOE Reply Comments at 8, 
10; New York Commission and NYSERDA Initial Comments at 8; NextEra 
Initial Comments at 20; NRECA Initial Comments at 25; NV Energy 
Initial Comments at 14; NYISO Initial Comments at 19-20; Omaha 
Public Power Initial Comments at 6; Pacific Northwest Utilities 
Initial Comments at 4; PJM Initial Comments at 24; PPL Initial 
Comments at 15; SEIA Initial Comments at 13; Southern Initial 
Comments at 8-9; SPP Initial Comments at 9; Tri-State Initial 
Comments at 4, 12.
    \988\ ELCON Initial Comments at 10; New York Commission and 
NYSERDA Initial Comments at 8-9; NextEra Initial Comments at 20.
    \989\ Clean Energy Associations Initial Comments at 30.
    \990\ CAISO Initial Comments at 15-16.
    \991\ PPL Initial Comments at 15 (noting that PJM's 
interconnection queue reform proposal includes higher deposits, 
ranging from $75,000 to $400,000 and a 10% nonrefundable component).
    \992\ Tri-State Initial Comments at 12.
    \993\ ENGIE Initial Comments at 4; MISO Initial Comments at 50; 
SPP Initial Comments at 9.
    \994\ MISO Initial Comments at 51; Shell Initial Comments at 17; 
Shell Reply Comments at 22.
---------------------------------------------------------------------------

    496. Several commenters argue that the final rule should provide 
each region with flexibility concerning the scope and application of 
any modifications to increased study deposits.\995\ Indicated PJM TOs 
contend that the transmission provider should be entitled to adjust the 
study deposit value if it observes that the actual cost of studies 
tends to be materially higher or lower.\996\ Dominion adds that the 
Commission should respect the previously accepted reforms made by 
transmission providers like Dominion and PJM with regard to study 
deposits.\997\
---------------------------------------------------------------------------

    \995\ Avangrid Initial Comments at 17; Bonneville Initial 
Comments at 11; Dominion Initial Comments at 24; Indicated PJM TOs 
Reply Comments at 29; Interwest Reply Comments at 12; ISO-NE Initial 
Comments at 28; National Grid Initial Comments at 21; New York 
Commission and NYSERDA Initial Comments at 9; NESCOE Reply Comments 
at 9-10; NRECA Initial Comments at 26; NYISO Initial Comments at 19; 
Pacific Northwest Utilities Initial Comments at 2; SPP Initial 
Comments at 10.
    \996\ Indicated PJM TOs Reply Comments at 29.
    \997\ Dominion Initial Comments at 24.
---------------------------------------------------------------------------

    497. APS suggests that any refundable deposits should not include 
the Commission interest rate and argues that, by requiring additional 
funds to be deposited as described in the NOPR, the Commission's 
proposal would lead to an exorbitant increase in the amount of 
Commission interest paid back to an interconnection customer as it 
moves along through the process at the transmission provider's 
expense.\998\
---------------------------------------------------------------------------

    \998\ APS Initial Comments at 13.
---------------------------------------------------------------------------

    498. Other commenters mostly oppose the NOPR proposal to increase 
study

[[Page 61088]]

deposits.\999\ CREA and NewSun agree that a tiered study deposit level 
tied to interconnection capacity requested may be warranted and at most 
study deposits should be increased to more accurately cover the cost of 
the studies, but comment that the rest of the NOPR's proposal appears 
to increase the study deposit levels solely to deter interconnection 
customers from entering the interconnection queue, not because the 
current level of study deposits is insufficient to cover the costs of 
the studies.\1000\ CREA and NewSun argue that, if this rulemaking 
generates evidence that the current study deposit levels are 
insufficient to cover the typical costs of studies, an increase may be 
justified, but until then, study deposits should not be increased. 
Eversource recommends that the Commission consider making the rate of 
increase per MW more gradual, and that based on the current proposed 
figures, the deposits may increase too quickly relative to generating 
facility size.\1001\ rPlus argues that study deposit requirements are 
unduly discriminatory or punitive to pumped storage as compared to 
other renewable technologies because a large capacity pumped storage 
facility would expect to hit the maximum deposit and/or penalty in 
every stage of the interconnection study process, LGIA, and potential 
withdrawal.\1002\ RWE Renewables fully supports allocating some risk 
for each generating facility entered into the interconnection queue to 
interconnection customers, but argues that increased financial deposits 
have unfortunately not been an adequate deterrent to a high volume of 
non-viable generating facilities entering into the interconnection 
queues.\1003\
---------------------------------------------------------------------------

    \999\ CREA and NewSun Initial Comments at 51-52; Eversource 
Initial Comments at 16; rPlus Initial Comments at 5; RWE Renewables 
Initial Comments at 2.
    \1000\ CREA and NewSun Initial Comments at 51-52.
    \1001\ Eversource Initial Comments at 16.
    \1002\ rPlus Initial Comments at 5.
    \1003\ RWE Renewables Initial Comments at 2.
---------------------------------------------------------------------------

    499. In response to the Commission's request for comment on whether 
the proposed study deposit amounts accurately estimate the cost of 
conducting cluster studies, Ameren states that, based on its 
experience, the proposed study deposits are in line with the cost of 
conducting the cluster studies.\1004\ Xcel contends that the proposed 
study deposits are more than the cost of studies in its experience, but 
as studies will need to be accelerated under the Commission's proposal 
(to meet timelines) and may involve more actions, the proposed study 
cost may be appropriate.\1005\ NV Energy states that, on average, it 
spends between $80,000 and $100,000 between the cluster system impact 
study and facilities studies and refunds the remaining deposits with 
interest.\1006\ Cypress Creek comments that in its experience, study 
costs can vary widely depending on the transmission provider, the staff 
resources it has available to conduct the study, and whether it needs 
to contract with external resources to conduct the study.\1007\
---------------------------------------------------------------------------

    \1004\ Ameren Initial Comments at 14.
    \1005\ Xcel Energy Initial Comments at 29-30.
    \1006\ NV Energy Initial Comments at 14.
    \1007\ Cypress Creek Initial Comments at 20-21.
---------------------------------------------------------------------------

    500. CREA and NewSun urge the Commission to maintain a lower study 
deposit prior to obtaining the initial cluster study. They argue that 
larger study deposits are only justified once the interconnection 
customer can realistically assess the commercial viability of its 
proposed generating facility within the cluster after obtaining the 
potential interconnection costs.\1008\ Fervo Energy contends that more 
information is needed before one can conclude that the proposed study 
deposit amount framework would not result in deposits that far exceed 
the actual cost of the studies, particularly in light of the withdrawal 
penalty proposal.\1009\ Cypress Creek suggests that the Commission 
should provide additional justification and argues that the NOPR fails 
to provide any further justification for study costs (i.e., based on a 
market analysis or other method), stating only that the proposed 
amounts ``better approximate the cost of the interconnection study 
process.'' \1010\
---------------------------------------------------------------------------

    \1008\ CREA and NewSun Initial Comments at 53.
    \1009\ Fervo Energy Initial Comments at 4.
    \1010\ Cypress Creek Initial Comments at 20 (quoting NOPR, 179 
FERC ] 61,194 at P 103).
---------------------------------------------------------------------------

    501. In response to the Commission's request for comment on whether 
the Commission should adopt additional provisions or a different 
framework that would require larger proposed generating facilities to 
provide a higher study deposit amount, such as a per MW framework, PJM 
contends that the Commission should adopt readiness payments or study 
deposits based on the costs of the network upgrades necessary to 
interconnect the generating facilities in the cluster, which also 
contain ``at-risk'' non-refundable provisions.\1011\
---------------------------------------------------------------------------

    \1011\ PJM Initial Comments at 24.
---------------------------------------------------------------------------

iii. Commission Determination
    502. We adopt, with modification, the NOPR proposal to require 
interconnection customers to pay, and transmission providers to 
collect, study deposits as part of the cluster study process.\1012\ 
Specifically, we adopt the NOPR proposal to require the following study 
deposit framework in section 3.1.1.1 of the pro forma LGIP:
---------------------------------------------------------------------------

    \1012\ Here, we refer to initial study deposits separately from 
the LGIA deposit. We discuss the latter in section III.A.6.d below. 
In the NOPR, the Commission discussed the deposits together, NOPR, 
179 FERC ] 61,194 at P 109, although the proposed pro forma LGIP 
treated the initial study deposit, proposed pro forma LGIP section 
3.1.1.1 (Initial Study Deposit), separate from the LGIA deposit, 
proposed pro forma LGIP section 3.1.1.3 (LGIA Deposit).

------------------------------------------------------------------------
   Size of proposed generating facility
  associated with interconnection request         Amount of deposit
------------------------------------------------------------------------
> 20 MW < 80 MW...........................  $35,000 + $1,000/MW.
>= 80 MW < 200 MW.........................  $150,000.
>= 200 MW.................................  $250,000.
------------------------------------------------------------------------

    503. However, we modify the NOPR proposal to require transmission 
providers to collect a single study deposit only once upon entry into 
the cluster (initial study deposit), rather than requiring transmission 
providers to collect a study deposit at each phase of the cluster study 
process, as proposed in the NOPR. Therefore, we decline to adopt the 
proposed revisions to sections 3.1.1.2, 7.5, and 8.1 of the pro forma 
LGIP that would have implemented the phased study deposit approach. As 
a result of this modification to the NOPR proposal, the initial study 
deposit will be required only at the time the interconnection customer 
submits an interconnection request. The amount of the initial study 
deposit will be calculated using the tiered approach proposed in the 
NOPR based on the proposed MW size of the generating facility, as shown 
in the chart above.
    504. We adopt the tiered approach based on the proposed MW size of 
the generating facility for determining the amount of the initial study 
deposit because larger proposed generating facilities within a cluster 
generally cost more to study than smaller proposed generating 
facilities within a cluster. Further, although we acknowledge that this 
approach does not perfectly approximate study costs, we find it 
appropriate to require the transmission provider to collect a study 
deposit based on a tiered approach because study costs will be trued up 
and any excess deposit refunded once the interconnection customer 
executes the LGIA or requests the filing of an unexecuted LGIA and 
submits the corresponding payment discussed below or withdraws from the 
interconnection queue.
    505. We modify the NOPR proposal to require only a single initial 
study deposit, rather than multiple deposits at

[[Page 61089]]

different stages of the cluster study process, as proposed in the NOPR. 
We believe that this modification will appropriately reduce the 
administrative burden for transmission providers to collect and manage 
the deposits.\1013\ We recognize that the amount of the study deposit 
for interconnection customers will be lower than that proposed in the 
NOPR because of this modification. We are persuaded by commenters' 
arguments that initial study deposits are best used to provide 
transmission providers with funds to cover the costs of studies 
performed for interconnection customers rather than to serve as a 
disincentive against speculative interconnection requests.\1014\ We 
therefore adopt an initial study deposit framework that better reflects 
the costs of the interconnection studies. For example, NV Energy states 
that, on average, it spends between $80,000 and $100,000 between the 
cluster system impact study and facilities studies and refunds the 
remaining deposits with interest.\1015\ Under the study deposit 
framework we adopt, study deposits range between $55,000 and $250,000 
for the smallest and largest proposed generating facilities, 
respectively, and thus reasonably track likely study costs based on the 
record. We believe that other reforms adopted in this final rule--
notably, the commercial readiness deposits and the site control 
requirements--will adequately serve as a disincentive against 
speculative interconnection requests without unnecessarily duplicating 
those efforts through increased study deposits.
---------------------------------------------------------------------------

    \1013\ See ENGIE Initial Comments at 4; MISO Initial Comments at 
50; SPP Initial Comments at 9.
    \1014\ See Order No. 2003, 104 FERC ] 61,103 at P 220.
    \1015\ NV Energy Initial Comments at 14.
---------------------------------------------------------------------------

    506. Additionally, we adopt the NOPR proposal to delete section 
8.1.1 of the pro forma LGIP to remove the requirement for transmission 
providers to invoice interconnection customers on a monthly basis for 
the work conducted on the facilities study. We find that this monthly 
invoicing requirement is burdensome to the transmission provider and 
unnecessary given that section 13.3 of the pro forma LGIP includes 
policies for invoicing and establishes that interconnection customers 
are responsible for the actual costs of interconnection studies. 
Accordingly, we also delete from pro forma LGIP Appendix 3 
(Interconnection Facilities Study Agreement), the portion of article 
5.0 that includes the monthly invoicing requirement.
    507. We disagree with rPlus' argument that study deposit 
requirements are unduly discriminatory or punitive to pumped storage 
because of its large capacity.\1016\ We note that the initial study 
deposit reforms we adopt in this final rule are agnostic to the type of 
generating facility. Rather, the initial study deposits are based on 
the MW size of the proposed generating facility, regardless of the type 
of generating facility, such that interconnection customers proposing 
larger generating facilities will pay a larger deposit. As explained 
above, this reflects the fact that the expected costs to study those 
generating facilities are generally higher. Nonetheless, the 
modification we adopt here has the effect of lowering the required 
study deposit for all interconnection customers relative to the NOPR 
proposal, a finding which may partially allay rPlus' concern.
---------------------------------------------------------------------------

    \1016\ See rPlus Initial Comments at 5.
---------------------------------------------------------------------------

b. Demonstration of Site Control
i. NOPR Proposal
    508. In the NOPR, the Commission stated that it believed that more 
stringent site control requirements will help prevent interconnection 
customers from submitting interconnection requests for speculative, 
commercially non-viable proposed generating facilities.\1017\ The 
Commission preliminarily found that an interconnection customer 
securing the exclusive land right necessary to construct its proposed 
generating facility (or for co-located resources, demonstration of 
shared land use) is sufficient evidence of the interconnection 
customer's commitment to construct the generating facility.
---------------------------------------------------------------------------

    \1017\ NOPR, 179 FERC ] 61,194 at P 115.
---------------------------------------------------------------------------

    509. The Commission proposed to revise the pro forma LGIP to 
require interconnection customers to demonstrate 100% site control for 
their proposed generating facilities when they submit their 
interconnection request.\1018\ The Commission proposed to have 
transmission providers include in their tariff specific acreage 
requirements for each generating facility technology type to 
demonstrate site control.
---------------------------------------------------------------------------

    \1018\ Id. P 116. In the NOPR, the Commission proposed to define 
``site control'' as ``the exclusive land right to develop, 
construct, operate, and maintain the Generating Facility over the 
term of expected operation of the Generating Facility.'' 
Specifically, the NOPR definition explained that site control may be 
demonstrated by documentation establishing: (1) ownership of, a 
leasehold interest in, or a right to develop a site of sufficient 
size to construct and operate the Generating Facility or multiple 
Generating Facilities on a shared site behind one Point of 
Interconnection; (2) an option to purchase or acquire a leasehold 
site for such purpose; (3) site of sufficient size to construct and 
operate the Generating Facility; or (4) any other documentation that 
clearly demonstrates the right of Interconnection Customer to 
exclusively occupy a site of sufficient size to construct and 
operate the Generating Facility. Site Control for any Co-Located 
Resource is demonstrated by a contract or other agreement 
demonstrating shared land use for all Co-Located Resources that meet 
the aforementioned provisions of the Site Control definition.
---------------------------------------------------------------------------

    510. To cut down on multiple interconnection customers leasing the 
same site in order to remain in the interconnection queue, the 
Commission proposed to revise the pro forma LGIP to require 
interconnection customers to demonstrate the exclusive land right 
(where the land rights are exclusive to the interconnection customer, 
not necessarily the individual generating facility) to develop, 
construct, operate, and maintain its generating facility or, where 
facilities are co-located, to demonstrate a shared land use right to 
develop, construct, operate, and maintain co-located facilities.\1019\
---------------------------------------------------------------------------

    \1019\ Id. P 117.
---------------------------------------------------------------------------

    511. Additionally, the Commission proposed to include a limited 
option for interconnection customers to submit a deposit in lieu of 
site control when they submit their interconnection request only when 
regulatory limitations prohibit the interconnection customer from 
obtaining site control.\1020\ The Commission explained that in such 
instances, the interconnection customer would submit an initial deposit 
in lieu of site control of $10,000 per MW, subject to a floor of 
$500,000 and a ceiling of $2 million, which would be applied toward any 
interconnection studies or a withdrawal penalty, if applicable. The 
Commission specified that such an interconnection customer must 
demonstrate 100% site control prior to the facilities study. The 
Commission further proposed that, after the interconnection customer 
notifies the transmission provider of a change to its site control 
demonstration, the transmission provider must give the interconnection 
customer 10 business days to demonstrate that the site control 
demonstration meets the applicable requirement after 
notification.\1021\
---------------------------------------------------------------------------

    \1020\ Id. P 118.
    \1021\ Id. P 119.
---------------------------------------------------------------------------

    512. The Commission sought comment on: (1) whether there are other 
specific situations in which the Commission should accept a deposit in 
lieu of site control; (2) whether the definition of site control, 
including the requirement to obtain an exclusive land right (or, for 
co-located resources, a shared land right), should be broadened or 
refined to account for circumstances that may arise in, for example, 
the siting

[[Page 61090]]

and permitting of offshore resources in bodies of water and/or 
submerged land; (3) whether and how the definition of site control 
should be adjusted for interconnection customers to account for any 
regulatory requirements they may have associated with proposed 
generating facilities developed on sites owned or physically controlled 
by a state government entity and/or a Federal Government entity; (4) 
the appropriate stage in developing such sites when the Commission 
should view completion of such stage as indicative of an 
interconnection customer's request being non-speculative and whether 
there are substantive differences among interconnection customers 
developing sites owned or physically controlled by a state government 
entity and/or a Federal Government entity; (5) whether the Commission 
should allow transmission providers to accept demonstrations of less 
than 100% site control in the initial phases of the interconnection 
study process, outside of when regulatory limitations prohibit the 
interconnection customer from obtaining site control; and (6) whether 
the Commission should instead adopt site control provisions that allow 
a deposit in lieu of site control to enter the generator 
interconnection process and be evaluated under the first-ready, first-
served cluster study process described above but require 
interconnection customers to demonstrate site control to enter the 
facilities study.\1022\
---------------------------------------------------------------------------

    \1022\ Id. PP 121-123.
---------------------------------------------------------------------------

ii. Comments
(a) General Comments
    513. Several parties generally support the proposal to increase 
site control requirements.\1023\ These commenters generally agree that 
the proposal is reasonable and that these measures can reduce 
speculative interconnection requests, represent a reasonable financial 
burden, help ensure that the interconnection customer is ready to enter 
the interconnection queue,\1024\ help load serving entities have 
generating facilities interconnected as quickly and efficiently as 
possible,\1025\ and reduce harm to other interconnection customers that 
have successfully secured site control for their proposed generating 
facility.\1026\
---------------------------------------------------------------------------

    \1023\ AEP Initial Comments at 21; AES Initial Comments at 15; 
Ameren Initial Comments at 15-16; APPA-LPPC Initial Comments at 17-
18; Avangrid Initial Comments at 9, 18-19; Bonneville Initial 
Comments at 11; CAISO Initial Comments at 16; Consumers Energy 
Initial Comments at 5; Dominion Reply Comments at 15; ELCON Initial 
Comments at 10; Enel Initial Comments at 40-42; Eversource Initial 
Comments at 16; Fervo Energy Reply Comments at 6; GSCE Initial 
Comments at 1; Hydropower Commenters Initial Comments at 12; 
Interwest Energy Alliance Reply Comments at 13; Invenergy Initial 
Comments at 9; Longroad Energy Initial Comments at 12; MISO Initial 
Comments at 53; NARUC Initial Comments at 10; NRECA Initial Comments 
at 27; NV Energy Initial Comments at 15; NYTOs Initial Comments at 
18-19; [Oslash]rsted Initial Comments at 10; Pacific Northwest 
Utilities Initial Comments at 4; PG&E Initial Comments at 4; Pattern 
Energy Initial Comments at 29-30; Pine Gate Initial Comments at 23; 
PJM Initial Comments at 21-22; SEIA Initial Comments at 14; SoCal 
Edison Initial Comments at 6; Tri-State Initial Comments at 13-15; 
U.S. Chamber of Commerce Initial Comments at 8; UMPA Initial 
Comments at 5; Xcel Initial Comments at 32.
    \1024\ Enel Initial Comments at 40.
    \1025\ Ameren Initial Comments at 15-16.
    \1026\ PJM Initial Comments at 29.
---------------------------------------------------------------------------

    514. CREA and NewSun, on the other hand, argue that the 
Commission's proposed site control requirements are anti-competitive 
because they allow utilities to erect market barriers to competitors' 
generating facilities and because the requirements bar investment by 
companies seeking to develop generating facilities using a merchant 
generation model.\1027\
---------------------------------------------------------------------------

    \1027\ CREA and NewSun Reply Comments at 46.
---------------------------------------------------------------------------

(b) Comments on Specific Proposal
(1) Definition and Reasonable Evidence of Site Control
    515. Some commenters support the proposed definition of site 
control.\1028\ MISO notes that the proposed requirement for exclusivity 
or the demonstration of a right to co-locate generating facilities is 
in MISO's current tariff and that these requirements have proven to be 
successful at preventing speculative interconnection requests from 
entering or continuing in the interconnection queue.\1029\
---------------------------------------------------------------------------

    \1028\ MISO Initial Comments at 53; National Grid Initial 
Comments at 22.
    \1029\ MISO Initial Comments at 53.
---------------------------------------------------------------------------

    516. Some commenters suggest modifications to the definition of 
site control. ENGIE and Tri-State recommend that the Commission 
consider requirements similar to MISO's requirements to identify when 
and whether an interconnection request is non-speculative.\1030\ Xcel 
supports modifying the definition of site control to ensure exclusivity 
and allow for co-ownership.\1031\
---------------------------------------------------------------------------

    \1030\ ENGIE Initial Comments at 5; Tri-State Initial Comments 
at 14.
    \1031\ Xcel Initial Comments at 31.
---------------------------------------------------------------------------

    517. PJM requests that the Commission clarify that interconnection 
customers are prohibited from submitting evidence of site control that 
uses the same land for multiple interconnection requests, unless the 
site is large enough to host multiple generating facilities.\1032\
---------------------------------------------------------------------------

    \1032\ PJM Initial Comments at 31.
---------------------------------------------------------------------------

    518. Enel supports the proposal to require land rights that are 
exclusive to one development company, but not necessarily to the 
individual generating facility.\1033\ According to Enel, when used 
regarding land rights, ``exclusive'' means that only the owner of those 
land rights can possess the property, and this interpretation could 
prevent co-located resources from being built if one parent company was 
using two separate special purpose vehicles for two different 
generating facilities sharing land. Enel therefore recommends that the 
Commission clarify the intent of this word so that it does not 
artificially restrict multi-use applications.
---------------------------------------------------------------------------

    \1033\ Enel Initial Comments at 42 (referencing NOPR, 179 FERC ] 
61,194 at P 117).
---------------------------------------------------------------------------

    519. Cypress Creek believes that, to the extent the Commission 
intends that a ``land right'' should involve zoning approval, such a 
proposal would be unreasonable because interconnection customers do not 
typically initiate local permitting until the system impact study 
phase, due to the system impact study's impact to overall generating 
facility commercial viability.\1034\
---------------------------------------------------------------------------

    \1034\ Cypress Creek Initial Comments at 22.
---------------------------------------------------------------------------

    520. Southern requests that the Commission clarify subpart (3) of 
the proposed site control definition, arguing that, as written, it 
appears to be an incomplete statement that may authorize an 
interconnection customer to simply provide evidence that a site is big 
enough to host a proposed generating facility rather than evidence that 
the interconnection customer actually has any rights to that 
property.\1035\ Enel argues that subpart (3) to the definition should 
be deleted, because as modified, that item is duplicative of and a 
subset of the materials covered under subpart (1).\1036\
---------------------------------------------------------------------------

    \1035\ Southern Initial Comments at 34-35.
    \1036\ Enel Initial Comments at 82.
---------------------------------------------------------------------------

    521. Other parties request that the Commission clarify the 
definition of site control to specify what constitutes reasonable 
evidence to demonstrate 100% site control \1037\ or provide suggestions 
for what should be considered reasonable evidence of site 
control.\1038\ NYISO requests that the final rule establish uniform 
requirements across regions for making the 100% site control 
determination.\1039\ APS requests that the Commission specify what is 
considered reasonable evidence in the same manner that the

[[Page 61091]]

Commission defines commercial readiness milestones and argues that 
clarification is needed in order to avoid subjectivity regarding what 
is considered ``reasonable'' evidence to the transmission 
provider.\1040\
---------------------------------------------------------------------------

    \1037\ APS Initial Comments at 7; NYISO Initial Comments at 21-
22; Omaha Public Power Initial Comments at 7.
    \1038\ EPSA Initial Comments at 8; National Grid Initial 
Comments at 22; NRECA Initial Comments at 27; Omaha Public Power 
Initial Comments at 7; SoCal Edison Initial Comments at 6.
    \1039\ NYISO Initial Comments at 21-22.
    \1040\ APS Initial Comments at 7.
---------------------------------------------------------------------------

    522. Omaha Public Power requests that the Commission clarify 
whether transmission providers will be able to accept lease options, 
instead of executed leases, as sufficient evidence of site 
control.\1041\ Omaha Public Power notes that it has become industry 
standard to use lease options and argues that the Commission should not 
enact a rule that conflicts with current industry standard practices. 
SoCal Edison supports the NOPR proposal, provided that 100% site 
control includes an option to lease up to, and including, the 
commercial operation date or acquire the land when the interconnection 
request is submitted.\1042\
---------------------------------------------------------------------------

    \1041\ Omaha Public Power Initial Comments at 7-8.
    \1042\ SoCal Edison Initial Comments at 6.
---------------------------------------------------------------------------

    523. EPSA advises the Commission to consider options to demonstrate 
site control, including requiring attestations that a lessee or 
potential owner is in exclusive negotiations to establish site control, 
though it generally supports the development of clearer 
demonstrations.\1043\ Interwest Energy Alliance recommends that the 
Commission consider evidence of active negotiations as potentially a 
sufficient demonstration of site control before the closing of the 
cluster request window.\1044\
---------------------------------------------------------------------------

    \1043\ EPSA Initial Comments at 8.
    \1044\ Interwest Energy Alliance Reply Comments at 13.
---------------------------------------------------------------------------

    524. SoCal Edison recommends that the Commission consider requiring 
that site control agreements be between the site owner and the same 
legal entity that is submitting the interconnection request.\1045\ 
SoCal Edison explains that it has run into challenges when trying to 
determine whether interconnection customers have exclusive site 
control, in part due to the fact that companies change over time with 
renaming and/or mergers.
---------------------------------------------------------------------------

    \1045\ SoCal Edison Initial Comments at 6.
---------------------------------------------------------------------------

    525. NRECA suggests that demonstration of site control with 
exclusive land rights should be allowed to include provisions that such 
rights are contingent upon favorable interconnection study results, 
inclusive of cost and schedule.\1046\ NRECA notes that site control 
land options on many occasions come with a caveat that the lessee or 
purchaser has the ability to terminate within a due diligence period if 
interconnection results are unfavorable due to cost or schedule.\1047\
---------------------------------------------------------------------------

    \1046\ NRECA Initial Comments at 27.
    \1047\ Id. at 27 n.70.
---------------------------------------------------------------------------

    526. NV Energy requests clarification on whether an interconnection 
request should be deemed withdrawn if the interconnection customer does 
not provide demonstration of site control by the execution of the 
facilities study agreement.\1048\
---------------------------------------------------------------------------

    \1048\ NV Energy Initial Comments at 15.
---------------------------------------------------------------------------

    527. [Oslash]rsted urges the Commission to clarify that, for 
offshore wind projects, the definition of ``exclusive site control of 
the entire generating facility'' means exclusive control of the Bureau 
of Ocean Energy Management (BOEM) issued offshore wind lease area, not 
cable routes on state submerged land or onshore cable routes to the 
point of interconnection.\1049\ [Oslash]rsted reasons that, due to the 
extensive state and Federal permitting process, offshore wind 
developers may not have authorization in the form of permits or other 
land use rights for portions of the offshore wind project on state 
submerged land or for the offshore and onshore cable routes during the 
interconnection process.
---------------------------------------------------------------------------

    \1049\ [Oslash]rsted Initial Comments at 14.
---------------------------------------------------------------------------

    528. NYTOs and Pacific Northwest Utilities argue that it is unclear 
what would constitute 100% site control and therefore regions should be 
allowed to implement appropriate definitions for their regions on 
compliance to address their specific circumstances.\1050\
---------------------------------------------------------------------------

    \1050\ NYTOs Initial Comments at 19; Pacific Northwest Utilities 
Initial Comments at 4.
---------------------------------------------------------------------------

    529. ISO-NE states that its existing LGIP and SGIP provisions, 
which are consistent with those proposed in the NOPR, have proven to be 
effective, and that the Commission should extend flexibility so that 
they may be maintained.\1051\ Similarly, Indicated PJM TOs argue that 
the final rule should permit PJM to implement its 2022 interconnection 
queue reform proposal for demonstrating site control, which is more 
rigorous than the NOPR proposal.\1052\
---------------------------------------------------------------------------

    \1051\ ISO-NE Initial Comments at 29.
    \1052\ Indicated PJM TOs Initial Comments at 25 (citing PJM 
Interconnection, L.L.C., Tariff Revisions for Interconnection 
Process Reform, Docket No. ER22-2110-000 (filed June 14, 2022)). The 
Commission conditionally accepted PJM's filing on November 29, 2022 
and accepted PJM's associated compliance filing on February 2, 2023. 
See PJM Interconnection, L.L.C., 181 FERC ] 61,162 (2022), order on 
reh'g, 184 FERC ] 61,006 (2023); PJM Interconnection, L.L.C., Docket 
No. ER22-2110-003 (Feb. 2, 2023) (delegated letter order).
---------------------------------------------------------------------------

    530. Several parties support the NOPR proposal to define 100% site 
control as an acreage requirement specific to the generating facility 
type and to require these acreage requirements in the tariff.\1053\ 
Enel states that inclusion of acreage requirements in the tariff gives 
the Commission visibility into regional requirements to ensure that no 
transmission provider is significantly out of line with national 
assumptions.\1054\
---------------------------------------------------------------------------

    \1053\ AES Initial Comments at 15; Enel Initial Comments at 42; 
NYISO Initial Comments at 21; Tri-State Initial Comments at 13.
    \1054\ Enel Initial Comments at 42.
---------------------------------------------------------------------------

    531. Several commenters request that the Commission create a 
process by which an interconnection customer can demonstrate that its 
generating facility requires a different amount of acreage than the 
default value listed in the tariff.\1055\ AES predicts that this 
approach will help ensure viable generating facilities are not 
inadvertently removed from the interconnection queue.\1056\ MISO states 
that its tariff also allows an interconnection customer to demonstrate 
that it can operate the proposed generating facility with fewer 
acres.\1057\ National Grid believes that regional flexibility would 
certainly be required for each transmission provider's proposed acreage 
requirements and requests clarification accordingly.\1058\ Some 
commenters suggest that transmission providers be required to update 
the acreage requirements periodically to reflect technological 
advancements.\1059\
---------------------------------------------------------------------------

    \1055\ AES Initial Comments at 16; Clean Energy Associations 
Initial Comments at 32-33; Public Interest Organizations Initial 
Comments at 27.
    \1056\ AES Initial Comments at 16.
    \1057\ MISO Initial Comments at 54.
    \1058\ National Grid Initial Comments at 23.
    \1059\ Clean Energy Associations Initial Comments at 32-33; 
Longroad Energy Initial Comments at 12; Pattern Energy Initial 
Comments at 29-30.
---------------------------------------------------------------------------

    532. Other parties oppose the NOPR proposal to require specific 
acreage requirements in the tariff \1060\ or suggest that these 
requirements should be included in business practice manuals rather 
than tariffs.\1061\ Some commenters argue that these acreage 
requirements will likely change with technology advances, and it would 
be burdensome if transmission providers are required to submit an FPA 
section 205 filing every time they need to change acreage 
requirements.\1062\ Fervo Energy argues that the risk in this proposal 
is that the acreage requirements may understate the energy

[[Page 61092]]

density of a generating facility and thus overstate the number of acres 
required for a given number of MW, resulting in discriminatory 
treatment between competing generation technologies.\1063\
---------------------------------------------------------------------------

    \1060\ EPSA Initial Comments at 8; Fervo Energy Initial Comments 
at 4; [Oslash]rsted Initial Comments at 11; Pine Gate Initial 
Comments at 24-25; PJM Initial Comments at 30.
    \1061\ MISO Initial Comments at 53-54; Pine Gate Initial 
Comments at 24-25; PJM Initial Comments at 30; Tri-State Initial 
Comments at 13.
    \1062\ [Oslash]rsted Initial Comments at 11; PJM Initial 
Comments at 30; Pine Gate Initial Comments at 24-25.
    \1063\ Fervo Energy Initial Comments at 4.
---------------------------------------------------------------------------

    533. [Oslash]rsted recommends that transmission providers use the 
most recent estimates of power density from BOEM when establishing 
acreage requirements for offshore wind projects.\1064\ [Oslash]rsted 
notes that offshore wind turbines have grown much larger in recent 
years, which allows significantly more power production from the same 
amount of acreage, and they argue that if transmission providers' 
tariffs were not updated frequently enough, the acreage requirements 
may become unreasonable.
---------------------------------------------------------------------------

    \1064\ [Oslash]rsted Initial Comments at 11.
---------------------------------------------------------------------------

    534. Pine Gate recommends that acreage requirements specifically 
address how the requirements will be applied to hybrid and co-located 
generating facilities.\1065\
---------------------------------------------------------------------------

    \1065\ Pine Gate Initial Comments at 24-25.
---------------------------------------------------------------------------

    535. Some commenters request that the Commission clarify whether 
the site control requirement is limited to the generating facility or 
whether it also applies to transmission system elements like 
interconnection facilities or other upgrades that may be identified 
through the interconnection study process.\1066\ Several parties argue 
that, for the initial request and study phase, 100% site control should 
not apply to land required to finalize routes for generator ties 
lines.\1067\ AES argues that interconnection customers require 
flexibility when siting generator tie lines, which usually occurs near 
the very end of the interconnection process.\1068\ Enel notes that 
there are sometimes crossings of railroads, streams, or other 
circumstances that require considerable time to complete and are 
outside the interconnection customer's control.\1069\ AEE explains that 
issues can occur when interconnection customers have all but one small 
parcel on the route of their generating facility secured, with only one 
small piece of connectivity missing due to permitting delays or other 
issues.\1070\ Similarly, Invenergy argues that it is unreasonable and 
impractical to predict and obtain rights to land for facilities that 
have not yet been identified.\1071\ Invenergy also states that the 
point of interconnection can change during the study process, thus 
changing the land needs for the interconnection customer's 
interconnection facilities, and this change may be driven by a number 
of different factors, including the transmission provider's preference, 
which may be outside the interconnection customer's control.
---------------------------------------------------------------------------

    \1066\ Interwest Energy Alliance Reply Comments at 13; NYISO 
Initial Comments at 22.
    \1067\ ACE-NY Initial Comments at 5; AES Initial Comments at 15; 
Avangrid Initial Comments at 18; Clean Energy Associations Initial 
Comments at 32; Enel Initial Comments at 41; ENGIE Initial Comments 
at 5; Equinor Reply Comments at 3; rPlus Initial Comments at 2-3; 
Shell Reply Comments at 23.
    \1068\ AES Initial Comments at 15.
    \1069\ Enel Initial Comments at 41.
    \1070\ AEE Initial Comments at 17.
    \1071\ Invenergy Initial Comments at 10.
---------------------------------------------------------------------------

    536. [Oslash]rsted, ACE-NY, and Equinor Wind note a myriad of 
challenges for obtaining site control for interconnection facilities 
for offshore wind projects, such as conflicts between Federal and state 
permitting entity requirements for project flexibility and 
adaptability.\1072\ [Oslash]rsted argues that site control for 
interconnection facilities for offshore wind developers is only 
obtainable very late in the interconnection process.\1073\
---------------------------------------------------------------------------

    \1072\ ACE-NY Initial Comments at 5; Equinor Reply Comments at 
4; [Oslash]rsted Initial Comments at 13; [Oslash]rsted Reply 
Comments at 2, 4, 5; Shell Reply Comments at 29.
    \1073\ [Oslash]rsted Initial Comments at 12.
---------------------------------------------------------------------------

    537. Other commenters argue that the Commission should expand the 
proposed definition of site control to apply some degree of site 
control requirements to interconnection facilities, such as a 
requirement to demonstrate 50% site control for interconnection 
facilities when submitting the interconnection request.\1074\ MISO 
encourages the Commission to require site control for interconnection 
facilities at the same time that it requires site control for the 
generating facilities.\1075\ AEP explains that some interconnection 
customers submit interconnection requests that are not feasible given 
where interconnection customer interconnection facilities would have to 
be sited to connect the generating facility to the transmission system 
at the selected point of interconnection.\1076\ Additionally, AEP 
explains that, even if a generation site is suitable, there may not be 
``room'' at certain locations for a substation or switchyard due to a 
variety of issues, including abandoned mines, surrounding wetlands, or 
other geographic impediments.\1077\ According to AEP, site control for 
generating facilities can be far less important than feasible control 
over the land needed to connect the generating facility to the 
transmission system.
---------------------------------------------------------------------------

    \1074\ AEE Initial Comments at 18; AEP Initial Comments at 21-
23; Cypress Creek Initial Comments at 22; Enel Initial Comments at 
41; MISO Initial Comments at 56; National Grid Initial Comments at 
22-23; Shell Reply Comments at 23.
    \1075\ MISO Initial Comments at 56.
    \1076\ AEP Initial Comments at 22.
    \1077\ Id. at 23.
---------------------------------------------------------------------------

    538. Enel argues that the addition of a generator tie line site 
control requirement will increase the quality of interconnection study 
results and increase certainty for interconnection customers as the 
interconnection process becomes more costly and risky to 
navigate.\1078\ Enel states that it has observed or heard of 
interconnection customers submitting existing site control from very 
remote locations to secure interconnection queue positions, and later 
submitting a modification request to move the generating facility site 
close to the point of interconnection after the generating facility's 
actual intended site control has been obtained. Enel states that this 
is done by interconnection customers to reduce the duration and 
subsequently the cost of maintaining site control, as a failed distant 
asset can be used for a new interconnection queue position elsewhere 
until site control for the new generating facility area is complete. In 
addition, Enel states that it supports SPP's approach, which also 
requires 75% of generator tie line site control after the first cluster 
restudy, to ensure interconnection customers are making reasonable 
progress.
---------------------------------------------------------------------------

    \1078\ Enel Initial Comments at 41-42.
---------------------------------------------------------------------------

    539. National Grid argues that demonstrating site control for 
interconnection facilities is crucial for generating facility 
development and interconnection queue management particularly in cases 
where numerous interconnection requests in the interconnection queue 
are reliant on the construction of certain network upgrades.\1079\ 
National Grid argues that the payment of cash or the provision of other 
security in lieu of demonstration of site control of transmission owner 
interconnection facilities or network upgrades built by an 
interconnection customer does not further the goals of the NOPR.
---------------------------------------------------------------------------

    \1079\ National Grid Initial Comments at 23.
---------------------------------------------------------------------------

(2) Site Control Demonstration
    540. Several commenters support the NOPR proposal to require 
interconnection customers to demonstrate 100% site control for their 
proposed generating facilities when they submit their interconnection 
request.\1080\ MISO argues that obtaining site control is consistent 
with the ``first-ready, first-served'' model and that delaying site 
control for interconnection

[[Page 61093]]

requests until later in the interconnection process just increases the 
instances of late-stage withdrawals that leads to uncertainty, 
unplanned restudies, and delays for the remaining interconnection 
requests.\1081\ National Grid asserts that the demonstration of 
complete and exclusive site control is necessary at the interconnection 
request stage to avoid submission of interconnection requests 
prematurely, potential conflicts with other interconnection requests, 
and delays in issuing cluster studies.\1082\ GSCE contends that there 
should be few exceptions to a site exclusivity requirement to enter the 
cluster study process so leniency is not granted to the type of 
interconnection requests that linger in the interconnection queue while 
they struggle to secure difficult land rights and permitting.\1083\
---------------------------------------------------------------------------

    \1080\ ACE-NY Initial Comments at 5; APS Initial Comments at 14; 
MISO Initial Comments at 56; National Grid Initial Comments at 22; 
[Oslash]rsted Initial Comments at 12.
    \1081\ MISO Initial Comments at 56-57.
    \1082\ National Grid Initial Comments at 22.
    \1083\ GSCE Initial Comments at 7.
---------------------------------------------------------------------------

    541. PJM opposes any requirement on transmission providers to 
accept demonstrations of less than 100% site control at the time of an 
interconnection request, except for accommodations for interconnection 
requests for proposed generating facilities to be sited offshore or on 
government owned land.\1084\
---------------------------------------------------------------------------

    \1084\ PJM Initial Comments at 32.
---------------------------------------------------------------------------

    542. MISO notes that its tariff requires redemonstrations of site 
control.\1085\ Similarly, Indicated PJM TOs support requiring 100% site 
control at more than one decision point,\1086\ and assert that 
transmission providers should be allowed to confirm site control 
throughout the interconnection process.\1087\ Indicated PJM TOs and 
Longroad Energy argue that the Commission should strengthen the 
proposed site control requirements to ensure that interconnection 
customers are maintaining site control throughout the interconnection 
process.\1088\
---------------------------------------------------------------------------

    \1085\ MISO Initial Comments at 53.
    \1086\ Indicated PJM TOs Initial Comments at 26 (citing PJM 
Interconnection, L.L.C., Motion for Leave to Answer and Answer of 
PJM Interconnection, L.L.C., Docket No. ER22-2110-000, at 20 (filed 
Aug. 2, 2022)).
    \1087\ Id. at 8, 26.
    \1088\ Indicated PJM TOs Reply Comments at 30; Longroad Energy 
Reply Comments at 18.
---------------------------------------------------------------------------

    543. On the other hand, APS believes that simultaneous submission 
of the interconnection customer-executed LGIA and the continued 
demonstration of site control is duplicative and unnecessary if an 
interconnection customer demonstrates site control at the time an 
interconnection request is made.\1089\
---------------------------------------------------------------------------

    \1089\ APS Initial Comments at 7.
---------------------------------------------------------------------------

    544. Several commenters oppose the NOPR proposal to require an 
interconnection customer to demonstrate 100% site control at the time 
of the interconnection request and/or propose alternative site control 
requirements.\1090\ A number of commenters express concern that the 
NOPR proposal is not compatible with the generating facility 
development cycle.\1091\ EPSA argues that a 100% exclusive site control 
requirement in advance of the processing of the facilities study is not 
reasonable because it overlooks the complicated and extensive process 
of negotiating for land leases or purchases.\1092\ Similarly, Cypress 
Creek and AEE argue that the NOPR proposal does not reflect realities 
of development, which include stringent permitting requirements, and 
may disadvantage certain interconnection customers despite being on a 
path to full site control and commercial readiness.\1093\ CESA and 
Clean Energy Associations argue that the requirement for 100% site 
control at the interconnection request stage is excessively stringent 
and would significantly favor utility-owned projects.\1094\
---------------------------------------------------------------------------

    \1090\ AEE Initial Comments at 17-18; Clean Energy Associations 
Initial Comments at 31-32; CREA and NewSun Initial Comments at 54; 
Cypress Creek Initial Comments at 22; EPSA Initial Comments at 8; 
NextEra Initial Comments at 21; Pine Gate Initial Comments at 24; R 
Street Initial Comments at 8; SEIA Initial Comments at 15; Shell 
Reply Comments at 23-24.
    \1091\ AEE Initial Comments at 17; Clean Energy Associations 
Initial Comments at 31; CREA and NewSun Initial Comments at 54; 
Cypress Creek Initial Comments at 22; EPSA Initial Comments at 8; 
NextEra Initial Comments at 21; R Street Initial Comments at 8.
    \1092\ EPSA Initial Comments at 8.
    \1093\ AEE Initial Comments at 17.
    \1094\ CESA Reply Comments at 5.
---------------------------------------------------------------------------

    545. CREA and NewSun argue that the NOPR proposal is not adequately 
supported and urge the Commission to maintain the existing site control 
requirements.\1095\ CREA and NewSun argue that the proposal is 
unreasonable and ``creates a Catch-22'': specifically, that without 
reliable visibility as to the interconnection costs and viability for 
its proposed generating facility within the specific cluster, the 
interconnection customer will not be able to attract investment needed 
to secure site control. CREA and NewSun also argue that a landowner 
hoping to see property developed may not agree to permanently tie up 
land in a lease before the interconnection customer can show 
interconnection is viable. CREA and NewSun argue that interconnection 
requests may prove uneconomic after receipt of initial interconnection 
studies and thereafter cannot finalize site control due to uneconomic 
interconnection costs. CREA and NewSun also assert that the Commission 
made no effort in the NOPR to ascertain the impact on the market of the 
``draconian'' site control rules for such transmission providers that 
have been allowed to adopt them.
---------------------------------------------------------------------------

    \1095\ CREA and NewSun Initial Comments at 54-55.
---------------------------------------------------------------------------

    546. R Street argues that requiring even partial site control at 
the time of the interconnection request may create delays and increase 
project development costs because it would require more options 
contracts to be in place with landowners.\1096\ NextEra argues that 
site control is a limited indicator of generating facility 
viability.\1097\ rPlus argues that requiring 100% site control at the 
interconnection request stage will inhibit the flexibility for 
interconnection request design changes that is needed to develop pumped 
storage projects.\1098\
---------------------------------------------------------------------------

    \1096\ R Street Initial Comments at 13.
    \1097\ NextEra Initial Comments at 21-22.
    \1098\ rPlus Initial Comments at 2.
---------------------------------------------------------------------------

    547. Several commenters recommend that the Commission modify the 
site control requirements in the final rule to require less than 100% 
site control at the time of the interconnection request. For example, 
Clean Energy Associations, SEIA, and Cypress Creek argue that no more 
than 75% site control is appropriate at the time of the interconnection 
request.\1099\ Shell argues that the Commission should only require 
partial site control when the interconnection request is made.\1100\ 
Clean Energy Associations supports an escalating schedule of site 
control through the interconnection process and suggests that the 
Commission should modify the NOPR proposal to also require 90% site 
control at the post-cluster study decision point and 100% site control 
at the post-facilities study decision point.\1101\
---------------------------------------------------------------------------

    \1099\ Clean Energy Associations Initial Comments at 31-32; 
Cypress Creek Initial Comments at 22; SEIA Initial Comments at 15.
    \1100\ Shell Reply Comments at 23-24.
    \1101\ Clean Energy Associations Initial Comments at 31-32.
---------------------------------------------------------------------------

    548. AEE argues that 90% site control at the time of the 
interconnection request provides interconnection customers sufficient 
flexibility.\1102\ Additionally, several commenters state that 100% 
site control at the post-facilities study decision point would be 
appropriate.\1103\ AEE argues that these altered requirements will 
reduce speculative interconnection requests while also providing 
incentive for

[[Page 61094]]

interconnection customers to pursue remaining land rights after 
entering the interconnection queue.\1104\
---------------------------------------------------------------------------

    \1102\ AEE Initial Comments at 18.
    \1103\ Id.; CESA Reply Comments at 5-6; Clean Energy 
Associations Initial Comments at 31-32; Cypress Creek Initial 
Comments at 22; Xcel Initial Comments at 32.
    \1104\ AEE Initial Comments at 18.
---------------------------------------------------------------------------

    549. Some commenters note that less than 100% site control at the 
interconnection request stage would allow interconnection customers 
flexibility to address the results of interconnection studies or other 
regulatory processes, which may lead to changes in the size or design 
of a generating facility.\1105\ Additionally, SEIA requests that the 
Commission require transmission providers to allow interconnection 
customers to change site boundaries or reduce the size of a proposed 
generating facility, as long as the point of interconnection remains 
the same, in order to accommodate changes resulting from 
interconnection studies or regulatory changes.\1106\ Pine Gate notes 
that sometimes interconnection customers are still actively negotiating 
with landowners close to the deadline for a cluster review window and 
requests the Commission to permit interconnection customers to 
demonstrate to the transmission prover that they are in active 
negotiations to meet the heightened site control requirements.\1107\
---------------------------------------------------------------------------

    \1105\ CREA and NewSun Initial Comments at 55; SEIA Initial 
Comments at 14-15.
    \1106\ SEIA Initial Comments at 15.
    \1107\ Pine Gate Initial Comments at 23-24. Pine Gate notes that 
this approach is similar to PJM's where, if PJM accepts the 
interconnection customer's demonstration, then PJM will add a 
condition precedent to the interconnection agreement requiring that 
all site control requirements be met within 180 days of execution.
---------------------------------------------------------------------------

    550. Some commenters highlight that the NOPR proposal may be 
problematic or challenging for interconnection customers of certain 
technology types or other circumstances where obtaining site control is 
difficult. Hydropower Commenters argue that most new hydropower 
facilities are sited at existing non-powered dams and therefore 
hydropower interconnection customers face unique challenges when it 
comes to obtaining site control.\1108\ The Ohio Commission Consumer 
Advocate asserts that the proposal may be problematic for 
interconnection customers in Ohio because a recent Ohio law permits 
Ohio counties to designate unincorporated areas in a county as an area 
in which the development of a renewable energy project is 
prohibited.\1109\
---------------------------------------------------------------------------

    \1108\ Hydropower Commenters Initial Comments at 13.
    \1109\ Ohio Commission Consumer Advocate Initial Comments at 11.
---------------------------------------------------------------------------

    551. According to Enel, some states limit the duration of site 
control.\1110\ Enel asserts that, if site control is near to expiring 
for any reason, whether due to state restriction or simply because the 
interconnection customer did not anticipate the length of 
interconnection or permitting processes, landowners can demand higher 
payments than agreed to in the original site control contract. Enel 
states that this can change the economics of a proposed generating 
facility and even make a proposed generating facility unprofitable, 
potentially leading to a late-stage interconnection request withdrawal.
---------------------------------------------------------------------------

    \1110\ Enel Initial Comments at 40.
---------------------------------------------------------------------------

    552. Several commenters argue that the Commission should reject 
proposals to weaken the site control requirements proposed in the 
NOPR.\1111\ APPA-LPPC argue that EPSA's and SEIA's generalized 
complaints do not identify a specific obstacle created by the 
Commission's proposal, and APPA-LPPC argue that SEIA's proposal to 
scale back the site control requirement to not more than 75% was 
considered and rejected by MISO's management and stakeholders over 
concerns that it may not be rigorous enough to mitigate the entry of 
speculative interconnection requests in the queue.\1112\
---------------------------------------------------------------------------

    \1111\ APPA-LPPC Reply Comments at 2-3; CREA and NewSun Initial 
Comments at 55; Indicated PJM TOs Reply Comments at 30; Ohio 
Commission Consumer Advocate Initial Comments at 11-12.
    \1112\ APPA-LPPC Reply Comments at 4 (citing Midcontinent Indep. 
Sys. Operator, Inc., 169 FERC ] 61,173, at P 9 (2019)).
---------------------------------------------------------------------------

(3) Deposits in Lieu of Site Control
    553. Several commenters support the NOPR proposal to eliminate the 
option for interconnection customers to submit a deposit in lieu of 
site control except in limited circumstances for regulatory 
limitations.\1113\ These commenters express that allowing deposits in 
lieu of site control is not sufficient to demonstrate readiness or 
deter speculative interconnection requests.\1114\ PJM notes that, in 
its experience, the option to provide money in lieu of actual site 
control is easily abused by interconnection customers with speculative 
interconnection requests.\1115\ CAISO notes that its most recent 
cluster study was inundated by interconnection requests without site 
control because even a $250,000 deposit in lieu of site control has not 
proven to be a deterrent for interconnection customers.\1116\
---------------------------------------------------------------------------

    \1113\ AES Initial Comments at 15; APPA-LPPC Reply Comments at 
4; CAISO Initial Comments at 16-17; CREA and NewSun Reply Comments 
at 50; Cypress Creek Initial Comments at 22; Dominion Initial 
Comments at 31; ENGIE Initial Comments at 4; EEI Initial Comments at 
7-8; Eversource Initial Comments at 17; MISO Initial Comments at 57; 
NY Commission and NYSERDA Initial Comments at 8-9; NYTOs Initial 
Comments at 18-19; Ohio Commission Consumer Advocate Initial 
Comments at 12; SEIA Initial Comments at 15; Shell Initial Comments 
at 23; Tri-State Initial Comments at 13.
    \1114\ APPA-LPPC Initial Comments at 19; Bonneville Initial 
Comments at 11; Idaho Power Initial Comments at 7; PJM Initial 
Comments at 26; PPL Initial Comments at 16; Southern Initial 
Comments at 8-9; Xcel Initial Comments at 30, 32.
    \1115\ PJM Initial Comments at 26.
    \1116\ CAISO Initial Comments at 17.
---------------------------------------------------------------------------

    554. Some commenters oppose the NOPR proposal and argue that the 
option to make deposits in lieu of site control should be available for 
all interconnection customers, not just those that demonstrate 
regulatory limitations.\1117\ Avangrid believes that an at-risk deposit 
in lieu of site control that is set at a reasonable magnitude may be a 
good alternative to ensure that an interconnection customer is 
rigorously pursuing completion of a proposed generating facility.\1118\ 
Pacific Northwest Utilities suggest that the Commission should allow 
transmission providers the flexibility to determine whether deposits in 
lieu of site control are applicable.\1119\
---------------------------------------------------------------------------

    \1117\ Avangrid Initial Comments at 19; Clean Energy 
Associations Initial Comments at 32; CREA and NewSun Initial 
Comments at 55; Interwest Energy Alliance Reply Comments at 13.
    \1118\ Avangrid Initial Comments at 19.
    \1119\ Pacific Northwest Utilities Initial Comments at 3.
---------------------------------------------------------------------------

(4) Site Control Considerations for Interconnection Customers With 
Regulatory Limitations
    555. Some commenters contend that the Commission should modify the 
proposed definition of site control to reasonably accommodate 
interconnection customers developing generating facilities on sites 
owned or controlled by a government entity.\1120\ Several commenters 
highlight unique circumstances and challenges for obtaining site 
control on certain public lands and other regulatory issues that may 
affect an interconnection customer's ability to demonstrate site 
control under the NOPR definition.\1121\
---------------------------------------------------------------------------

    \1120\ PPL Initial Comments at 16; Tri-State Initial Comments at 
14; Xcel Initial Comments at 31.
    \1121\ Clean Energy Associations Initial Comments at 33-34; CREA 
and NewSun Reply Comments at 47-49; Dominion Initial Comments at 31; 
ENGIE Initial Comments at 4; Hydropower Commenters Initial Comments 
at 14-18, 24-25; Idaho Power Initial Comments at 6-7; NV Energy 
Initial Comments at 15-16; [Oslash]rsted Initial Comments at 12; 
OSPA Initial Comments at 16-18; rPlus Initial Comments at 2-3.
---------------------------------------------------------------------------

    556. Several commenters argue that the Commission should provide 
flexibility to allow transmission providers to establish site control 
requirements for generating facilities sited on Federal and public 
land.\1122\

[[Page 61095]]

Shell notes that securing site control can often be complicated by 
fast-changing local, county, and state regulations, and encourages the 
Commission to provide sufficient flexibility to enable transmission 
providers to make accommodations for local site control 
challenges.\1123\
---------------------------------------------------------------------------

    \1122\ Dominion Initial Comments at 32; Indicated PJM TOs 
Initial Comments at 26; Pacific Northwest Utilities Initial Comments 
at 3; PJM Initial Comments at 31; Shell Initial Comments at 23.
    \1123\ Shell Initial Comments at 23.
---------------------------------------------------------------------------

    557. Some commenters provide recommendations on how the Commission 
could clarify what may constitute a sufficient demonstration of site 
control for generating facilities being developed on land owned or 
controlled by a government entity.\1124\ Pattern Energy argues that 
interconnection customers proposing to develop generating facilities on 
land owned or managed by state, Federal, or Tribal government entities 
should be required to provide evidence that they submitted any required 
applications to the relevant government entity or entities in order to 
advance the development of their proposed generating facility. Pattern 
Energy states that such an interconnection request should provide for 
an exclusive right to advance the development of a generating facility, 
provided that the relevant government entity or entities allow for such 
an exclusive right.\1125\
---------------------------------------------------------------------------

    \1124\ Id. at 22-23; CREA and NewSun Reply Comments at 50; 
Equinor Reply Comments at 4; Hydropower Commenters Initial Comments 
at 15-18; Idaho Power Initial Comments at 7; Indicated PJM TOs Reply 
Comments at 31; [Oslash]rsted Initial Comments at 12-13; 
[Oslash]rsted Reply Comments at 2, 4-5; OSPA Initial Comments at 18; 
Pattern Energy Initial Comments at 30; rPlus Initial Comments at 3-
4.
    \1125\ Pattern Energy Initial Comments at 30.
---------------------------------------------------------------------------

    558. PJM notes that the proposed site control requirements that PJM 
included in its interconnection queue reform filing with the Commission 
provide some leeway for generating facilities constructed on Federal or 
state lands or water, such as offshore wind projects.\1126\ 
Alternatively, Dominion requests that the Commission clarify that the 
deposit in lieu of site control exception would apply to offshore wind 
projects, in addition to other proposed generating facilities subject 
to similar government control that may prevent timely demonstration of 
site control.\1127\
---------------------------------------------------------------------------

    \1126\ PJM Initial Comments at 29-30, 32; see PJM 
Interconnection, L.L.C., 181 FERC ] 61,162 at PP 83-105.
    \1127\ Dominion Initial Comments at 32.
---------------------------------------------------------------------------

    559. Several commenters note that certain interconnection customers 
with generating facilities and interconnection facilities on land 
controlled by the Bureau of Land Management (BLM) face extended time 
frames for obtaining firm site control.\1128\ For example, NV Energy 
states that the BLM permitting process can take between 18 months and 5 
years.\1129\ Idaho Power states that BLM goes through various stages of 
review, but there is no specific stage that is indicative of an 
interconnection customer's request having firm site control until the 
permit is in hand, which can take up to three years to obtain.\1130\ 
Idaho Power states that, currently, interconnection customers with 
generating facilities on BLM lands typically reference the section of 
the site control definition that allows for ``an exclusivity or other 
business relationship between interconnection customer and the entity 
having the right to sell, lease or grant interconnection customer the 
right to possess or occupy a site for such purpose.'' \1131\ Idaho 
Power argues that generating facilities on land managed by BLM should 
have the same site control requirements as all other generating 
facilities, but that they would support an expanded and/or clarified 
definition of site control to capture the limitations of these 
generating facilities. Idaho Power states that, for example, site 
control evidence may include evidence that the necessary application 
has been received by the agency, is in process, and the agency has 
indicated the generating facility is permittable.
---------------------------------------------------------------------------

    \1128\ CREA and NewSun Reply Comments at 49; Idaho Power Initial 
Comments at 6; NV Energy Initial Comments at 16.
    \1129\ NV Energy Initial Comments at 16.
    \1130\ Idaho Power Initial Comments at 6-7.
    \1131\ Id.
---------------------------------------------------------------------------

    560. NV Energy proposes that the deposit in lieu of site control be 
used for lands that are federally managed, and that those deposits be 
held until the decision record, record of decision, notice to proceed, 
or right-of-way grant is issued for a generating facility, which NV 
Energy notes may not be until after the facilities study due to timing 
of the BLM process.\1132\ To ensure the generating facility is 
progressing in the BLM process, NV Energy also proposes that the 
interconnection customer be required to submit with its interconnection 
request a schedule of the land rights and permitting as well as 
documentation from BLM that the draft environmental assessment or draft 
environmental impact statement is expected to be completed by issuance 
of the system impact study. NV Energy also proposes that 
interconnection customers be required to provide the administrative 
draft environmental assessment or draft environmental impact statement 
to the transmission provider for review and comment once BLM has issued 
it to ensure its interconnection facilities are included in the right-
of-way that BLM will issue.
---------------------------------------------------------------------------

    \1132\ NV Energy Initial Comments at 17.
---------------------------------------------------------------------------

    561. CREA and NewSun encourage the Commission to modify its 
proposed site control requirements, such that an interconnection 
customer developing generating facilities on public lands is allowed to 
proceed with the interconnection process if it can demonstrate that the 
relevant public agency has received and has agreed to process the 
necessary permits to develop the interconnection customer's proposed 
generating facility.\1133\
---------------------------------------------------------------------------

    \1133\ CREA and NewSun Reply Comments at 50.
---------------------------------------------------------------------------

    562. For generating facilities on Bureau of Reclamation lands, 
Hydropower Commenters argue that a lease of power privilege should be 
considered a sufficient demonstration of site control.\1134\ 
Additionally, Hydropower Commenters note that generating facilities 
under a certain size can obtain an exemption from Commission licensing 
requirements, and they argue that an exemption from licensing should 
also be considered a sufficient demonstration of site control. 
Similarly, Hydropower Commenters argue that developers of pumped 
storage projects on U.S. Forest Service or BLM lands should not be 
required to complete the required Federal Land Policy and Management 
Act process before they can be considered to have demonstrated 
sufficient evidence of site control.\1135\ Hydropower Commenters 
contend that such generating facilities should be allowed to 
demonstrate site control by submitting evidence that they have a permit 
application pending with U.S. Forest Service or BLM.
---------------------------------------------------------------------------

    \1134\ Hydropower Commenters Initial Comments at 16-17.
    \1135\ Id. at 25.
---------------------------------------------------------------------------

    563. Some commenters argue that the 100% site control requirement 
should not apply to generating facilities being developed on Tribal 
lands.\1136\ OSPA claims that development on Tribal land is more 
challenging than other kinds of development because Tribes have three 
different classes of land that have different ownership structures and 
regulatory restrictions, including ``Trust'' land, which is held by the 
Federal Government on behalf of Tribes and regulated by the Bureau of 
Indian Affairs.\1137\ OSPA notes that Tribes' Reservations are often 
``checker-boarded'' with the three different classes of land, and that 
large wind generating facilities will necessarily be sited on all three 
classes of land. OSPA argues that

[[Page 61096]]

securing Bureau of Indian Affairs regulatory approvals can take years 
and that the ownership structure of ``Allotted'' lands can make it even 
difficult to expediently obtain consent from all owners to lease 
certain tracts, which is required as part of the Bureau of Indian 
Affairs process.\1138\
---------------------------------------------------------------------------

    \1136\ OSPA Initial Comments at 16; rPlus Initial Comments at 2.
    \1137\ OSPA Initial Comments at 17.
    \1138\ Id. at 17-18.
---------------------------------------------------------------------------

    564. OSPA proposes that, for Tribes and Tribal Energy Development 
Organizations, the Commission clarify that interconnection queue 
positions may be secured if the Tribe has signed a lease, even if the 
Bureau of Indian Affairs has not issued a final approval.\1139\ 
Similarly, rPlus recommends that the filing of a valid preliminary 
permit application with the Commission satisfy the site control 
requirement for a pumped storage project and for generating facilities 
on Tribal lands.\1140\ rPlus notes that suitable pumped storage sites 
are limited in availability and are increasingly located on public or 
Tribal lands, which involve significant environmental review. rPlus 
notes that pumped storage projects located on Federal and Tribal lands 
generally cannot achieve full site control until Federal environmental 
reviews are complete and the Commission issues a license. For 
circumstances where a pumped storage project does not require a 
Commission license, rPlus requests that the site control requirement be 
only 50% of the land needed for the core generating facility.\1141\
---------------------------------------------------------------------------

    \1139\ Id. at 18.
    \1140\ rPlus Initial Comments at 2-3.
    \1141\ Id. at 4.
---------------------------------------------------------------------------

    565. Several commenters state that the proposed site control 
requirements may present challenges for offshore wind projects, which 
face extensive permitting timelines.\1142\ Clean Energy Associations 
argue that the formal issuance of a public lease often requires 
multiple preliminary stages and major financial commitments from 
interconnection customers and that requiring a lease prior to entering 
the interconnection queue would unduly delay generating facilities on 
public lands.\1143\ [Oslash]rsted and Clean Energy Associations further 
explain that the permitting process for an offshore wind farm often 
involves multiple Federal and state agencies and runs concurrently with 
the interconnection process. [Oslash]rsted and Clean Energy 
Associations note that the permitting process can lead to changes in 
the generating facility layout within a lease area, routing of offshore 
cables, siting of onshore cable landing, routing of onshore cables, and 
siting of the interconnection switchyard.\1144\
---------------------------------------------------------------------------

    \1142\ Clean Energy Associations Initial Comments at 33; CREA 
and NewSun Reply Comments at 48; Dominion Initial Comments at 31; 
[Oslash]rsted Initial Comments at 12.
    \1143\ Clean Energy Associations Initial Comments at 33.
    \1144\ Id. at 33-34; [Oslash]rsted Initial Comments at 12.
---------------------------------------------------------------------------

    566. Shell, Dominion, and CREA and NewSun argue that the high cost 
of market entry for offshore wind projects is a substantial financial 
commitment and that such generating facilities are by their very nature 
not speculative.\1145\ Shell argues that offshore wind generation 
should be able to demonstrate site control by showing evidence of 
commitments to purchase offshore lease areas from BOEM, as commitments 
often demand hundreds of millions of dollars.\1146\
---------------------------------------------------------------------------

    \1145\ CREA and NewSun Reply Comments at 48; Dominion Initial 
Comments at 31; Shell Initial Comments at 22.
    \1146\ Shell Initial Comments at 22.
---------------------------------------------------------------------------

    567. CREA and NewSun contend that the site control requirements in 
the NOPR would require an offshore developer to win a competitive 
solicitation or obtain a term sheet from an off-taker before entering 
the interconnection queue, which at best will add years of delay to 
developing these generating facilities and at worst will kill the 
proposals outright due to a lack of information on interconnection 
feasibility and cost.\1147\
---------------------------------------------------------------------------

    \1147\ CREA and NewSun Reply Comments at 48.
---------------------------------------------------------------------------

    568. MISO notes that it has not interpreted its tariff to mean that 
a BOEM-administered Wind Energy Area auction that an offshore wind 
interconnection customer can participate in, but which will occur after 
the close of an application window, is a regulatory restriction.\1148\ 
MISO is concerned that broadening the regulatory restriction 
interpretation to allow for offshore wind to submit an interconnection 
request in such instances would enable speculative interconnection 
requests, which will result in withdrawals, restudies, uncertainty, and 
study delays. MISO states that interconnection customers that seek to 
develop a generating facility on government owned lands that are 
awarded to the winner of an auction, and interconnection customers that 
seek to develop a generating facility on private land, are held to the 
same standard in the MISO process.
---------------------------------------------------------------------------

    \1148\ MISO Initial Comments at 55.
---------------------------------------------------------------------------

    569. Some commenters request that ``regulatory limitations'' be 
more clearly defined.\1149\ CAISO expresses concern that, absent 
clarification, the regulatory limitation provision will leave 
transmission provider staff as adjudicators of whether obtaining site 
control is possible for each proposed generating facility, and 
interconnection staff are not experts on real property law or public 
permitting requirements.\1150\ CAISO and Indicated PJM TOs argue that 
without further clarification, the regulatory limitation provision may 
be interpreted too broadly and interconnection customers could argue 
site control was impossible where it was simply impractical or 
expensive.\1151\ CAISO suggests, as an example, that the Commission 
could limit ``regulatory limitations'' only to apply to interconnection 
customers sited in offshore areas, public lands, and Tribal 
lands.\1152\
---------------------------------------------------------------------------

    \1149\ APS Initial Comments at 14; CAISO Initial Comments at 17; 
EEI Initial Comments at 7-8; NYISO Initial Comments at 22; PG&E 
Reply Comments at 2; Indicated PJM TOs Initial Comments at 26-27; 
Shell Reply Comments at 24.
    \1150\ CAISO Initial Comments at 17 & n.29.
    \1151\ Id. at 17; Indicated PJM TOs Initial Comments at 26-27, 
31.
    \1152\ CAISO Initial Comments at 17.
---------------------------------------------------------------------------

    570. Several parties support the NOPR proposal to allow 
interconnection customers with regulatory limitations to submit a 
deposit in lieu of site control.\1153\ For projects on government 
lands, Indicated PJM TOs argue that the interconnection customer should 
be allowed to enter and remain in the interconnection queue, with a 
deposit in lieu of site control, if they identify the steps needed to 
achieve site control and show how they are exercising due diligence to 
obtain a final government determination.\1154\ Indicated PJM TOs argue 
that the regulatory limitations exception should be limited to just 
government lands.
---------------------------------------------------------------------------

    \1153\ APPA-LPPC Initial Comments at 3-4; Cypress Creek Initial 
Comments at 22; SEIA Initial Comments at 15-16; NY Commission and 
NYSERDA Initial Comments at 8-9.
    \1154\ Indicated PJM TOs Reply Comments at 31.
---------------------------------------------------------------------------

    571. MISO supports such an option specifically when the 
interconnection customer is prevented from obtaining site control by a 
regulatory restriction that the passage of time itself will not cure 
(e.g., while participating in an auction that occurs after the 
interconnection request deadline can be cured by time, a requirement to 
obtain an LGIA to participate in an auction cannot be cured by 
time).\1155\
---------------------------------------------------------------------------

    \1155\ MISO Initial Comments at 57.
---------------------------------------------------------------------------

    572. Tri-State suggests modifying section 3.4.[1]2 of the pro forma 
LGIP so that the site control for state or federally controlled land 
must still be fully attained at the time of LGIA execution.\1156\ For 
example, Tri-State states that in Colorado, a state land planning lease 
(which does not meet the Commission's proposed definition of

[[Page 61097]]

site control) could be used with a financial deposit during the cluster 
study process, and a state land production lease (which does meet the 
Commission's proposed definition of site control) would be needed prior 
to LGIA execution.\1157\
---------------------------------------------------------------------------

    \1156\ Tri-State Initial Comments at 13, 27.
    \1157\ Id. at 13.
---------------------------------------------------------------------------

    573. APPA-LPPC argue that, if the NOPR proposal is adopted, at a 
minimum, the interconnection customer should be required to provide an 
affidavit from a company officer, a detailed explanation, and 
documentation justifying the proposed regulatory limitation exception 
and to demonstrate 100% site control as soon as possible after the 
generator interconnection request is submitted, and certainly prior to 
the facilities study stage, as the NOPR proposes.\1158\ PPL contends 
that, while additional flexibility for interconnection customers that 
face regulatory limitation may be appropriate in the early stages of 
review, the Commission should require that full site control be 
demonstrated before proceeding to an LGIA.\1159\
---------------------------------------------------------------------------

    \1158\ APPA-LPPC Initial Comments at 20.
    \1159\ PPL Initial Comments at 16.
---------------------------------------------------------------------------

    574. A number of commenters oppose the NOPR's proposed option to 
allow deposits in lieu of site control where Federal or state 
regulatory limitations prohibit the interconnection customer from 
obtaining site control.\1160\ Idaho Power argues that any allowance of 
a deposit must be accompanied by some evidence of achieving site 
control.\1161\ APS asserts that speculative interconnection requests do 
not necessarily have financial limitations and extra deposits would not 
act as the same deterrent as requiring 100% site control; therefore, 
APS requests that the Commission not allow an exception for regulatory 
restrictions.\1162\
---------------------------------------------------------------------------

    \1160\ APPA-LPPC Initial Comments at 19; APS Initial Comments at 
14; Bonneville Initial Comments at 11; Idaho Power Initial Comments 
at 7; Indicated PJM TOs Initial Comments at 11; Indicated PJM TOs 
Reply Comments at 31; PJM Initial Comments at 26; PPL Initial 
Comments at 16; Southern Initial Comments at 9; SPP Initial Comments 
at 10; Xcel Initial Comments at 30, 32.
    \1161\ Idaho Power Initial Comments at 7.
    \1162\ APS Initial Comments at 14.
---------------------------------------------------------------------------

    575. OSPA argues that requiring interconnection customers that face 
regulatory barriers to submit any deposits, including deposits in lieu 
of site control, will create insuperable barriers to renewable energy 
development by Native American Tribes and Tribal Energy Development 
Organizations on Tribal lands,\1163\ stating that Tribes have limited 
access to capital and face other challenges that large developers do 
not share.\1164\
---------------------------------------------------------------------------

    \1163\ OSPA Initial Comments at 18.
    \1164\ OSPA Reply Comments at 12.
---------------------------------------------------------------------------

    576. A few commenters support the proposed amounts for the deposit 
in lieu of site control.\1165\ MISO agrees that the proposed deposit 
thresholds are sufficient, noting that the amount of the deposits under 
MISO's tariff are the same amounts the Commission proposed in the 
NOPR.\1166\ Tri-State contends that the proposed deposit amounts would 
be sufficient to ensure advanced-stage interconnection requests are 
able to continue to move toward interconnection.\1167\
---------------------------------------------------------------------------

    \1165\ MISO Initial Comments at 57; NV Energy Initial Comments 
at 15; Tri-State Initial Comments at 13.
    \1166\ MISO Initial Comments at 57.
    \1167\ Tri-State Initial Comments at 13.
---------------------------------------------------------------------------

    577. Several parties support a deposit in lieu of site control high 
enough to deter speculative interconnection requests that are unlikely 
to achieve site control.\1168\ Avangrid argues that any deposit in lieu 
of site control should be proportionate to the size of the 
interconnection request, and ``reflect collateral'' while an 
interconnection customer works through site control agreements.\1169\ 
Eversource similarly argues that the Commission should set the deposit 
so that the interconnection customer fully internalizes the risk of 
failing to obtain site control.\1170\ Tri-State also argues that the 
deposit should not apply to interconnection study costs.\1171\
---------------------------------------------------------------------------

    \1168\ Id. at 14; Avangrid Initial Comments at 19; ENGIE Initial 
Comments at 4; GSCE Initial Comments at 7; NYTOs Initial Comments at 
19; Pacific Northwest Utilities Initial Comments at 3-4.
    \1169\ Avangrid Initial Comments at 19.
    \1170\ Eversource Initial Comments at 17.
    \1171\ Tri-State Initial Comments at 14.
---------------------------------------------------------------------------

    578. Some commenters provide alternative suggestions for the 
deposit in lieu of site control amounts.\1172\ Longroad Energy argues 
that the Commission should consider requiring that such deposits be set 
as a multiple of the interconnection study deposit (such as three times 
the deposit amount), rather than as a dollar amount per MW of 
generating facility size, as proposed in the NOPR.\1173\ NYTOs argue 
that the MW capacity of a generating facility is not necessarily 
relevant to determining the appropriate deposit requirement and that 
deposits should be more closely tied to the generating facility's 
potential impact on the interconnection process.\1174\
---------------------------------------------------------------------------

    \1172\ Eversource Initial Comments at 17; Longroad Energy 
Initial Comments at 12; NYTOs Initial Comments at 19.
    \1173\ Longroad Energy Initial Comments at 12; Longroad Energy 
Reply Comments at 18.
    \1174\ NYTOs Initial Comments at 19.
---------------------------------------------------------------------------

    579. A number of entities argue that any deposits in lieu of site 
control should be non-refundable.\1175\ Avangrid suggests that the 
deposit be non-refundable to avoid gaming by prospective 
interconnection customers.\1176\ National Grid argues that absent 
circumstances outside the control of the interconnection customer, any 
deposit should be non-refundable, and any security should be able to be 
drawn upon in the event the interconnection customer withdraws or fails 
to demonstrate site control at the required time.\1177\ National Grid 
contends that if the Commission intends to permit refunds or returns of 
a deposit in lieu of site control, such deposits should be provided 
only after deducting the actual costs and fees, e.g., escrow account 
initiation and maintenance fees, incurred by the transmission provider 
or RTOs/ISOs prior to the time of the withdrawal request or the 
demonstration of site control. National Grid also requests that the 
Commission clarify that withdrawal penalties are separate and may be 
deducted from the deposit amount.
---------------------------------------------------------------------------

    \1175\ Avangrid Initial Comments at 19; EEI Initial Comments at 
8; Longroad Energy Initial Comments at 12; National Grid Initial 
Comments at 23; NYTOs Initial Comments at 19.
    \1176\ Avangrid Initial Comments at 19.
    \1177\ National Grid Initial Comments at 23-24.
---------------------------------------------------------------------------

    580. Similarly, Longroad Energy suggests that to ensure that the 
proper incentives exist, the Commission may wish to evaluate if a 
security deposit in lieu of site control should become non-refundable 
if an interconnection customer withdraws at any point in the 
interconnection process or fails to achieve commercial operation.\1178\ 
EEI argues that the Commission can further reduce potential risks by 
making deposits non-refundable, or if the Commission declines to do so, 
it should ensure that withdrawal penalties are significant enough to 
discourage speculative interconnection requests.\1179\ On the other 
hand, NYTOs argue that regions should have the flexibility to determine 
whether, under certain circumstances, deposits should become fully non-
refundable.\1180\
---------------------------------------------------------------------------

    \1178\ Longroad Energy Initial Comments at 12.
    \1179\ EEI Initial Comments at 8.
    \1180\ NYTOs Initial Comments at 19.
---------------------------------------------------------------------------

    581. Xcel argues that in addition to requiring a deposit, 
interconnection customers facing regulatory limitations should be 
required to provide status updates to the transmission provider, and 
there should be sufficient penalties to ensure interconnection 
customers provide accurate information on the

[[Page 61098]]

status of regulatory proceedings.\1181\ Xcel contends that, if 
regulatory limitations prohibit an interconnection customer from 
obtaining site control, transmission providers should be allowed to 
propose constructs that facilitate interconnection, including the 
ultimate achievement of site control.
---------------------------------------------------------------------------

    \1181\ Xcel Initial Comments at 30-31.
---------------------------------------------------------------------------

(c) Miscellaneous
    582. Public Interest Organizations argue that it is unreasonable 
that the pro forma LGIP allows interconnection customers to propose a 
decrease to the generating facility's output of up to 60% without 
losing queue position while also requiring a demonstration of 100% site 
control upon entering the interconnection queue.\1182\ Public Interest 
Organizations also argue that the NOPR proposal to require 
interconnection customers to remedy any change in site control within 
10 days or have their interconnection request withdrawn is 
unreasonable. In addition, Public Interest Organizations argue that it 
is unduly discriminatory to allow interconnection customers proposing a 
thermal project to keep their queue position by downsizing the 
generating facility's turbines but not allow interconnection customers 
proposing wind generating facilities to keep their queue position if 
they lose part of a lease. Public Interest Organizations argue that the 
cure period should be long enough to allow for routine events that 
affect site control, such as the death of a landowner or the change of 
ownership at a commercial facility hosting a proposed generating 
facility.
---------------------------------------------------------------------------

    \1182\ Public Interest Organizations Initial Comments at 27-28.
---------------------------------------------------------------------------

iii. Commission Determination
    583. As discussed herein, we adopt in part and modify in part the 
NOPR proposal to revise sections 1, 3.4.2, 7.5, 8.1, and 11.3 of the 
pro forma LGIP and Appendix B of the pro forma LGIA to add more 
stringency to the site control requirements and to help prevent 
speculative interconnection requests from entering the interconnection 
queue. We believe that, taken together, these reforms will help ensure 
that commercially viable interconnection requests with demonstrated 
site control or with demonstrated regulatory limitations will be able 
to enter the interconnection queue, thereby reducing the negative 
impacts of speculative interconnection requests.
(a) Definition and Reasonable Evidence of Site Control
    584. We adopt the NOPR proposal to revise the definition of site 
control in section 1 of the pro forma LGIP with several modifications. 
As modified, the definition states that site control may be 
demonstrated by documentation establishing: ``(1) ownership of, a 
leasehold interest in, or a right to develop a site of sufficient size 
to construct and operate the Generating Facility; (2) an option to 
purchase or acquire a leasehold site of sufficient size to construct 
and operate the Generating Facility; or (3) any other documentation 
that clearly demonstrates the right of Interconnection Customer to 
exclusively occupy a site of sufficient size to construct and operate 
the Generating Facility.'' Additionally, we agree with commenters' 
observations \1183\ that subpart (3) of the pro forma LGIP definition 
of site control proposed in the NOPR, which stated ``site of sufficient 
size to construct and operate the Generating Facility,'' was 
duplicative; therefore, we modify the NOPR proposal to delete this 
subpart and provide clarification that all three remaining, enumerated 
options to demonstrate site control require control of a site of 
sufficient size to construct and operate the generating facility or 
multiple generating facilities on a shared site.
---------------------------------------------------------------------------

    \1183\ See Enel Initial Comments at 82; Southern Initial 
Comments at 34-35.
---------------------------------------------------------------------------

    585. To prevent multiple interconnection customers from leasing the 
same site in order to remain in the interconnection queue, we adopt the 
NOPR's proposed revisions to the pro forma LGIP that require an 
interconnection customer to demonstrate the exclusive land right to 
develop, construct, operate, and maintain its generating facility or, 
where facilities are co-located, to demonstrate a shared land use right 
to develop, construct, operate, and maintain co-located facilities. We 
further clarify that the right to ``exclusively'' occupy the site to 
develop, construct, operate, or maintain a generating facility means 
both that the right belongs solely to the interconnection customer (no 
other entity shares the right to use the site for those purposes), as 
well as that the right is solely for purposes of a single 
interconnection request. We find that an interconnection customer 
securing the exclusive land right necessary to construct its proposed 
generating facility (or for co-located generating facilities, 
demonstration of shared land use) is sufficient evidence of the 
interconnection customer's commitment to construct the generating 
facility.
    586. We also modify section 3.4.2 of the pro forma LGIP to provide 
that site control for a generating facility that is co-located with one 
or more generating facilities on the same site and behind the same 
point of interconnection must be demonstrated by a contract or other 
agreement that allows for shared land use for all generating facilities 
that are co-located that meet the provisions of the site control 
definition. We clarify that interconnection customers are prohibited 
from submitting evidence of site control that uses the same land for 
multiple interconnection requests, unless the site is large enough to 
host multiple generating facilities. We note that section 3.4.2 of the 
pro forma LGIP that we adopt in this final rule permits shared land use 
for co-located generating facilities on the same site and behind the 
same point of interconnection, and we clarify below that transmission 
providers have flexibility to establish appropriate technology-specific 
acreage requirements for generating facilities.\1184\ Permitting 
multiple interconnection requests to use the same land to demonstrate 
exclusive site control would inherently result in at least one 
commercially non-viable interconnection request entering the 
interconnection queue and thus would be insufficient to ensure that 
interconnection customers are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner. We 
also clarify that the interconnection customer is required to meet the 
technology-specific acreage requirement for its generating facility 
that is publicly posted by the transmission provider at the time it 
submits its interconnection request.
---------------------------------------------------------------------------

    \1184\ This is consistent with the practice that several 
transmission providers currently follow. See Midcontinent Indep. 
Sys. Operator, Inc., 169 FERC ] 61,173 at P 48; Sw. Power Pool, 
Inc., 128 FERC ] 61,114 at P 48; PJM Interconnection, L.L.C., 181 
FERC ] 61,162 at P 102.
---------------------------------------------------------------------------

    587. Likewise, in response to Enel, we clarify that the term 
``exclusive land rights'' in the definition of site control applies 
only to the exclusivity required to develop, construct, operate, and 
maintain the interconnection customer's proposed generating facility; 
the term ``exclusive land rights'' does not restrict multi-use 
applications of the site in addition to its use for the generating 
facility, such as agriculture, ranching, etc.\1185\ Similarly, in 
response to Cypress Creek, we clarify that a land right does not 
involve zoning approval.
---------------------------------------------------------------------------

    \1185\ See Enel Initial Comments at 42.

---------------------------------------------------------------------------

[[Page 61099]]

    588. In response to commenters,\1186\ we further clarify that the 
adopted definition of site control permits an interconnection customer 
to demonstrate site control with lease options, instead of executed 
leases, provided that the interconnection customer is the exclusive 
holder of such a lease option(s). The adopted definition explicitly 
provides for such a lease option, by including the phrase, ``an option 
to purchase or acquire a leasehold site.'' However, evidence of active 
negotiations for a lease is not a sufficient demonstration of site 
control at any time during the interconnection process. Allowing active 
negotiations for a lease to serve as a demonstration of site control, 
as some commenters suggest,\1187\ would allow speculative, commercially 
non-viable interconnection requests to proceed through the 
interconnection queue, which would be inconsistent with ensuring that 
interconnection customers are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner. 
Likewise, with respect to NRECA's request,\1188\ we clarify that this 
final rule permits leases and lease options as sufficient evidence of 
site control as discussed above, and transmission providers have 
discretion to evaluate the content of such leases and lease options and 
any conditions contained therein to determine whether they sufficiently 
demonstrate site control.
---------------------------------------------------------------------------

    \1186\ Omaha Public Power Initial Comments at 7; SoCal Edison 
Initial Comments at 6.
    \1187\ EPSA Initial Comments at 8; Interwest Reply Comments at 
13.
    \1188\ NRECA Initial Comments at 27.
---------------------------------------------------------------------------

    589. Several commenters seek clarification as to whether the 
proposed pro forma LGIP definition of site control would allow certain 
types of generating facilities developed on lands owned or controlled 
by a government entity to demonstrate site control. We agree with 
commenters that offshore wind interconnection customers must make a 
substantial financial commitment to win a competitive auction and 
secure a lease from BOEM, and such generating facilities that have 
secured a lease agreement are not speculative.\1189\ We therefore 
clarify that a lease agreement with BOEM to pursue development of an 
offshore wind generating facility can serve as a sufficient 
demonstration of site control under the site control definition adopted 
in this final rule. This clarification is consistent with our finding 
above that a variety of lease options satisfy the site control 
requirement. In response to MISO's concerns about allowing multiple 
offshore wind interconnection customers to submit an interconnection 
request for the same ``Wind Energy Area'' before it has been auctioned 
by BOEM, we find that the pro forma LGIP site control definition that 
we adopt herein appropriately limits such potentially speculative 
interconnection requests by requiring offshore wind interconnection 
customers to provide evidence of an exclusive right to develop a lease 
area to satisfy the site control requirements.
---------------------------------------------------------------------------

    \1189\ CREA and NewSun Reply Comments at 48; Dominion Initial 
Comments at 31; Shell Initial Comments at 22.
---------------------------------------------------------------------------

    590. With respect to OSPA's concerns regarding the challenges of 
demonstrating site control on Tribal lands due to the nature of land 
ownership on Reservations and the need for the Bureau of Indian Affairs 
to approve certain leases, we clarify that under the site control 
definition, interconnection customers developing generating facilities 
on Tribal lands can demonstrate site control with a signed lease 
agreement with the applicable Tribe-owner.\1190\ As discussed below in 
section III.A.6.b.iii.b, an interconnection customer with a 
demonstrated regulatory limitation, including those associated with 
obtaining a lease on Tribal lands, may submit a deposit in lieu of site 
control.
---------------------------------------------------------------------------

    \1190\ OSPA Initial Comments at 17-18.
---------------------------------------------------------------------------

    591. Similarly, in response to commenters' concerns about 
demonstrating site control for hydropower projects on sites owned or 
controlled by a government entity, we clarify that certain 
documentation can be used to demonstrate site control under the pro 
forma LGIP definition of site control. For interconnection customers 
developing generating facilities at non-powered dams, we clarify that a 
FERC license \1191\ can serve as a demonstration of site control under 
subpart (3). However, we also clarify that neither a Memorandum of 
Agreement with the U.S. Army Corps of Engineers regarding a proposed 
hydropower project at a U.S. Army Corps of Engineers dam nor a 
preliminary permit for a pumped storage project or other hydropower 
generating facility to be located on Tribal lands would be sufficient 
to demonstrate site control because we do not have enough information 
in this record to determine that such documentation provides sufficient 
evidence of the interconnection customer's exclusive right to occupy a 
site of sufficient size to construct and operate a generating facility.
---------------------------------------------------------------------------

    \1191\ A FERC license provides the licensee with the power of 
eminent domain to secure property rights needed to construct and 
operate the project. See 16 U.S.C. 814. While a FERC license does 
not explicitly convey an exclusive right to develop a project, the 
Commission does not approve more than one license for the same site.
---------------------------------------------------------------------------

    592. For hydropower projects that are not subject to the 
Commission's hydropower permitting jurisdiction, such as projects on 
Bureau of Reclamation lands, we clarify that a lease of power privilege 
can serve as a demonstration of site control under the site control 
definition. Finally, for hydropower projects that are small enough to 
be exempted from FERC licensing requirements, Hydropower Commenters 
explain that an exemption from FERC licensing provides an exclusive 
right to the recipient to develop a project at the site and the 
exemption is issued in perpetuity.\1192\ Because such an exemption 
includes an exclusive right to develop, we clarify that providing a 
written statement as evidence of an exemption from licensing under the 
FPA can serve as a demonstration of site control under subpart (3) of 
the site control definition.
---------------------------------------------------------------------------

    \1192\ Hydropower Commenters Initial Comments at 17.
---------------------------------------------------------------------------

    593. We note NV Energy's explanation that its previous efforts to 
allow interconnection customers to demonstrate site control by showing 
a draft preliminary plan of development, one of the earlier required 
documents in the BLM permitting process, have led to speculative 
interconnection requests that slow down the interconnection 
process.\1193\ We agree, and we therefore decline to adopt commenters' 
proposal to modify the proposed pro forma LGIP definition of site 
control to allow interconnection customers to demonstrate site control 
by providing documentation indicating that they are pursuing the 
necessary permits with the appropriate government entity or 
entities.\1194\ As with our finding that active negotiations for lease 
agreements are not sufficient to demonstrate site control, discussed 
above, we find that such an expansion of the site control definition 
could weaken the site control requirements included in the pro forma 
LGIP and could undermine the effectiveness of this reform in helping to 
prevent speculative interconnection requests.
---------------------------------------------------------------------------

    \1193\ NV Energy Initial Comments at 15-16.
    \1194\ See CREA and NewSun Reply Comments at 50; Pattern Energy 
Initial Comments at 30.
---------------------------------------------------------------------------

(b) Site Control Demonstration and Deposits in Lieu of Site Control
    594. We adopt the NOPR proposal, with modification, to revise 
section 3.4.2 of the pro forma LGIP to require

[[Page 61100]]

interconnection customers to demonstrate site control at the time of 
submission of the interconnection request. However, we modify the 
proposal and require interconnection customers to provide evidence of 
90% site control for the generating facility at the time of submission 
of the interconnection request and, pursuant to revised sections 8.1 
and 11.3 of the pro forma LGIP, provide evidence of 100% site control 
for the generating facility at the time of execution of the facilities 
study agreement and when executing, or requesting the unexecuted filing 
of, the LGIA.
    595. We decline to adopt the NOPR proposal to require technology-
specific acreages to be listed in the transmission provider's tariff. 
As discussed below, instead, we require transmission providers to 
establish acreage requirements for each generating facility technology 
type and to publicly post these acreage requirements. We adopt the 
following aspects of the NOPR proposal to revise sections 3.4.2 and 
11.3 of the pro forma LGIP to: (1) eliminate the option to provide a 
deposit in lieu of site control demonstration except in limited 
circumstances where an interconnection customer demonstrates a 
regulatory limitation to obtaining site control, as discussed below, 
and eliminate the option to post $250,000 of non-refundable security in 
lieu of site control at LGIA execution; and (2) require that 
interconnection customers that could not demonstrate the requisite 
level of site control at the relevant milestone of the interconnection 
process (i.e., 90% for the cluster study and cluster restudy, and 100% 
for the interconnection facilities study and when executing, or 
requesting the unexecuted filing of, the LGIA) would have their 
interconnection request deemed withdrawn and could be subject to 
withdrawal penalties under certain circumstances, as discussed below.
    596. We adopt the NOPR proposal to revise sections 3.4.2, 7.5 and 
8.1 of the pro forma LGIP such that, after notifying the transmission 
provider of any change to the interconnection customer's site control 
demonstration, the transmission provider must give the interconnection 
customer 10 business days to demonstrate satisfaction with the 
applicable requirement. We find the adopted approach to require 90% 
site control at the time of the interconnection request and 100% site 
control at the time of the facilities study and when executing, or 
requesting the unexecuted filing of, the LGIA appropriately balances 
the concerns identified in the record. In particular, we find that it 
will provide sufficiently stringent site control requirements to help 
prevent interconnection customers from submitting interconnection 
requests for speculative, commercially non-viable proposed generating 
facilities, while accommodating development challenges faced by 
interconnection customers that may otherwise present unjust and 
unreasonable barriers to entering the interconnection queue. We believe 
that this approach appropriately recognizes that issues often arise in 
developing a generating facility, such that requiring a demonstration 
of 90% site control at the time of the interconnection request, rather 
than 100%, provides valuable flexibility for interconnection customers 
with viable prospective generating facilities to resolve those issues 
and continue through the interconnection process.
    597. We are persuaded by commenters that contend that there are 
significant benefits to allowing interconnection customers to enter the 
cluster study process and potentially use the interconnection study 
results to better understand their generating facility configuration 
before obtaining 100% site control. We agree with commenters that 
allowing less than 100% site control at the interconnection request 
stage would provide interconnection customers flexibility to address 
the results of interconnection studies or other regulatory processes 
\1195\ and afford flexibility for interconnection customers that are 
still actively negotiating with landowners close to the deadline for a 
cluster request window.\1196\ Establishing a requirement for 90% site 
control at the time of an interconnection request allows an 
interconnection request to be submitted even if a few parcels of land 
are still in negotiation or where a different site configuration arises 
based on the scoping meeting with the transmission provider. Moreover, 
the adopted approach provides flexibility for interconnection customers 
to sign certain leases for particularly challenging parcels at a later 
point in time, reducing the exposure to risk of expiration of those 
leases.\1197\ Additionally, we agree with commenters that shifting the 
100% site control requirement until the execution of a facilities study 
agreement allows the interconnection customer to put less money at risk 
for obtaining particularly challenging land rights and to obtain a more 
meaningful understanding of what upgrade costs its generating facility 
may be assigned, for instance, from the cluster study report that is 
provided before the execution of the facilities study agreement.\1198\
---------------------------------------------------------------------------

    \1195\ See CREA and NewSun Initial Comments at 55; SEIA Initial 
Comments at 14-15.
    \1196\ See Pine Gate Initial Comments at 23-24.
    \1197\ Enel Initial Comments at 40.
    \1198\ AEE Initial Comments at 18; Clean Energy Associations 
Initial Comments at 31-32; CREA and NewSun Initial Comments at 55; 
Cypress Creek Initial Comments at 22; SEIA Initial Comments at 15; 
Shell Reply Comments at 23-24.
---------------------------------------------------------------------------

    598. At the same time, we believe that the approach adopted in this 
final rule, along with the other reforms adopted herein, is 
sufficiently stringent to help prevent speculative, commercially non-
viable proposed generating facilities from entering and continuing 
through the interconnection queue. As an initial matter, we establish a 
more stringent requirement for site control at the time of submission 
of an interconnection request than required by the pro forma LGIP prior 
to this final rule. In particular, obtaining nearly all of the land 
rights necessary to develop a proposed generating facility prior to 
submitting the interconnection request entails a significant 
commitment, both financial and in terms of the time and resources 
required to negotiate with landowners. Moreover, the 100% site control 
requirement at the time of the execution of the facilities study 
agreement adds further stringency to ensure generating facilities that 
proceed through the interconnection queue are the most likely to be 
commercially viable.
    599. We agree with commenters that requiring 100% site control at 
the time of submission of an interconnection request may not be 
compatible with the project development cycle,\1199\ which includes 
stringent permitting requirements, and may disadvantage certain 
interconnection customers despite there being a path to full site 
control and commercial readiness.\1200\ Further, requiring 100% site 
control at submission of the interconnection request would not allow 
for minor revisions to the generating facility plan if, upon meeting 
with the transmission provider at the scoping meeting, such revisions 
would facilitate an improved generating facility design. This could 
present a barrier to entry for interconnection customers with viable 
proposed generating facilities.
---------------------------------------------------------------------------

    \1199\ AEE Initial Comments at 17; CREA and NewSun Initial 
Comments at 54; Clean Energy Associations Initial Comments at 31; 
Cypress Creek Initial Comments at 22; EPSA Initial Comments at 8; 
NextEra Initial Comments at 21; R Street Initial Comments at 8.
    \1200\ AEE Initial Comments at 17.
---------------------------------------------------------------------------

    600. We decline to adopt commenters' suggestions that transmission 
providers be allowed to confirm site control

[[Page 61101]]

throughout the interconnection process.\1201\ The adopted site control 
requirements require site control demonstrations at three specific 
points in the interconnection process--submission of the 
interconnection request; at the time of execution of the facilities 
study agreement; and when executing, or requesting the unexecuted 
filing of, an LGIA. We find that these points are sufficient to help 
prevent interconnection customers with commercially non-viable 
interconnection requests from entering and proceeding through the 
interconnection queue.
---------------------------------------------------------------------------

    \1201\ See Indicated PJM TOs Initial Comments at 26; MISO 
Initial Comments at 53.
---------------------------------------------------------------------------

    601. With respect to eliminating the option for any interconnection 
customer to submit a deposit in lieu of site control, except in limited 
circumstances where an interconnection customer demonstrates a 
regulatory limitation, we find that, because a deposit in lieu of site 
control does not demonstrate that an interconnection customer has the 
exclusive right to develop a site, it does not indicate that an 
interconnection customer is ready to proceed with construction and 
commercial operation of the generating facility. As a result, we 
believe that allowing deposits in lieu of site control for all 
interconnection customers, as requested by some commenters, would not 
help to prevent speculative, commercially non-viable interconnection 
requests from entering the interconnection queue. Thus, we decline to 
include such an option in the pro forma LGIP.
    602. We are persuaded by commenters that requiring transmission 
providers to publicly maintain per MW acreage requirements for each 
generating facility technology type is necessary to afford adequate 
transparency and certainty to interconnection customers. At the same 
time, we do not believe that such acreage requirements must be 
contained within transmission providers' tariffs; rather, we find that, 
consistent with the rule of reason, transmission providers may choose 
to maintain acreage requirements in their business practice manuals or 
may otherwise post them on a publicly accessible website. We find that 
acreage requirements are properly classified as implementation details 
that do not significantly affect rates, terms, and conditions of 
service,\1202\ and we therefore do not require their inclusion in 
tariffs. This is consistent with previous Commission orders approving 
transmission providers' proposals to specify technology-specific 
acreage requirements for site control in their business practice 
manuals.\1203\ This will also afford transmission providers more 
flexibility in updating acreage requirements to account for 
technological advancements without being required to make FPA section 
205 filings each time they seek to modify the acreage requirements. On 
the other hand, to give the interconnection customer certainty, as 
noted above, we clarify that the interconnection customer is required 
to meet the technology-specific acreage requirement for its generating 
facility publicly posted by the transmission provider at the time it 
submits its interconnection request.
---------------------------------------------------------------------------

    \1202\ See, e.g., N.Y. Indep. Sys. Operator, Inc., 179 FERC ] 
61,102 at PP 105-114.
    \1203\ See Midcontinent Indep. Sys. Operator, Inc., 169 FERC ] 
61,173 at P 48 (finding MISO's proposal to place resource-specific 
acreage requirements in its business practice manuals to be 
appropriate because ``these requirements include technical 
calculations that may require updates from time to time''); Sw. 
Power Pool, Inc., 128 FERC ] 61,114 at P 48; PJM Interconnection, 
L.L.C., 181 FERC ] 61,162 at P 102.
---------------------------------------------------------------------------

    603. To provide clarity for interconnection customers and 
transmission providers, we modify the pro forma LGIP definition of 
``Generating Facility'' to replace ``device'' with ``device(s)'' to 
clarify that this definition includes hybrid generating 
facilities.\1204\ We believe this clarification is necessary to ensure 
that hybrid generating facilities have the same rights and 
responsibilities as other types of generating facilities under the pro 
forma LGIP and pro forma LGIA. In response to commenters and consistent 
with the modified definition of ``Generating Facility,'' we clarify 
that the transmission providers' per MW acreage requirements for each 
generating facility technology-type must include specific requirements 
for hybrid generating facilities. We also clarify that generating 
facilities that are co-located on the same site and behind the same 
point of interconnection are subject to the technology-specific acreage 
requirements based on the generating facilities' technology-type.
---------------------------------------------------------------------------

    \1204\ A hybrid generating facility is a generating facility 
composed of more than one device of different technology types for 
the production and/or storage for later injection of electricity 
that are located on the same site and are operated and dispatched as 
a single integrated generating facility.
---------------------------------------------------------------------------

    604. In response to requests for clarification as to whether the 
site control demonstration at the time of submission of the 
interconnection request applies to interconnection facilities as well 
as generating facilities, we clarify that the site control 
demonstration requirements apply only to the land needed for the 
generating facility. In the NOPR, the Commission did not propose site 
control requirements for interconnection facilities.\1205\ Based on 
this clarification, we decline to address comments suggesting 
alternative site control requirements for interconnection facilities or 
network upgrades.
---------------------------------------------------------------------------

    \1205\ Under the pro forma LGIP, interconnection facilities 
shall mean the transmission provider's interconnection facilities 
and the interconnection customer's interconnection facilities. 
Collectively, interconnection facilities include all facilities and 
equipment between the generating facility and the point of 
interconnection, including any modification, additions or upgrades 
that are necessary to physically and electrically interconnect the 
generating facility to the transmission provider's transmission 
system. Interconnection facilities are sole use facilities and shall 
not include distribution upgrades, stand alone network upgrades or 
network upgrades.
---------------------------------------------------------------------------

(c) Site Control Considerations for Interconnection Customers With 
Regulatory Limitations
    605. We adopt the NOPR proposal, with modification, to revise 
section 3.4.2 of the pro forma LGIP to include a limited option for 
interconnection customers to submit a deposit in lieu of site control 
when they submit their interconnection request--only if qualifying 
regulatory limitations prohibit the interconnection customer from 
obtaining site control. We adopt the NOPR proposal to provide that 
interconnection customers with regulatory limitations may submit an 
initial deposit in lieu of site control of $10,000 per MW, subject to a 
floor of $500,000 and a ceiling of $2 million. As discussed below, this 
deposit shall be refundable but may not be applied toward 
interconnection studies or withdrawal penalties, if applicable. 
However, we decline to adopt the proposed requirement in the NOPR that 
an interconnection customer facing regulatory limitations must 
demonstrate 100% site control prior to the execution of a facilities 
study agreement. Instead, we modify the proposed requirement for an 
interconnection customer facing regulatory limitations to provide that 
a deposit in lieu of site control will be accepted and held by the 
transmission provider until the interconnection customer can 
demonstrate 90% site control prior to execution of the facilities study 
agreement or 100% site control at execution of the facilities study 
agreement or thereafter. Additionally, we modify the NOPR proposal to 
specify in Appendix B of the pro forma LGIA that interconnection 
customers facing qualifying regulatory limitations must demonstrate 
100% site control within 180 calendar days of the effective date of the 
LGIA or the LGIA may be terminated per article 17

[[Page 61102]]

(Default) of the pro forma LGIA and the interconnection customer may be 
subject to withdrawal penalties per new pro forma LGIP section 3.7.1.1 
(Calculation of the Withdrawal Penalty).
    606. We adopt the NOPR proposal to revise section 3.4.2 of the pro 
forma LGIP to provide how interconnection customers may demonstrate 
regulatory limitations. Specifically interconnection customers must 
provide to the transmission provider: (1) a signed affidavit from an 
officer of the company indicating that site control is unobtainable due 
to regulatory limitations as such term is defined by the transmission 
provider; and (2) documentation sufficiently describing and explaining 
the source and effects of such regulatory limitations, including a 
description of any conditions that must be met to satisfy the 
regulatory limitations and the anticipated time by which the 
interconnection customer expects to satisfy the regulatory 
restrictions.
    607. With respect to what qualifies as a regulatory limitation, we 
require transmission providers to define regulatory limitations 
relevant to their service territory, to publicly post the definition, 
and to provide a narrative description of how they define regulatory 
limitations as part of their compliance filings. While we decline to 
require a uniform definition of regulatory limitations for all 
transmission providers, we clarify that a regulatory limitation is 
generally a Federal, state, Tribal, or local law that makes it 
practically infeasible to obtain site control within the time frame 
detailed in the pro forma LGIP. We allow transmission providers 
flexibility on how to publicly post the definition, such as by 
including it in business practice manuals or posting on a publicly 
accessible website. We consider the definition of regulatory 
limitations to be an implementation detail appropriately housed outside 
of transmission providers' tariffs, consistent with the rule of reason. 
We expect that the appropriate scope of regulatory limitations may vary 
by region and is likely to need to be updated over time as relevant 
Federal, state, Tribal, or local laws change. For these reasons, we do 
not require transmission providers to include their definitions of 
regulatory limitations in their tariffs.
    608. We believe that these requirements will ensure a transparent, 
consistent, and orderly process to facilitate demonstration of 
regulatory limitations by interconnection customers and will establish 
minimum requirements to provide transmission providers sufficient 
information to evaluate such demonstrations. We agree with commenters 
that transmission providers are best positioned to develop appropriate 
definitions of regulatory limitations to address the specific 
circumstances and unique regulatory limitations that interconnection 
customers in their regions may face. We believe that this approach 
preserves flexibility for transmission providers to account for 
regional diversity.
    609. As noted above, we decline to adopt the proposed requirement 
in the NOPR that an interconnection customer facing regulatory 
limitations must demonstrate 100% site control prior to commencement of 
the facilities study. We agree with commenters that the requirement to 
demonstrate site control at the facilities study stage could act as a 
barrier for generating facilities faced with regulatory limitations in 
demonstrating site control because the permitting process may still be 
underway at the facilities study stage.\1206\ To account for these 
barriers, we clarify that, in such circumstances, interconnection 
customers are permitted to proceed through the interconnection process 
and execute, or request the unexecuted filing of, an LGIA before 
obtaining site control, by providing documentation that demonstrates 
they are taking identifiable steps to secure the necessary regulatory 
approvals from the applicable Federal, state, and/or Tribal entities, 
as described above. Such interconnection customers must provide this 
documentation at the time of execution of the facilities study 
agreement and when executing, or requesting the unexecuted filing of, 
the LGIA, or alternatively, demonstrate site control in accordance with 
the requirements of the pro forma LGIP.
---------------------------------------------------------------------------

    \1206\ See, e.g., NV Energy Initial Comments at 17.
---------------------------------------------------------------------------

    610. We acknowledge that certain interconnection customers 
developing generating facilities on sites owned or controlled by a 
government entity, such as those who site generating facilities on BLM 
lands, may not be able to demonstrate site control under the pro forma 
LGIP definition even by the later stages of the interconnection process 
because final permitting approval from BLM may not occur until after 
the facilities study stage.\1207\ We believe the site control 
requirements included in the pro forma LGIP strike an appropriate 
balance between disincentivizing speculative interconnection requests 
and accommodating interconnection customers facing extensive permitting 
requirements by allowing such customers to submit a deposit in lieu of 
site control where they demonstrate a qualifying regulatory limitation.
---------------------------------------------------------------------------

    \1207\ See, e.g., id.
---------------------------------------------------------------------------

    611. In response to commenters' concerns that, without 
clarification, the regulatory limitations exception to the site control 
requirement may be interpreted broadly to allow interconnection 
customers to claim regulatory limitations when obtaining site control 
is simply impractical or expensive, we reiterate that transmission 
providers may exercise discretion when defining regulatory 
limitations--generally a Federal, state, Tribal, or local law that 
makes it practically infeasible to obtain site control within the time 
frame detailed in the pro forma LGIP--as appropriate for 
interconnection customers in their regions. We believe that allowing 
flexibility in defining regulatory limitations will enable transmission 
providers to account for any local, county, Tribal and state 
regulations in their respective region that may delay an 
interconnection customer's efforts to obtain site control.
    612. With respect to the amount of the deposit in lieu of site 
control for interconnection customers with regulatory limitations, we 
find that the amounts that we adopt in this final rule will help 
prevent speculative interconnection requests without placing an undue 
burden on interconnection customers. We are not persuaded by commenters 
that argue that the deposit amounts in lieu of site control for 
interconnection customers with regulatory limitations need to be even 
higher to deter interconnection requests that are not likely to achieve 
site control, particularly when considered in conjunction with the 
commercial readiness deposits and withdrawal penalties adopted in this 
final rule, discussed below. We also find that deposits in lieu of site 
control for interconnection customers with regulatory limitations 
should be refundable, but may not be applied toward interconnection 
studies or withdrawal penalties. We find that making these deposits in 
lieu of site control for interconnection customers with regulatory 
limitations non-refundable, as some commenters argue, may unduly burden 
certain interconnection customers facing regulatory limitations where 
certain regulatory constraints may be beyond their control.
c. Commercial Readiness
i. NOPR Proposal
    613. In the NOPR, the Commission proposed to revise the pro forma 
LGIP to include a commercial readiness

[[Page 61103]]

framework, which included commercial readiness demonstration options 
and commercial readiness deposits.\1208\ The Commission explained that 
such a framework would encourage interconnection customers that are not 
ready to proceed to withdraw from the interconnection queue earlier in 
the study process while also providing them the flexibility to enter 
and remain in the interconnection queue without an off-take agreement; 
reduce the number of times an interconnection customer executes and 
suspends an LGIA for a speculative interconnection request, only to 
later withdraw the request, leading to the shifting of network upgrade 
costs to lower-queued interconnection customers; and reduce the strain 
on transmission providers and enable viable interconnection requests to 
progress more quickly through a less congested interconnection queue, 
thereby remedying the unjust and unreasonable Commission-jurisdictional 
rates discussed in section II of this final rule.
---------------------------------------------------------------------------

    \1208\ NOPR, 179 FERC ] 61,194 at P 128.
---------------------------------------------------------------------------

    614. Therefore, the Commission proposed to establish the defined 
terms ``commercial readiness demonstration \1209\ and ``commercial 
readiness deposit'' \1210\ in the pro forma LGIP.\1211\ The Commission 
also proposed to add to sections 3.4.2, 7.5, and 8.1 of the pro forma 
LGIP the following options as acceptable forms of commercial readiness 
demonstration to enter into the cluster study and cluster restudy:
---------------------------------------------------------------------------

    \1209\ The Commission proposed to revise section 1 of the pro 
forma LGIP to provide that commercial readiness demonstration shall 
have the meaning set forth in sections 3.4.2, 7.5, and 8.1 of the 
pro forma LGIP. Id. P 129 n.204.
    \1210\ The Commission proposed to revise section 1 of the pro 
forma LGIP to provide that commercial readiness deposit shall mean a 
deposit paid in lieu of submitting a commercial readiness 
demonstration, as set forth in sections 3.4.2, 7.5, and 8.1 of the 
pro forma LGIP. Id. P 129 n.205.
    \1211\ Id. P 129.
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     An executed term sheet (or comparable evidence) related to 
a contract, binding upon the parties to the contract, for sale of (1) 
the constructed generating facility, (2) the generating facility's 
energy or capacity, or (3) the generating facility's ancillary 
services; where the term of sale is not less than five years;
     Reasonable evidence that the generating facility has been 
selected in a resource plan or resource solicitation process by or for 
a load-serving entity (LSE), is being developed by an LSE, or is being 
developed for purposes of a sale to a commercial, industrial, or other 
large end-use customer; or
     A provisional LGIA which has been filed at the Commission 
(executed or unexecuted), which is not suspended and includes a 
commitment to construct the generating facility.
    615. The Commission also proposed to add to section 8.1 of the pro 
forma LGIP the following options to serve as forms of commercial 
readiness demonstration to enter the facilities study, to be provided 
with the executed facilities study agreement:
     An executed contract (as opposed to a term sheet), binding 
upon the parties to the contract, for sale of (1) the constructed 
generating facility, (2) the generating facility's energy or capacity, 
or (3) the generating facility's ancillary services; where the term of 
sale is not less than five years;
     Reasonable evidence that the generating facility has been 
selected in a resource plan or resource solicitation process by or for 
an LSE, is being developed by an LSE, or is being developed for 
purposes of a sale to a commercial, industrial, or other large end-use 
customer; or
     A provisional LGIA accepted for filing by the Commission, 
which is not suspended, with reasonable evidence that the generating 
facility and interconnection facilities have commenced design and 
engineering.\1212\
---------------------------------------------------------------------------

    \1212\ Id. P 130.
---------------------------------------------------------------------------

    616. The Commission also proposed to require the interconnection 
customer to inform the transmission provider of any material change to 
its commercial readiness demonstration. The Commission proposed to 
require the transmission provider to give the interconnection customer 
10 business days to demonstrate satisfaction with the applicable 
requirement after notification of a change to the interconnection 
request's commercial readiness demonstration.\1213\ The Commission 
explained that the interconnection customer would have the option to 
submit a commercial readiness deposit within the 10-day cure period if 
the change to the commercial readiness demonstration meant that the 
interconnection request no longer satisfied the criteria.
---------------------------------------------------------------------------

    \1213\ Id. P 131.
---------------------------------------------------------------------------

    617. The Commission preliminarily concluded that this approach was 
appropriate for all transmission providers and therefore proposed to 
allow interconnection customers the option to submit a commercial 
readiness deposit, in lieu of demonstrating commercial readiness 
through the commercial readiness demonstration options required to 
enter a cluster study, cluster restudy, and facilities study.\1214\ The 
Commission noted that, outside of RTOs/ISOs, transmission providers may 
be able to provide certain contractual arrangements to their own 
generating facilities or other preferred interconnection customers, 
such as the term sheet option noted above, which could lead to unduly 
discriminatory behavior. The Commission stated that this deposit in 
lieu of demonstrating commercial readiness may potentially prevent any 
undue discrimination in the generator interconnection process, 
consistent with the adoption of a standard set of procedures in the 
first instance.\1215\
---------------------------------------------------------------------------

    \1214\ Id. P 132.
    \1215\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 1-2).
---------------------------------------------------------------------------

    618. The Commission proposed to revise the pro forma LGIP to 
include a framework to allow interconnection customers to provide a 
commercial readiness deposit in lieu of meeting commercial readiness 
requirements in the following amounts:
     Two times the study deposit amount to enter the initial 
cluster study phase;
     Five times the study deposit amount after the initial 
cluster study phase and before the system impact restudy phase; and
     Seven times the study deposit amount after receipt of the 
facilities study agreement.\1216\
---------------------------------------------------------------------------

    \1216\ Id. P 133.
---------------------------------------------------------------------------

    619. The Commission clarified that the proposed commercial 
readiness deposit is separate from the study deposit.\1217\ The 
Commission stated that the commercial readiness deposit would be 
returned if the interconnection customer later makes a commercial 
readiness demonstration. If the interconnection customer withdraws from 
the interconnection queue, the Commission proposed that the commercial 
readiness deposit would be applied toward any incurred withdrawal 
penalties.
---------------------------------------------------------------------------

    \1217\ Id. P 134.
---------------------------------------------------------------------------

    620. Additionally, the Commission proposed revisions to the list of 
development milestones in section 11.3 of the pro forma LGIP to clarify 
the following:
     A contract for the supply or transportation of fuel and a 
contract for the supply of cooling water will not be accepted for wind, 
storage, or solar photovoltaic resources;
     Comparable evidence of a contract for the sale of energy 
or capacity will be accepted; and
     Any of the commercial readiness demonstration options 
accepted to enter

[[Page 61104]]

the facilities study will be accepted along with the executed LGIA or 
within 15 days of the Commission issuing an order on the unexecuted 
LGIA filing, while a commercial readiness deposit will not be 
accepted.\1218\
---------------------------------------------------------------------------

    \1218\ Id. P 135.
---------------------------------------------------------------------------

    621. The Commission preliminarily found that this framework would 
allow interconnection customers to calculate the exact deposit that 
would be required prior to entering the interconnection queue, as it is 
based on multiples of the study deposit, and the study deposit is based 
on the size of the proposed generating facility, as chosen by the 
interconnection customer, leading to predictability in the deposit 
amount.\1219\ The Commission explained that this increased transparency 
in the deposit amount early in the interconnection process would 
discourage speculative interconnection requests from entering the 
interconnection queue.
---------------------------------------------------------------------------

    \1219\ Id. P 136.
---------------------------------------------------------------------------

    622. The Commission sought comment on whether the Commission should 
also establish, as other alternative demonstrations of commercial 
readiness, evidence of a commitment to participate in RTO/ISO markets, 
a site-specific purchase order for generating equipment specific to the 
interconnection request, or a statement signed by an officer or 
authorized agent of the interconnection customer attesting that the 
generating facility is to be supplied with major electric generating 
components (such as wind turbines) with a manufacturer's blanket 
purchase agreement to which the interconnection customer is a 
party.\1220\
---------------------------------------------------------------------------

    \1220\ Id. P 137.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    623. Several commenters support the commercial readiness framework 
because they believe that it will reduce the submission of exploratory 
or speculative interconnection requests.\1221\ These commenters argue 
that requiring financial commitments and commercial readiness 
requirements early in the interconnection process, as the Commission 
proposed, is important to more efficiently allocate transmission 
provider resources to generating facilities that are more likely to 
achieve commercial operation and to enhance the certainty of 
interconnection study results, benefiting all interconnection 
customers. Pacific Northwest Utilities similarly assert that requiring 
commercial readiness at an appropriate point in the cluster study 
process minimizes the cost and inefficiency risk of restudies and 
increases the probability that planned network upgrades will be funded 
and constructed.\1222\ Navajo Utility also supports the Commission's 
use of the commercial readiness requirements to discourage speculative 
interconnection requests from slowing the interconnection 
process.\1223\
---------------------------------------------------------------------------

    \1221\ APPA-LPPC Reply Comments at 5; Avangrid Initial Comments 
at 9; Consumer Energy Initial Comments at 5; EEI Initial Comments at 
6-7; EEI Reply Comments at 5; NERC Initial Comments at 26; Google 
Initial Comments at 20; Idaho Power Initial Comments at 7; MISO TOs 
Initial Comments at 28-29; NARUC Initial Comments at 10; NESCOE 
Initial Comments at 13; North Carolina Commission and Staff Initial 
Comments at 26; Ohio Commission Consumer Advocate Initial Comments 
at 12; Omaha Public Power Initial Comments at 9; Pacific Northwest 
Utilities Initial Comments at 3, 6; Pennsylvania Commission Initial 
Comments at 14; U.S. Chamber of Commerce Initial Comments at 9; UMPA 
Initial Comments at 5; Xcel Reply Comments at 6-10.
    \1222\ Pacific Northwest Utilities Initial Comments at 6.
    \1223\ Navajo Utility Initial Comments at 10.
---------------------------------------------------------------------------

    624. Navajo Utility explains that, as an LSE that constructs 
generating facilities for the benefit of the Navajo Nation and to 
export clean energy to surrounding LSEs, it specifically supports the 
second criterion related to generating facilities developed by an 
LSE.\1224\ NRECA contends that the proposed commercial readiness 
demonstration requirements protect generating facilities that have been 
committed to serve load from being hindered by interconnection requests 
for generating facilities that are still looking for off-takers, 
thereby helping reduce the pressure on transmission provider 
interconnection queues.\1225\
---------------------------------------------------------------------------

    \1224\ Id. at 10-11.
    \1225\ NRECA Initial Comments at 29.
---------------------------------------------------------------------------

    625. APPA-LPPC note that there may be power purchase agreements, 
asset sales agreements and competitive procurement programs that 
currently contemplate full knowledge of interconnection costs before 
deals may be finalized.\1226\ However, APPA-LPPC argue that there is 
nothing inevitable about the structure and sequencing of these 
arrangements. APPA-LPPC state that, assuming the Commission moves ahead 
with a commercial readiness requirement, it is not hard to envision 
revisions to standard form power purchase agreements, asset sales 
agreements, and bids into power procurement programs that are 
contingent on specified assumptions regarding interconnection costs. 
APPA-LPPC contend that with improvements in the availability of 
interconnection costs, along with much-needed stability in the 
interconnection queues, it is reasonable to expect that interconnection 
costs will be substantially more predictable than is now the case.
---------------------------------------------------------------------------

    \1226\ APPA-LPPC Reply Comments at 5.
---------------------------------------------------------------------------

    626. SoCal Edison supports the proposals to require the 
interconnection customer to notify the transmission provider of any 
material change to its commercial readiness demonstration and to 
require the transmission provider to give the interconnection customer 
10 business days to cure the commercial readiness deficiency.\1227\
---------------------------------------------------------------------------

    \1227\ SoCal Edison Initial Comments at 9.
---------------------------------------------------------------------------

(b) Comments in Opposition
    627. Several commenters argue that the NOPR proposal is 
inconsistent with prevailing commercial practices (especially those in 
RTOs/ISOs), sets unreasonable standards for off-take agreements, and 
ignores the commercial reality of the competitive solicitation process, 
which could create an undue preference for self-build options in areas 
that rely on competitive solicitations and undue discrimination against 
merchant developers, thereby subverting competition in wholesale power 
markets.\1228\ Some commenters contend that the proposed commercial 
readiness demonstration options are heavily weighted in favor of 
incumbent utility practices, such as evidence of a power purchase 
agreement or executed term sheet or evidence that a project has been 
selected in a resource plan or resource solicitation process by an 
LSE.\1229\
---------------------------------------------------------------------------

    \1228\ ACORE Reply Comments at 4; AEE Initial Comments at 20; 
AEE Reply Comments at 12; Alliant Energy Initial Comments at 5-6; 
Clean Energy Associations Initial Comments at 34-35; Clean Energy 
Associations Reply Comments at 4-6; CREA and NewSun Initial Comments 
at 57; CREA and NewSun Reply Comments at 22-45; Cypress Creek 
Initial Comments at 22-23; Enel Initial Comments at 44; ENGIE 
Initial Comments at 5; ENGIE Reply Comments at 2-3; EPSA Initial 
Comments at 9; Fervo Energy Reply Comments at 6-7; New Jersey 
Commission Reply Comments at 6-8; NextEra Initial Comments at 24; 
Pine Gate Initial Comments at 27; NextEra Reply Comments at 14-16; 
Public Interest Organizations Initial Comments at 29-30; R Street 
Initial Comments at 13; SEIA Initial Comments at 25; Vistra Initial 
Comments at 6.
    \1229\ EPSA Initial Comments at 9; R Street Initial Comments at 
13.
---------------------------------------------------------------------------

    628. Enel argues that ratepayers and off-takers benefit from 
generating facilities being selected in competitive processes that 
consider both a generating facility's inherent characteristics and its 
interconnection costs and schedule, which cannot be done if off-take 
arrangements are made prior to applying for interconnection 
service.\1230\ NextEra asserts that being part of the interconnection 
queue is an essential step in the competitive

[[Page 61105]]

process,\1231\ and Public Interest Organizations note that utilities 
conducting RFPs for their resource plans often require at least a 
position in an interconnection queue as a precondition of 
offering.\1232\ Cypress Creek argues that commercial readiness 
demonstrations should not apply until an interconnection customer 
receives the results from the proposed initial cluster study, which may 
be required to bid into a resource solicitation.\1233\ Cypress Creek 
contends that it is impractical to include the proposed demonstration 
requirements at early stages in the interconnection study process and 
that this construct is not workable in markets where merchant sales are 
common.
---------------------------------------------------------------------------

    \1230\ Enel Initial Comments at 44.
    \1231\ NextEra Initial Comments at 24.
    \1232\ Public Interest Organizations Initial Comments at 29.
    \1233\ Cypress Creek Initial Comments at 22-23.
---------------------------------------------------------------------------

    629. Enel, NextEra, and Public Interest Organizations argue that 
precluding entry into the interconnection queue due to lack of a 
demonstration of commercial readiness would be an anticompetitive 
measure favoring entities, such as incumbent transmission providers, 
that could favor their own proposed generating facilities ahead of 
others because of their enhanced ability to demonstrate their proposed 
generating facilities as commercially ready.\1234\ For instance, CREA 
and NewSun assert that, unlike independent power producers, an 
incumbent, vertically integrated utility can easily meet the second 
prong of the readiness criteria to enter the interconnection queue and 
proceed to the facilities study by simply identifying its preferred 
resource in its own resource plan, selecting it as the winning bid in 
its own utility-run RFP, or just attesting that the utility is 
``developing'' the generating facility.\1235\
---------------------------------------------------------------------------

    \1234\ Enel Initial Comments at 44; NextEra Initial Comments at 
24; Public Interest Organizations Initial Comments at 29.
    \1235\ CREA and NewSun Initial Comments at 66 (citing NOPR, 179 
FERC ] 61,194 at PP 129, 130).
---------------------------------------------------------------------------

    630. CREA and NewSun claim that the commercial readiness proposal 
would drive most, if not all, independent power producers from the 
market, which would raise costs to consumers by eliminating competition 
and innovation.\1236\ SEIA asserts that by proposing a commercial 
readiness demonstration framework that is nearly impossible for 
independent power producers to meet, the Commission is incorrectly 
implying that generating facilities developed by independent power 
producers are inherently not commercially viable.\1237\ SEIA emphasizes 
that independent power producers play a critical role in bringing 
robust competition to markets by driving innovation and decreasing the 
cost of providing power.\1238\
---------------------------------------------------------------------------

    \1236\ Id. at 57.
    \1237\ SEIA Initial Comments at 16, 25.
    \1238\ Id. at 25.
---------------------------------------------------------------------------

    631. Alliant Energy claims that requiring demonstration of 
commercial readiness prior to an interconnection customer entering the 
interconnection queue may do more harm than good.\1239\ Alliant Energy 
argues that the commercial viability of a proposed generating facility 
depends heavily on the costs of network upgrades and interconnection 
facilities required to accommodate a generating facility's 
interconnection, which cannot be known prior to a generating facility 
receiving cost estimates that are dependable and enable interconnection 
customers to make decisions during the interconnection process.
---------------------------------------------------------------------------

    \1239\ Alliant Energy Initial Comments at 5-6.
---------------------------------------------------------------------------

    632. Vistra argues that the proposed increase in study deposits, 
withdrawal penalties, and exclusive site control requirements will 
significantly reduce the number of speculative interconnection requests 
entering the interconnection queue, making the commercial readiness 
proposal redundant.\1240\ Vistra notes that the Commission has relied 
on fact-specific showings to accept requirements to demonstrate 
commercial readiness thus far, and Vistra argues that the fact that the 
Commission has accepted a transmission provider's revised LGIP under 
FPA section 205 does not establish that the pro forma LGIP is unjust 
and unreasonable without the commercial readiness proposal.\1241\
---------------------------------------------------------------------------

    \1240\ Vistra Initial Comments at 6.
    \1241\ Id. at 6, 8.
---------------------------------------------------------------------------

    633. Vistra states that, beyond simple timing concerns, procurement 
decisions and eligibility to enter the interconnection queue are 
interrelated in a way that creates a chicken-and-egg problem.\1242\ 
Vistra explains that it is difficult for a generating facility to be 
shortlisted for procurement without line of sight to obtaining a signed 
interconnection agreement because the signed interconnection agreement 
brings more certainty to the generating facility's commercial operation 
date. Vistra expresses concern that the Commission's proposal to 
require an executed term sheet to enter the interconnection queue and 
an executed contract to enter the facilities study process will simply 
shift the burden of this chicken-and-egg problem to the procurement 
process. Vistra asserts that the status quo appropriately balances the 
inherent difficulty of coordinating procurement and interconnection.
---------------------------------------------------------------------------

    \1242\ Id. at 9.
---------------------------------------------------------------------------

    634. Invenergy argues that the proposed requirements are 
inappropriate and should not be applied nationally because they are 
based on a small subset of transmission providers that have adopted 
``readiness'' requirements with little evidence that they are 
effective, given the continuing interconnection queue reform efforts in 
some of those same regions.\1243\ Invenergy adds that, if additional 
assurance of an interconnection customer's intent to pursue its 
interconnection request is needed, the Commission should consider a 
requirement to post a certain amount of security that becomes 
increasingly at risk to move through the interconnection queue, as is 
done in some RTO/ISO regions.
---------------------------------------------------------------------------

    \1243\ Invenergy Initial Comments at 11-12.
---------------------------------------------------------------------------

    635. NextEra asserts that generating facilities may be fully viable 
based on criteria that are different from what the NOPR proposes. For 
example, NextEra states that it is possible that storage or other types 
of generating facilities entering the market will not require power 
purchase agreements or designation as network resources to be 
commercially viable.\1244\
---------------------------------------------------------------------------

    \1244\ NextEra Initial Comments at 24.
---------------------------------------------------------------------------

    636. R Street argues that a key to efficient generating facility 
development is to enable parallel work flows.\1245\ R Street claims 
that, by imposing extensive prerequisites to advance in the 
interconnection process, commercial readiness requirements would 
introduce greater process dependencies in generating facility 
development. R Street adds that granting non-RTO/ISO transmission 
providers discretion over commercial readiness requirements could lead 
to discriminatory behavior (e.g., non-RTO/ISO transmission providers 
withholding off-take contracts to discriminate against other potential 
suppliers).
---------------------------------------------------------------------------

    \1245\ R Street Initial Comments at 13.
---------------------------------------------------------------------------

    637. MISO states that it is concerned about the utility and impacts 
of the proposed commercial readiness framework.\1246\ MISO explains 
that interconnection customers with commitments from off-takers can be 
commercially unready and often cause the greatest interconnection queue 
disruption by lingering the longest in the queue. As an example, MISO 
posits a proposed generating facility that would be commercially viable 
provided it does not incur network upgrade costs

[[Page 61106]]

in excess of $5 million dollars. MISO argues that such a generating 
facility is likely to remain in the interconnection queue despite not 
having a viable business case, in the hopes that other interconnection 
customers will withdraw their requests and costs will decrease. MISO 
asserts that, to indicate commercial readiness, a term sheet or 
contract would need to show not only that there was an off-taker but 
also that the projected income for the proposed generating facility is 
sufficient to render the generating facility commercially viable, given 
estimated study and network upgrade costs, which would be exceedingly 
difficult to require from interconnection customers and nearly 
impossible for a transmission provider to evaluate and verify.
---------------------------------------------------------------------------

    \1246\ MISO Initial Comments at 62-63.
---------------------------------------------------------------------------

    638. Anbaric claims that the proposed core readiness requirements 
do not align with the development trajectory of planned transmission 
projects for offshore wind generation.\1247\
---------------------------------------------------------------------------

    \1247\ Anbaric Initial Comments at 15-16.
---------------------------------------------------------------------------

    639. NextEra asserts that commercial readiness requirements at the 
interconnection request stage are inappropriate.\1248\ NextEra explains 
that interconnection customers do not have a simple test for 
distinguishing speculative interconnection requests from other 
interconnection requests. Rather, NextEra continues, successful 
generating facility development depends on whether the interconnection 
customer concludes that the interconnection arrangement is acceptable 
and whether the generating facility's location and costs are agreeable 
to its customers.
---------------------------------------------------------------------------

    \1248\ NextEra Initial Comments at 23-24.
---------------------------------------------------------------------------

    640. NextEra also argues that meeting any readiness milestones 
after the submission of an interconnection request (e.g., when entering 
the facilities study phase) should be premised on the interconnection 
customer having received timely and accurate study results, including 
from affected systems.\1249\ NextEra asserts that it is not just and 
reasonable to impose increasingly strict requirements on 
interconnection customers without devising means of accelerating 
interconnection queue processing by transmission providers and ensuring 
transmission providers comply with their tariffs.
---------------------------------------------------------------------------

    \1249\ Id. at 25.
---------------------------------------------------------------------------

    641. Longroad recommends that the Commission clearly tie the 
interconnection customer's commitment to pay for network upgrades to a 
security deposit applied toward the costs thereof during the cluster 
study phases, and that the security deposits for network upgrades 
progressively increase at each stage of the cluster study 
process.\1250\ Longroad asserts that in the initial cluster study, the 
security deposit should be a modest percentage of the allocated network 
upgrade cost and increase to, for example, 25% of the network upgrade 
cost allocation to enter the facilities study. Longroad contends that 
the interconnection customer should have the option to either fully 
fund the network upgrade as a milestone in the LGIA or to fund in 
advance the transmission provider's estimated quarterly spending 
towards engineering, procurement, and construction of the network 
upgrades.
---------------------------------------------------------------------------

    \1250\ Longroad Reply Comments at 13.
---------------------------------------------------------------------------

(c) Comments on Specific Proposals
(1) Proposed Readiness Demonstrations
    642. Commenters raise significant issues with the readiness 
demonstration options proposed in the NOPR. With respect to the first 
proposed readiness demonstration option,\1251\ commenters argue that 
providing power purchase agreements or term sheets will be unworkable 
for most interconnection customers, particularly merchant developers, 
because: (1) developers do not have sufficient information about 
interconnection costs to move forward with a term sheet or power 
purchase agreement at the time they enter into the interconnection 
study process; and (2) the proposals to make more information available 
to interconnection customers prior to submitting an interconnection 
request will not provide sufficiently granular or certain information 
to overcome this barrier.\1252\
---------------------------------------------------------------------------

    \1251\ Executed term sheet (or comparable evidence) related to a 
contract for sale of (1) the constructed generating facility to a 
load-serving entity or to a commercial, industrial, or other large 
end-use customer, (2) the generating facility's energy or capacity 
where the term of sale is not less than five (5) years, or (3) the 
generating facility's ancillary services where the term of sale is 
not less than five (5) years.
    \1252\ AEE Initial Comments at 21; AES Clean Energy Initial 
Comments at 16; CAISO Initial Comments at 18; CESA Initial Comments 
at 10; CESA Reply Comments at 6; Clean Energy Associations Initial 
Comments at 37; ClearPath Initial Comments at 8; CREA and NewSun 
Initial Comments at 57-58; New Jersey Commission Reply Comments at 
6-7; Enel Initial Comments at 42-43; Invenergy Initial Comments at 
13-15; Invenergy Reply Comments at 1-5; Fervo Energy Initial 
Comments at 5; Longroad Energy Reply Comments at 17; SEIA Initial 
Comments at 17; SEIA Reply Comments at 7-9; Shell Reply Comments at 
20-21; Longroad Energy Initial Comments at 15-16; Omaha Public Power 
Initial Comments at 8-9; R Street Initial Comments at 13; Shell 
Initial Comments 13-15; Vistra Initial Comments at 8, 10.
---------------------------------------------------------------------------

    643. Commenters further note that the vast majority of power 
purchasers seek generating facilities with advanced interconnection 
queue positions (with preference for a finalized LGIA or SGIA) before 
signing a power purchase agreement or finalizing a state 
procurement.\1253\ CREA and NewSun, as well as SEIA, argue that a 
contract for provision of ancillary services, is almost entirely 
foreclosed to many non-synchronous generating facilities because nearly 
every transmission provider bars non-synchronous generating facilities 
from providing ancillary services, either explicitly or through 
operating requirements.\1254\
---------------------------------------------------------------------------

    \1253\ Invenergy Initial Comments at 13; Northwest and 
Intermountain Initial Comments at 9; Public Interest Organizations 
Initial Comments at 28.
    \1254\ CREA and NewSun Initial Comments at 62; SEIA Initial 
Comments at 17.
---------------------------------------------------------------------------

    644. Commenters also assert that, if independent power producers 
are forced to enter into contracts before costs are certain, then they 
would need to incorporate that uncertainty into the power purchase 
agreement offer, which would drive up the costs of these contracts, 
resulting in higher consumer costs.\1255\ Commenters contend that, if 
the independent power producer does not reflect the costs of the 
network upgrades in its power purchase agreement price, either the 
independent power producer or the consumer may attempt to break the 
contract, which would lead to increased contractual litigation.\1256\ 
Vistra adds that the purchaser will then need to start the procurement 
process over or choose to over-procure as insurance against potential 
contract termination, to the detriment of reliability and cost.\1257\
---------------------------------------------------------------------------

    \1255\ CREA and NewSun Initial Comments at 57; Clean Energy 
Associations Initial Comments at 37; SEIA Initial Comments at 17; 
SoCal Edison Initial Comments at 8; Vistra Initial Comments at 9-10.
    \1256\ AEE Initial Comments at 21; Longroad Energy Initial 
Comments at 15; SEIA Initial Comments at 17; Vistra Initial Comments 
at 10.
    \1257\ Vistra Initial Comments at 10.
---------------------------------------------------------------------------

    645. SoCal Edison argues that, in some regions, an executed 
contract option for entering the facilities study could unintentionally 
encourage LSEs to sign contracts with developers for more energy or 
capacity than they need to secure resources to meet their procurement 
targets.\1258\ SoCal Edison contends that competition in certain areas 
for particular generation resources may be high, which may force other 
LSEs to prematurely enter into contracts with developers to secure 
generation without the benefit of the facilities study, which is 
currently relied on by LSEs to assess commercial viability of a 
generating facility before contracts are signed. AEE asserts that 
customers may ultimately bear the cost of the selection of generating 
facilities that may not be the least cost options in the market but

[[Page 61107]]

are able to execute a term sheet or power purchase agreement regardless 
of the ultimate level of interconnection costs.\1259\
---------------------------------------------------------------------------

    \1258\ SoCal Edison Initial Comments at 7-8.
    \1259\ AEE Initial Comments at 21.
---------------------------------------------------------------------------

    646. Commenters also assert that it is unreasonable to expect that 
a buyer and seller will be able to finalize negotiation of a contract 
between the time of the cluster restudy (or amendment of the restudy if 
additional interconnection customers withdraw upon receipt of the 
restudy results) and the time the facilities study agreement must be 
executed.\1260\
---------------------------------------------------------------------------

    \1260\ CREA and NewSun Initial Comments at 62; Longroad Energy 
Initial Comments at 16; SEIA Initial Comments at 17.
---------------------------------------------------------------------------

    647. CAISO requests that the Commission describe in detail what 
would constitute a term sheet.\1261\ CAISO states that in its 
experience with similar tariff provisions, interconnection customers 
frequently try to submit questionable or even misleading documentation 
to meet the tariff requirements.
---------------------------------------------------------------------------

    \1261\ CAISO Initial Comments at 20.
---------------------------------------------------------------------------

    648. Invenergy argues that, to the extent an off-take agreement or 
term sheet remains an option to demonstrate readiness, the Commission 
should clarify that transmission providers are not entitled or even 
permitted to review the commercial terms of the term sheet or 
agreement, which may be confidential and is not subject to the 
transmission provider's discretion.\1262\
---------------------------------------------------------------------------

    \1262\ Invenergy Initial Comments at 18.
---------------------------------------------------------------------------

    649. GSCE does not dispute that readiness requirements are 
important but argues that basing them on contracting status is 
misguided for the following reasons: (1) it does not focus on early-
stage developmental steps that drive generating facility viability and 
indicate true commercial readiness; (2) it provides incentives for 
interconnection customers that have not taken concrete steps toward 
readiness to bid low in competitive solicitations, creating fictional 
``contracted'' capacity that may never prove viable; (3) the 
contracting landscape is evolving, and long-term contracting is no 
longer required for successful project financing or the emerging 
realities of capital markets, and with the inflationary environment, 
long-term contracts may currently be harder to finance than short-term 
contracts; and (4) a focus on contracting to enter the interconnection 
study process forces commercial negotiations to occur before generating 
facilities are studied and have sufficient cost certainty or 
development timeline assurances.\1263\
---------------------------------------------------------------------------

    \1263\ GSCE Initial Comments at 8-9.
---------------------------------------------------------------------------

    650. Commenters also point to significant issues with the second 
proposed readiness demonstration option.\1264\ They argue that 
requiring evidence that a proposed generating facility is ``selected in 
a resource plan or resource solicitation plan by or for [an LSE], is 
being developed by [an LSE], or is being developed for purposes of a 
sale to a commercial, industrial, or other a large end-use customer'' 
is discriminatory and preferential without cause or reasonable 
support.\1265\
---------------------------------------------------------------------------

    \1264\ Reasonable evidence that the generating facility has been 
selected in a resource plan or resource solicitation process by or 
for an LSE, is being developed by an LSE, or is being developed for 
purposes of a sale to a commercial, industrial, or other large end-
use customer.
    \1265\ AEE Initial Comments at 23; Clean Energy Associations 
Initial Comments at 35; CREA and NewSun Initial Comments at 58-70; 
EPSA Initial Comments at 9; Interwest Initial Comments at 19-20; 
SEIA Initial Comments at 18; Shell Initial Comments at 16.
---------------------------------------------------------------------------

    651. Several commenters argue that the option for interconnection 
customers to demonstrate commercial readiness by showing that the 
generating facility is being developed for purposes of a sale to an 
end-use customer suffers a timing challenge because it is nearly 
impossible for the independent power producer to price a sales contract 
to a retail customer, or the customer having much interest in 
discussing the transaction, without having reasonable certainty as to 
the generating facility's likely interconnection costs.\1266\
---------------------------------------------------------------------------

    \1266\ AEE Initial Comments at 22-23; CREA and NewSun Initial 
Comments at 59; SEIA Initial Comments at 19-20; Shell Initial 
Comments at 14; Vistra Initial Comments at 6.
---------------------------------------------------------------------------

    652. SoCal Edison recommends that the Commission clarify or give 
additional examples of reasonable evidence that a proposed generating 
facility has been selected in an LSE's resource solicitation process or 
allow a transmission provider to determine how this option can be 
met.\1267\ SoCal Edison states that evidence that a proposed generating 
facility has been short-listed in an LSE request for offer should be 
considered reasonable evidence for moving into the facilities study.
---------------------------------------------------------------------------

    \1267\ SoCal Edison Initial Comments at 8.
---------------------------------------------------------------------------

    653. Several commenters argue that the third readiness 
demonstration option, a provisional LGIA,\1268\ is likely unworkable as 
well because it would require independent power producers to assume 
almost all the risk of the network upgrade costs without knowing those 
costs.\1269\ On the other hand, CAISO asserts that interconnection 
customers could escape financial consequences and bypass the NOPR's 
requirements through the provisional LGIA option.\1270\ CAISO argues 
that, at a minimum, the Commission should allow transmission providers 
to provide the provisional LGIA option where they believe it will work, 
but not require all transmission providers to enable interconnection 
customers to bypass commercial readiness through provisional LGIAs.
---------------------------------------------------------------------------

    \1268\ A provisional LGIA that has been filed at the Commission 
executed, or requested to be filed unexecuted, which is not in 
suspension pursuant to article 5.16 of the LGIA, and includes a 
commitment to construct the generating facility.
    \1269\ AEE Initial Comments at 23-24; CREA and NewSun Initial 
Comments at 59-63; SEIA Initial Comments at 20-23.
    \1270\ CAISO Initial Comments at 20-21.
---------------------------------------------------------------------------

    654. SoCal Edison and CAISO recommend that the Commission provide 
additional guidance on, or more clearly define, the term ``provisional 
LGIA.'' \1271\ CAISO also states that it is unclear how interconnection 
customers that have yet to be studied could submit provisional LGIAs 
because LGIAs describe the network upgrades and facilities from 
interconnection studies.\1272\ CAISO states that interconnection 
customers are likely to request provisional LGIAs because demonstrating 
commercial readiness in RTOs/ISOs is generally impossible until after 
studies are complete.
---------------------------------------------------------------------------

    \1271\ SoCal Edison Initial Comments at 8; CAISO Initial 
Comments at 20.
    \1272\ CAISO Initial Comments at 20.
---------------------------------------------------------------------------

    655. Commenters claim that the record does not support adopting the 
proposed commercial readiness framework within RTOs/ISOs, arguing that 
it would be unreasonable and unduly discriminatory.\1273\ These 
commenters argue that the record in RTOs/ISOs does not support the 
NOPR's assertion that generating facilities are generally not 
constructed without some form of off-take agreement. They assert that 
the commercial readiness criteria should not be required at all in RTO/
ISO regions (with locational marginal price-based markets), where 
generating facilities can move forward in many cases without a specific 
off-taker. Some commenters also argue that an RTO/ISO should not have 
to evaluate contracts for the sale of a generating facility's output or 
determine whether the generating facility has been selected in a 
resource plan or resource solicitation process in

[[Page 61108]]

any of the potentially multiple states within its footprint.\1274\
---------------------------------------------------------------------------

    \1273\ ACE-NY Initial Comments at 6-7; AEE Initial Comments at 
22; AES Clean Energy Initial Comments at 16-17; CESA Initial 
Comments at 9-10; Clean Energy Associations Initial Comments at 38; 
PJM Initial Comments at 33-34; Public Interest Organizations Initial 
Comments at 28-29; SEIA Initial Comments at 23-24.
    \1274\ MISO Initial Comments at 63; MISO TOs Initial Comments at 
29; PJM Initial Comments at 33.
---------------------------------------------------------------------------

    656. Commenters argue that the proposed 10-business day cure period 
to resolve potential commercial readiness deficiencies is insufficient 
given the complicated business and technical decisions involved.\1275\ 
Invenergy states the interconnection process often extends for several 
years and it is entirely possible that commercial arrangements may 
change during that time.\1276\ Invenergy states that these changes may 
require additional negotiations, but should not call into question the 
customer's commitment to developing its project and risk being 
withdrawn from the interconnection queue. [Oslash]rsted requests a 30-
business day cure period instead.\1277\
---------------------------------------------------------------------------

    \1275\ Invenergy Initial Comments at 21; [Oslash]rsted Initial 
Comments at 13.
    \1276\ Invenergy Initial Comments at 21.
    \1277\ [Oslash]rsted Initial Comments at 13.
---------------------------------------------------------------------------

(2) Alternative Commercial Readiness Demonstrations
    657. Some commenters argue that the Commission should consider 
expanding this list of proposed criteria to include other 
demonstrations of commercial readiness, such as completion of 
environmental, local, state, or Federal permitting processes.\1278\ 
CREA and NewSun, as well as Northwest and Intermountain, ask the 
Commission to provide QFs a more relaxed readiness option than a fully 
executed power purchase agreement, especially when a transmission 
provider requires qualifying facilities to have a completed 
interconnection study result to obtain a draft power purchase agreement 
under its state Public Utility Regulatory Policies Act (PURPA) 
implementation programs (e.g., PacifiCorp).\1279\ CREA and NewSun 
suggest that the Commission could allow QFs to submit an affidavit from 
the interconnection customer, stating that the avoided cost rates 
offered are sufficient to finance and bring the QF into commercial 
operation if interconnection can be obtained.\1280\ CREA and NewSun 
contend that this option is consistent with the Commission's obligation 
to adopt regulations that encourage development of QFs.
---------------------------------------------------------------------------

    \1278\ ClearPath Initial Comments at 9; CREA and NewSun Initial 
Comments at 71; Enel Initial Comments at 47; Longroad Energy Initial 
Comments at 17; Northwest and Intermountain Initial Comments at 11; 
Vistra Initial Comments at 11.
    \1279\ CREA and NewSun Initial Comments at 72-73; Northwest and 
Intermountain Initial Comments at 11.
    \1280\ CREA and NewSun Initial Comments at 73.
---------------------------------------------------------------------------

    658. Comments are mixed on the potential additional demonstrations 
of commercial readiness on which the Commission requested comment in 
the NOPR. Several commenters support the three potential other 
readiness options suggested in the NOPR, or a combination 
thereof.\1281\
---------------------------------------------------------------------------

    \1281\ Id. at 70-71; APS Initial Comments at 15; NERC Initial 
Comments at 26-27; ENGIE Initial Comments at 5-6; Clean Energy 
Associations Initial Comments at 39; Invenergy Initial Comments at 
16-17; NESCOE Initial Comments at 13; NextEra Initial Comments at 
25; Pattern Energy Initial Comments at 31-32; R Street Initial 
Comments at 13; SEIA Initial Comments at 25; Tri-State Initial 
Comments at 15.
---------------------------------------------------------------------------

    659. Other commenters oppose the various alternative demonstration 
options. With regard to the first--evidence of a commitment to 
participate in RTO/ISO markets--several commenters argue that the 
proposal would be essentially meaningless because practically all 
interconnection requests would qualify.\1282\
---------------------------------------------------------------------------

    \1282\ Indicated PJM TOs Initial Comments at 31-32; PJM Initial 
Comments at 34.
---------------------------------------------------------------------------

    660. As for the second and third potential alternative 
demonstration options--a site specific purchase order for generating 
equipment specific to the interconnection request, or a statement 
signed by an officer or authorized agent of the interconnection 
customer attesting that the generating facility is to be supplied with 
major electric generating components (such as wind turbines) with a 
manufacturer's blanket purchase agreement to which the interconnection 
customer is a party--PacifiCorp and Ameren oppose these options.\1283\ 
PacifiCorp argues that, although it originally adopted a similar 
provision in its initial interconnection queue reform process, in the 
course of administering its first two cluster studies, it determined 
that this readiness option set a low hurdle that speculative 
interconnection requests could easily overcome.\1284\ Similarly, SPP 
does not support site-specific purchase orders or statements attesting 
to supply of major components as evidence of commercial 
readiness.\1285\ Enel asserts that it is inappropriate to require 
procurement of major power equipment prior to an interconnection 
request or, in many cases, even before executing an LGIA.\1286\ Enel 
contends that requiring procurement of specific generating equipment 
prior to applying for interconnection is detrimental to reliability 
because newer technologies procured after the execution of an LGIA 
often have advanced features that did not exist a few years earlier. 
Enel explains that it procures major wind, solar, and battery 
generation equipment between 12 and 24 months prior to energizing a new 
generating facility to the transmission system, typically after 
execution of an LGIA and a full investment review (including knowledge 
of interconnection costs and schedules) are complete. Enel adds that a 
generating facility without interconnection results carries too much 
risk for interconnection customers and investors to risk significant 
financial deposits to reserve site specific generation equipment. 
Similarly, Xcel states that interconnection customers want the 
flexibility to wait until the last minute to order equipment and start 
construction, which results in different equipment being ordered than 
initially expected.\1287\
---------------------------------------------------------------------------

    \1283\ Ameren Initial Comments at 17; PacifiCorp Initial 
Comments at 31.
    \1284\ PacifiCorp Initial Comments at 31.
    \1285\ SPP Initial Comments at 10.
    \1286\ Enel Initial Comments at 46.
    \1287\ Xcel Initial Comments at 33.
---------------------------------------------------------------------------

    661. Some commenters argue that the proposed commercial readiness 
requirements unduly discriminate against pumped storage projects, which 
often do not have the commercial pathways and timelines associated with 
other types of generating facilities.\1288\ Those commenters explain 
that the development of a pumped storage project is an iterative 
process of assessment and de-risking that takes several years to 
complete, at a cost of tens of millions of dollars. They suggest that 
achieving one of the following three criteria would be sufficient 
evidence of commercial readiness for a pumped storage project: (1) a 
filing of notice of intent to apply for an original license and pre-
application document with the Commission; (2) an executed memorandum of 
understanding, letter of intent, or an equivalent term sheet with a 
utility; or (3) selection of the project in an integrated resource plan 
(IRP) process. They add that, in lieu of having achieved one of these, 
a commercial readiness deposit of $2,000 per MW is appropriate. These 
commenters ask the Commission to add the receipt of a Commission 
license to the list of milestone developments in section 11.3 of the 
pro forma LGIP.
---------------------------------------------------------------------------

    \1288\ Hydropower Commenters Initial Comments at 9, 25-26; rPlus 
Initial Comments at 4.
---------------------------------------------------------------------------

    662. Commenters recommend several alternative bases to determine 
commercial readiness, including: (1) a 50% generator tie line site 
control requirement; \1289\ (2) a project development plan to determine 
readiness; \1290\ (3) documentation of developer due diligence, 
including

[[Page 61109]]

available transmission capacity and modeling; \1291\ (4) participating 
in and meeting the eligibility requirements for a state-mandated 
procurement program; \1292\ and (5) an executed firm point-to-point 
transmission service agreement from the proposed point of 
interconnection to a point of consumption for the generating facility's 
output.\1293\
---------------------------------------------------------------------------

    \1289\ Enel Initial Comments at 45.
    \1290\ Xcel Initial Comments at 33.
    \1291\ SEIA Initial Comments at 25.
    \1292\ SoCal Edison Initial Comments at 8.
    \1293\ Avangrid Initial Comments at 15.
---------------------------------------------------------------------------

    663. To address the Commission's concerns while maintaining the 
commercial viability of planned transmission projects for offshore 
wind, Anbaric asks the Commission to consider requiring such projects 
to make the following demonstrations to satisfy the commercial 
readiness requirements: (1) site control of property near the point of 
interconnection suitable for a converter station of a specified size 
(expressed in MWs) needed to enable high voltage direct current (HVDC) 
lines carrying offshore wind energy to be put onto the regional 
transmission system; (2) site control of a property at a coastline 
location suitable for the transition from seabed to terrestrial routes 
sufficient to move the specified amount of MWs identified in 
interconnection requests; and (3) a state procurement policy or goal to 
procure a defined amount of offshore wind generation associated with a 
planned transmission project within a defined time frame.\1294\
---------------------------------------------------------------------------

    \1294\ Anbaric Initial Comments at 17-18.
---------------------------------------------------------------------------

    664. Eversource supports the Commission's proposed commercial 
readiness framework but asks the Commission to strengthen it by 
requiring the interconnection customer to demonstrate project financing 
(along with the current proposed requirements).\1295\ Eversource also 
asks the Commission to require interconnection customers to provide a 
preliminary project schedule that identifies all key milestones and 
timelines.
---------------------------------------------------------------------------

    \1295\ Eversource Initial Comments at 18.
---------------------------------------------------------------------------

    665. Fervo Energy argues that, for cluster study and restudy 
processes, the proposed framework should allow the interconnection 
customer to demonstrate readiness by using a combination of options, 
such as executed term sheets for a portion of the facility plus 
deposits on a $/MW basis calculated from the quotient of the study 
deposit amount and the proposed generating facility size.\1296\
---------------------------------------------------------------------------

    \1296\ Fervo Energy Initial Comments at 4.
---------------------------------------------------------------------------

    666. ENGIE and SEIA ask the Commission to make the commercial 
readiness demonstration a requirement for entering into an LGIA.\1297\ 
ENGIE and SEIA assert that a later-stage commercial readiness 
demonstration will allow independent power producers to make rational 
business decisions based on reasonably certain network upgrade costs.
---------------------------------------------------------------------------

    \1297\ ENGIE Initial Comments at 6; SEIA Initial Comments at 25.
---------------------------------------------------------------------------

(3) Deposit in Lieu of Readiness
    667. Some commenters contend that the proposal to allow 
interconnection customers to provide a deposit in lieu of demonstrating 
commercial readiness does not cure the potential for undue 
discrimination that results from retaining commercial readiness options 
that are easily attained by incumbent, vertically integrated utilities 
but infeasible for independent power producers.\1298\ These commenters 
claim that, because it is nearly impossible for an independent power 
producer to make any of the commercial readiness demonstrations 
currently proposed, the deposit in lieu of meeting the commercial 
readiness requirements would not be an ``option'' for independent power 
producers but rather would be the only path forward in the 
interconnection process.
---------------------------------------------------------------------------

    \1298\ AEE Initial Comments at 24; Clean Energy Associations 
Initial Comments at 38; NextEra Initial Comments at 24; SEIA Initial 
Comments at 22-25; Vistra Initial Comments at 6-7.
---------------------------------------------------------------------------

    668. Some commenters support the deposit in lieu of readiness 
option, as proposed. For instance, SoCal Edison asserts that an 
increased financial requirement via a deposit in lieu of demonstrating 
commercial readiness should help to identify those interconnection 
requests that are economically viable and to which the transmission 
provider should focus its resources.\1299\ Northwest and Intermountain 
state that providing interconnection customers with an option to 
demonstrate commercial readiness through a deposit is essential to 
ensuring a competitive market for generation by providing a way for 
independent power producers to enter the interconnection queue.\1300\ 
MISO supports the concept of commercial readiness deposits, with the 
first one due at the time of submission of an interconnection request, 
which would then be forfeited if the interconnection request does not 
result in an LGIA, and a second, higher deposit due at the time of 
execution of an LGIA, to be refunded upon a generating facility 
achieving commercial operation.\1301\ MISO also supports the 
Commission's proposal to make these deposits separate from, and in 
addition to, study deposits, as well as MISO's existing milestone 
requirements in its interconnection study process. MISO believes that 
these proposals could be a useful deterrent to speculative or unviable 
interconnection requests entering into or lingering in MISO's 
interconnection queue.
---------------------------------------------------------------------------

    \1299\ SoCal Edison Initial Comments at 9.
    \1300\ Northwest and Intermountain Initial Comments at 12.
    \1301\ MISO Initial Comments at 60.
---------------------------------------------------------------------------

    669. MISO TOs argue that, in keeping with the overall theme of 
flexibility and respect for regional differences, the Commission should 
afford transmission providers flexibility to adopt readiness 
requirements and deposit amounts that are appropriate for their 
regions.\1302\ MISO suggests deposits could consist of two components: 
(1) a minimum amount per interconnection request, regardless of 
proposed service levels, and (2) a per MW amount.\1303\ MISO asks that 
the commercial readiness deposit increase the pool of money available 
to offset cost shifts, and any additional monies be utilized to defray 
the study costs of interconnection customers that actually reach 
commercial operation.
---------------------------------------------------------------------------

    \1302\ MISO TOs Initial Comments at 29.
    \1303\ MISO Initial Comments at 61.
---------------------------------------------------------------------------

    670. Some commenters argue that allowing deposits and security to 
be posted in lieu of demonstrating commercial readiness may not be 
sufficient to accomplish the NOPR's goals,\1304\ and may, in fact, 
hinder the NOPR's goals.\1305\ APPA-LPPC assert that the financial 
commitments proposed in the NOPR, while not insignificant, do not 
reflect the potentially substantial cost of continuing to tolerate the 
ongoing uncertainty.\1306\ APS claims that, in its experience, 
speculative interconnection requests are well-funded but may not be 
commercially viable.\1307\ Tri-State asserts that the fact that all 53 
applicants in its 2022 interconnection queue elected to provide 
additional financial security at phase 1 in its study process, instead 
of one of three readiness milestones, demonstrates that deposits are 
not effective at deterring unready interconnection requests from 
entering the interconnection queue.\1308\
---------------------------------------------------------------------------

    \1304\ APS Initial Comments at 15; EEI Initial Comments at 7-8; 
Idaho Power Initial Comments at 7; Omaha Public Power Initial 
Comments at 8; Southern Initial Comments at 8.
    \1305\ APPA-LPPC Initial Comments at 19; APS Initial Comments at 
15; Omaha Public Power Initial Comments at 8; Southern Initial 
Comments at 9-10.
    \1306\ APPA-LPPC Initial Comments at 19.
    \1307\ APS Initial Comments at 15.
    \1308\ Tri-State Initial Comments at 15-16.
---------------------------------------------------------------------------

    671. Other commenters recommend changes to the Commission's 
proposal.

[[Page 61110]]

For instance, North Dakota Commission recommends either removing the 
deposits in lieu of demonstrating readiness or increasing readiness 
deposit amounts to an amount that provides a quantifiable, evidence-
based reduction in speculative interconnection requests.\1309\
---------------------------------------------------------------------------

    \1309\ North Dakota Commission Initial Comments at 5.
---------------------------------------------------------------------------

    672. PacifiCorp states that its interconnection process also allows 
an interconnection customer to make a payment of $3,000/MW in lieu of 
meeting commercial readiness demonstration requirements.\1310\ 
PacifiCorp expresses concern that the NOPR proposal would reduce the 
payment obligation (in comparison to what is required today under 
PacifiCorp's LGIP), thus lowering the bar for more speculative 
interconnection requests to enter the interconnection queue and 
increasing risks for further study delays.
---------------------------------------------------------------------------

    \1310\ PacifiCorp Initial Comments at 30.
---------------------------------------------------------------------------

    673. CAISO contends that the Commission's proposed deposit 
requirements are low, such that any modern interconnection customer 
could meet them.\1311\ CAISO questions whether the deposit requirements 
(or any deposit requirements) would deter uncompetitive interconnection 
requests or reduce interconnection queue sizes. CAISO argues that using 
arbitrary figures to set deposit requirements is unlikely to yield 
meaningful results. CAISO urges the Commission to gather more data or 
hold a technical conference to develop meaningful deposit amounts, 
based on data provided by transmission providers.
---------------------------------------------------------------------------

    \1311\ CAISO Initial Comments at 19-20.
---------------------------------------------------------------------------

    674. EEI and NRECA suggest further reducing potential risks of 
speculative interconnection requests by making deposits non-
refundable.\1312\ NRECA argues that the deposit in lieu of readiness 
should only be refunded when the interconnection customer has provided 
an appropriate commercial readiness demonstration or achieves 
commercial operation, adding that allowing any other refund of this 
deposit dilutes the effectiveness of this readiness requirement.\1313\ 
EEI and NYTOs assert that a deposit in lieu of readiness should only be 
allowed in limited circumstances.\1314\
---------------------------------------------------------------------------

    \1312\ EEI Initial Comments at 8; NRECA Initial Comments at 9.
    \1313\ NRECA Initial Comments at 29.
    \1314\ EEI Initial Comments at 7; NYTOs Initial Comments at 20.
---------------------------------------------------------------------------

    675. Commenters urge the Commission to decline to adopt a 
commercial readiness standard that is tied to the status of an 
interconnection customer's off-take arrangements and instead to adopt 
an increasingly ``at-risk'' readiness deposit framework, similar to 
what has been accepted in various RTOs/ISOs.\1315\ They contend that 
more directly associating readiness deposits to the estimated costs and 
likely impact to other interconnection customers if an interconnection 
customer withdraws would provide greater accountability for 
interconnection customers and transmission providers.\1316\
---------------------------------------------------------------------------

    \1315\ AEE Initial Comments at 20, 24-25; AES Clean Energy 
Initial Comments at 16-19; Clean Energy Associations Initial 
Comments at 39; EPSA Initial Comments at 10; Indicated PJM TOs 
Initial Comments at 30-31; Invenergy Initial Comments at 16; MISO 
Initial Comments at 64-65; R Street Initial Comments at 13; Shell 
Initial Comments at 15-16.
    \1316\ AEE Initial Comments at 20, 24-25; AES Clean Energy 
Initial Comments at 16- 19; Clean Energy Associations Initial 
Comments at 39; EPSA Initial Comments at 10; Indicated PJM TOs 
Initial Comments at 30-31; Invenergy Initial Comments at 16; MISO 
Initial Comments at 64-65; R Street Initial Comments at 13; Shell 
Initial Comments at 15-16.
---------------------------------------------------------------------------

    676. PJM and Omaha Public Power assert that the Commission should 
consider basing the readiness deposit amount on an average cost of 
network upgrades in the region determined during previous studies, as 
this method would be based on a less arbitrary valuation than as 
proposed.\1317\ SEIA urges the Commission to set the value of the 
deposit amount as a percentage of the estimated network upgrade costs, 
which should be capped at $2 million.\1318\ rPlus recommends a 
commercial readiness deposit of $2,000/MW, noting that this figure is 
common in industry practice.\1319\
---------------------------------------------------------------------------

    \1317\ Omaha Public Power Initial Comments at 8; PJM Initial 
Comments at 35.
    \1318\ SEIA Initial Comments at 25.
    \1319\ rPlus Initial Comments at 4.
---------------------------------------------------------------------------

    677. Some commenters contend that the level of the proposed 
readiness deposits is too high and should be significantly 
revised.\1320\ Pattern Energy requests that the Commission clarify if 
these deposits are additive or whether they would require an 
interconnection customer to have available seven times the study 
deposit amount by the time the interconnection request reaches the 
facilities study phase. Pattern Energy states that if the payments are 
additive, then the Commission would be requiring an interconnection 
customer to have 14 times its initial study deposit on hand by the time 
the interconnection customer reaches the LGIA milestone, which Pattern 
Energy contends would be unreasonable.\1321\
---------------------------------------------------------------------------

    \1320\ CREA and NewSun Initial Comments at 63; ACE-NY Initial 
Comments at 7; Invenergy Initial Comments at 15-16.
    \1321\ Pattern Energy Initial Comments at 31.
---------------------------------------------------------------------------

    678. Invenergy argues that depositing as much as $3.5 million 
before learning how much must be spent on network upgrades is not 
reasonable.\1322\ ACE-NY argues that the deposit values for the second 
cluster and beyond should be limited to just two times the study 
deposit amount.\1323\ CREA and NewSun contend that the hefty deposits 
will bar smaller companies with less access to capital from competing 
and entering the interconnection study process.\1324\ CREA and NewSun 
argue that the NOPR's deposit levels are purely arbitrary and appear 
aimed at driving interconnection customers out of the interconnection 
process rather than measurably improving the process.
---------------------------------------------------------------------------

    \1322\ Invenergy Initial Comments at 15-16.
    \1323\ ACE-NY Initial Comments at 7.
    \1324\ CREA and NewSun Initial Comments at 65.
---------------------------------------------------------------------------

    679. National Grid requests clarification that transmission 
providers may deduct from a to-be-returned deposit any expenses 
incurred by the transmission provider in administering the respective 
escrow account.\1325\
---------------------------------------------------------------------------

    \1325\ National Grid Initial Comments at 24-25.
---------------------------------------------------------------------------

    680. Pattern Energy contends that the Commission must clarify that 
deposits will be applied toward future security obligations if a 
generating facility reduces its size as it progresses through the 
interconnection process.\1326\ Pattern Energy states that if the size 
of an interconnection request is reduced, in accordance with allowable 
reduction amounts, then: (1) future deposits should be based on the new 
generating facility size; and (2) previous deposits should be credited 
toward future deposits based on the portion of those previous deposits 
that are associated with the reduced MW quantity.
---------------------------------------------------------------------------

    \1326\ Pattern Energy Initial Comments at 31.
---------------------------------------------------------------------------

(d) Requests for Flexibility
    681. Several commenters generally support the proposed commercial 
readiness requirements but ask the Commission to provide flexibility to 
allow transmission providers to determine the detailed readiness and 
deposit criteria for their footprint.\1327\ These commenters argue that 
such measures need to be carefully balanced to avoid overly burdening 
interconnection customers with legitimate interconnection requests that 
are delayed for reasons out of their control. For example, NY 
Commission

[[Page 61111]]

and NYSERDA explain that, in New York, renewable energy certificates 
procured by NYSERDA could demonstrate commercial readiness, and a 
similar state agency certificate could be used in a different 
state.\1328\
---------------------------------------------------------------------------

    \1327\ Avangrid Initial Comments at 15; Dominion Initial 
Comments at 25; Dominion Reply Comments at 10, 13-14; El Paso 
Electric Initial Comments at 4; Invenergy Initial Comments at 12; 
ISO-NE Initial Comments at 31; National Grid Initial Comments at 25; 
NEPOOL Initial Comments at 14; NESCOE Reply Comments at 8; NY 
Commission and NYSERDA Initial Comments at 8; NYISO Initial Comments 
at 23; NYTOs Initial Comments at 20; Pacific Northwest Utilities 
Initial Comments at 2-4.
    \1328\ NY Commission and NYSERDA Initial Comments at 9.
---------------------------------------------------------------------------

    682. Pacific Northwest Utilities claim that it would be difficult 
for transmission providers to implement the commercial readiness 
proposal in regions such as the Northwest without reforming RFP 
processes and coordinating amongst multiple transmission owners and 
LSEs.\1329\ Pacific Northwest Utilities explain that many generating 
facilities in the Pacific Northwest use interconnection and 
transmission services crossing multiple balancing authority areas, 
which require coordination of timelines, milestones, and off-ramps in 
both the RFPs and interconnection queues.
---------------------------------------------------------------------------

    \1329\ Pacific Northwest Utilities Initial Comments at 4-5.
---------------------------------------------------------------------------

(e) Miscellaneous
    683. Enel supports the proposed modification to pro forma LGIP 
section 11.3 to require submission of the development milestones 
concurrently with returning the executed LGIA so that the 
interconnection customer cannot avoid the demonstration required by pro 
forma LGIP section 11.3 by suspending its LGIA.\1330\ However, Enel 
notes that it is important for the Commission to retain (and 
reinstitute where removed by specific transmission providers) the 
ability for interconnection customers to suspend work under their LGIAs 
for up to three years.
---------------------------------------------------------------------------

    \1330\ Enel Initial Comments at 45.
---------------------------------------------------------------------------

    684. Arizona Commission generally supports the prioritization of 
commercially ready projects and agrees with the proposed readiness 
criteria, but also encourages the Commission to consider the 
possibility of allowing market forces to provide discipline to the 
interconnection process, such as by allowing transmission owners to 
prioritize generation projects through the use of competitive 
solicitations.\1331\
---------------------------------------------------------------------------

    \1331\ Arizona Commission Initial Comments at 2.
---------------------------------------------------------------------------

    685. The Colorado Commission generally supports prioritizing 
commercially ready interconnection requests and agrees with the 
proposed readiness criteria.\1332\ However, the Colorado Commission 
emphasizes that the NOPR does not include a mechanism to prioritize 
among the many viable, and competing, interconnection requests when 
interconnection service capacity is scarce.\1333\ The Colorado 
Commission argues that, under existing RTO/ISO interconnection 
processes as well as the proposed revised pro forma LGIP, there is 
limited ability in the interconnection process to consider the 
generating facility's broader attributes from a system perspective, 
including cost, timing, location, and resource type.\1334\ The Colorado 
Commission asserts that new proposed generating facilities would likely 
be stuck in cluster studies with no clear or timely prioritization that 
ensures that the lowest cost or highest value generating facilities 
come online quickly and at a reasonable cost. The Colorado Commission 
contends that prioritizing native load and end-use customers and third-
party owned generating facilities through competitive bid processes is 
the most logical criteria to maintain a reliable system at reasonable 
cost.\1335\ To accomplish this, and help the system rationally move 
forward in a timely manner, the Colorado Commission suggests adding the 
following additional language to the commercial readiness section: 
``RTOs and Transmission Providers shall have the ability to create a 
separate cluster study process or other mechanisms to prioritize 
executed contracts that serve and benefit native load in accordance 
with local load-serving resources needs and priorities as determined 
through equitable competitive bid processes.'' \1336\
---------------------------------------------------------------------------

    \1332\ Colorado Commission Initial Comments at 1.
    \1333\ Id. at 2.
    \1334\ Id. at 7.
    \1335\ Id. at 28.
    \1336\ Id. The Colorado Commission also notes that some or all 
of this proposed language may be more appropriate for section 4 
(Queue Position) of the pro forma LGIP.
---------------------------------------------------------------------------

    686. AEE, on the other hand, responds to the Colorado Commission by 
arguing that allowing transmission providers to prioritize generating 
facilities that are selected through IRP processes or utility 
procurements and that benefit native load could allow vertically 
integrated utilities to push preferred generating facilities through 
the interconnection process and therefore comes with a risk of 
discrimination.\1337\
---------------------------------------------------------------------------

    \1337\ AEE Reply Comments at 16.
---------------------------------------------------------------------------

    687. CESA argues that proposals to prioritize and favor certain 
generating facilities and interconnection customers must be rejected as 
violating the Commission's long-standing policies on open access and 
non-discriminatory interconnection procedures.\1338\ CESA contends that 
the Colorado Commission's proposal is therefore unduly discriminatory 
and also goes well beyond what the Commission contemplated in the NOPR.
---------------------------------------------------------------------------

    \1338\ CESA Reply Comments at 11.
---------------------------------------------------------------------------

    688. Clean Energy Associations state that they support the 
Commission's instead accepting regionally specific proposals that would 
align the interconnection process with competitive procurements 
associated with resource planning, rather than placing them at 
odds.\1339\ Clean Energy Associations state that projects selected 
though competitive procurement processes are ready projects, and these 
processes attempt to consider the transmission (interconnection service 
and transmission service) costs and the production-related costs. Clean 
Energy Associations state that one way to accomplish this might be to 
grant resource solicitation clusters a queue position distinct from 
other clustered projects, but that concept could be extended to ensure 
more certainty to the bidder and the resource planning entity of the 
interconnection and delivery requirements and associated rights.
---------------------------------------------------------------------------

    \1339\ Clean Energy Associations Initial Comments at 38.
---------------------------------------------------------------------------

    689. Bonneville sees value in applying commercial readiness 
requirements to the pro forma SGIP and SGIA and contends that failing 
to do so could create a perverse incentive for interconnection 
customers to break up large projects into smaller projects to avoid 
stringent commercial readiness requirements under the pro forma 
LGIP.\1340\
---------------------------------------------------------------------------

    \1340\ Bonneville Initial Comments at 24-25.
---------------------------------------------------------------------------

iii. Commission Determination
    690. We adopt a modified NOPR proposal to revise sections 3.4.2, 
7.5, 8.1, and 11.3 of the pro forma LGIP, insofar as they require 
interconnection customers to submit commercial readiness deposits, and 
we do not adopt the NOPR proposal insofar as it included non-financial 
commercial readiness demonstrations in the pro forma LGIP. To 
effectuate the requirements that we adopt in this final rule, we modify 
the proposed revisions to sections 3.4.2, 7.5, and 8.1 to remove the 
proposed readiness demonstrations and to require that the 
interconnection customer submit the commercial readiness deposit at the 
beginning of each study in the cluster study process (i.e., the initial 
cluster study, the cluster restudy, and the facilities study). For the 
commercial readiness deposit submitted to enter the cluster restudy and 
the commercial readiness deposit to enter the facilities study, we also 
modify the NOPR proposal to move from commercial readiness deposits 
based on study deposit amounts to commercial

[[Page 61112]]

readiness deposits based on percentages of the interconnection 
customer's identified network upgrade costs. We also modify proposed 
section 11.3 of the pro forma LGIP to remove the language providing 
that one of the proposed readiness demonstrations can be provided when 
the interconnection customer returns the executed LGIA or requests that 
the LGIA be filed unexecuted. We also adopt the definition of 
commercial readiness deposit but do not adopt the definition of 
commercial readiness demonstration. We discuss each in turn.
    691. We believe that, along with the other reforms adopted in this 
final rule, the commercial readiness deposits we require will address 
the need for reform underlying this section by helping reduce the 
submission of speculative, commercially non-viable interconnection 
requests into interconnection queues.\1341\ Further, because the 
interconnection customer's total commercial readiness deposit held by 
the transmission provider increases as the interconnection process 
proceeds, we find that this approach will encourage interconnection 
customers not ready to proceed through the interconnection process--or 
whose projects become commercially non-viable during the 
interconnection process--to withdraw earlier in the process, thereby 
lessening the incidence of late-stage withdrawals that result in delays 
and restudies. Similarly, by basing the cluster restudy and the 
facilities study commercial readiness deposits on the interconnection 
customer's identified network upgrade cost assignment, an 
interconnection customer will be subject to the cost consequences of 
its estimated network upgrades earlier. As a result, this approach will 
encourage interconnection customers to withdraw earlier in the 
interconnection process if they face large network upgrade initial cost 
assignments or encounter other concerns that cause their 
interconnection request to be uneconomic. By reducing the number of 
speculative interconnection requests submitted into the interconnection 
queue and the number of late-stage withdrawals of interconnection 
requests, we believe that the commercial readiness deposit requirements 
that we adopt herein will also enable commercially viable 
interconnection requests to progress more quickly through the 
interconnection process. Transmission providers will be able to focus 
their resources on those interconnection requests most likely to 
achieve commercial operation, to the benefit of all interconnection 
customers.\1342\
---------------------------------------------------------------------------

    \1341\ SoCal Edison Initial Comments at 9, Northwest and 
Intermountain Initial Comments at 12, MISO Initial Comments at 60, 
PJM Initial Comments at 35.
    \1342\ Alliant Energy Initial Comments at 6; Avangrid Initial 
Comments at 9; Consumer Energy Initial Comments at 5; EEI Initial 
Comments at 6-7; NERC Initial Comments at 26; Google Initial 
Comments at 20; Idaho Power Initial Comments at 7; MISO TOs Initial 
Comments at 28-29; NARUC Initial Comments at 10; NESCOE Initial 
Comments at 13; North Carolina Commission and Staff Initial Comments 
at 26; Ohio Commission Consumer Advocate Initial Comments at 12; 
Omaha Public Power Initial Comments at 9; Pacific Northwest 
Utilities Initial Comments at 3, 6; Pennsylvania Commission Initial 
Comments at 14; U.S. Chamber of Commerce Initial Comments at 9; UMPA 
Initial Comments at 5.
---------------------------------------------------------------------------

    692. The commercial readiness deposit amounts proposed in the NOPR 
are tied to generating facility size, as they are based on the initial 
study deposit, which is likewise tied to generating facility size. We 
adopt the NOPR proposal for the initial commercial readiness deposit, 
where the interconnection customer pays a deposit of two times the 
study deposit to enter the cluster study. Basing the initial commercial 
readiness deposit on the size of the generating facility aligns the 
size of the deposit roughly with any impact from a withdrawal of the 
interconnection request, as generally, all else equal, increasing the 
size of the generating facility increases the likelihood of larger, 
more costly network upgrades and a greater change in interconnection 
study inputs.
    693. However, we are persuaded by several commenters that 
commercial readiness deposits should be based on assigned network 
upgrade costs.\1343\ Therefore, we modify the remaining commercial 
readiness deposits (i.e., the second and third commercial readiness 
deposits) such that, rather than relying on multiples of the initial 
study deposit, once estimates of network upgrade costs are available, 
the commercial readiness deposits equate to increasing percentages of 
the interconnection customer's identified network upgrade cost 
assignment. Specifically, we adopt a deposit structure where the 
commercial readiness deposit to enter the cluster restudy is the amount 
required to bring the total amount of the interconnection customer's 
commercial readiness deposit to 5% of the interconnection customer's 
network upgrade cost assignment identified in the cluster study, and 
the commercial readiness deposit to enter the facilities study is the 
amount required to bring the total amount of the interconnection 
customer's commercial readiness deposit to 10% of the interconnection 
customer's network upgrade cost assignment identified in the cluster 
study or restudy, as applicable.\1344\ We find that tying the 
commercial readiness deposits to the network upgrade cost estimate 
requires the interconnection customer to deposit an amount that 
corresponds to its network upgrade cost estimates earlier and, thereby, 
can incentivize interconnection customers with large network upgrade 
cost estimates to withdraw at earlier points in the interconnection 
process to the extent the network upgrade cost assignment causes the 
interconnection request to no longer be viable. This approach achieves 
the Commission's goals of ensuring that interconnection customers are 
able to interconnect in a reliable, efficient, transparent, and timely 
manner.
---------------------------------------------------------------------------

    \1343\ For assertions that more directly associating commercial 
readiness deposits to the estimated costs and likely impact to other 
interconnection customers in the case of withdrawal would provide 
greater accountability for interconnection customers and 
transmission providers, see AEE Initial Comments at 24-25; AES Clean 
Energy Initial Comments at 16- 19; CAISO Initial Comments at 23-24; 
Clean Energy Associations Initial Comments at 39; EPSA Initial 
Comments at 10; Indicated PJM TOs Initial Comments at 30-31; 
Invenergy Initial Comments at 16; MISO Initial Comments at 64-65; R 
Street Initial Comments at 13; Shell Initial Comments at 15-16.
    \1344\ See SEIA Initial Comments at 25 (urging the Commission to 
set the value of the commercial readiness deposit as a percentage of 
the estimated network upgrade costs).
---------------------------------------------------------------------------

    694. We decline to adopt the non-financial commercial readiness 
demonstrations proposed in the NOPR. We find that the non-financial 
commercial readiness demonstrations are not necessary to address the 
subject of these reforms--providing additional deterrence of 
speculative, commercially non-viable interconnection requests--given 
the significant, increasing commercial readiness deposits we adopt 
instead.\1345\
---------------------------------------------------------------------------

    \1345\ See N.Y. v. FERC, 535 U.S. 1, 27 (2002) (declining to 
require reforms where ``FERC determined that the remedy it ordered 
constituted a sufficient response to the problems FERC had 
identified'').
---------------------------------------------------------------------------

    695. We are also persuaded by commenters who express concerns that 
the non-financial commercial readiness demonstrations in the NOPR 
proposal may not necessarily serve as appropriate indicators of a 
proposed generating facility's commercial viability on a national 
basis. In some instances, the proposed non-financial commercial 
readiness demonstrations may be unavailable to interconnection 
customers with commercially viable projects. For example, this may be 
true as a result of a misalignment of the timing between resource 
procurement

[[Page 61113]]

decisions and interconnection study processes or inconsistency with a 
relevant local commercial practice, rather than because the proposed 
generating facilities lack commercial viability.
    696. As commenters note, resource procurement efforts across the 
country all have different timelines, and the timeline to demonstrate 
commercial readiness proposed in the NOPR was not tailored to meet the 
timelines of multiple state procurement efforts.\1346\ As commenters 
explain, an interconnection queue position is often a precondition of 
offering into a resource solicitation.\1347\ We agree that, absent a 
regionally tailored tariff process pursuant to which commercial 
readiness criteria could be aligned with applicable resource 
solicitation processes, the commercial readiness criteria proposed in 
the NOPR may not be workable in markets where merchant sales are 
common, and this generally applicable final rule is not an appropriate 
forum to dictate regionally tailored solutions.
---------------------------------------------------------------------------

    \1346\ AEE Initial Comments at 21; SoCal Edison Initial Comments 
at 7-8; Vistra Initial Comments 6-10.
    \1347\ See Cypress Creek Initial Comments at 22-23; NextEra 
Initial Comments at 24; Public Interest Organizations Initial 
Comments at 29.
---------------------------------------------------------------------------

    697. We are further concerned that there may be trade-offs entailed 
in requiring the proposed non-financial commercial readiness 
demonstrations, which are more appropriately assessed on a regional, 
rather than national basis. We agree with Enel that ratepayers may 
benefit from generating facilities being selected in competitive 
processes that consider the facilities' interconnection costs and 
schedule, which cannot be done if off-take arrangements are made prior 
to applying for interconnection service.
    698. In addition, we are concerned that the proposed non-financial 
commercial readiness demonstrations could incentivize power purchasers 
in some regions to execute purchase contracts with interconnection 
customers whose generating facilities will later be determined to be 
commercially non-viable. As commenters note, this could lead to 
purchasers having to start the procurement process over or choose to 
over-procure as insurance against potential contract termination, to 
the detriment of reliability and cost.
    699. Therefore, we are persuaded to adopt a framework that requires 
a commercial readiness deposit for all interconnection customers, 
similar to what the Commission has accepted in various RTO/ISO 
regions.\1348\ We find that requiring deposits in amounts substantial 
enough to demonstrate commitment to reaching commercial operation at 
progressive milestones throughout the interconnection process will be a 
sufficient deterrent to speculative behavior--especially when 
considered as part of the comprehensive package of reform, including 
increased site control requirements, increased study deposits, and 
withdrawal penalties, established by this final rule.
---------------------------------------------------------------------------

    \1348\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 158 
FERC ] 61,003 (2017); Sw. Power Pool, Inc., 178 FERC ] 61,015 
(2022).
---------------------------------------------------------------------------

    700. In the NOPR, the Commission acknowledged the potential that 
certain non-financial commercial readiness demonstrations could provide 
an unduly discriminatory or preferential advantage to projects being 
developed by transmission providers or their affiliates.\1349\ As 
summarized above, several commenters have raised--and elaborated on--
those concerns. Because we find that the commercial readiness deposits 
that we adopt in this final rule are sufficient to address the relevant 
need for reform, and therefore do not adopt the proposed non-financial 
commercial readiness demonstrations, we need not further address those 
concerns in this final rule.
---------------------------------------------------------------------------

    \1349\ NOPR, 179 FERC ] 61,194 at P 132.
---------------------------------------------------------------------------

    701. We recognize that the Commission has previously accepted 
proposals that include commercial readiness demonstration requirements 
similar to those proposed in the NOPR. Although we find that commercial 
readiness deposits are sufficient to address the need for reform in 
this proceeding, this finding does not preclude transmission providers 
from adopting non-financial commercial readiness demonstrations, 
provided they meet the relevant standards when requesting a variation, 
as discussed above.
    702. Some commenters suggest that the Commission could add 
government and environmental permits as commercial readiness 
demonstrations as an indicator of commercial readiness that is viable 
both for independent power producers and for transmission providers and 
their affiliates.\1350\ Although the record provides some support for 
this, we are concerned that permits and studies may expire due to the 
length of the interconnection process, and those re-permitting and 
restudy efforts are still at risk of rejection or failure, which could 
lead to late-stage withdrawals.\1351\ We are also concerned about the 
possible administrative burden placed on transmission providers, as 
they must determine which types of permits should be accepted as 
commercial readiness demonstrations and evaluate the validity of 
different permits submitted by interconnection customers.
---------------------------------------------------------------------------

    \1350\ ClearPath Initial Comments at 9; CREA and NewSun Initial 
Comments at 71; Enel Initial Comments at 47; Longroad Energy Initial 
Comments at 17; Northwest and Intermountain Initial Comments at 11; 
Vistra Initial Comments at 11.
    \1351\ Enel Initial Comments at 47.
---------------------------------------------------------------------------

    703. Pattern Energy requests that the Commission clarify whether 
the commercial readiness deposits are additive, meaning that, as each 
phase of the interconnection process is reached, the full amount of 
each new readiness deposit must be added on top of the full amounts of 
earlier readiness deposits (as opposed to merely increasing the total 
amount of the aggregate readiness deposit to match the level specified 
for that phase). In response, we clarify that, as modified, the 
commercial readiness deposits in sections 7.5 and 8.1 of the pro forma 
LGIP make clear that for the second and third commercial readiness 
deposits, the interconnection customer is only required to submit an 
additional deposit that brings the total commercial readiness deposit 
to the amount specified in sections 7.5 and 8.1 of the pro forma LGIP 
(5% of the interconnection customer's identified network upgrade cost 
estimate and 10% of the interconnection customer's identified network 
upgrade cost estimate, respectively).
    704. In response to comments on the magnitude of commercial 
readiness deposits (e.g., too high or too low), we reiterate that the 
commercial readiness deposits are part of a package of reforms meant to 
deter speculative behavior that also includes site control requirements 
and withdrawal penalties. Thus, the commercial readiness deposits are 
not intended to be of such magnitude to alone prevent speculative 
behavior as they are intended to work together with other reforms 
adopted in this final rule, such as site control and withdrawal 
penalties. We believe that the deposits should not be so high that 
viable projects from smaller developers are unable to enter the queue. 
At the same time, they will only achieve the aims if they are 
sufficiently high to serve as some deterrent, in concert with the other 
relevant reforms adopted in this final rule. In response to National 
Grid's request that the final rule provide for the deduction from a to-
be-returned deposit of any expenses incurred by the transmission 
provider or RTO/ISO in administering the respective escrow account, we 
note that Order No. 2003

[[Page 61114]]

required the collection of various deposits without addressing this 
type of administrative expense.\1352\ We find, in this instance, that 
there is no need to deviate from Order No. 2003, and we decline to 
adopt tariff revisions to address the management of an escrow account.
---------------------------------------------------------------------------

    \1352\ Order No. 2003, 104 FERC ] 61,103 at PP 91-92, 100, 101, 
218-219.
---------------------------------------------------------------------------

    705. In response to Pattern Energy's request for clarification of 
the commercial readiness deposit amounts in the event that an 
interconnection customer reduces the size of a proposed generating 
facility, we clarify that because the modified commercial readiness 
deposit structure is based on network upgrade cost estimates, a size 
reduction to a proposed generating facility may or may not impact the 
remaining commercial readiness deposits, depending on whether the size 
reduction reduces the interconnection customer's assigned network 
upgrade costs. This is consistent with the requirements for entering 
the cluster restudy and facilities study adopted in pro forma LGIP 
sections 7.5 and 8.1, respectively, which require commercial readiness 
deposits based on percentages of the interconnection customer's 
identified network upgrade costs.
    706. Pattern Energy's request to require that previous deposits be 
credited towards future deposits based on the portion of those previous 
deposits that are associated with the reduced MW quantity therefore 
represents the modified commercial readiness deposit framework we 
adopt. Under this modified framework, an interconnection customer's 
previous commercial readiness deposits are effectively credited when it 
pays later commercial readiness deposits (i.e., the second and third 
commercial readiness deposits); it pays the required amount of a 
commercial readiness deposit less the amounts paid for through earlier 
commercial readiness deposits.
    707. We also decline to adopt Bonneville's suggestion to add the 
commercial readiness provisions to the SGIP because the record does not 
demonstrate a need for such reform at this time. Because we are not 
adopting the proposed non-financial commercial readiness 
demonstrations, we do not address comments proposing revisions or 
clarifications to those demonstrations. Additionally, several 
commenters provide additional suggestions for the NOPR proposal, 
including: (1) addressing the Commission's rules for suspending an 
LGIA; \1353\ (2) addressing queue priority; \1354\ and (3) better 
supporting competitive procurement processes.\1355\ We find these 
comments to be outside the scope of the NOPR.
---------------------------------------------------------------------------

    \1353\ Clean Energy Associations Initial Comments at 38; PPL 
Initial Comments at 10.
    \1354\ Arizona Commission Initial Comments at 2; Colorado 
Commission Initial Comments at 1-2.
    \1355\ Clean Energy Associations Initial Comments at 38; 
Colorado Commission Initial Comments at 1-2, 7, 28.
---------------------------------------------------------------------------

d. LGIA Deposit
i. NOPR Proposal
    708. In the NOPR, the Commission proposed to require 
interconnection customers to submit a deposit equal to nine times the 
amount of its study deposit when executing the LGIA or requesting the 
filing of an unexecuted LGIA. The Commission explained that this 
deposit would be fully refunded once the generating facility achieves 
commercial operation, but if the interconnection customer withdraws 
after executing the LGIA or after requesting the filing of an 
unexecuted LGIA, this deposit would be refunded subject to the 
withdrawal penalty.\1356\ The Commission also sought comment on whether 
to adopt additional provisions or a different framework that would 
require larger proposed generating facilities to provide a higher 
deposit amount--such as a per MW framework.\1357\
---------------------------------------------------------------------------

    \1356\ NOPR, 179 FERC ] 61,194 at P 108.
    \1357\ Id. P 110.
---------------------------------------------------------------------------

ii. Comments
    709. MISO supports the proposal to require interconnection 
customers to submit a deposit equal to nine times the amount of its 
study deposit at LGIA execution because MISO believes it is necessary 
to continue the commercial readiness deposit and withdrawal penalty 
framework until the interconnection request achieves commercial 
operation.\1358\ Shell supports the security deposit obligations used 
in MISO's and SPP's generator interconnection processes, which include 
a deposit at LGIA execution.\1359\
---------------------------------------------------------------------------

    \1358\ MISO Initial Comments at 51.
    \1359\ Shell Initial Comments at 19.
---------------------------------------------------------------------------

    710. Invenergy argues that requiring more security at LGIA 
execution, in addition to the other proposed burdens on interconnection 
customers in the NOPR, goes beyond the goal of disincentivizing 
speculative interconnection requests to creating potentially 
prohibitive burdens on all interconnection customers, including those 
with commercially viable proposed generating facilities.\1360\ 
Invenergy contends that, while a deposit based on study costs may make 
sense in earlier stages of the study process when assigned network 
upgrade costs are not yet known, it is not appropriate after an LGIA is 
executed and assigned network upgrade costs are known and memorialized. 
ACE-NY and AES oppose any additional deposits due from an 
interconnection customer at the signing of the LGIA that are not tied 
to network upgrade costs.\1361\ AES asserts that in many RTOs/ISOs, 
interconnection customers have to post security for a portion, if not 
all, of the assigned network upgrade costs associated with an 
interconnection request, and such posted security is a sufficient 
incentive to keep an interconnection customer engaged so that they will 
complete a generating facility after the LGIA is executed.\1362\
---------------------------------------------------------------------------

    \1360\ Invenergy Initial Comments at 6.
    \1361\ ACE-NY Initial Comments at 5; AES Initial Comments at 14.
    \1362\ AES Initial Comments at 14.
---------------------------------------------------------------------------

    711. Several commenters argue that the Commission's LGIA deposit 
proposal is excessive and potentially exposes ratepayers to unjust and 
unreasonable costs.\1363\ [Oslash]rsted would support a lower amount, 
such as two times the study deposit, because it believes that the 
current proposal would not necessarily accurately estimate the costs of 
required network upgrades.\1364\ PJM contends that the Commission 
should allow transmission providers to adopt security amounts and 
structures that are rationally related to relevant costs.\1365\ Cypress 
Creek asks the Commission to provide a non-arbitrary basis for its 
proposed security deposit of nine times the study deposit.\1366\ Shell 
argues that the LGIA deposit appears to be a security deposit and adds 
that MISO and SPP use a separate security deposit obligation that the 
Commission should consider.\1367\
---------------------------------------------------------------------------

    \1363\ Id.; Clean Energy Associations Initial Comments at 30; 
ENGIE Initial Comments at 4; [Oslash]rsted Initial Comments at 9; 
PJM Initial Comments at 24; Shell Reply Comments at 22.
    \1364\ [Oslash]rsted Initial Comments at 9.
    \1365\ PJM Initial Comments at 24.
    \1366\ Cypress Creek Initial Comments at 53.
    \1367\ Shell Initial Comments at 19.
---------------------------------------------------------------------------

    712. Several commenters argue that study deposits should be 
refunded in certain circumstances.\1368\ Invenergy argues that any 
deposit due at LGIA execution should be subject to a $2 million cap and 
that deposit should be released dollar for dollar as the 
interconnection customer posts security or makes required payments 
under the LGIA.\1369\ Invenergy asks that the

[[Page 61115]]

Commission also clarify that, in the event a proposed generating 
facility does not achieve commercial operation, any deposit forfeited 
under this proposal offsets, and is not in addition to, any withdrawal 
penalties that may be imposed. Invenergy adds that it is unreasonable 
to require that additional deposits be provided when an interconnection 
customer asks that the LGIA be filed unexecuted, and if the Commission 
does nonetheless require interconnection customers to post the deposit 
as a condition of having the LGIA filed unexecuted, the deposit should 
be refundable if the interconnection customer elects to withdraw within 
30 days of the date of the Commission's order in the applicable docket. 
[Oslash]rsted and Shell assert that, for interconnection customers 
withdrawing after executing the LGIA, all deposits should be refunded 
in the event that the interconnection customer withdraws as a result of 
circumstances outside of its control and the withdrawal does not harm 
any other entity.\1370\ AES argues that all study deposits should be 
refunded at the time of LGIA execution, and opposes any additional 
deposits not tied to network upgrade costs.\1371\
---------------------------------------------------------------------------

    \1368\ AES Initial Comments at 14; Invenergy Initial Comments at 
7; [Oslash]rsted Initial Comments at 10; Shell Reply Comments at 23.
    \1369\ Invenergy Initial Comments at 7-8.
    \1370\ [Oslash]rsted Initial Comments at 10; Shell Reply 
Comments at 23.
    \1371\ AES Initial Comments at 14.
---------------------------------------------------------------------------

    713. Southern, on the other hand, argues that making deposits 
refundable may not be stringent enough and therefore may not accomplish 
the goals set forth in the NOPR.\1372\ NRECA also believes that the 
Commission should consider whether to make these study deposits non-
refundable in the case of withdrawal, as a further disincentive for 
speculative interconnection requests to enter the interconnection 
queue.\1373\
---------------------------------------------------------------------------

    \1372\ Southern Initial Comments at 8-9.
    \1373\ NRECA Initial Comments at 26.
---------------------------------------------------------------------------

iii. Commission Determination
    714. We adopt, with modification, the NOPR proposal to revise new 
section 11.3 of the pro forma LGIP to require interconnection customers 
to submit a deposit when executing the LGIA, or requesting the filing 
of an unexecuted LGIA,and add the new term ``LGIA deposit'' to section 
1 of the pro forma LGIP.\1374\ Specifically, we modify the NOPR 
proposal to require interconnection customers to provide a deposit that 
will increase the total commercial readiness deposit paid to be equal 
to 20% of the estimated network upgrade costs identified in the LGIA, 
rather than providing a deposit equal to nine times the amount of the 
interconnection customer's study deposit, as proposed in the 
NOPR.\1375\ Additionally, revised section 11.3 of the pro forma LGIP 
requires that interconnection customers submit the LGIA deposit when 
returning the executed LGIA to the transmission provider, or within 10 
business days of the interconnection customer requesting that the LGIA 
be filed unexecuted at the Commission.
---------------------------------------------------------------------------

    \1374\ LGIA deposit shall ``mean the deposit Interconnection 
Customer submits when returning the executed LGIA, or within 10 
Business Days of the LGIA being filed unexecuted at the Commission, 
in accordance with Section 11.3 of this LGIP.''
    \1375\ At LGIA execution or at the time the request is made to 
file the unexecuted LGIA, the interconnection customer must deposit 
the difference between its total commercial readiness deposits 
submitted at that point and 20% of its estimated network upgrade 
cost responsibility.
---------------------------------------------------------------------------

    715. In the NOPR, the Commission sought comment on whether to adopt 
additional provisions or a different framework for deposits, including 
the LGIA deposit.\1376\ In response, commenters provided suggestions, 
including suggestions to base deposits on network upgrade costs.\1377\ 
We agree that tying the LGIA deposit to the network upgrade cost 
estimate sends a more accurate cost signal to the interconnection 
customer and better aligns the LGIA deposit to its function of ensuring 
that network upgrades are paid for and constructed than the NOPR 
proposal. We also agree with commenters that a deposit based on the 
study deposit amount may make sense in the early stage of the cluster 
study process when assigned network upgrade costs are not yet 
estimated, but later in the process, when network upgrade cost 
estimates are available, the use of percentages of network upgrade cost 
estimates more closely indicates interconnection request 
viability.\1378\ This approach also addresses comments that the LGIA 
deposit, as proposed, may have been arbitrary, excessive, and 
unreasonable.\1379\
---------------------------------------------------------------------------

    \1376\ NOPR, 179 FERC ] 61,194 at P 110.
    \1377\ See, e.g., Longroad Reply Comments at 13; PJM Initial 
Comments at 24.
    \1378\ ACE-NY Initial Comments at 5; AES Initial Comments at 14; 
Invenergy Initial Comments at 6.
    \1379\ AES Initial Comments at 14; Clean Energy Associations 
Initial Comments at 30; ENGIE Initial Comments at 4; [Oslash]rsted 
Initial Comments at 9; PJM Initial Comments at 24; Shell Reply 
Comments at 22.
---------------------------------------------------------------------------

    716. The NOPR proposed that this deposit would be fully refunded 
once the generating facility achieves commercial operation, but we are 
modifying the NOPR proposal to remove that statement from pro forma 
LGIP section 11.3, and as explained further below, this deposit will be 
used as part of the security the interconnection customer must provide 
for the construction of network upgrades and transmission provider's 
interconnection facilities. However, this LGIA deposit could be 
refunded, subject to the withdrawal penalty, if the interconnection 
customer withdraws after executing the LGIA or after requesting the 
filing of an unexecuted LGIA.
    717. We also revise the pro forma LGIP and pro forma LGIA, as 
suggested by Invenergy,\1380\ to treat the LGIA deposit as part of the 
security the interconnection customer must provide for the construction 
of network upgrades and transmission provider's interconnection 
facilities. Article 11.5 (Provision of Security) of the pro forma LGIA 
requires that, 30 calendar days prior to the commencement of 
construction under its LGIA, the interconnection customer must provide 
security for a discrete portion of network upgrades and transmission 
provider's interconnection facilities, as specified in its LGIA. We 
revise section 11.3 of the pro forma LGIP and article 11.5 of the pro 
forma LGIA to require the transmission provider to use the LGIA 
deposit, in its entirety, before requiring the interconnection customer 
to submit additional security for construction of network upgrades and 
transmission provider's interconnection facilities. By allowing the 
transmission provider to draw down this LGIA deposit as construction 
proceeds, the construction of network upgrades and transmission 
provider's interconnection facilities can commence quickly thereby 
streamlining the interconnection process. With this revision, requiring 
the LGIA deposit to be returned at commercial operation is now 
unnecessary as there will be no deposit remaining to return; therefore, 
we decline to adopt the NOPR proposal to do so.\1381\
---------------------------------------------------------------------------

    \1380\ Invenergy Initial Comments at 7.
    \1381\ NOPR, 179 FERC ] 61,194 at P 108.
---------------------------------------------------------------------------

    718. We also revise article 11.5 of the pro forma LGIA to require 
transmission providers to draft Appendix B (Milestones) of the 
interconnection customer's LGIA to clearly explain and estimate at 
which point of construction the interconnection customer's LGIA deposit 
will be depleted, and the interconnection customer must provide 
additional financial security. In the event the interconnection 
customer requests suspension of the LGIA under article 5.16 of its LGIA 
prior to the commencement of construction, the transmission provider is 
prohibited from using the LGIA deposit to commence construction until 
the

[[Page 61116]]

interconnection customer requests to exit suspension and resume 
construction, unless there is a need for the transmission provider to 
use a portion of the LGIA deposit to ensure its system is left in a 
reliable condition during the period of suspension.
    719. We do not adopt the suggestion of [Oslash]rsted and Shell 
that, for interconnection customers withdrawing their interconnection 
requests after executing an LGIA, all deposits should be refunded if 
withdrawal is the result of circumstances outside the interconnection 
customer's control and the withdrawal does not harm other 
entities.\1382\ We believe that the exceptions to the application of 
withdrawal penalties discussed in the section III.A.6.e below 
appropriately balance the need to deter withdrawals with the reality 
that withdrawal is not always due to circumstances within 
interconnection customers' control.
---------------------------------------------------------------------------

    \1382\ See [Oslash]rsted Initial Comments at 10; Shell Reply 
Comments at 23.
---------------------------------------------------------------------------

    720. In response to Southern's comments that making both study and 
LGIA deposits refundable may not be stringent enough and therefore may 
not disincentivize speculative interconnection requests,\1383\ we 
reiterate that, as adopted, the deposits serve different functions. In 
this instance, the LGIA deposit serves as a credit towards the security 
the interconnection customer must provide for network upgrades and 
transmission provider's interconnection facilities. To the extent the 
LGIA deposit pays for the construction of network upgrades, such a 
deposit would be refunded through transmission credits in regions that 
follow the pro forma LGIA provisions on crediting.
---------------------------------------------------------------------------

    \1383\ Southern Initial Comments at 8-9.
---------------------------------------------------------------------------

e. Withdrawal Penalties
i. NOPR Proposal
    721. The Commission preliminarily found that withdrawal penalties 
are needed to account for the harms that can occur when interconnection 
customers withdraw from the interconnection queue.\1384\ The Commission 
proposed to revise the pro forma LGIP to require transmission providers 
to assess withdrawal penalties to interconnection customers in certain 
circumstances. Specifically, the Commission proposed to revise the pro 
forma LGIP to require transmission providers to assess withdrawal 
penalties to interconnection customers that choose to withdraw at any 
point in the interconnection process or do not otherwise reach 
commercial operation, unless: (1) the withdrawal does not delay the 
timing of other proposed generating facilities in the same cluster; (2) 
the withdrawal does not increase the cost of network upgrades for other 
proposed generating facilities in the same cluster; (3) the 
interconnection customer withdraws after receiving the most recent 
cluster study report and the costs assigned to the interconnection 
customer have increased 25% compared to the previous cluster study 
report; or (4) the interconnection customer withdraws after receiving 
the individual facilities study report and the costs assigned to the 
interconnection customer have increased by more than 100% compared to 
costs identified in the cluster study report.\1385\ Thus, the 
Commission proposed that interconnection customers would be exempt from 
a withdrawal penalty if the withdrawal does not harm other 
interconnection customers or if the withdrawal follows a significant 
unanticipated increase in network upgrade cost estimates.
---------------------------------------------------------------------------

    \1384\ NOPR, 179 FERC ] 61,194 at P 140.
    \1385\ Id. P 141.
---------------------------------------------------------------------------

    722. The Commission proposed that the withdrawal penalty would 
increase as the interconnection customer moves through the study 
process and would also increase if an interconnection customer provides 
a commercial readiness deposit in lieu of a demonstration of commercial 
readiness.\1386\ For an interconnection customer that provides a 
commercial readiness deposit in lieu of a demonstration of commercial 
readiness, the Commission proposed that its withdrawal penalty would be 
higher and increase as the interconnection customer progresses in the 
interconnection process.
---------------------------------------------------------------------------

    \1386\ Id. P 142 (citing May Joint Task Force Tr. 75:23-76:1 
(Kimberly Duffley) (``I think one of the best practices of the new 
system that [Duke Energy Progress and Duke Energy Carolinas] have 
implemented is the increase of withdrawal penalties as the 
interconnection moves through the process.'')).
---------------------------------------------------------------------------

    723. The Commission proposed that the withdrawal penalty for an 
interconnection customer that provides a commercial readiness deposit 
in lieu of a demonstration of commercial readiness will be the greater 
of the study deposit or: (1) two times the study cost if the customer 
withdraws during the cluster study or after receipt of a cluster study 
report, capped at $1 million; (2) three times the study cost if the 
customer withdraws during the cluster restudy or after receipt of any 
applicable restudy reports, capped at $1.5 million; (3) five times the 
study cost if the customer withdraws during the facilities study, after 
receipt of the individual facilities study report, or after receipt of 
the draft LGIA, capped at $2 million; or (4) nine times the study costs 
if the customer withdraws before achieving commercial operation and 
after executing the LGIA or filing an unexecuted LGIA.\1387\ The 
Commission also proposed that the withdrawal penalty revenues be used 
to fund studies conducted under the cluster study process.
---------------------------------------------------------------------------

    \1387\ Id. P 143.
---------------------------------------------------------------------------

    724. The table below summarizes the proposed withdrawal penalty 
structure for both interconnection requests that have demonstrated 
commercial readiness and those that have not (by instead submitting a 
deposit in lieu of demonstrating commercial readiness).\1388\
---------------------------------------------------------------------------

    \1388\ Id. P 144.

----------------------------------------------------------------------------------------------------------------
                                                                    Total withdrawal
         Phase of withdrawal             Commercial readiness     penalty (if greater     Withdrawal penalty cap
                                       demonstration provided?    than study deposit)
----------------------------------------------------------------------------------------------------------------
1....................................  Yes....................  1 times study costs....  No Cap.
2....................................  Yes....................  1 times study costs....  No Cap.
3....................................  Yes....................  1 times study costs....  No Cap.
LGIA.................................  Yes....................  9 times study costs....  No Cap.
1....................................  No.....................  2 times study costs....  $1 million.
2....................................  No.....................  3 times study costs....  $1.5 million.
3....................................  No.....................  5 times study costs....  $2 million.
LGIA.................................  No.....................  9 times study costs....  No Cap.
----------------------------------------------------------------------------------------------------------------

[[Page 61117]]

    725. The Commission also proposed to add the defined term 
``withdrawal penalty'' to the pro forma LGIP.\1389\ The Commission 
sought comment on: (1) how to define the circumstances in which a 
withdrawal is deemed to have delayed the timing or increased the cost 
of network upgrades for other proposed generating facilities in the 
same cluster, including what criteria should be used to determine 
whether the withdrawal caused the delay or increased cost, and whether 
to establish a threshold for when a delay or increase in cost will 
trigger a withdrawal penalty (and if so, what that threshold should 
be); (2) whether the Commission should consider exceptions to the 
proposed withdrawal penalties beyond those proposed in the NOPR; (3) 
whether withdrawal penalties that increase with proposed generating 
facility size (as measured by MW) would more effectively deter 
withdrawals that cause the greatest harm; and (4) whether a correlation 
exists between the size of a withdrawing proposed generating facility 
and the relative level of harm (in terms of delays and increased cost) 
to other interconnection customers as a result of the withdrawal.\1390\
---------------------------------------------------------------------------

    \1389\ Id. P 145.
    \1390\ Id. PP 145-148.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    726. Multiple commenters generally support the Commission's 
proposed withdrawal penalties and view the proposal as appropriate to 
reduce the volume of speculative interconnection requests.\1391\ 
Environmental Defense Fund states that, if adopted with certain of the 
other NOPR proposals, the Commission's proposed withdrawal penalties 
are appropriate to address the delays and costs caused by speculative 
interconnection requests.\1392\ Eversource states that properly 
calibrated withdrawal penalties are essential to dissuade withdrawals 
and reduce study process delays.\1393\
---------------------------------------------------------------------------

    \1391\ ACE-NY Initial Comments at 7; Ameren Initial Comments at 
18; APPA-LPPC Initial Comments at 17-18; APS Initial Comments at 15; 
CAISO Initial Comments at 21; Consumers Energy Initial Comments at 
5; Dominion Initial Comments at 33; MISO Initial Comments at 66; 
NARUC Initial Comments at 10; National Grid Initial Comments at 26; 
NextEra Initial Comments at 6; NRECA Initial Comments at 9; NV 
Energy Initial Comments at 6; NYTOs Initial Comments at 20-21; Omaha 
Public Power Initial Comments at 9; PPL Initial Comments at 17; 
SoCal Edison Initial Comments at 10; U.S. Chamber of Commerce 
Initial Comments at 9; UMPA Initial Comments at 3-5; Vistra Initial 
Comments at 6-7.
    \1392\ Environmental Defense Fund Initial Comments at 4.
    \1393\ Eversource Initial Comments at 18.
---------------------------------------------------------------------------

    727. MISO supports the Commission's proposal to impose a withdrawal 
penalty on withdrawing interconnection customers, a penalty that MISO 
suggests should be secured by the commercial readiness deposit.\1394\ 
That said, MISO asserts that the study cost for interconnection 
requests is not that substantial, and MISO does not believe that paying 
a withdrawal penalty in the amount of only the study costs would be a 
sufficient deterrent to prevent speculative interconnection requests 
from entering or remaining in the interconnection queue.
---------------------------------------------------------------------------

    \1394\ MISO Initial Comments at 66-67.
---------------------------------------------------------------------------

(b) Comments in Opposition
    728. Many commenters oppose the withdrawal penalty proposal.\1395\ 
CREA and NewSun encourage instead better cost certainty for 
interconnection customers earlier in the study process.\1396\ CREA and 
NewSun suggest that the Commission incorrectly assumes that the 
interconnection customer has adequate visibility into likely 
interconnection costs, and thus the financial viability of its proposed 
generating facility before entering the interconnection queue and 
becoming liable for these penalties. CREA and NewSun state that the 
NOPR provides no realistic path to know likely interconnection costs 
prior to entering the interconnection queue.\1397\
---------------------------------------------------------------------------

    \1395\ CREA and NewSun Initial Comments at 74-77; ENGIE Initial 
Comments at 6; Hydropower Commenters Initial Comments at 26; 
Interwest Initial Comments at 21; Northwest and Intermountain 
Initial Comments at 12; New York State Department Initial Comments 
at 11; Pacific Northwest Organizations Initial Comments at 3-4; 
rPlus Initial Comments at 5; R Street Initial Comments at 12; SEIA 
Initial Comments at 25-27; SEIA Reply Comments at 10-11; Shell 
Initial Comments at 25.
    \1396\ CREA and NewSun Initial Comments at 74, 77.
    \1397\ Id. at 76.
---------------------------------------------------------------------------

    729. ENGIE does not support the implementation of withdrawal 
penalties and notes that withdrawal penalties without meaningful 
opportunity for interconnection customers to exit the interconnection 
process are unlikely to incentivize withdrawal.\1398\ New York State 
Department is skeptical that a withdrawal penalty program will be 
beneficial to ratepayers.\1399\
---------------------------------------------------------------------------

    \1398\ ENGIE Initial Comments at 6.
    \1399\ New York State Department Initial Comments at 11.
---------------------------------------------------------------------------

    730. Pacific Northwest Organizations claim that, without access to 
interconnection cost information and with larger withdrawal penalties, 
independent power producers may be discouraged from entering the 
interconnection queue.\1400\ Some commenters claim that withdrawal 
penalties (including in a transitional cluster study process) can 
result in the potential for discrimination against independent power 
producers.\1401\ These commenters assert that LSEs can recover 
withdrawal penalties they incur from their retail ratepayers, whereas 
independent power producers must absorb these costs and risks in their 
solicitation process bids. Interwest also suggests that the proposed 
withdrawal penalties are less likely to apply to LSEs than to 
independent power producers because LSEs will likely be able to use the 
proposed commercial readiness demonstration path, as opposed to paying 
the deposits in lieu of demonstrating commercial readiness, and would 
thus not be subject to the harsher withdrawal penalties.\1402\ 
Interwest urges the Commission to require waiver of, or a substantial 
reduction in, withdrawal penalties from the transition cluster or 
resource solicitation cluster if the interconnection customer 
participated in an RFP or other competitive solicitation process but 
was not ultimately selected, or if a permit becomes unavailable due to 
some regulatory or regime change.\1403\
---------------------------------------------------------------------------

    \1400\ Pacific Northwest Organizations Initial Comments at 3-4.
    \1401\ Interwest Initial Comments at 21; Northwest and 
Intermountain Initial Comments at 12.
    \1402\ Interwest Reply Comments at 13-14.
    \1403\ Interwest Initial Comments at 21.
---------------------------------------------------------------------------

    731. R Street claims that the proposal risks imposing severe anti-
competitive barriers to entry.\1404\ New York State Department makes 
similar anti-competitive impact arguments.\1405\ R Street asserts that 
imposing financial commitments and readiness requirements can create 
regulatory barriers to entry if they deter interconnection requests for 
commercially viable generating facilities or increase financing 
costs.\1406\ R Street argues that the proposal is misguided because it 
would add another administrative process that increases implementation 
complications and costs.\1407\ R Street suggests that the Commission 
should instead use a simple loss of deposit as its financial lever.
---------------------------------------------------------------------------

    \1404\ R Street Initial Comments at 12.
    \1405\ New York State Department Initial Comments at 11.
    \1406\ R Street Initial Comments at 12.
    \1407\ Id. at 14.
---------------------------------------------------------------------------

    732. rPlus argues that withdrawal penalties, particularly when 
coupled with the proposed study deposit requirements and study cost 
allocations, are unduly discriminatory or punitive to

[[Page 61118]]

pumped storage as compared to other renewable technologies.\1408\ rPlus 
and Hydropower Commenters claim that, under these proposals, a large 
capacity pumped storage project (ranging from 400 MW to over 1,000 MW 
in size, according to rPlus) would expect to hit the maximum deposit 
and/or penalty in every stage of the interconnection process.\1409\ 
rPlus claims that the high cost of entry and the liability associated 
with withdrawal may give large utilities an unfair advantage in 
commercial negotiations.\1410\
---------------------------------------------------------------------------

    \1408\ rPlus Initial Comments at 5.
    \1409\ Id.; Hydropower Commenters Initial Comments at 26.
    \1410\ rPlus Initial Comments at 5.
---------------------------------------------------------------------------

    733. Shell calls for a reconsideration of the withdrawal penalties 
proposed in the NOPR, claiming that the proposal could disrupt project 
development when paired with the proposed commercial readiness 
requirements and financial commitments (for deposits and site 
control).\1411\ Shell suggests that the Commission adopt withdrawal 
penalties modeled on MISO's framework, which encourages interconnection 
customers to withdraw from the interconnection queue with refunded 
deposits rather than penalizing interconnection customers for making 
justifiable decisions. Shell contends that there should only be a large 
penalty for late-stage withdrawals.\1412\ Shell contends that, 
otherwise, the Commission is sending the wrong signal and driving out 
competition without linking the underlying issue of unexpected network 
upgrade costs that typically come from affected system studies that are 
provided very late in the study process.
---------------------------------------------------------------------------

    \1411\ Shell Initial Comments at 9, 24; Shell Reply Comments at 
26.
    \1412\ Shell Initial Comments at 25.
---------------------------------------------------------------------------

    734. Some commenters contend that increasing the amount of money at 
stake for an interconnection customer without providing off-ramps from 
the interconnection process at reasonable decision points where 
previously unavailable information is supplied does not necessarily 
incentivize interconnection customers to exit the interconnection 
queue.\1413\ CREA and NewSun suggest that the proposed withdrawal 
penalties may incentivize an interconnection customer to remain in the 
interconnection queue waiting for other interconnection customers to 
withdraw, and the penalty those interconnection customers pay will 
eventually be distributed to the remaining interconnection customers in 
the cluster, or interconnection customers may elect to remain in the 
interconnection queue in the hopes that others in the cluster withdraw 
to the point where the cost of network upgrades become more 
palatable.\1414\
---------------------------------------------------------------------------

    \1413\ CREA and NewSun Initial Comments at 76; SEIA Initial 
Comments at 25-27; SEIA Reply Comments at 10-11.
    \1414\ CREA and NewSun Initial Comments at 76.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) Withdrawal Penalty Amounts
    735. Several commenters oppose the proposed withdrawal penalty 
amounts.\1415\ AEE argues that the Commission's proposed withdrawal 
penalty amounts are overly punitive, especially for those 
interconnection customers that submit a deposit in lieu of 
demonstrating commercial readiness, which many interconnection 
customers will be forced to do under the Commission's proposed 
commercial readiness requirements.\1416\ AEE and Clean Energy 
Associations assert that the Commission's proposed withdrawal penalty 
amounts also appear arbitrary, with no basis in the costs of conducting 
studies or other relevant factors.\1417\ AEE argues that the Commission 
should reduce these amounts and tie them more closely to its objectives 
and to the study costs that transmission providers are expected to 
incur, which it asserts will avoid turning the penalties into a 
punitive measure that provides a profit opportunity for transmission 
providers.\1418\ AEE contends that the withdrawal penalty frameworks 
and time frames should be designed to discipline the decisions of 
interconnection customers rather than being punitive. Google does not 
support the proposal to impose higher withdrawal penalties on 
interconnection customers that submit a deposit in lieu of 
demonstrating commercial readiness.\1419\
---------------------------------------------------------------------------

    \1415\ AEE Initial Comments at 19; CREA and NewSun Initial 
Comments at 75; Interwest Initial Comments at 22.
    \1416\ AEE Initial Comments at 19.
    \1417\ Id.; Clean Energy Associations Initial Comments at 41.
    \1418\ AEE Initial Comments at 19-20.
    \1419\ Google Initial Comments at 21.
---------------------------------------------------------------------------

    736. Interwest argues that some of the proposed withdrawal 
penalties--those in the range of five to nine times the study costs--
far exceed reasonableness, especially in the face of the potential for 
a myriad of ways in which an LSE can bias the bid review process and 
slow the cluster study process under existing rules without stringent 
oversight.\1420\ Interwest argues that the NOPR does not sufficiently 
acknowledge the need to reform study processes to prevent inaccurate 
studies, which create widely different results from one study to 
another.\1421\ Interwest suggests that these inaccurate studies, along 
with delayed affected system study results, lead to withdrawals, 
strengthening the case that withdrawal penalties should not increase 
dramatically toward the end of the study process and around execution 
of an LGIA without appropriate recourse for the interconnection 
customer. Interwest argues that a 25% increase in study costs from one 
study to another should be a sufficient basis for withdrawal without 
incurring withdrawal penalties, as part of a tariff with incentives for 
transmission providers to provide accurate estimates of network upgrade 
costs. Interwest argues that, for these reasons, withdrawal penalties 
are redundant and punitive when combined with increasingly large at-
risk deposits as proof of commercial readiness.
---------------------------------------------------------------------------

    \1420\ Interwest Initial Comments at 22.
    \1421\ Interwest Reply Comments at 13-14.
---------------------------------------------------------------------------

    737. SDG&E asserts that a withdrawal penalty of nine times the 
study deposit amount will provide a disincentive for late-stage 
withdrawals in certain cases, but that a penalty alone should not be 
relied on in lieu of other financial security mechanisms.\1422\ SDG&E 
maintains that a more reasonable amount for a withdrawal penalty may be 
the greater of nine times the study deposit and a CAISO-style financial 
security posting that is based on factors such as network upgrade and 
interconnection facilities costs.
---------------------------------------------------------------------------

    \1422\ SDG&E Initial Comments at 6.
---------------------------------------------------------------------------

    738. Some commenters argue that the Commission should adopt the 
RTO/ISO model of financial readiness milestones that are tied to 
network upgrade costs.\1423\ Clean Energy Associations submit that 
tying deposits and penalties to network upgrade costs allocated to the 
interconnection customer is superior because network upgrade costs are 
a better indicator of the harm that may be caused by a withdrawal than 
generating facility size.\1424\
---------------------------------------------------------------------------

    \1423\ ACE-NY Initial Comments at 8; AES Initial Comments at 19; 
AES Reply Comments at 3-6; Enel Initial Comments at 4; Invenergy 
Initial Comments at 24; Pine Gate Initial Comments at 34.
    \1424\ Clean Energy Associations Initial Comments at 41.
---------------------------------------------------------------------------

    739. AES contends that tying the withdrawal penalty to the 
percentage of network upgrade deposit at risk provides a better 
incentive for interconnection customers with proposed generating 
facilities with high network upgrade costs to withdraw earlier in the 
interconnection process, rather than risk losing their posted 
security.\1425\ Invenergy suggests that any withdrawal penalty imposed 
after LGIA execution should be tied to assigned

[[Page 61119]]

network upgrade costs and should be subject to a $2 million cap to 
avoid unnecessarily punitive penalties, as the LGIA may impose 
additional financial obligations for construction of the assigned 
upgrades.\1426\ CAISO argues that network upgrade-based financial 
requirements are far more effective than the withdrawal penalties 
proposed in the NOPR because network upgrade-based requirements are 
tied to the project's actual interconnection costs, which correlate 
with its competitiveness to obtain a power purchase agreement and 
therefore its likelihood to remain in the queue.\1427\
---------------------------------------------------------------------------

    \1425\ AES Initial Comments at 19.
    \1426\ Invenergy Initial Comments at 24.
    \1427\ CAISO Initial Comments at 23.
---------------------------------------------------------------------------

    740. NYISO argues that the withdrawal penalty amounts proposed in 
the NOPR, which are tied to study costs, are unlikely to provide 
sufficient capital to cover the costs of constructing the network 
upgrades of withdrawn generating facilities on which other 
interconnection customers are relying.\1428\ SoCal Edison suggests 
that, instead of using study costs as the basis for the withdrawal 
penalty amount, which would not be known until completion of the 
interconnection studies, the Commission should require that withdrawal 
penalties be calculated based on increasing multiples of the study 
deposits, which are known and serve as a proxy of the study 
costs.\1429\
---------------------------------------------------------------------------

    \1428\ NYISO Initial Comments at 25.
    \1429\ SoCal Edison Initial Comments at 10.
---------------------------------------------------------------------------

(2) Proposed Withdrawal Penalty Exemptions
    741. Some commenters support the NOPR proposal to exempt 
interconnection customers from withdrawal penalties in certain 
instances, stating that the proposal achieves a workable balance 
between the needs of interconnection customers and transmission 
providers.\1430\ For example, MISO agrees that interconnection requests 
that experience significant cost increases should be able to withdraw 
without a penalty.\1431\ Omaha Public Power states that the four 
scenarios proposed in the NOPR for interconnection customers to qualify 
for exemptions to withdrawal penalties seem to properly acknowledge 
instances where other interconnection customers are not negatively 
impacted by a withdrawal, or when it is no longer economically viable 
for the interconnection customer to move forward with the generating 
facility due to drastically increased network upgrade costs.\1432\
---------------------------------------------------------------------------

    \1430\ MISO Initial Comments at 68; Omaha Public Power Initial 
Comments at 9-10.
    \1431\ MISO Initial Comments at 68.
    \1432\ Omaha Public Power Initial Comments at 9-10.
---------------------------------------------------------------------------

    742. On the other hand, SEIA contends that, although the NOPR 
proposal exempts interconnection customers from withdrawal penalties if 
there is no impact to other generating facilities in the same cluster, 
withdrawals almost always impact other generating facilities in the 
cluster, such that withdrawal penalties are likely unavoidable.\1433\ 
Pine Gate states that the proposed list of withdrawal penalty 
exemptions is not reflective of an appropriate balance between 
interconnection customer and transmission provider accountability 
because it increases the burden on interconnection customers without 
any increase to accountability for transmission providers.\1434\ 
Pattern Energy disagrees with a standard tied to a potential delay of a 
lower-queued interconnection customer, given the Commission's proposed 
transition to a cluster study approach.\1435\ Pattern Energy contends 
that the only impact that should be relevant to granting an exemption 
is a financial impact.
---------------------------------------------------------------------------

    \1433\ SEIA Initial Comments at 26.
    \1434\ Pine Gate Initial Comments at 34.
    \1435\ Pattern Energy Initial Comments at 33.
---------------------------------------------------------------------------

    743. NRECA supports including the 100% cost increase exemption in 
the final rule, which would apply where there is a large late-stage 
cost increase, making the interconnection request's success 
economically challenging.\1436\ Pattern Energy, on the other hand, 
claims that the Commission's proposal incentivizes transmission 
providers to overestimate costs in cluster studies for fear that there 
will be later, unexpected cost increases in the facilities study, which 
Pattern Energy argues presents a barrier to entry.\1437\ Pine Gate also 
claims that requiring a 100% increase in costs between the facilities 
study phase and the previous cluster study phase in order to allow for 
penalty-free withdrawal exposes interconnection customers to withdrawal 
penalties in instances where costs increase dramatically due to no 
fault of the interconnection customer.\1438\ Several commenters 
recommend that the Commission ensure that any penalties for withdrawal 
account for unanticipated cost increases.\1439\
---------------------------------------------------------------------------

    \1436\ NRECA Initial Comments at 30.
    \1437\ Pattern Energy Initial Comments at 34.
    \1438\ Pine Gate Initial Comments at 35.
    \1439\ Clean Energy Associations Initial Comments at 40 (arguing 
that the Commission should allow interconnection customers to 
withdraw without penalty if costs in a restudy increase by over 25% 
relative to prior study results); CREA and NewSun Initial Comments 
at 78 (suggesting that withdrawal penalties should not apply anytime 
an interconnection customer withdraws after receipt of a system 
impact study, facilities study, or restudy that contains a 25% cost 
increase over the prior study or a 50% cumulative increase over the 
initial study); ENGIE Initial Comments at 7; Invenergy Initial 
Comments at 25 (arguing that the Commission should allow 
interconnection customers to withdraw without penalty if affected 
system study results cause an interconnection customer's costs to 
increase by more than 25% compared to costs allocated to it by the 
host transmission provider in a prior study); Longroad Energy 
Initial Comments at 18 (recommending that the Commission reduce the 
penalty exemption threshold to a cost-increase of only 20% from the 
initial cluster study to the restudy and a cost increase of only 10% 
from the final restudy to the individual cluster facilities study); 
NextEra Initial Comments at 26 (suggesting that a more reasonable 
withdrawal penalty exemption threshold for cost increases for late-
stage withdrawals would be in the range of 30%); [Oslash]rsted 
Initial Comments at 15 (arguing that the Commission should allow 
interconnection customers to withdraw without penalty if costs in a 
restudy increase by over 25% relative to prior study results); 
Pattern Energy Initial Comments at 33 (suggesting that, if costs 
increase by 15% from the first to the second study report, but a 
restudy results in an additional 20% increase compared to the second 
study report, then the total increase from the first study report to 
the restudy report would be 35%, and this total additive percentage 
increase should be deemed sufficient to constitute an excusable 
withdrawal event); Pine Gate Initial Comments at 35.
---------------------------------------------------------------------------

    744. Xcel recommends that the Commission allow an interconnection 
request, submitted by a resource planning entity as agent for an 
interconnection customer, that is withdrawn by the resource planning 
entity because it was not picked in a resource solicitation process, to 
be exempt from withdrawal penalties, as the withdrawal was due to no 
fault of the interconnection customer.\1440\ Xcel states that, other 
than this exemption, the Commission should not expand the exemptions 
from withdrawal penalties beyond those proposed in the NOPR.
---------------------------------------------------------------------------

    \1440\ Xcel Initial Comments at 35.
---------------------------------------------------------------------------

    745. NextEra and Northwest and Intermountain argue that 
interconnection customers should be exempt from withdrawal penalties if 
the transmission provider's or affected system operator's studies or 
posted information are untimely.\1441\
---------------------------------------------------------------------------

    \1441\ NextEra Initial Comments at 26; Northwest and 
Intermountain Initial Comments at 13.
---------------------------------------------------------------------------

    746. NextEra contends that the NOPR does not explain why there are 
different withdrawal penalty levels for interconnection customers 
demonstrating commercial readiness via the proposed non-financial 
demonstration options and those submitting a deposit in lieu of 
demonstrating commercial readiness.\1442\
---------------------------------------------------------------------------

    \1442\ NextEra Initial Comments at 27.
---------------------------------------------------------------------------

    747. Several commenters argue that the proposed exemptions require

[[Page 61120]]

clarification.\1443\ For one, CAISO claims that the exemption criteria, 
as written in the NOPR, are not workable.\1444\ CAISO argues that the 
Commission's description of the exemptions is problematic due to the 
use of ``or,'' which suggests meeting any criterion would relieve the 
interconnection customer of withdrawal penalties. CAISO posits that, 
under the Commission's criteria, a withdrawal could not affect the 
timing of other generating facilities but still increase their costs; 
however, the interconnection customer would meet the first exemption 
and not be subject to withdrawal penalties. CAISO argues that 
withdrawals would never delay the timing of generating facilities in 
the same cluster. CAISO states that a cluster's upgrades are a package, 
and the construction schedule would not change simply because one 
interconnection customer that is sharing upgrades withdraws. CAISO 
suggests that the Commission clarify that, to be exempt from withdrawal 
penalties, each interconnection customer must meet (1) both criterion 
one and two, and (2) criterion three or four.
---------------------------------------------------------------------------

    \1443\ CAISO Initial Comments at 21-22; Environmental Defense 
Fund Initial Comments at 4-5; EEI Initial Comments at 8; EEI Reply 
Comments at 6-7; Eversource Initial Comments at 19; Shell Reply 
Comments at 27.
    \1444\ CAISO Initial Comments at 21-22.
---------------------------------------------------------------------------

    748. Invenergy proposes that the list of exemptions to withdrawal 
penalties be revised to include: (1) the withdrawal does not directly 
cause material delays in the timing of other interconnection requests 
within the same cluster, as determined at the time of withdrawal by the 
transmission provider; or (2) the withdrawal does not directly cause a 
material increase in the costs assigned to other interconnection 
requests within the same cluster, as determined at the time of 
withdrawal by the transmission provider.
    749. Omaha Public Power contends that the exemption to withdrawal 
penalties cannot be applied to the interconnection process as it 
currently functions for those transmission providers that allow for 
overlapping studies (e.g., when a cluster study is being studied prior 
to the conclusion of the preceding cluster study).\1445\ Omaha Public 
Power claims that overlapping studies lead to baseline costs in the 
subsequent cluster studies that are inherently wrong and do not factor 
in the previously existing unfinished cluster studies. Omaha Public 
Power claims that this inaccurate starting point for costs is likely 
higher than what is accurate, and any subsequent restudy will likely 
lead to identification of network upgrades that fall below the 
exemption threshold, subjecting interconnection customers to wrongful 
withdrawal penalties. Omaha Public Power argues that, until an 
interconnection process can be conducted without overlapping studies, 
these exemptions will be woefully misapplied. Southern raises similar 
concerns.\1446\
---------------------------------------------------------------------------

    \1445\ Omaha Public Power Initial Comments at 10.
    \1446\ Southern Initial Comments at 21-22.
---------------------------------------------------------------------------

    750. Yet other commenters believe that the NOPR proposal is too 
lenient.\1447\ NRECA suggests that transmission providers should be 
afforded flexibility whether to adopt exemptions to withdrawal 
penalties related to: (1) not delaying the timing of other 
interconnection requests in the same cluster; (2) not increasing the 
cost of network upgrades for other interconnection requests in the same 
cluster; and (3) withdrawing if the most recent cluster study report 
shows a cost increase of at least 25% compared to the previous cluster 
study report.\1448\ NRECA asserts that these exemptions may or may not 
be needed for a particular transmission provider and potentially may 
allow withdrawals that trigger time-consuming restudy processes. SDG&E 
generally opposes exemptions to withdrawal penalties and claims that 
material modification provisions in the pro forma LGIP already address 
impacts to other interconnection customers.\1449\ SDG&E argues that, 
regardless of the impact to other interconnection customers, there are 
still costs and resources committed between all entities to study and 
assess proposed generating facilities. SDG&E believes that withdrawal 
penalties should apply for all generating facilities, and any 
exemptions should be sparing.
---------------------------------------------------------------------------

    \1447\ NRECA Initial Comments at 30; SDG&E Initial Comments at 
6-7.
    \1448\ NRECA Initial Comments at 30.
    \1449\ SDG&E Initial Comments at 6-7.
---------------------------------------------------------------------------

(3) How To Determine if a Withdrawal Has Delayed or Increased the Cost 
of Network Upgrades for Other Generating Facilities in the Same Cluster
    751. Some commenters argue that it would be difficult to define the 
circumstances under which a withdrawal is deemed to have delayed the 
timing or increased the cost of network upgrades for other 
interconnection requests in the same cluster.\1450\ APS and Bonneville 
argue that attempting to do so would create an undue burden on 
transmission providers, and that the withdrawal of an interconnection 
request could have an impact on generating facilities in a subsequent 
cluster.\1451\ NextEra suggests that one test to determine whether a 
withdrawal delays other interconnection requests could be whether the 
withdrawal delays the planned in-service date of other interconnection 
requests in the same cluster.\1452\ However, NextEra acknowledges that 
even this assessment could be difficult to calculate, as delays could 
not manifest themselves for months or years, other factors could cause 
delays, and interconnection customers could seek to delay their 
generating facilities for commercial reasons. Pattern Energy asserts 
that the Commission must clearly define the standard for timing delays 
and increasing the cost of network upgrades for other interconnection 
customers.\1453\
---------------------------------------------------------------------------

    \1450\ APS Initial Comments at 16-17; Bonneville Initial 
Comments at 12; MISO Initial Comments at 67.
    \1451\ APS Initial Comments at 16-17; Bonneville Initial 
Comments at 12.
    \1452\ NextEra Initial Comments at 26.
    \1453\ Pattern Energy Initial Comments at 33.
---------------------------------------------------------------------------

    752. Bonneville suggests that, similar to the method used to assess 
a material modification under the pro forma LGIP and pro forma SGIP, 
the Commission could provide a non-exhaustive list of examples that 
would be deemed as delaying the timing or increasing the costs of 
network upgrades.\1454\ Bonneville suggests that transmission providers 
could be given discretion to determine whether other withdrawal 
situations that are not listed should fall under this category by 
considering whether the withdrawal has delayed the timing or increased 
the cost of network upgrades for other interconnection requests in a 
cluster.
---------------------------------------------------------------------------

    \1454\ Bonneville Initial Comments at 12.
---------------------------------------------------------------------------

    753. Invenergy argues that transmission providers should not be 
permitted to simply assume that withdrawals cause some harm to other 
interconnection requests and that there should be a requirement for 
transmission providers to perform an analysis to determine whether a 
withdrawal results in material harm to other interconnection requests, 
which interconnection customers could review.\1455\ Invenergy states 
that the analysis of whether a withdrawal causes a cost increase or 
delays the timing for other interconnection requests should be 
performed at each phase of the study process.
---------------------------------------------------------------------------

    \1455\ Invenergy Initial Comments at 26-27.
---------------------------------------------------------------------------

    754. Invenergy requests that the Commission clarify that a 
withdrawal will not delay the timing of another interconnection request 
or increase its network upgrade costs if the withdrawal simply requires 
the transmission

[[Page 61121]]

provider to account for the withdrawal. Invenergy requests that the 
Commission clarify that any delay or cost increase analysis must be 
based on a reasonable analysis and show a direct relationship between 
the withdrawal and the asserted impact on another interconnection 
request.
    755. MISO encourages the Commission to impose the withdrawal 
penalty whenever an interconnection request withdraws from the 
interconnection queue.\1456\ MISO argues that even if after restudy it 
turns out that the withdrawal of an interconnection request did not 
actually increase network upgrade costs to other interconnection 
customers in the cluster, the withdrawal still negatively impacts the 
interconnection queue by increasing uncertainty for other 
interconnection customers, prompting further withdrawals and adding 
administrative cost and burden that impede efficient interconnection 
queue processing. Pattern Energy likewise argues that the withdrawal of 
any interconnection request from the interconnection queue results in 
some form of delay, such as the time taken by a transmission provider 
to perform a review of the potential impacts of the withdrawal, which 
could be interpreted as causing a delay because the withdrawal impact 
analysis could delay the receipt of final study results and 
agreements.\1457\ PJM makes similar arguments.\1458\
---------------------------------------------------------------------------

    \1456\ MISO Initial Comments at 67-68.
    \1457\ Pattern Energy Initial Comments at 33.
    \1458\ PJM Initial Comments at 41.
---------------------------------------------------------------------------

    756. Xcel contends that, if a withdrawal results in a restudy of a 
cluster or subsequent clusters, that restudy will delay the receipt of 
study results, LGIA execution, and the construction of required network 
upgrades.\1459\ Therefore, Xcel argues that any withdrawal that results 
in a restudy should not be exempt from a withdrawal penalty unless the 
commercial operation dates of other impacted interconnection requests 
in the same or subsequent cluster are not impacted. Xcel asserts that 
delaying LGIA execution may negatively impact off-take agreements and 
should also be considered harm to equally or lower-queued 
interconnection customers. Xcel notes that harm is not limited to the 
reallocation of interconnection costs to equally or lower-queued 
interconnection requests. Xcel contends that delays, resulting in 
clogged interconnection queues, can impact resource decisions and thus 
harm interconnection requests not yet in the interconnection queue. 
Xcel argues that, if the withdrawal causes restudy, but the restudy 
does not impact the timing discussed above, then the restudy results 
should be used to determine the impact on costs allocated to equally or 
lower-queued interconnection requests.
---------------------------------------------------------------------------

    \1459\ Xcel Initial Comments at 33-34.
---------------------------------------------------------------------------

    757. Xcel notes that it may be difficult to determine if a single 
withdrawal would have caused harm when multiple interconnection 
requests are withdrawn in the same time frame.\1460\ Xcel generally 
supports penalizing withdrawals if they have a combined impact, as it 
would be difficult, if not impossible and time consuming, to determine 
each individual withdrawal's impact. According to Xcel, if the 
withdrawal penalty was determined on an individual basis, some 
interconnection customers may wait for others to withdraw, then argue 
that their secondary withdrawals did not have an impact because all 
delays and cost impacts were caused by the first withdrawal.
---------------------------------------------------------------------------

    \1460\ Id. at 34.
---------------------------------------------------------------------------

    758. Indicated PJM TOs state that a withdrawal can impose costs on 
other interconnection customers even if it does not delay the timing of 
other proposed generating facilities. Indicated PJM TOs argue that if 
withdrawals impose more network upgrade costs on other interconnection 
customers, it would be unfair to excuse withdrawing interconnection 
customers just because the transmission provider can keep to its 
original timelines.\1461\ Indicated PJM TOs further claim that, 
particularly in a large RTO/ISO, it is not clear how the transmission 
provider would determine that a particular withdrawal did or did not 
delay the processing of other interconnection requests. Indicated PJM 
TOs argue that this criterion for being excused from penalties or 
forfeitures should be eliminated.
---------------------------------------------------------------------------

    \1461\ Indicated PJM TOs Reply Comments at 35-36.
---------------------------------------------------------------------------

(4) Withdrawal Penalty Collection and Distribution
    759. APS seeks clarification on the mechanism the Commission 
proposes for transmission providers to collect withdrawal penalties 
from interconnection customers.\1462\ APS and MISO express concerns 
that, under the withdrawal penalty collection proposal, a transmission 
provider would have to act as a collection agency, which is likely 
unworkable.\1463\ EEI suggests that the Commission institute financial 
assurance requirements for interconnection customers to reduce the 
likelihood that penalized entities are unable to pay the penalties they 
are assessed.\1464\ Eversource asserts that the Commission should set 
clear rules that include policies governing how RTOs/ISOs will collect 
penalties and address potential scenarios in which interconnection 
customers refuse to pay or declare bankruptcy.\1465\ MISO claims that 
interconnection customers can structure the businesses behind the 
interconnection request in such a way so that the legal entity would be 
very difficult to collect from.\1466\
---------------------------------------------------------------------------

    \1462\ APS Initial Comments at 16.
    \1463\ Id.; MISO Initial Comments at 69.
    \1464\ EEI Initial Comments at 8.
    \1465\ Eversource Initial Comments at 19.
    \1466\ MISO Initial Comments at 69.
---------------------------------------------------------------------------

    760. Some commenters do not support the Commission's proposal to 
require withdrawal penalty revenues to be used to fund studies 
conducted under the cluster study process.\1467\ CAISO states that 
transmission providers already have provisions specifying where non-
refundable funds go, and using them for interconnection studies would 
require careful accounting without relieving study burdens.\1468\ 
NextEra and PJM suggest that transmission providers should be allowed 
to use forfeited funds to help pay for increased network upgrade costs 
incurred by other interconnection customers due to a withdrawal.\1469\ 
Invenergy asserts that excess funds should be applied to offset network 
upgrade costs assigned through that cluster study process in proportion 
to any upgrade costs that were directly shifted from a withdrawn 
interconnection customer.\1470\ RWE Renewables assert that withdrawal 
penalties should be used to create meaningful decision points for 
interconnection customers, to discern whether they are willing to 
commit resources to each particular generating facility.\1471\ RWE 
Renewables and Interwest contend that withdrawal penalties should be 
allocated between and among different clusters for transmission 
expansion, so that they benefit load and interconnection customers, 
rather than restudies, which they believe will not be needed as 
frequently in the proposed cluster study process.\1472\
---------------------------------------------------------------------------

    \1467\ CAISO Initial Comments at 22; Interwest Reply Comments at 
14; NextEra Initial Comments at 27-28; PJM Initial Comments at 39; 
RWE Renewables Initial Comments at 2.
    \1468\ CAISO Initial Comments at 22.
    \1469\ NextEra Initial Comments at 27-28; PJM Initial Comments 
at 39.
    \1470\ Invenergy Initial Comments at 27-28.
    \1471\ RWE Renewables Initial Comments at 2.
    \1472\ Id.; Interwest Reply Comments at 14.
---------------------------------------------------------------------------

    761. CAISO opposes the NOPR proposal to cap withdrawal

[[Page 61122]]

penalties.\1473\ CAISO contends that larger projects create the most 
churn in queue, and projects that cannot demonstrate commercial 
readiness should be the most likely to withdraw. CAISO argues that 
withdrawal penalty caps will disproportionately affect smaller and more 
competitive interconnection requests more than larger and less 
competitive interconnection requests and suggests that the Commission 
remove the withdrawal penalty caps so the withdrawal penalties affect 
interconnection customers equally.
---------------------------------------------------------------------------

    \1473\ CAISO Initial Comments at 24.
---------------------------------------------------------------------------

    762. Pattern Energy suggests that, in addition to the Commission's 
proposed use of withdrawal penalties to defray future study costs, the 
Commission should designate a portion of any withdrawal penalties to be 
used for recruitment, retention, and performance bonuses for engineers, 
administrators, and/or consultants, who can then be deployed to help 
alleviate queue backlogs.\1474\
---------------------------------------------------------------------------

    \1474\ Pattern Energy Initial Comments at 34.
---------------------------------------------------------------------------

    763. Other commenters request clarification of the proposal for 
distribution of withdrawal penalty funds. AES and EDF Renewables argue 
that it is critical that the Commission clarify that transmission 
providers do not receive any benefits from withdrawal fee and non-
refundable deposit proceeds; otherwise, they argue, transmission 
providers would be financially incentivized to force interconnection 
customers to withdraw.\1475\ Several commenters request clarification 
of the Commission's intent for excess money that remains after funding 
any appropriate restudies for the current cluster, and some of these 
commenters have suggested uses for this excess.\1476\ AES asserts that 
any withdrawal fees and non-refundable deposits collected should go 
towards improving the interconnection process.\1477\ EDF Renewables 
suggests that any remainder should be refunded to the interconnection 
customer.\1478\ On the other hand, Southern opposes refunding excess 
penalty amounts to the interconnection customer and proposes that any 
remaining amounts be applied to network upgrades needed in the same 
cluster or treated as a revenue credit against the revenue requirement 
in the determination of transmission rates.\1479\ APS suggests that the 
remainder act as a credit towards the transmission provider's 
transmission rates, as this method would guarantee that all 
transmission customers benefit from the penalties.\1480\
---------------------------------------------------------------------------

    \1475\ AES Initial Comments at 19-20; EDF Renewables Initial 
Comments at 7.
    \1476\ AES Initial Comments at 19-20; APS Initial Comments at 
16; EDF Renewables Initial Comments at 7; Invenergy Initial Comments 
at 27-28; ISO-NE Initial Comments at 33; Southern Initial Comments 
at 22.
    \1477\ AES Initial Comments at 19-20.
    \1478\ EDF Renewables Initial Comments at 7.
    \1479\ Southern Initial Comments at 22.
    \1480\ APS Initial Comments at 16.
---------------------------------------------------------------------------

    764. Shell claims that withdrawal penalties will accumulate faster 
than they may be spent by the relevant transmission provider.\1481\ 
Therefore, Shell asserts that the Commission must address the 
following: (1) the system of independent checks and balances that 
transmission providers will employ to ensure that only specific 
individuals have access to the withdrawal penalty account; (2) the 
average cost of a cluster study from start to finish so that, if a 
withdrawal penalty is forfeited, it can be determined how many future 
cluster studies the transmission provider could expect to perform with 
forfeited funds; (3) if funds from a withdrawal penalty are used to pay 
for future study costs, whether future interconnection customers must 
still post a study deposit; and (4) if a withdrawal penalty account 
balance accumulates faster than funds can be spent, what independent 
system of checks and balances transmission providers will use to ensure 
that their staff and/or consultants do not overcharge for their 
services related to studies.
---------------------------------------------------------------------------

    \1481\ Shell Initial Comments at 18-19.
---------------------------------------------------------------------------

(d) Requests for Flexibility, Clarification, or Technical Conference
    765. Some commenters would prefer that the Commission allow for 
transmission providers to craft and use their own withdrawal penalty 
structure instead of having a standardized approach for all 
transmission providers.\1482\ AEP supports the adoption of withdrawal 
penalties with reasonable penalty-free off ramps but asserts that this 
is an area in which flexibility should be permitted, particularly where 
alternative approaches already have been through robust stakeholder 
processes.\1483\ NYTOs suggest that there should be flexibility 
regarding the amount of the withdrawal penalties, which NYTOs argue 
should be tied to each transmission provider's and associated 
transmission owners' interconnection processes.\1484\ Pacific Northwest 
Utilities argue that the Commission should allow flexibility as to the 
timing of the penalties.\1485\ Pacific Northwest Utilities also request 
flexibility to define their own requirements for withdrawal penalties 
to limit interconnection queue overcrowding.\1486\ Interwest contends 
that the Commission should not attempt to predetermine the amount of 
withdrawal penalties in a rulemaking proceeding with limited evidence; 
rather, the Commission should require that transmission providers 
develop appropriate mechanisms and determine appropriate monetary 
amounts to substantially reduce the risk that the efforts of 
interconnection customers are not thwarted or delayed by others' overly 
speculative interconnection requests.\1487\
---------------------------------------------------------------------------

    \1482\ AEP Initial Comments at 24; Avangrid Initial Comments at 
9; Avangrid Reply Comments at 4; CREA and NewSun Initial Comments at 
77-78; Dominion Initial Comments at 34; Indicated PJM TOs Initial 
Comments at 33; NYISO Initial Comments at 24; NYTOs Initial Comments 
at 21; Omaha Public Power Initial Comments at 11; OMS Initial 
Comments at 13; Pacific Northwest Utilities Initial Comments at n.6; 
PJM Initial Comments at 41; SDG&E Initial Comments at 6; SEIA 
Initial Comments at 27; Southern Initial Comments at 20; Shell 
Initial Comments at 24-25; SPP Initial Comments at 11.
    \1483\ AEP Initial Comments at 23-24.
    \1484\ NYTOs Initial Comments at 21.
    \1485\ Pacific Northwest Utilities Initial Comments at 2, 4-5, & 
n.6.
    \1486\ Id. at 2.
    \1487\ Interwest Reply Comments at 13.
---------------------------------------------------------------------------

    766. Some commenters seek general clarification on several of the 
withdrawal penalty proposals. For example, NV Energy requests 
clarification on whether, if a withdrawal penalty is deemed appropriate 
at the time an interconnection customer withdraws its interconnection 
request, that the interconnection customer is charged both the actual 
costs incurred to perform studies and the applicable withdrawal penalty 
(i.e., two separate charges).\1488\
---------------------------------------------------------------------------

    \1488\ NV Energy Initial Comments at 6-7.
---------------------------------------------------------------------------

    767. NV Energy seeks clarification, if an interconnection 
customer's generating facility does not achieve commercial operation, 
whether the nine times the actual study cost deposit would be applied 
toward its withdrawal penalties, and whether the interconnection 
customer would be charged nine times the actual study costs.
    768. Southern suggests that, in the NOPR's proposed definition of 
``withdrawal penalty'' and in the exemptions to that penalty, the 
phrase ``the commercial operation date in the interconnection request'' 
should replace the phrase ``commercial operation,'' such that the 
definition would read ``the penalty assessed by Transmission Provider 
to an Interconnection Customer that chooses to withdraw from the queue 
or does not otherwise reach the Commercial Operation Date in the

[[Page 61123]]

Interconnection Request.'' \1489\ Southern argues that to be consistent 
and clear with pro forma LGIP section 3.7.1.1, the definition of 
withdrawal penalty must be revised to reflect that the withdrawal 
penalty is applicable if the interconnection customer is deemed 
withdrawn.
---------------------------------------------------------------------------

    \1489\ Southern Initial Comments at 21-22.
---------------------------------------------------------------------------

    769. Invenergy requests that the Commission clarify that, to the 
extent withdrawal penalty amounts are used to fund some portion of an 
interconnection study, that it does not reduce the transmission 
provider's potential exposure for penalties in the event that study is 
not timely completed.\1490\
---------------------------------------------------------------------------

    \1490\ Invenergy Initial Comments at 28.
---------------------------------------------------------------------------

    770. Invenergy requests that the Commission clarify that, to the 
extent any post-LGIA withdrawal penalty is imposed, it is offset by the 
deposit posted at LGIA execution and not additional to that deposit, 
which would be unreasonable and unnecessarily punitive.\1491\
---------------------------------------------------------------------------

    \1491\ Id. at 24.
---------------------------------------------------------------------------

    771. MISO encourages the Commission to bolster the definitions of 
``commercial readiness deposit,'' ``study deposit,'' and ``withdrawal 
penalty'' to clearly enable the transmission provider to apply those 
deposits toward the withdrawal penalty.\1492\
---------------------------------------------------------------------------

    \1492\ MISO Initial Comments at 68-69.
---------------------------------------------------------------------------

    772. CAISO seeks clarification that the NOPR's proposed withdrawal 
penalties would not displace transmission providers' other existing 
procedures and penalties that incentivize interconnection customers to 
withdraw earlier rather than later and cites its own requirement that 
interconnection customers post financial security based on their 
allocated network upgrade costs.\1493\
---------------------------------------------------------------------------

    \1493\ CAISO Initial Comments at 22-23.
---------------------------------------------------------------------------

    773. NV Energy requests that the Commission clarify what happens if 
only a portion of an interconnection request is brought to commercial 
operation, as it relates to withdrawal penalties and the construction 
of network upgrades.\1494\
---------------------------------------------------------------------------

    \1494\ NV Energy Initial Comments at 7.
---------------------------------------------------------------------------

    774. Tri-State requests clarification on the meaning of ``previous 
withdrawal penalty revenue received'' in section 3.7.1.1 of the pro 
forma LGIP \1495\ and requests clarification on whether section 3.7.1.2 
of the pro forma LGIP includes the paragraph after (c) regarding 
commercial operation.
---------------------------------------------------------------------------

    \1495\ Tri-State Initial Comments at 28.
---------------------------------------------------------------------------

(e) Alternatives and Miscellaneous
    775. Some commenters provide comments in response to the 
Commission's query on whether a correlation exists between the size of 
a withdrawing proposed generating facility and the relative level of 
harm, in terms of delays and increased cost, to other interconnection 
customers as a result of the withdrawal.\1496\ Some commenters indicate 
that there can be a correlation between the size of a withdrawing 
proposed generating facility and the relative level of harm caused by 
the withdrawal and encourage withdrawal penalties that increase with 
the proposed generating facility size.\1497\ For example, Idaho Power 
contends that large generating facilities typically trigger more 
expensive network upgrades which, when withdrawn, are more likely to 
trigger restudies.\1498\ Other commenters do not support withdrawal 
penalties that increase based on the size of a generating 
facility.\1499\ APS argues that the determinant of ``relative level of 
harm'' is entirely subjective to the transmission provider and could 
lead to litigation.\1500\ APS argues that the location of the 
interconnection request is more closely correlated with the effect on 
other interconnection customers than is the size of a proposed 
generating facility. Xcel states that, although larger generating 
facilities tend to have a larger impact, if the total impact to other 
projects is calculated as a combined impact, then the size of the 
project should not impact the withdrawal penalty calculation.\1501\
---------------------------------------------------------------------------

    \1496\ NOPR, 179 FERC ] 61,194 at P 148.
    \1497\ Avangrid Initial Comments at 20; Clean Energy States 
Initial Comments at 10; Enel Initial Comments at 35; Idaho Power 
Initial Comments at 8; PPL Initial Comments at 17.
    \1498\ Idaho Power Initial Comments at 8.
    \1499\ APS Initial Comments at 17; Xcel Initial Comments at 35.
    \1500\ APS Initial Comments at 17.
    \1501\ Xcel Initial Comments at 35.
---------------------------------------------------------------------------

    776. [Oslash]rsted expresses concern that relatively small 
generating facilities (by MW) that fail to demonstrate commercial 
readiness and are forced to withdraw from the interconnection queue 
pose significant threats to the efficient management of the cluster 
study process and recommends that withdrawal penalties be correlated to 
an interconnection customer's commercial readiness.\1502\
---------------------------------------------------------------------------

    \1502\ [Oslash]rsted Initial Comments at 13.
---------------------------------------------------------------------------

    777. AEP supports the idea of off-ramp opportunities at specific 
times in the cluster study process rather than having to analyze 
individual withdrawal impacts throughout a cluster study process.\1503\ 
AEP contends that such an approach should limit restudies and minimize 
delays to remaining interconnection customers. Similarly, PJM asserts 
that only allowing withdrawals during certain decision points ensures 
that studies start and finish at the same time and that the cluster 
status is maintained during the duration of the study.\1504\ According 
to PJM, allowing withdrawals at any point in the study process, as 
proposed in the NOPR, even with relevant penalties assessed, will cause 
cascading restudies and negative impacts on other interconnection 
customers in a cluster.
---------------------------------------------------------------------------

    \1503\ AEP Initial Comments at 24.
    \1504\ PJM Initial Comments at 41.
---------------------------------------------------------------------------

    778. SPP states that, under its current LGIP, interconnection 
customers provide progressively increasing financial security deposits 
at each stage of the study process, and the amounts of the financial 
security deposits required to enter into later stages of the study 
process are based on the amount of network upgrade costs assigned in 
the previous stage, which it asserts is better related to the risk and 
harm of a withdrawal than the NOPR proposal.\1505\
---------------------------------------------------------------------------

    \1505\ SPP Initial Comments at 11.
---------------------------------------------------------------------------

    779. Rather than being assessed withdrawal penalties, CREA and 
NewSun assert that interconnection customers should be refunded any 
unused study deposits.\1506\ CREA and NewSun argue that penalties 
should apply only to deter wrongful conduct that the interconnection 
customer can avoid committing and should not be used as an arbitrary 
barrier to market entry.\1507\
---------------------------------------------------------------------------

    \1506\ CREA and NewSun Initial Comments at 77.
    \1507\ Id. at 74-75.
---------------------------------------------------------------------------

iii. Commission Determination
    780. We adopt, with modifications, the NOPR proposal to impose 
withdrawal penalties on interconnection customers for withdrawing their 
interconnection requests from the interconnection queue, absent 
qualification for one of the limited exemptions, as discussed below. We 
add the defined term ``withdrawal penalty,'' as modified below, to the 
pro forma LGIP; revise section 3.7 of the pro forma LGIP; and add 
sections 3.7.1, 3.7.1.1, and 3.7.1.2 to the pro forma LGIP, with the 
modifications to the NOPR proposal discussed below. However, we decline 
to adopt the withdrawal penalty caps proposed in the NOPR.
    781. We find that, along with the other reforms adopted in this 
final rule, adopting a withdrawal penalty framework is needed to remedy 
the issues regarding speculative interconnection requests, including

[[Page 61124]]

study delays from overcrowded interconnection queues and the harms to 
the function of the interconnection queue that occur when 
interconnection customers withdraw from the interconnection queue at 
various stages of the study process. We believe that withdrawal 
penalties--as adopted herein--will encourage interconnection customers 
to ensure that their proposed generating facilities are likely 
commercially viable when they submit their interconnection requests 
because withdrawal, in most instances, will incur a penalty. We adopt 
withdrawal penalties that increase in amount as interconnection 
customers proceed through the interconnection process in order to 
ensure that interconnection customers continue to evaluate whether 
their proposed generating facilities are commercially viable, thereby 
reducing the number of late-stage withdrawals and accompanying 
restudies.\1508\ We additionally modify the proposal, as discussed 
below, regarding how the withdrawal penalty funds are distributed. 
Specifically, after withdrawal penalty funds are used to fund studies 
conducted under the cluster study process in the same cluster, as 
proposed in the NOPR, we modify the proposal to require any remaining 
withdrawal penalty funds be used to offset net increases to network 
upgrade cost assignments experienced by interconnection customers from 
the same cluster that remain in the interconnection queue and are 
directly affected by the withdrawal of an interconnection request 
because they previously shared an obligation to fund a network upgrade 
\1509\ with the withdrawn interconnection request in the same 
cluster.\1510\ If the interconnection customer withdraws before it 
executes its LGIA or requests to file its LGIA unexecuted and after the 
interconnection customers in the same cluster that the withdrawn 
interconnection customer participated in have executed LGIAs, requested 
their LGIAs to be filed unexecuted, or withdrawn (or have been deemed 
withdrawn), any remaining withdrawal penalty funds not applied to study 
costs or net increases in network upgrade cost assignments must be 
returned to the withdrawn interconnection customer.\1511\
---------------------------------------------------------------------------

    \1508\ See RWE Renewables Initial Comments at 2 (asserting that 
withdrawal penalties should be used to create meaningful decision 
points for interconnection customers to demonstrate project 
commitment through the interconnection process).
    \1509\ Sharing an obligation means (1) interconnecting to the 
same substation network upgrade, or (2) in the case of a system 
network upgrade, where interconnection customers are identified 
through the proportional impact method, as contributing to the need 
for the same system network upgrade.
    \1510\ See Invenergy Initial Comments at 27-28; NextEra Initial 
Comments at 27-28; PJM Initial Comments at 39; Southern Initial 
Comments at 22 (suggesting that transmission providers should be 
allowed to use forfeited funds to help pay for increased network 
upgrade costs incurred by other interconnection customers in the 
same cluster due to a withdrawal). We disagree with RWE Renewables 
and Interwest that withdrawal penalties should be allocated between 
and among different clusters because we find that withdrawal 
penalties should only be allocated to interconnection customers that 
are directly affected by a withdrawal because they share an 
obligation to fund a network upgrade. See RWE Renewables Initial 
Comments at 2; Interwest Reply Comments at 14.
    \1511\ See EDF Renewables Initial Comments at 7.
---------------------------------------------------------------------------

    782. As explained in section II of this final rule, we find that 
Commission-jurisdictional rates have been rendered unjust and 
unreasonable due to speculative interconnection requests that enter and 
remain in the interconnection queue. By incentivizing interconnection 
customers to submit interconnection requests only for proposed 
generating facilities that they believe will be commercially viable and 
to remain in the interconnection queue only as long as that continues 
to be true, and by offsetting increases in network upgrade cost 
responsibility experienced by interconnection customers directly 
affected by a withdrawal because they share an obligation to fund a 
network upgrade with the withdrawn interconnection request in the same 
cluster, we believe that the withdrawal penalty requirements will work 
in tandem with the other reforms adopted in this final rule to remedy 
those unjust and unreasonable rates.
    783. Specifically, we adopt the NOPR proposal, with modification, 
to revise the pro forma LGIP to require the transmission provider to 
assess withdrawal penalties, unless an exemption applies at any point 
in the interconnection process. The withdrawal penalties will be 
applied to an interconnection customer if: (1) the interconnection 
customer withdraws its interconnection request at any point in the 
interconnection process; (2) the interconnection customer's 
interconnection request has been deemed withdrawn by the transmission 
provider at any point in the interconnection process; or (3) the 
interconnection customer's generating facility does not reach 
commercial operation (such as when an interconnection customer's LGIA 
is terminated prior to reaching commercial operation). We note that a 
withdrawal could trigger minor adjustments to the study results of the 
remaining equally- or lower-queued interconnection requests that do not 
represent a significant harm to those remaining in the queue. 
Therefore, we are modifying the NOPR proposal to require the 
transmission provider to assess a withdrawal penalty only if the 
withdrawal has a material impact on the cost or timing of any 
interconnection requests with an equal or lower queue position. If the 
transmission provider determines that the impact of the withdrawal is 
immaterial, the transmission provider must not assess a withdrawal 
penalty.
    784. We adopt this provision in place of the NOPR proposal to 
exempt interconnection customers from withdrawal penalties if: (1) the 
withdrawal does not delay the timing of other proposed generating 
facilities in the same cluster; or (2) the withdrawal does not increase 
the cost of network upgrades for other proposed generating facilities. 
We adopt the NOPR proposal that the interconnection customer will also 
be exempt from paying a withdrawal penalty if (1) the interconnection 
customer withdraws its interconnection request after receiving the most 
recent cluster study report and the network upgrade costs assigned to 
the interconnection customer's request have increased 25% compared to 
the previous cluster study report, or (2) the interconnection customer 
withdraws its interconnection request after receiving the individual 
facilities study report and the network upgrade costs assigned to the 
interconnection customer's request have increased by more than 100% 
compared to costs identified in the cluster study report. Accordingly, 
with these exemptions from the withdrawal penalty, the required 
withdrawal penalty approach adopted herein does not allow for penalties 
if the impact of the withdrawal is immaterial to other interconnection 
customers or if the withdrawal follows significant, unanticipated 
increases in network upgrade cost estimates.
    785. For the withdrawal penalty exemptions, we clarify that the 
relevant cost increases are network upgrade cost estimate increases, 
and we adopt revisions to the pro forma LGIP accordingly. This 
clarification is consistent with the Commission's description of these 
exemptions in the NOPR: ``Thus, under this proposal, interconnection 
customers would be exempt from a withdrawal penalty . . . if the 
withdrawal follows a significant unanticipated increase in network 
upgrade cost estimates.'' \1512\
---------------------------------------------------------------------------

    \1512\ NOPR, 179 FERC ] 61,194 at P 141 (emphasis added).

---------------------------------------------------------------------------

[[Page 61125]]

    786. We disagree with commenters that the thresholds to trigger the 
exemptions--a 25% increase in estimated network upgrade costs above the 
cluster study report estimate or a 100% increase in estimated network 
upgrade costs in the facilities study report--are too high. As an 
initial matter, the potential interconnection customer will have access 
to heatmap information, as required in this final rule, that will allow 
it to evaluate project feasibility without a financial commitment and 
thereby avoid potential withdrawal penalty risk. As stated by Omaha 
Public Power and Southern, upon entering the interconnection queue and 
receiving the estimates provided in the cluster study report, the 
interconnection customer is aware that the estimates may change. 
Additionally, we find that the trigger thresholds are set at an amount 
that provides sufficient room for estimates to change as the cluster 
evolves while limiting interconnection customer exposure to withdrawal 
penalties when such estimates change by a significant amount. Moreover, 
the increasing threshold triggers reflect the fact that estimates 
should improve in accuracy as interconnection customers move through 
the interconnection process and should increasingly disincentivize 
commercially non-viable generating facilities from staying in the 
interconnection queue. An interconnection customer will know to factor 
in both the cost estimates and the potential withdrawal penalty but 
also the exemption trigger thresholds as it proceeds through the 
interconnection queue.
    787. We do not believe that interconnection customers will be 
subject to ``wrongful withdrawal penalties'' as suggested by some 
commenters. In addition, the withdrawal penalty exemptions are designed 
to allow penalty-free withdrawal if the withdrawal does not materially 
harm other interconnection customers or if the withdrawal follows a 
significant unanticipated increase in network upgrade cost estimates. 
The withdrawal penalty exemptions are not designed to mitigate all 
business risk associated with interconnecting a new generating 
facility. The withdrawal penalty structure adopted herein, where the 
withdrawal penalty at the earlier stages of the interconnection process 
is generally lower than the withdrawal penalty at later stages also 
lessens the cost exposure for an interconnection customer that 
withdraws at an earlier stage, when the impact of the withdrawal is 
less disruptive to the administration of the interconnection queue and 
other interconnection customers. We find that, by increasing the 
withdrawal penalty amounts as the interconnection customer proceeds 
through the interconnection queue, interconnection customers will be 
incentivized to withdraw non-viable interconnection requests earlier in 
the process, leading to fewer late-stage withdrawals.
    788. We also disagree with commenters that request additional 
exemptions to the withdrawal penalty structure. We believe that the 
withdrawal penalty exemptions and withdrawal penalty structure, as 
modified by this final rule, will deter unwarranted assessments of 
withdrawal penalties.
    789. Regarding commenters' requests for clarification concerning 
how to determine whether a withdrawal impacts other interconnection 
requests with the same or lower queue positions for purposes of 
assessing qualification for an exemption to a withdrawal penalty, we 
defer to the transmission provider's discretion because the 
transmission provider is best suited to determine whether a withdrawal 
has a material impact on the cost or timing of any interconnection 
customer with the same or lower queue position.
    790. We do not adopt the NOPR proposal regarding withdrawal penalty 
calculations for interconnection customers that provide demonstrations 
of commercial readiness because we do not adopt the non-financial 
commercial readiness demonstration options in this final rule, as 
discussed above in section III.A.6.c.iii. Instead, we modify the 
proposed penalty structure to base the withdrawal penalty calculation 
on an increasing percentage of the cost of the identified network 
upgrades assigned to the interconnection customer as the 
interconnection customer moves through the interconnection queue.\1513\ 
We also decline to adopt the withdrawal penalty caps proposed in the 
NOPR. We believe that this structure will provide better financial 
incentives for interconnection customers to avoid late-stage 
withdrawals that cause the greatest disruption to interconnection queue 
processing via restudies and delays because interconnection customers 
will be subject to higher withdrawal penalties late in the 
interconnection process.
---------------------------------------------------------------------------

    \1513\ See Invenergy Initial Comments at 27-28; NextEra Initial 
Comments at 27-28; PJM Initial Comments at 39; Southern Initial 
Comments at 22 (suggesting that transmission providers should be 
allowed to use forfeited funds to help pay for increased network 
upgrade costs incurred by other interconnection customers in the 
same cluster due to a withdrawal).
---------------------------------------------------------------------------

    791. With regard to the withdrawal penalty calculation structure 
more specifically, we modify the NOPR proposal and require that, unless 
an interconnection customer qualifies for one of the stated exemptions 
discussed above, the transmission provider must assess a withdrawal 
penalty on an interconnection customer with a proposed generating 
facility that does not reach commercial operation based either on the 
actual study costs or on a percentage of the interconnection customer's 
assigned network upgrade costs, depending on what phase the 
interconnection customer withdraws its interconnection request. Thus, 
the withdrawal penalty for an interconnection customer will be 
calculated as the greater of the study deposit or: (1) two times the 
study cost if the interconnection customer withdraws during the cluster 
study or after receipt of a cluster study report; (2) 5% of the 
interconnection customer's identified network upgrade costs if the 
interconnection customer withdraws during the cluster restudy or after 
receipt of any applicable restudy reports; (3) 10% of the 
interconnection customer's identified network upgrade costs if the 
interconnection customer withdraws during the facilities study, after 
receipt of the individual facilities study report, or after receipt of 
the draft LGIA; or (4) 20% of the interconnection customer's identified 
network upgrade costs if, after executing, or requesting to file 
unexecuted, the LGIA, the interconnection customer's LGIA is terminated 
before its generating facility achieves commercial operation. The table 
below summarizes the withdrawal penalty structure adopted herein.

------------------------------------------------------------------------
                                              Total withdrawal  penalty
            Phase of withdrawal                (if greater than study
                                                      deposit)
------------------------------------------------------------------------
Initial Cluster Study.....................  2 times study costs.
Cluster Restudy...........................  5% of network upgrade costs.
Facilities Study..........................  10% of network upgrade
                                             costs.
After Execution of, or After the Request    20% of network upgrade
 to File Unexecuted, the LGIA.               costs.
------------------------------------------------------------------------

    792. We find that the withdrawal penalty structure adopted herein, 
which requires larger withdrawal penalties as the interconnection 
customer progresses through the interconnection process, combined with 
the exemptions, strikes the proper balance between enabling 
interconnection customers that possess

[[Page 61126]]

imperfect information when entering into and remaining in the 
interconnection queue to make withdrawal decisions and deterring 
speculative interconnection requests from entering into and remaining 
in the queue when they are unlikely to be completed, to the detriment 
of other interconnection customers, especially when these 
interconnection requests are withdrawn at later stages of the 
interconnection process.
    793. We decline to adopt the withdrawal penalty caps proposed in 
the NOPR because such caps would mute the economic signals that 
withdrawal penalties are intended to send to interconnection customers 
in the interconnection queue. The withdrawal penalty structure is meant 
to incentivize interconnection customers to withdraw from the 
interconnection queue upon receipt of network upgrade cost assignments 
that make the interconnection request commercially non-viable. However, 
withdrawal penalty caps would shield interconnection customers that 
withdraw due to higher-cost network upgrades from consequences 
proportional to the impact of that withdrawal, which can drive 
cascading withdrawals, creating the need for restudies and leading to 
delays. We accordingly agree with CAISO that the withdrawal penalty 
caps proposed in the NOPR would disproportionately benefit 
interconnection requests for larger generating facilities.\1514\ We 
find that, while withdrawal penalty caps protect interconnection 
customers that are allocated relatively high network upgrade costs, 
they offer no such commensurate protection for interconnection 
customers with lower network upgrade cost assignments, reflecting an 
imbalanced withdrawal penalty structure.
---------------------------------------------------------------------------

    \1514\ See CAISO Initial Comments at 23-24.
---------------------------------------------------------------------------

    794. We also adopt and modify the proposed definition of 
``withdrawal penalty'' in section 1 of the pro forma LGIP to address 
situations in which it may be unclear what it means to be withdrawn 
from the interconnection queue. Specifically, we clarify that a 
withdrawal penalty applies when an interconnection customer actively 
chooses to withdraw its interconnection request but also when its 
interconnection request is deemed to have been withdrawn from the 
interconnection queue for one reason or another, or if it otherwise 
does not reach commercial operation, per the terms of the pro forma 
LGIP.
    795. Commenters observe that, under the NOPR proposal, 
interconnection customers with large projects (in terms of MW) would be 
subject to large withdrawal penalties.\1515\ While this is true for the 
initial withdrawal penalty, which continues to be based on project size 
because it is tied to study costs, the modification to the NOPR 
proposal described above, where later withdrawal penalties are based on 
percentages of identified network upgrade costs, reflects the potential 
impact of a withdrawal on the remaining interconnection customers in a 
cluster. Additionally, as some commenters point out, there is typically 
a correlation between the size of the proposed generating facility and 
the relative harm to other interconnection customers from the 
withdrawal of the interconnection request, so we believe that basing 
the initial withdrawal penalty on project size is appropriate.\1516\
---------------------------------------------------------------------------

    \1515\ See Hydropower Commenters Initial Comments at 26; rPlus 
Initial Comments at 5.
    \1516\ Avangrid Initial Comments at 20; CAISO Initial Comments 
at 24; Idaho Power Initial Comments at 8; National Grid Initial 
Comments at 26-27; PPL Initial Comments at 17.
---------------------------------------------------------------------------

    796. Because we modify the process for distributing withdrawal 
penalty funds in response to comments, as described below, transmission 
providers will not accumulate large amounts of funds from withdrawal 
penalties, and therefore Shell's concerns are moot.\1517\
---------------------------------------------------------------------------

    \1517\ Shell Initial Comments at 18-19.
---------------------------------------------------------------------------

    797. Furthermore, we believe the proposed pro forma LGIP section 
3.7.1.2 requirement that transmission providers post on their OASIS 
site, and update quarterly, the balance of withdrawal penalty revenue 
held by them but not yet dispersed, and the instructions of how to 
distribute withdrawal penalty funds contained in this provision provide 
sufficient transparency to help interested parties understand, monitor, 
and review withdrawal penalty funds. Transmission providers have 
substantial experience collecting and accounting for fees assessed to 
customers, and we will not mandate here what accounting method they 
should use for the collection and tracking of withdrawal penalties.
    798. With respect to the distribution of withdrawal penalty funds, 
we adopt the NOPR proposal to require transmission providers to use 
withdrawal penalty funds to fund studies and restudies conducted under 
the cluster study process, with modification. Specifically, we adopt a 
structure whereby, if interconnection customers withdraw and are 
subject to withdrawal penalties, the transmission provider must use the 
withdrawal penalty funds as follows: (1) to fund studies and restudies 
in the same cluster; (2) if withdrawal penalty funds remain, to offset 
net increases in costs borne by other remaining interconnection 
customers from the same cluster for network upgrades shared by both the 
withdrawing and non-withdrawing interconnection customers prior to the 
withdrawal; and (3) if any withdrawal penalty funds remain, they will 
be returned to the withdrawing interconnection customer.
    799. We believe that using withdrawal penalty funds to reduce 
network upgrade cost shifts caused by withdrawals will reduce the risk 
that the shifted costs are so large as to cause cascading withdrawals, 
thus ensuring that interconnection customers are able to interconnect 
in a reliable, efficient, transparent, and timely manner. We agree with 
Invenergy that it is appropriate for there to be a relationship between 
the impact caused by the withdrawal of an interconnection request and 
how the withdrawal penalty funds are distributed. We also are persuaded 
by Invenergy, PJM, NextEra, and Southern that there are benefits to 
distributing withdrawal penalty funds to other interconnection 
customers remaining in the cluster to offset increased network upgrade 
costs resulting from the withdrawal.\1518\ We therefore modify the NOPR 
proposal and revise section 3.7.1 of the pro forma LGIP consistent with 
the discussion below.
---------------------------------------------------------------------------

    \1518\ Invenergy Initial Comments at 27-28; NextEra Initial 
Comments at 27-28; PJM Initial Comments at 39; Southern Initial 
Comments at 20-21.
---------------------------------------------------------------------------

    800. In the paragraphs that follow we summarize the steps a 
transmission provider must follow in distributing withdrawal penalty 
funds, as fully detailed in section 3.7.1.2 of the pro forma LGIP, and 
we present an illustrative example.
    801. Section 3.7.1.2.1 of the pro forma LGIP describes the 
transmission provider's handling of withdrawal penalty funds and the 
first step of distributing them to fund studies and restudies. For a 
single cluster, the transmission provider shall hold all withdrawal 
penalty funds until all interconnection customers in that cluster have: 
(1) withdrawn or been deemed withdrawn; (2) executed an LGIA; or (3) 
requested an LGIA to be filed unexecuted. Any withdrawal penalty funds 
collected shall first be used to fund studies for interconnection 
customers in the same cluster that have executed an LGIA or requested 
an LGIA to be filed unexecuted. Distribution of the withdrawal penalty 
funds for such

[[Page 61127]]

study costs shall not exceed the total actual study costs.
    802. Section 3.7.1.2.2 of the pro forma LGIP provides that if, 
after the first distribution step is complete, withdrawal penalty funds 
remain, the transmission provider must proceed to the second step of 
distributing them to offset net increases in network upgrade cost 
assignments driven by the withdrawal. The transmission provider will 
determine if the withdrawn interconnection customers, at any point in 
the cluster study process, shared cost assignment for one or more 
network upgrades with any remaining interconnection customers in the 
same cluster based on the cluster study report, cluster restudy 
report(s), interconnection facilities study report, and any subsequent 
issued restudy report for the cluster.
    803. If the transmission provider determines that withdrawn 
interconnection customers shared cost assignment for network upgrades 
with remaining interconnection customers in the same cluster, the 
transmission provider will calculate the remaining interconnection 
customers' net increase in costs (i.e., financial impact) due to a 
shared cost assignment for network upgrades with the withdrawn 
interconnection customer. It will then distribute withdrawal penalty 
funds as described in section 3.7.1.2.3 of the pro forma LGIP, 
depending on whether the withdrawal occurred before the withdrawing 
interconnection customer executed an LGIA (i.e., during the cluster 
study process) or after.
    804. If the transmission provider determines that more than one 
interconnection customer in the same cluster was financially impacted 
by the same withdrawn interconnection customer, the transmission 
provider will apply the relevant withdrawn interconnection customer's 
withdrawal penalty to reduce the financial impact to each impacted 
interconnection customer based on each withdrawn interconnection 
customer's proportional share of the financial impact. Each 
interconnection customer's proportional share will be determined by 
either the proportional impact method if the net cost increase is 
related to a system network upgrade or on a per capita basis if the net 
cost increase is related to a substation network upgrade.
    805. Section 3.7.1.2.4 of the pro forma LGIP details the process by 
which the transmission provider will provide amended LGIAs to any 
interconnection customers in the cluster that qualify for distribution 
of withdrawal penalty funds under this framework. To account for 
withdrawals that occurred during the cluster study process, the 
transmission provider must do the following: Within 30 calendar days of 
all interconnection customers in the same cluster having: (1) withdrawn 
or been deemed withdrawn; (2) executed an LGIA; or (3) requested an 
LGIA to be filed unexecuted, determine if, and to what extent, any 
interconnection customers qualify to have their increased network 
upgrade costs offset by withdrawal penalty funds and provide such 
interconnection customers with an amended LGIA that provides the 
reduction in network upgrade cost assignment and associated reduction 
to the interconnection customer's financial security requirements.
    806. To account for withdrawals that occurred in the same cluster 
after the withdrawing interconnection customer executed an LGIA, or 
requests the filing of an unexecuted LGIA, the transmission provider 
must do the following: Within 30 calendar days of such withdrawal or 
termination, determine if, and to what extent, any interconnection 
customers qualify to have their increased network upgrade costs offset 
by withdrawal penalty funds and provide such interconnection customers 
with an amended LGIA that provides the reduction in network upgrade 
cost assignment and associated reduction to the interconnection 
customer's financial security requirements.
    807. For any given withdrawal, if the transmission provider 
determines that there are no network upgrade cost assignments in the 
withdrawn interconnection customer's cluster shared with the withdrawn 
interconnection customer, or if the transmission provider determines 
that the withdrawn interconnection customer's withdrawal did not cause 
a net increase in the shared cost assignment for any remaining 
interconnection customers in the cluster, the transmission provider 
must return the remaining withdrawal penalty to the withdrawn 
interconnection customer. Such remaining withdrawal penalties will be 
returned to withdrawn interconnection customers based on the proportion 
of each withdrawn interconnection customer's contribution to the total 
amount of withdrawal penalty funds collected for the cluster. The 
transmission provider must make such disbursement within 60 calendar 
days of the date on which all interconnection customers in the same 
cluster have either (1) withdrawn or been deemed withdrawn; (2) 
executed an LGIA; or (3) requested an LGIA to be filed unexecuted.
    808. By way of example, assume that the transmission provider's 
proportional impact method identifies that interconnection customers A, 
B, and C in the same cluster all contribute to the need for system 
network upgrade A, estimated at $40 million, in the proportions of 50%, 
25% and 25%, respectively. Interconnection customer C withdraws from 
the interconnection queue after the facilities study, but before 
executing, or requesting the unexecuted filing of, the LGIA and pays a 
withdrawal penalty of $1 million.\1519\ System network upgrade A is 
still required for interconnection customers A and B, and when the 
transmission provider conducts the proportional impact method in the 
cluster restudy for the same cluster, it now determines that 
interconnection customer A's revised network upgrade cost allocation 
for system network upgrade A would increase to 67% and interconnection 
customer B's revised network upgrade cost allocation for system network 
upgrade A would increase to approximately 33%. The transmission 
provider would base the distribution of this interconnection customer's 
withdrawal penalty on the proportional impact analysis and credit 67% 
of the $1 million to interconnection customer A and 33% to 
interconnection customer B.
---------------------------------------------------------------------------

    \1519\ In this example, interconnection customer C paid a $1 
million withdrawal penalty because it was allocated $10 million in 
network upgrade cost (i.e., 25% of $40 million) and withdrew after 
receiving the facilities study report, at which point the withdrawal 
penalty is 10% of the amount of network upgrades allocated to the 
interconnection customer.
---------------------------------------------------------------------------

    809. Finally, section 3.7.1.2.5 of the pro forma LGIP provides that 
if, after the first and second distribution steps are complete, some or 
all of an interconnection customer's withdrawal penalty remains, the 
transmission provider must return the balance of the withdrawn 
interconnection customer's withdrawal penalty funds to the withdrawn 
interconnection customer.
    810. In response to commenter's concerns regarding the ability of 
transmission providers to collect withdrawal penalties from 
interconnection customers,\1520\ we further clarify that, in addition 
to study deposits, transmission providers must apply commercial 
readiness deposits received from the interconnection customer that 
exceed the costs that the transmission provider has incurred, including 
interest calculated in accordance with Sec.  35.19a(a)(2) of the 
Commission's regulations, toward any

[[Page 61128]]

withdrawal penalties assessed to the interconnection customer, in 
accordance with pro forma LGIP section 3.7.
---------------------------------------------------------------------------

    \1520\ APS Initial Comments at 16; EEI Initial Comments at 8; 
Eversource Initial Comments at 19; MISO Initial Comments at 69.
---------------------------------------------------------------------------

    811. In response to NV Energy and Invenergy, we clarify that an 
interconnection customer that withdraws during any time in the 
interconnection process is responsible for the applicable withdrawal 
penalty as well as the costs incurred to perform studies up to that 
point, and withdrawal penalty amounts will not be applied toward 
incurred study costs. Additionally, in response to NV Energy, we 
clarify that if any portion of a generating facility proposed in an 
interconnection request achieves commercial operation, even if less 
than the original requested MW amount, the interconnection customer 
will not be subject to withdrawal penalties.
    812. In response to Tri-State, we clarify that the phrase 
``regardless of any previous Withdrawal Penalty revenues received'' in 
pro forma LGIP section 3.7.1.1 means that the withdrawal penalty will 
be calculated based on actual study costs and will exclude any credits 
to the study costs from penalties assessed to and received from other 
interconnection customers.
    813. We disagree with commenters that assert that a technical 
conference is needed to further develop the record on withdrawal 
penalties before finalizing requirements in this final rule. For the 
reasons explained above, we believe that the record supports the 
reforms that we adopt herein and that their adoption is needed to 
ensure that interconnection customers are able to interconnect in a 
reliable, efficient, transparent, and timely manner.
7. Transition Process
a. NOPR Proposal
    814. In the NOPR, the Commission proposed to revise the pro forma 
LGIP to require transmission providers to establish a transition 
process for moving to a first-ready, first-served cluster study 
process.\1521\ Specifically, the Commission proposed to require 
transmission providers to offer existing, eligible interconnection 
customers the options to either enter a transitional serial 
interconnection facilities study or a transitional cluster study,\1522\ 
with commercial readiness requirements, or withdraw from the 
interconnection queue without penalty.
---------------------------------------------------------------------------

    \1521\ NOPR, 179 FERC ] 61,194 at P 156.
    \1522\ In the NOPR, the Commission explained that the 
transmission provider would consider all interconnection requests 
accepted within a standard cluster study request period have equal 
queue priority for purposes of the cluster study. See id. P 67. This 
would be true for all interconnection requests accepted for the 
transitional cluster study as well, per the NOPR.
---------------------------------------------------------------------------

    815. To proceed to the transitional serial study, the Commission 
proposed that eligible interconnection customers (i.e., interconnection 
customers that have executed a facilities study agreement before the 
effective date of the transmission provider's compliance filing) would 
execute a transitional serial interconnection facilities study 
agreement to codify their choice.\1523\ The Commission proposed that at 
the time of execution of such agreement, the interconnection customer 
would be required to provide a deposit equal to 100% of the 
interconnection facility and network upgrade costs allocated to the 
interconnection customer in the system impact study report. The 
Commission explained that if the interconnection customer's proposed 
generating facility reaches commercial operation, this deposit would be 
used toward construction costs of the same facilities.
---------------------------------------------------------------------------

    \1523\ Id. P 158.
---------------------------------------------------------------------------

    816. The Commission further explained that if the interconnection 
customer withdraws, the deposit would be refunded after the final 
invoice for study costs and the withdrawal penalty are settled. The 
Commission proposed that the transitional serial study withdrawal 
penalty would equal nine times the study cost. The Commission also 
proposed that transitional serial generating facilities would be 
required to provide evidence of exclusive site control for the entire 
generating facility and any interconnection customer's interconnection 
facilities, as well as demonstrate commercial readiness through one of 
the following: (1) an executed term sheet (or comparable evidence) 
related to a contract for the sale of the generating facility's output 
or its energy/ancillary services; (2) reasonable evidence that the 
generating facility is included in a resource planning entity's 
resource plan, has received a contract via a resource solicitation 
process, or is being developed for a large end-use customer; or (3) a 
provisional LGIA that is not suspended and includes a commitment to 
build the generating facility. The Commission proposed that the 
deadline for the interconnection customer to meet all the provisions 
above would be 60 calendar days after the effective date of a 
transmission provider's compliance filing to the final rule. Finally, 
the Commission proposed that the transmission provider complete 
transitional serial studies within 90 calendar days after the deadline 
for eligibility requirements to be satisfied.\1524\
---------------------------------------------------------------------------

    \1524\ NOPR, 179 FERC ] 61,194 at P 158.
---------------------------------------------------------------------------

    817. The Commission proposed that existing interconnection 
customers that opt for the transitional cluster study would execute a 
transitional cluster study agreement to codify their choice.\1525\ The 
Commission proposed that interconnection customers may make a one-time 
extension of their requested commercial operation date upon entry into 
the transitional cluster study, where any such extension shall not 
result in a commercial operation date later than December 31, 2027. The 
Commission proposed that the costs of this study and the identified 
facilities would be allocated as the costs are allocated for future 
cluster studies, as set forth in this final rule. The Commission also 
proposed that the transitional cluster would be subject to an expedited 
combined system impact and interconnection facilities study. The 
Commission explained that transitional cluster study generating 
facilities would be required to select ERIS or NRIS. The Commission 
proposed to require interconnection customers opting for a transitional 
cluster study to make a $5 million deposit. The Commission proposed to 
subject this deposit to the same conditions as the transitional serial 
study deposit.
---------------------------------------------------------------------------

    \1525\ Id. P 159.
---------------------------------------------------------------------------

    818. The Commission also proposed to require interconnection 
customers with interconnection requests in the transitional cluster to 
produce evidence of exclusive site control for their entire generating 
facilities and demonstrate commercial readiness through one of the same 
three options described above for transitional serial studies.\1526\ 
The Commission proposed that the deadline to satisfy these requirements 
would be 60 calendar days after the effective date of a transmission 
provider's compliance filing to the final rule. Finally, the Commission 
proposed that the transitional cluster study be completed by the 
transmission provider within 300 calendar days after the deadline for 
eligibility requirements to be satisfied.
---------------------------------------------------------------------------

    \1526\ Id. P 159.
---------------------------------------------------------------------------

    819. The Commission sought comment on: (1) whether certain 
interconnection customers with pending interconnection requests 
submitted prior to the issuance of a final rule should be allowed to 
proceed to LGIA execution without entering the transition process; (2) 
whether the Commission should require transmission providers to accept 
any additional commercial readiness demonstrations for entry into the

[[Page 61129]]

transition process, and whether existing interconnection customers 
should be permitted to enter their interconnection requests into the 
transitional cluster study process by posting a deposit in lieu of 
demonstrating commercial readiness; and (3) whether $5 million is a 
reasonable estimate of the costs that would be allocated to the 
interconnection customer via the transitional cluster study.\1527\
---------------------------------------------------------------------------

    \1527\ Id. P 160.
---------------------------------------------------------------------------

b. Comments
i. Comments in Support
    820. A few commenters fully support the proposed transition 
process.\1528\ For example, NRECA states that it strongly supports the 
proposed transition process because it fulfills the Commission's goal 
of ensuring an efficient way to prioritize and process interconnection 
requests, based on how far they have advanced through the 
interconnection process and their commercial readiness.\1529\
---------------------------------------------------------------------------

    \1528\ Affected Interconnection Customers Initial Comments at 
13; Consumers Energy Initial Comments at 5; Idaho Power Initial 
Comments at 9; Longroad Energy Reply Comments at 16; NRECA Initial 
Comments at 9, 31.
    \1529\ NRECA Initial Comments at 31.
---------------------------------------------------------------------------

    821. More commenters support the NOPR's core proposal to require 
transmission providers to offer interconnection customers with existing 
interconnection requests three options for moving forward (i.e., 
entering a transitional serial study, entering a transitional cluster 
study, or withdrawing without penalty).\1530\ For example, Pine Gate 
asserts that, given the current interconnection queue backlogs in 
multiple regions, it is essential that the Commission craft a 
transition process that permits late-stage interconnection requests to 
finish the interconnection process under the existing rules, while 
transitioning most interconnection requests to the new cluster study 
process.\1531\
---------------------------------------------------------------------------

    \1530\ Clean Energy Associations Initial Comments at 42-43; 
ENGIE Initial Comments at 7; NARUC Initial Comments at 10; NextEra 
Initial Comments at 28; [Oslash]rsted Initial Comments at 13; Pine 
Gate Initial Comments at 35-36.
    \1531\ Pine Gate Initial Comments at 35-36; see also NextEra 
Initial Comments at-+28.
---------------------------------------------------------------------------

    822. With respect to the transitional serial study,\1532\ many 
commenters, predominantly interconnection customers, support the 
proposal to provide this option to interconnection customers that have 
executed a facilities study agreement.\1533\ AEE and Pine Gate state 
that this provision respects the investments made by interconnection 
customers based on current interconnection procedures.\1534\ Similarly, 
Pattern Energy argues that, at the facilities study stage, an 
interconnection customer has relatively concrete economic expectations 
about its potential network upgrade obligations and should not be 
required to start the interconnection process over again.\1535\
---------------------------------------------------------------------------

    \1532\ Note that most commenters refer to this as ``proceeding 
to LGIA'' or ``proceeding to LGIA without going through the 
transition process,'' while a few use the term ``transitional serial 
study.'' These terms are taken to be synonymous because the NOPR 
describes the transitional serial study process as permitting 
interconnection customers to ``continue under the existing serial 
study process, enter into an LGIA, and interconnect.'' See NOPR, 179 
FERC ] 61,194 at P 158.
    \1533\ AEE Initial Comments at 27; AES Initial Comments at 20; 
Affected Interconnection Customers Initial Comments at 9; Idaho 
Power Initial Comments at 9; Longroad Energy Reply Comments at 16; 
NARUC Initial Comments at 10; NextEra Initial Comments at 28; 
Northwest and Intermountain Initial Comments at 5; [Oslash]rsted 
Initial Comments at 14; Pattern Energy Initial Comments at 35; Pine 
Gate Initial Comments at 37; SEIA Initial Comments at 28.
    \1534\ AEE Initial Comments at 27; Pine Gate Initial Comments at 
37.
    \1535\ Pattern Energy Initial Comments at 35.
---------------------------------------------------------------------------

    823. Other commenters express qualified support for the proposal. 
Noting that significant investments have been made and that generating 
facility contracting and financing patterns have been developed based 
on existing tariffs, Interwest calls for a structured, well-noticed 
transition period, to allow the market sufficient time to adjust to new 
processes, especially if the new process dramatically alters 
interconnection and cost allocation principles.\1536\ Similarly, the 
Pennsylvania Commission agrees that a transition process is necessary 
to integrate the Commission's proposed interconnection queue reforms to 
allow individual interconnection customers the opportunity to decide, 
based on the newly adopted minimum interconnection parameters, whether 
to remain in the interconnection queue.\1537\
---------------------------------------------------------------------------

    \1536\ Interwest Initial Comments at 6, 23-24.
    \1537\ Pennsylvania Commission Initial Comments at 15.
---------------------------------------------------------------------------

ii. Comments in Opposition
    824. CREA and NewSun argue that the proposed transition process is 
unnecessary, as a first-ready, first-served cluster study process 
places the decision to enter a cluster in the hands of the 
interconnection customer regardless of whether there are previously 
queued interconnection requests.\1538\ In a similar vein, EEI contends 
that it would be reasonable to require transmission providers to 
establish their own transition processes or to allow existing 
interconnection customers to proceed to LGIA execution without entering 
the transition process.\1539\
---------------------------------------------------------------------------

    \1538\ CREA and NewSun Initial Comments at 79.
    \1539\ EEI Initial Comments at 9.
---------------------------------------------------------------------------

    825. CREA and NewSun also fault the proposal to treat all 
interconnection requests in a transitional cluster as having a single 
queue priority because it fails to protect the investment expectations 
of interconnection customers with interconnection requests that have 
entered the interconnection queue.\1540\ CREA and NewSun argue that the 
Commission has previously recognized that queue positions should be 
respected and either grandfathered or otherwise transitioned into a 
cluster study process that avoids devaluing the existing queue 
position. CREA and NewSun urge the Commission to modify its proposed 
cluster study process so that higher-queued interconnection requests 
are given a higher-priority than lower-queued interconnection requests. 
CREA and NewSun explain that this has worked in CAISO and Bonneville, 
which they assert uses a similar mechanism to respect queue positions 
in its transmission planning expansion process.
---------------------------------------------------------------------------

    \1540\ CREA and NewSun Initial Comments at 45.
---------------------------------------------------------------------------

    826. Shell requests that the Commission let existing processes 
continue for all interconnection customers that have executed a system 
impact study agreement or cluster study agreement because such 
processes, while not perfect, are functioning ``well enough.'' \1541\ 
Illinois Commission expresses more general concern about the time 
required for a transition process to be completed, noting that PJM's 
transition process for a recent set of interconnection queue reforms is 
expected to result in significant delays.\1542\ Such delays, Illinois 
Commission contends, could prompt withdrawals and less-than-optimal use 
of potential new resources, which in turn would undermine state public 
policy goals and potentially threaten reliability. Longroad Energy 
similarly recommends that the Commission seek to avoid creating a 
situation whereby a transmission provider is forced to institute a 
pause on reviewing interconnection requests, similar to PJM's recent 
proposal to halt its review of interconnection requests for a two-year 
period.\1543\
---------------------------------------------------------------------------

    \1541\ Shell Initial Comments at 37.
    \1542\ Illinois Commission Initial Comments at 7.
    \1543\ Longroad Energy Reply Comments at 16-17.
---------------------------------------------------------------------------

iii. Comments on Specific Proposal
(a) Serial Study Eligibility and Transition Process Exceptions
    827. Numerous commenters express support for one or more of the 
eligibility

[[Page 61130]]

requirements proposed in the NOPR. To proceed with a transitional 
serial study, Affected Interconnection Customers agree that 
interconnection customers should provide evidence of exclusive site 
control, demonstrate commercial readiness, and fund 100% of their 
interconnection facility and network upgrade costs upfront.\1544\ 
Affected Interconnection Customers reason that delays in processing 
interconnection requests occur if speculative interconnection requests 
without adequate funding are allowed to enter and clog the serial study 
process, only to drop out later and cause the need for restudies.
---------------------------------------------------------------------------

    \1544\ Affected Interconnection Customers Initial Comments at 
10.
---------------------------------------------------------------------------

    828. However, Bonneville, PJM, OPSI, RWE Renewables, and NextEra 
express concern that offering interconnection customers a serial study 
option may be inefficient.\1545\ Bonneville states that it has received 
52 interconnection requests, totaling 33 GW, in the 90 days since the 
NOPR's issuance, and that completing existing studies under the current 
process could delay Bonneville's ability to implement a new cluster 
study process, thus diminishing its near-term benefits.\1546\ OPSI 
calls for the Commission to analyze whether this option could 
materially delay the transition process, and if so, consider using a 
cluster study process as soon as feasible in the transition.\1547\ 
Similarly, RWE Renewables assert that all parties should already be on 
notice about the pending changes, allowing for swifter movement to new 
processes, particularly for those that have not yet had any studies 
completed.\1548\ NextEra argues that it is best for all interconnection 
customers at the same stage in the interconnection process to abide by 
the same transition rules rather than giving them a choice between a 
serial or cluster study process.\1549\
---------------------------------------------------------------------------

    \1545\ Bonneville Initial Comments at 14; NextEra Initial 
Comments at 28; OPSI Initial Comments at 6; PJM Initial Comments at 
42; RWE Renewables Initial Comments at 1-2.
    \1546\ Bonneville Initial Comments at 14.
    \1547\ OPSI Initial Comments at 6.
    \1548\ RWE Renewables Initial Comments at 2.
    \1549\ NextEra Initial Comments at 28.
---------------------------------------------------------------------------

    829. Several commenters suggest broadening opportunities for a 
transitional serial study and/or exempting certain interconnection 
requests from transitional study. AEE, Clean Energy Associations, and 
Pine Gate support allowing interconnection requests with an executed or 
unexecuted facilities study agreement to proceed with a serial 
study.\1550\ Clean Energy Associations propose serial study eligibility 
for any interconnection request that has a system impact study 
underway, provided the interconnection customer can meet commercial 
readiness demonstration and deposit requirements on par with what would 
be required at the equivalent stage of the standard cluster study 
process.\1551\ ENGIE supports a process that exempts interconnection 
requests with interconnection costs of $5 million or less from a 
transitional study.\1552\ ENGIE also proposes that interconnection 
requests that do not contribute to the need for network upgrades and/or 
do not need facilities studies be permitted to proceed to an LGIA 
early.
---------------------------------------------------------------------------

    \1550\ AEE Initial Comments at 27; Clean Energy Associations 
Initial Comments at 43; Pine Gate Initial Comments at 37.
    \1551\ Clean Energy Associations Initial Comments at 43.
    \1552\ ENGIE Initial Comments at 7.
---------------------------------------------------------------------------

    830. Cypress Creek suggests that eligibility for a transitional 
serial study \1553\ be based on: (1) a specified interconnection queue 
window developed through a stakeholder process that extends to late 
stage interconnection requests; and (2) an objective assessment of the 
plotted distribution of total network upgrades (in terms of millions of 
dollars) to which the candidate interconnection request contributes, 
such that the total number of interconnection requests eligible for 
transitional serial and transitional cluster studies is known so 
transitional studies can be completed by a reasonable deadline.\1554\ 
Cypress Creek states that the distribution curve of network upgrades 
will help support eligibility to those interconnection requests on the 
lower half of impacts. Finally, Cypress Creek suggests that the 
Commission establish a date by which the transitional serial process 
would conclude, and by which the transitional cluster process would 
begin. Following these transitional studies, Cypress Creek recommends 
that the new cluster study process commence, in lieu of the second 
transitional cluster proposed by the Commission. Cypress Creek argues 
that this more rapid transition process better balances interconnection 
rights of late-stage interconnection requests with the need to move to 
the new process compared to the proposed transition process.
---------------------------------------------------------------------------

    \1553\ The original term used by Cypress Creek, ``transitional 
serial cluster,'' is assumed to mean transitional serial study.
    \1554\ Cypress Creek Initial Comments at 25-26.
---------------------------------------------------------------------------

(b) New Requirements on Existing Interconnection Customers
    831. AEE, Invenergy, NESCOE, and Shell argue that it is wrong, or 
could be unfairly burdensome, to impose significant new requirements on 
interconnection customers that have entered and proceeded through the 
interconnection queue in good faith.\1555\ Invenergy adds that this is 
especially true of interconnection customers that may have entered the 
interconnection queue years before the NOPR was issued.\1556\ Other 
commenters make similar points.\1557\
---------------------------------------------------------------------------

    \1555\ AEE Initial Comments at 26; Invenergy Initial Comments at 
37; NESCOE Reply Comments at 10; Shell Initial Comments at 37.
    \1556\ Invenergy Initial Comments at 37.
    \1557\ AEE Initial Comments at 26; EDF Renewables Initial 
Comments at 8; ACE-NY Initial Comments at 4; AEE Initial Comments at 
26; EDF Renewables Initial Comments at 8; Northwest and 
Intermountain Initial Comments at 2, 5.
---------------------------------------------------------------------------

    832. AEE and EDF Renewables stress the importance of not disrupting 
or further delaying interconnection requests that are well along in the 
interconnection process.\1558\ ACE-NY states, more broadly, that 
interconnection requests currently in serial interconnection queues 
should not be unduly harmed, adding that any transition process should 
not delay the commercial operation date of existing and future 
generating facilities.\1559\
---------------------------------------------------------------------------

    \1558\ AEE Initial Comments at 26; EDF Renewables Initial 
Comments at 8.
    \1559\ ACE-NY Initial Comments at 4.
---------------------------------------------------------------------------

    833. Clean Energy Associations argue that transition 
interconnection customers, whether they be in the serial or cluster 
study process, should not be held to higher standards than those 
interconnection customers that would proceed with the regular cluster 
study process unless the transition process leads to an LGIA and 
includes only ready interconnection requests that have been delayed in 
the existing interconnection queue.\1560\ Invenergy concurs with this 
principle, if the Commission elects to impose requirements on existing 
interconnection customers.\1561\
---------------------------------------------------------------------------

    \1560\ Clean Energy Associations Initial Comments at 43.
    \1561\ Invenergy Initial Comments at 38.
---------------------------------------------------------------------------

(c) Deposits
    834. Several commenters object to the proposal to require that 
interconnection customers, at the time of execution of the transitional 
serial study agreement, provide a deposit equal to 100% of the 
interconnection facility and network upgrade costs allocated to them in 
the system impact study report.\1562\ AEE and EDF Renewables argue that 
the costs assigned at the system impact study stage often vary 
significantly from the network upgrade costs provided at

[[Page 61131]]

the facilities study stage.\1563\ EDF Renewables also argue that the 
NOPR proposal is inconsistent with Order No. 2003, which specifically 
rejected such a proposal in favor of requiring security for discrete 
portions of these costs.\1564\ EDF Renewables adds that requiring a 
full deposit imposes a real cost on interconnection customers, which 
typically obtain a letter of credit from a bank.
---------------------------------------------------------------------------

    \1562\ Clean Energy Associations Initial Comments at 43; Cypress 
Creek Initial Comments at 26; EDF Renewables Initial Comments at 9; 
Invenergy Initial Comments at 38; Pine Gate Initial Comments at 36; 
SEIA Initial Comments at 28.
    \1563\ AEE Initial Comments at 26-27; EDF Renewables Initial 
Comments at 9.
    \1564\ EDF Renewables Initial Comments at 9 (citing Order No. 
2003, 104 FERC ] 61,103 at P 596).
---------------------------------------------------------------------------

    835. Likewise, several commenters object to the proposal to require 
a $5 million deposit to proceed to the transitional cluster 
study.\1565\ Most of these commenters claim that $5 million dollars is 
excessive and/or arbitrary; \1566\ fails to reflect the relative impact 
of smaller proposed generating facilities; \1567\ likely is not 
indicative of costs across all markets; \1568\ and will prompt 
otherwise viable interconnection requests to withdraw.\1569\ With 
respect to the NOPR's reliance on PSCo's claim that $5 million is 
within the range of interconnection costs on its system, CREA and 
NewSun question whether PSCo intended the deposit to serve as a barrier 
to its competitors in the generation market.\1570\ CREA and NewSun note 
that the three orders cited by the Commission in the NOPR mention a $5 
million deposit, but none provide a reasoned decision for acceptance of 
this deposit amount.\1571\ Conversely, Xcel asserts that $5 million 
dollars is a low estimate of costs that may ultimately be allocated to 
interconnection customers.\1572\
---------------------------------------------------------------------------

    \1565\ AEE Initial Comments at 26; Clean Energy Associations 
Initial Comments at 43; CREA and NewSun Initial Comments at 81; EDF 
Renewables Initial Comments at 9; Invenergy Initial Comments at 38; 
Northwest and Intermountain Initial Comments at 5; Pine Gate Initial 
Comments at 36.
    \1566\ AEE Initial Comments at 26; Clean Energy Associations 
Initial Comments at 43; CREA and NewSun Initial Comments at 81; EDF 
Renewables Initial Comments at 9; Pine Gate Initial Comments at 36.
    \1567\ CREA and NewSun Initial Comments at 81; EDF Renewables 
Initial Comments at 9.
    \1568\ AEE Initial Comments at 26; CREA and NewSun Initial 
Comments at 81; Pine Gate Initial Comments at 36.
    \1569\ AEE Initial Comments at 26.
    \1570\ CREA and NewSun Initial Comments at 81.
    \1571\ Id. at 81-82 (citing Pub. Serv. Co. of Colo., 169 FERC ] 
61,182; Tri-State Generation & Transmission Ass'n, Inc., 173 FERC ] 
61,015; Tri-State Generation & Transmission Ass'n, Inc., 174 FERC ] 
61,021 (2021).
    \1572\ Xcel Initial Comments at 36.
---------------------------------------------------------------------------

    836. AEE, Invenergy, and Pine Gate recommend that the deposit for 
either the transitional serial facilities study agreement or 
transitional cluster study agreement reflect a percentage of the 
network upgrade costs allocated to the interconnection customer, with 
Invenergy recommending 20%.\1573\ Northwest and Intermountain and Xcel 
recommend that the final rule require transmission providers to propose 
a deposit amount for transitional studies that is appropriate to their 
interconnection queue and their specific system configurations.\1574\ 
Xcel suggests that the Commission should accept proposals that use an 
average of actual historical estimates of costs allocated to 
interconnection customers with executed LGIAs to determine the security 
required to enter the transitional cluster.\1575\
---------------------------------------------------------------------------

    \1573\ AEE Initial Comments at 26; Invenergy Initial Comments at 
38; Pine Gate Initial Comments at 36.
    \1574\ Northwest and Intermountain Initial Comments at 5; Xcel 
Initial Comments at 36.
    \1575\ Xcel Initial Comments at 36.
---------------------------------------------------------------------------

(d) Commercial Readiness and Site Control
    837. Idaho Power and Xcel emphasize the importance of requiring a 
commercial readiness demonstration to enter the transition 
process.\1576\ Xcel argues that if a readiness demonstration is not 
required, unready interconnection requests may be in the study models 
for more than three years after they execute an LGIA and when they 
ultimately withdraw, which will cause delays and cascading 
restudies.\1577\ Idaho Power asserts that commercial readiness 
demonstrations for interconnection customers with executed LGIAs are 
also critical, as their resource and network upgrades will need to be 
modeled in the transitional cluster study.\1578\ NRECA proposes that 
interconnection customers that show requisite site control and 
commercial readiness proceed to the ``front of the line'' as ``first-
ready'' in the transition cluster process without additional 
evaluation.\1579\ Both Idaho Power and EEI recommend that 
interconnection customers with LGIAs, but that have suspended 
interconnection-related construction, be required to meet the 
commercial readiness requirements, with EEI also recommending that they 
be required to demonstrate site control.\1580\
---------------------------------------------------------------------------

    \1576\ Idaho Power Initial Comments at 9; NRECA Initial Comments 
at 31; Pattern Energy Initial Comments at 35; Xcel Initial Comments 
at 36.
    \1577\ Xcel Initial Comments at 36.
    \1578\ Idaho Power Initial Comments at 9.
    \1579\ NRECA Initial Comments at 31.
    \1580\ EEI Initial Comments at 9-10; Idaho Power Initial 
Comments at 9.
---------------------------------------------------------------------------

    838. In addition to the proposed commercial readiness demonstration 
requirements, Affected Interconnection Customers recommend that 
interconnection customers also be allowed to provide evidence of (1) 
major equipment either contracted to purchase or owned as part of an 
existing equipment fleet or (2) a completed engineering package under 
provisional LGIAs.\1581\ SEIA recommends that interconnection customers 
be allowed to demonstrate commercial readiness by providing a 
commitment to participate in RTO/ISO markets or an application for a 
site permit.\1582\
---------------------------------------------------------------------------

    \1581\ Affected Interconnection Customers Initial Comments at 
10-11.
    \1582\ SEIA Reply Comments at 12.
---------------------------------------------------------------------------

    839. A number of commenters oppose the NOPR's proposed commercial 
readiness requirements, as applied to the transition process.\1583\ 
SEIA states that the proposed requirements will be nearly impossible 
for an independent power producer to meet and ignore the very nature of 
a capacity market, which is to allow independent power producers to 
sell capacity into a market.\1584\
---------------------------------------------------------------------------

    \1583\ AEE Initial Comments at 26; CREA and NewSun Initial 
Comments at 79; Pine Gate Initial Comments at 36; SEIA Initial 
Comments at 29.
    \1584\ SEIA Initial Comments at 28.
---------------------------------------------------------------------------

    840. Several commenters support allowing a deposit in lieu of 
demonstrating commercial readiness, as applied to the transition 
process.\1585\ Pattern Energy argues for this option to be available 
specifically for the transitional cluster study and recommends a $5 
million deposit value.\1586\ Pattern Energy claims that this would 
balance the need for interconnection customers that may have been 
waiting for years to have their interconnection requests studied with 
the need to transition to a new process. SEIA and Pine Gate recommend 
that a commercial readiness deposit should be the norm, not the 
exception, with SEIA also recommending that interconnection customers 
be required to provide evidence of site control.\1587\ Pine Gate 
recommends a readiness deposit framework that requires interconnection 
customers to make incrementally at-risk payments throughout the 
interconnection process.\1588\
---------------------------------------------------------------------------

    \1585\ AEE Initial Comments at 26; EDF Renewables Initial 
Comments at 9; Invenergy Initial Comments at 38; Pattern Energy 
Initial Comments at 35.
    \1586\ Pattern Energy Initial Comments at 35.
    \1587\ SEIA Initial Comments at 29.
    \1588\ Pine Gate Initial Comments at 36.
---------------------------------------------------------------------------

    841. At the same time, several commenters oppose permitting 
deposits in lieu of demonstrating commercial readiness, as applied to 
the transition process.\1589\ Ameren calls such deposits 
``opportunities for delay'' that will not facilitate the 
interconnection of

[[Page 61132]]

interconnection requests for which the interconnection customer has 
demonstrated commercial readiness.\1590\ Idaho Power opposes the option 
because the transitional cluster study is an expedited, combined system 
impact and interconnection facilities study.\1591\ If the Commission 
does allow a deposit, EEI argues that the option should apply only in 
specific circumstances, and should be sufficiently high to deter 
interconnection requests that are not ready from entering the 
transitional cluster.\1592\
---------------------------------------------------------------------------

    \1589\ Ameren Initial Comments at 19; EEI Initial Comments at 
10; Idaho Power Initial Comments at 9; Xcel Initial Comments at 36.
    \1590\ Ameren Initial Comments at 19.
    \1591\ Idaho Power Initial Comments at 9.
    \1592\ EEI Reply Comments at 10.
---------------------------------------------------------------------------

(e) Withdrawal Penalties
    842. Many commenters oppose the NOPR's proposed transition process 
withdrawal penalties.\1593\ CREA and NewSun, Pine Gate, and 
[Oslash]rsted call the penalties harsh or draconian.\1594\ 
[Oslash]rsted notes that offshore wind project interconnection 
customers with contracts awarded via a state-sponsored resource 
solicitation process have already spent tens of millions of dollars to 
secure leaseholds, conduct extensive geotechnical studies of these 
lease areas, and engineering studies.\1595\ Given these investments, 
[Oslash]rsted contends that the decision to withdraw from the 
interconnection queue is most likely going to be based on some issue 
outside of the control of the interconnection customer, such as supply 
chain constraints, and not because the interconnection request will not 
go forward at some point.
---------------------------------------------------------------------------

    \1593\ AEE Initial Comments at 26; AES Initial Comments at 20; 
CREA and NewSun Initial Comments at 79; EDF Renewables Initial 
Comments at 8; [Oslash]rsted Initial Comments at 14; Pine Gate 
Initial Comments at 36; SEIA Initial Comments at 37.
    \1594\ CREA and NewSun Initial Comments at 79; [Oslash]rsted 
Initial Comments at 14; Pine Gate Initial Comments at 36.
    \1595\ [Oslash]rsted Initial Comments at 14.
---------------------------------------------------------------------------

    843. AES states that withdrawal should be penalty-free if an 
interconnection customer decides not to move forward with a proposed 
generating facility during the transition.\1596\ EDF Renewables asserts 
that a transition process should offer existing interconnection 
customers an opportunity to exit the interconnection queue in line with 
what they expected when entering.\1597\ SEIA recommends that the 
withdrawal penalty for interconnection customers in the transitional 
cluster study be capped at the withdrawing interconnection request's 
allocation of network upgrade costs.\1598\
---------------------------------------------------------------------------

    \1596\ AES Initial Comments at 20.
    \1597\ EDF Renewables Initial Comments at 8.
    \1598\ SEIA Initial Comments at 37.
---------------------------------------------------------------------------

(f) Compliance Timeline
    844. NRECA supports the NOPR's proposed timeline for 
compliance.\1599\ NRECA states that the 180-day \1600\ period proposed 
in the NOPR would be sufficient to allow interconnection customers to 
get their deposits, site control, and commercial readiness 
demonstrations in order.\1601\ PPL states that transmission providers 
should continue moving requests to the LGIA execution stage and have 
interconnection customers demonstrate commercial readiness as normal 
until the effective date of the transition process.\1602\
---------------------------------------------------------------------------

    \1599\ NRECA Initial Comments at 32; PPL Initial Comments at 18.
    \1600\ Note that the proposed deadline for transmission 
providers to submit a compliance filing is within 180 calendar days 
of the effective date of the final rule. The proposed deadline for 
interconnection customers to meet the requirements for transitional 
serial study or transitional cluster study is 60 calendar days after 
the Commission-approved effective date of a transmission provider's 
filing in compliance with this final rule.
    \1601\ NRECA Initial Comments at 32.
    \1602\ PPL Initial Comments at 18.
---------------------------------------------------------------------------

    845. AES, CREA and NewSun, and Invenergy assert that the NOPR's 
proposed 60-day deadline for compliance is difficult or impossible to 
meet for most interconnection customers.\1603\ Invenergy adds that the 
fact of the rulemaking's existence is insufficient to put 
interconnection customers on notice of potential reforms, given that 
any aspect of the NOPR could be modified in the final rule and be 
subject to variations in compliance filings.\1604\ AES states that it 
does not oppose requiring interconnection customers to demonstrate site 
control and meet commercial readiness criteria but recommends that at 
least six months be given for compliance.\1605\
---------------------------------------------------------------------------

    \1603\ AES Initial Comments at 20; CREA and NewSun Initial 
Comments at 79; Invenergy Initial Comments at 37-38.
    \1604\ Invenergy Initial Comments at 37.
    \1605\ AES Initial Comments at 20.
---------------------------------------------------------------------------

(g) Alternatives
    846. Shell argues that the final rule should allow an opt-out 
provision for the transition process under which transmission providers 
can demonstrate their existing processes' efficiencies by detailing 
their prior performance on certain measures, such as the average 
duration of each interconnection study and the average length of time 
from submission of an interconnection request to execution of an LGIA 
or filing of an unexecuted LGIA.\1606\
---------------------------------------------------------------------------

    \1606\ Shell Initial Comments at 37.
---------------------------------------------------------------------------

    847. In cases where the transition process is slow due to the sheer 
scale of change, Illinois Commission calls for an accelerated process 
for interconnection requests that allow states to ensure reliability 
and meet statutory obligations and public policy objectives.\1607\ 
Illinois Commission adds that such a process could be accomplished in a 
narrowly tailored manner and would be more efficient than allowing 
RTOs/ISOs an extended period to clear out prior interconnection queue 
backlogs.
---------------------------------------------------------------------------

    \1607\ Illinois Commission Initial Comments at 7-8.
---------------------------------------------------------------------------

    848. CREA and NewSun propose, and SEIA supports, a transitional 
cluster study process for transmission providers facing an otherwise 
unmanageable volume of interconnection requests.\1608\ CREA and NewSun 
assert that such a process would expedite interconnection study, 
eliminate excessive deposits and penalties, permit withdrawals without 
penalty if no burden is imposed on other interconnection customers, 
respect queue positions and associated investment expectations of 
queued interconnection requests, and avoid ``years of bottlenecks and 
market distorting problems'' associated with solutions based on 
readiness requirements.\1609\ CREA and NewSun state that this proposed 
process draws on Bonneville, CAISO, and MISO's current practices as 
examples and would take an estimated 460 days to complete, 
incorporating four milestones with increasing deposits and two off-
ramps (or decision points).\1610\
---------------------------------------------------------------------------

    \1608\ SEIA Reply Comments at 12.
    \1609\ CREA and NewSun Initial Comments at 82, Ex. A at 4.
    \1610\ Id., Ex. A at 3.
---------------------------------------------------------------------------

    849. CREA and NewSun further propose to respect queue positions by 
providing a separate cluster study for existing interconnection 
customers that have advanced to the system impact study stage and 
having interconnection requests retain queue position even as they are 
studied in a cluster.\1611\ CREA and NewSun also propose to allow 
interconnection customers to trade queue positions.\1612\
---------------------------------------------------------------------------

    \1611\ Id., Ex. A at 2.
    \1612\ Id., Ex., at 2-3.
---------------------------------------------------------------------------

(h) Tariff Language
    850. Southern notes that under proposed section 5.1.1.2(2) of the 
pro forma LGIP, the true-up of actual construction costs must be 
completed within 30 days of a generating facility achieving commercial 
operation, which appears to conflict with the true-up provisions in pro 
forma LGIA article 12.2 (Final Invoice), which, Southern states, 
provides that the true-up is due within six months.\1613\ Southern 
requests that the Commission make

[[Page 61133]]

these provisions consistent at six months.
---------------------------------------------------------------------------

    \1613\ Southern Initial Comments at 35.
---------------------------------------------------------------------------

iv. Requests for Flexibility and Clarification
    851. Several commenters argue that a one-size-fits-all transition 
plan is not appropriate, given the diversity of processes currently 
used by transmission providers and the varying volumes of 
interconnection requests in their interconnection queues.\1614\ For 
instance, Duke Southeast Utilities references the Commission's 
recognition that transmission providers that already have a Commission-
approved LGIP and LGIA based on a first-ready, first-served cluster 
study process may not need another transition process. Duke adds that 
requiring a second transition process would likely add confusion and 
potentially result in waiver requests filed with the Commission.\1615\ 
ISO-NE states that New England does not currently suffer 
interconnection queue backlogs to the same extent as other regions, and 
transition provisions could have a significant impact on 
interconnection requests that are currently proceeding through the 
existing interconnection process.\1616\ WAPA claims that it needs 
sufficient flexibility to develop new programs within its existing 
appropriations (or to seek additional appropriations or spending 
authority) and to accommodate Federal contracting timelines (because it 
hires contractors to conduct facilities studies).\1617\
---------------------------------------------------------------------------

    \1614\ Ameren Initial Comments at 19; Avangrid Initial Comments 
at 8; Bonneville Initial Comments at 13; CAISO Initial Comments at 
24; Duke Southeast Utilities Initial Comments at 11; EEI Initial 
Comments at 10; Indicated PJM TOs Reply Comments at 42; Invenergy 
Initial Comments at 39; ISO-NE Initial Comments at 33; MISO Initial 
Comments at 70; NARUC Initial Comments at 10-11; National Grid 
Initial Comments at 28; NEPOOL Initial Comments at 14; NYISO Initial 
Comments at 12; NYTOs Initial Comments at 21; WAPA Initial Comments 
at 8-9; see also Invenergy Initial Comments at 41 (asserting that, 
while many of the NOPR proposals should be prospective only, 
affected systems reform should apply immediately to all pending 
requests and active studies).
    \1615\ Duke Southeast Utilities Initial Comments at 11.
    \1616\ ISO-NE Initial Comments at 33-34.
    \1617\ WAPA Initial Comments at 8-9.
---------------------------------------------------------------------------

    852. CAISO, Duke Southeast Utilities, and Invenergy call on the 
Commission to permit transmission providers in regions that already use 
a first-ready, first-served cluster study process to minimize or omit a 
transition process.\1618\ CAISO recommends that transmission providers 
be permitted to propose just and reasonable effective dates for each 
reform.\1619\ CAISO adds that it anticipates that most reforms should 
be effective with the beginning of the next cluster study after a 
compliance filing is approved, but some reforms could be implemented 
for existing interconnection requests in the queue, especially for 
interconnection customers that may not have executed an LGIA. 
Conversely, Tri-State states that a transition period will be 
necessary, even for those transmission providers already employing a 
first-ready, first-served cluster study process, due to changes beyond 
the overarching structure of the interconnection queue, such as a 
requirement for 100% site control.\1620\
---------------------------------------------------------------------------

    \1618\ CAISO Initial Comments at 25.
    \1618\ Id.; Duke Southeast Utilities Initial Comments at 11; 
Invenergy Initial Comments at 39.
    \1619\ CAISO Initial Comments at 25.
    \1620\ Tri-State Initial Comments at 17.
---------------------------------------------------------------------------

    853. Several commenters ask the Commission to let transmission 
providers establish their own transition plans.\1621\ MISO notes that 
this previously occurred after the 2008 interconnection queue technical 
conference, where transmission providers were able to propose their own 
transition plan in adopting a first-ready, first-served model.\1622\ 
Ameren, National Grid, and NEPOOL call for RTOs/ISOs, in particular, to 
be allowed flexibility to develop a transition process with input from 
stakeholders.\1623\ Avangrid notes that determining an equitable and 
achievable transition plan was among the most challenging aspects of 
the stakeholder process that led to PJM's recent interconnection queue 
reform filing and asserts that other regions should have the chance for 
similar deliberations.\1624\ NYTOs argue that transmission providers 
should be allowed to propose: (1) setting an effective date for new 
interconnection requests that will be subject to the new cluster study 
process; (2) establishing an approach for the existing interconnection 
queue to be seen through to completion; and (3) determining a high-
level process, including a high-level time frame for updating tariffs, 
if the proposed reforms are approved.\1625\
---------------------------------------------------------------------------

    \1621\ Ameren Initial Comments at 19; Avangrid Initial Comments 
at 37; MISO Initial Comments at 70; National Grid Initial Comments 
at 28-29; NEPOOL Initial Comments at 14; NESCOE Reply Comments at 
10; NYTOs Initial Comments at 21-22.
    \1622\ MISO Initial Comments at 70.
    \1623\ Ameren Initial Comments at 19; National Grid Initial 
Comments at 28; NEPOOL Initial Comments at 14.
    \1624\ Avangrid Initial Comments at 8, 36-37.
    \1625\ NYTOs Initial Comments at 21-22.
---------------------------------------------------------------------------

    854. Several commenters request that the Commission clarify how the 
NOPR's proposed transition process relates to PJM's transition process 
accepted as part of its recent interconnection queue reforms.\1626\ 
OPSI requests that the final rule not extend any transition process 
beyond what PJM proposed.\1627\ Indicated PJM TOs request that the 
Commission allow PJM to implement its carefully negotiated transition 
process to a first-ready, first-served cluster study process.\1628\ PJM 
suggests that the Commission hold in abeyance any compliance filing 
obligations in this proceeding until PJM has completed its proposed 
transition process.\1629\ PJM argues that this would be in keeping with 
the Commission's statement that it will review any filings that result 
from transmission provider interconnection queue reform efforts ``based 
on the record before us in those proceedings and not based on whether 
they comply with the proposed reforms in this NOPR.'' \1630\ PJM also 
asserts that, given the size of its interconnection queue backlog, 
allowing interconnection customers the option of a transitional serial 
study process will delay implementation of PJM's cluster study process 
by several years and create uncertainty regarding that process.\1631\ 
PJM emphasizes that elsewhere in the NOPR, the Commission acknowledges 
the importance of allowing transmission providers to clear their 
interconnection queue backlogs quickly.\1632\
---------------------------------------------------------------------------

    \1626\ Indicated PJM TOs Initial Comments at 34; OPSI Initial 
Comments at 7; Pennsylvania Commission Initial Comments at 15; PJM 
Initial Comments at 42; see also PJM Interconnection, L.L.C., 181 
FERC ] 61,162 at PP 60-69.
    \1627\ OPSI Initial Comments at 7.
    \1628\ Indicated PJM TOs Initial Comments at 34.
    \1629\ PJM Initial Comments at 42.
    \1630\ Id. at 42-43 (citing NOPR, 179 FERC ] 61,194 at P 6).
    \1631\ Id. at 43.
    \1632\ PJM Reply Comments at 8-9.
---------------------------------------------------------------------------

c. Commission Determination
    855. We adopt the NOPR proposal to modify section 5 of the pro 
forma LGIP to establish a transition process for moving to the first-
ready, first-served cluster study process adopted in this final rule 
from the existing first-come, first-served serial study process. 
Specifically, we adopt the NOPR proposal to require transmission 
providers to offer existing interconnection customers up to three 
transition options, depending on which phase of the serial study 
process their interconnection requests are in: (1) a transitional 
serial study comprised of a facilities study (i.e., a transitional 
serial interconnection facilities study), (2) a transitional cluster 
study comprised of a clustered system impact study and individual 
facilities studies, or (3) withdrawal from the interconnection

[[Page 61134]]

queue without penalty. We also adopt definitions for the reports issued 
in association with options (1) and (2), respectively (i.e., a 
transitional serial interconnection facilities study report and a 
transitional cluster study report). As discussed below, regarding 
eligibility for the transitional serial study, we modify the NOPR 
proposal to require transmission providers to offer the transitional 
serial study option to interconnection customers that have been 
tendered a facilities study agreement, even if they have not yet 
executed that agreement, as of 30 calendar days after the filing date 
of the transmission provider's initial filing to comply with this final 
rule. Similarly, regarding eligibility for the transitional cluster 
study, we modify the NOPR proposal to require transmission providers to 
offer the transitional cluster study option to interconnection 
customers with an assigned queue position as of 30 calendar days after 
the filing date of the transmission provider's initial filing to comply 
with this final rule. We also adopt the NOPR proposals for transition 
process deposits, withdrawal penalties, and deadlines. We decline to 
adopt the proposal to impose a commercial readiness demonstration 
requirement and adopt, with modification, the NOPR proposal for site 
control requirements.
    856. We concur with commenters that, given current interconnection 
queue backlogs in multiple regions, it is essential that the Commission 
craft a transition process. Doing so will give interconnection 
customers, along with other market participants, time to adjust to new 
processes and requirements. We note that many responsive commenters 
support the proposed three options and, in particular, support 
providing interconnection customers at the facilities study stage the 
option for a transitional serial study.\1633\ We concur with NRECA that 
the NOPR's proposed transition process will create an efficient way to 
prioritize and process interconnection requests, based on how far they 
have advanced through the interconnection process and their level of 
commercial readiness. We further find that the transition process, as 
adopted herein, appropriately balances the need to move expeditiously 
to the new cluster study process with the need to respect the 
investments and expectations of interconnection customers at an 
advanced stage in the existing interconnection process.\1634\
---------------------------------------------------------------------------

    \1633\ Clean Energy Associations Initial Comments at 42-43; 
Consumers Energy Initial Comments at 5; ENGIE Initial Comments at 7; 
Longroad Energy Reply Comments at 16; NARUC Initial Comments at 10; 
NextEra Initial Comments at 28; [Oslash]rsted Initial Comments at 
13; Pine Gate Initial Comments at 35-36.
    \1634\ See e.g., Pub. Serv. Co. of Colo., 169 FERC ] 61,182.
---------------------------------------------------------------------------

    857. We disagree with commenters that contend that the NOPR's 
proposed transition process is unnecessary, should be optional, or 
poses an undue risk of delay. As stated in the NOPR and affirmed in our 
findings in section II of this final rule, we believe that 
interconnection queue backlogs exist throughout the country, in part, 
because the pro forma LGIP creates an incentive for interconnection 
customers to submit multiple interconnection requests for a given 
potential generating facility and remain in the interconnection queue 
to determine which of those interconnection requests has the lowest 
costs to interconnect.\1635\ Given this, simply moving to the new 
cluster study process, as CREA and NewSun suggest, risks creating large 
initial clusters, which may prevent interconnection customers from 
being able to interconnect in a reliable, efficient, transparent, and 
timely manner. Similarly, if transmission providers only used serial 
study processes to transition, it could put existing interconnection 
requests at greater risk of cascading withdrawals that would delay the 
adoption of standard cluster study processes. With respect to concerns 
that a transition process could introduce delays, we note that the 
serial study portion of the transition process is limited to 90 
calendar days, after which point the transitional cluster study 
commences.
---------------------------------------------------------------------------

    \1635\ NOPR, 179 FERC ] 61,194 at PP 24-35.
---------------------------------------------------------------------------

    858. We decline requests to modify the proposed transitional 
cluster study process to give higher-queued interconnection requests a 
higher queue position than lower-queued interconnection requests. As 
stated above, to address the interconnection queue backlogs that 
currently exist, it is necessary to move the bulk of existing 
interconnection requests to the cluster study process, and as such, 
interconnection requests studied in the same cluster have equal queue 
priority to avoid undue discrimination.
    859. We also decline calls to modify the NOPR proposal to require 
that: (1) interconnection customers electing the transitional serial 
study must provide a deposit equal to 100% of the interconnection 
facility and network upgrade costs allocated to the interconnection 
customer in the system impact study; and (2) interconnection customers 
electing the transitional cluster study must provide a deposit equal to 
$5 million. As noted earlier, the transition process is anticipated to 
involve more interconnection customers than standard annual clusters 
(due to existing interconnection queue backlogs), which greatly 
increases the risk of late-stage withdrawals. Adopting deposit 
requirements for the transitional studies higher than those adopted for 
the cluster study process will help to ensure that the transitional 
process is used by interconnection customers that intend to proceed 
with their proposed generating facilities. In response to arguments 
that the proposed deposit amounts are arbitrary and/or excessive, we 
note that they are based on expected costs to the extent practicable 
and that only a portion of these deposits are ultimately at-risk. That 
is, the withdrawal penalty is set at nine times the study cost, as 
discussed below, with the remainder of deposits to be refunded.\1636\ 
We also note that existing interconnection customers that are currently 
in an interconnection queue can opt to withdraw their interconnection 
requests without penalty and wait for the first standard cluster study 
with associated lower deposit requirements. Finally, with respect to 
EDF Renewable's claim that the transitional serial study deposit 
conflicts with the Commission's intentions in Order No. 2003, we find 
that the heightened need to avoid late-stage withdrawals during the 
transition process--a need that the Commission could not have 
anticipated in Order No. 2003--warrants the transitional use of this 
requirement for the transitional serial study.
---------------------------------------------------------------------------

    \1636\ See supra section III.A.7.a. Also, as one indicator of 
study costs, NV Energy states that, on average, it spends between 
$80,000 and $100,000 between the clustered system impact study and 
facilities studies. See supra section III.A.6.a.
---------------------------------------------------------------------------

    860. We adopt the NOPR proposal that the transitional study 
withdrawal penalty should equal nine times the study cost. The 
withdrawal penalty plays an important role in deterring speculative 
interconnection requests in both the standard cluster study and the 
transition process. We disagree with commenters that call for a lower 
penalty to apply during the transition process, given that the risk of 
withdrawals is heightened during the transition process. With respect 
to [Oslash]rsted's contention that offshore wind developers will likely 
withdraw interconnection requests solely due to circumstances beyond 
their control, we note that, regardless of the cause, a withdrawal may 
cause harm to other interconnection customers in the transition 
process. Thus, we find it appropriate to impose penalties on

[[Page 61135]]

those that choose to withdraw notwithstanding that withdrawal may at 
times be due to circumstances beyond the interconnection customer's 
control. Interconnection customers will bear the risk of withdrawal 
penalties and consider that risk in deciding whether to elect to join a 
transition process.
    861. We recognize that some transmission providers have existing 
cluster studies in progress and others have Commission-approved 
transition plans in progress. We emphasize that the provisions of this 
final rule are not intended to interfere with the timely completion of 
those in-progress cluster studies and transition processes. With 
respect to concerns about duplicative transition processes, we clarify 
that transmission providers that have already adopted a cluster study 
process or are currently undergoing a transition to a cluster study 
process will not be required to implement a new transition process.
    862. We are not persuaded by commenters' requests to permit 
transmission providers to establish their own transition plans. 
Transmission providers would likely require months-to-years to develop 
and execute their own transition plans, given the need for stakeholder 
dialogue and internal approval, followed by Commission review and 
approval. We find that the benefits of moving forward with an 
efficient, standardized transition process outweigh the potential 
benefits of relying on tailor-made transition processes developed by 
each transmission provider and its stakeholders.
    863. Likewise, we decline to adopt any of the alternatives put 
forth by commenters. We are not persuaded by Shell's proposal to allow 
transmission providers to ``opt-out'' of the transition process based 
on their prior performance. We view the existing serial study process 
as inherently more prone to cascading withdrawals and delays, and thus 
ill-suited to a transition period intended to set the stage for a 
standard cluster study process. We view the Illinois Commission's 
proposal for an accelerated process (for interconnection requests 
related to states' objectives) in regions that may propose a lengthier 
transition process timeline, as more appropriately addressed by 
transmission providers in individual compliance filings. And, given the 
need for even more stringent requirements in a transition process 
discussed earlier, we view CREA and NewSun's proposal to use 
progressively increasing deposits, during a transition process, as 
inherently ill-suited to address major interconnection queue backlogs.
    864. Finally, we decline calls to modify the NOPR proposal to 
require interconnection customers to meet transitional serial study 
eligibility requirements in 60 days after the Commission-approved 
effective date of a transmission provider's filing in compliance with 
this final rule. Given that we do not adopt the proposed commercial 
readiness demonstration requirements, we find that the 60-calendar day 
deadline provides interconnection customers with sufficient time to 
adjust to the new requirements, i.e., to choose a transition option 
and, depending on the option chosen, demonstrate site control and 
provide a deposit. Furthermore, we concur with NRECA that this period 
will be augmented, in practice, by the 90-calendar day period afforded 
to transmission providers to submit their compliance filings.\1637\
---------------------------------------------------------------------------

    \1637\ See infra section IV.C.
---------------------------------------------------------------------------

i. Transition Process Eligibility and Exceptions
    865. As stated above, we modify the NOPR proposal regarding the 
eligibility for the transitional serial study and transitional cluster 
study.\1638\ Any interconnection customer that has been tendered a 
facilities study agreement as of 30 calendar days after the filing date 
of the transmission provider's initial filing to comply with this final 
rule (even if it has not yet executed that agreement) may opt to 
proceed with a transitional serial study or withdraw its 
interconnection request without penalty. Transmission providers are 
required to tender an LGIA, pursuant to the requirements of section 11 
of the pro forma LGIP, to any interconnection customer that has 
received a final facilities study report before the transmission 
provider commences transitional serial studies. Any interconnection 
customer that has an assigned queue position as of 30 calendar days 
after the filing date of the transmission provider's initial filing to 
comply with this final rule may opt to proceed with a transitional 
cluster study or withdraw its interconnection request without penalty.
---------------------------------------------------------------------------

    \1638\ See supra section III.A.7.c.
---------------------------------------------------------------------------

    866. We find that an earlier eligibility cut-off for the 
transitional studies will allow the transitional studies to begin 
sooner, which in turn, will allow transmission providers and 
interconnection customers to benefit from the Commission's new cluster 
study process sooner. Further, we consider this modification 
appropriate because interconnection customers will have 120 calendar 
days after the publication of this final rule in the Federal Register 
to achieve eligibility for the transition process (90 calendar days for 
transmission providers to submit compliance filings, plus the 30-
calendar day eligibility cut-off).
    867. Additionally, we modify the NOPR proposal to require the 
transmission provider to tender the appropriate transitional study 
agreements (serial and/or cluster as applicable) to eligible 
interconnection customers no later than the Commission-approved 
effective date of the transmission provider's compliance filing with 
this final rule. We find that this requirement will help ensure that 
interconnection customers are informed about their eligibility for the 
transitional studies (including the associated requirements and 
deadlines) in a timely manner.
    868. Transmission providers are not required to tender transitional 
study agreements to interconnection customers that submit an 
interconnection request after the 30-calendar day eligibility cut-off 
described above. Interconnection customers that submit an 
interconnection request after the 30-calendar day eligibility cut-off 
will be required to pay for any studies conducted by the transmission 
provider under its existing tariff (as required by pro forma LGIP 
section 13.3), and their interconnection requests will not be allowed 
to enter the transition process, although they may enter their 
interconnection requests in the transmission provider's first standard 
cluster study, provided that they meet the new requirements for 
interconnection requests by the close of the first cluster request 
window.
    869. We are persuaded by commenters' suggestion to require 
transmission providers to offer the transitional serial study option to 
interconnection customers that have been tendered a facilities study 
agreement, even if they have not yet executed that agreement, as of 30 
calendar days after the filing date of the transmission provider's 
initial filing to comply with this final rule, and we modify the NOPR 
proposal accordingly. We find that interconnection requests at this 
point in the interconnection process are at an equivalent point as 
those interconnection requests for which interconnection customers have 
executed a facilities study agreement, as in both cases, the 
transmission provider has completed the system impact study but has not 
yet commenced the facilities study. We are not persuaded by commenters 
to extend the option for

[[Page 61136]]

transitional serial study to interconnection requests at earlier stages 
in the interconnection process, as such modifications may undermine the 
ability of the proposed reforms to accelerate interconnection queue 
processing and could delay the transition to the new, more efficient 
cluster study process. We disagree with the proposal to exempt from the 
transition process interconnection requests that appear, based on a 
feasibility study, to require limited or no network upgrades. The 
results of this feasibility study may no longer be accurate depending 
on which higher-queued interconnection customers remain in the 
interconnection queue after the transition date.
ii. Commercial Readiness and Site Control
    870. We decline to adopt the proposed commercial readiness 
demonstration options for transitional studies for the same reasons 
that we are not adopting those options for cluster studies going 
forward, as discussed above. We adopt with modification the NOPR's 
proposed site control requirements. Specifically, we require 
interconnection customers electing a transitional study, regardless of 
whether they select the transitional serial study or the transitional 
cluster study, to demonstrate 100% site control for their proposed 
generating facilities. We find that such a requirement will provide 
further assurance that such interconnection customers are ready to 
proceed to construction. We modify the NOPR proposal by declining to 
require that interconnection customers that choose to proceed with a 
transitional serial interconnection facilities study must also 
demonstrate 100% site control for any interconnection customer's 
interconnection facilities because such a requirement would be overly 
burdensome for interconnection customers, in addition to the other 
requirements we are adopting elsewhere in this final rule. Further, we 
find that this requirement is not needed to ensure that such 
interconnection customers are ready to proceed to construction.
iii. Tariff Language
    871. We agree with Southern's recommendation to align timelines for 
truing up construction costs in the proposed pro forma LGIP section 
5.1.1.2(2) and current, unmodified by this final rule, pro forma LGIA 
article 12.2 (Final Invoice) by making these provisions consistent at 
six months, and we modify the NOPR proposal accordingly. We agree with 
Southern that consistent timelines for truing up construction costs 
will provide clarity and certainty for interconnection customers.

B. Reforms To Increase the Speed of Interconnection Queue Processing

1. Elimination of the Reasonable Efforts Standard
a. Need for Reform and NOPR Proposal
    872. As the Commission explained in the NOPR, the pro forma LGIP 
does not require transmission providers to meet deadlines for 
conducting interconnection studies.\1639\ Rather, transmission 
providers are only required to use ``reasonable efforts'' to complete 
interconnection studies on time.\1640\ ``Reasonable efforts'' are 
defined as ``actions that are timely and consistent with Good Utility 
Practice and are substantially equivalent to those a Party would use to 
protect its own interests.'' \1641\ There are no explicit consequences 
in the pro forma LGIP for transmission providers that fail to meet 
their study deadlines.
---------------------------------------------------------------------------

    \1639\ NOPR, 179 FERC ] 61,194 at P 28.
    \1640\ See pro forma LGIP sections 2.2, 6.3, 7.4, 8.3.
    \1641\ Order No. 2003, 104 FERC ] 61,103 at P 67; pro forma LGIP 
section 1.
---------------------------------------------------------------------------

    873. In the NOPR, the Commission preliminarily found that the use 
of the reasonable efforts standard for transmission providers to 
complete interconnection studies resulted in Commission-jurisdictional 
rates that were unjust and unreasonable because: (1) the timely 
provision of interconnection service was critical to maintaining just 
and reasonable rates; (2) the data collected pursuant to Order No. 845 
demonstrated that the failure to timely complete interconnection 
studies was a significant nationwide problem, even for transmission 
providers that had implemented other interconnection reforms; and (3) 
the reasonable efforts standard did not provide a meaningful incentive 
for transmission providers to complete their interconnection studies 
within the deadlines established in their tariffs.\1642\
---------------------------------------------------------------------------

    \1642\ NOPR, 179 FERC ] 61,194 at PP 165-167 (citing May Joint 
Task Force Tr. 89:6-25 (Thad LeVar) (encouraging the Commission to 
examine ``appropriate consequences to the transmission providers 
when they [do not] comply with the tariffs,'' including by missing 
study deadlines)).
---------------------------------------------------------------------------

    874. The Commission proposed to revise the pro forma LGIP to 
eliminate the reasonable efforts standard for transmission providers 
completing interconnection studies and instead impose firm study 
deadlines and establish penalties that would apply when transmission 
providers fail to meet study deadlines.\1643\ Specifically, the 
Commission proposed to require transmission providers that do not 
complete a cluster study, cluster restudy, facilities study, or 
affected system study by the deadline specified in the pro forma LGIP 
to pay a penalty of $500 per each business day that the study is late, 
except in situations where force majeure applies. The Commission 
proposed that those penalties would be distributed to the delayed 
interconnection customers on a pro rata basis to offset their study 
costs. Consistent with other penalties, the Commission proposed that 
such penalties would not be recoverable in transmission rates.\1644\
---------------------------------------------------------------------------

    \1643\ Id. P 168.
    \1644\ Id. P 169.
---------------------------------------------------------------------------

    875. The Commission also proposed to cap penalties at 100% of the 
total study deposit received for the late study to provide a safeguard 
against overly large penalties that may be considered punitive.\1645\ 
The Commission further proposed that no financial penalties on 
transmission providers that fail to meet study deadlines would be 
assessed until one cluster study cycle (that is not a transitional 
study cycle) after the Commission-approved effective date for 
implementing the reforms proposed in the NOPR. Additionally, the 
Commission proposed a 10-business day grace period such that no 
penalties would be assessed for a study that is delayed by 10 business 
days or less; for studies that are delayed by more than 10 business 
days, the penalty would be calculated based on the first business day 
the study was late. Further, the Commission proposed to permit the 
transmission provider to extend the deadline for a particular study by 
30 business days by mutual agreement of the transmission provider and 
all interconnection customers in the relevant study. Finally, the 
Commission proposed to require transmission providers to post to their 
OASIS or a public website on a quarterly basis the total amount of such 
penalties from the previous quarter and the highest amount of such 
penalties paid to a single interconnection request from the previous 
quarter.
---------------------------------------------------------------------------

    \1645\ Id. P 170.
---------------------------------------------------------------------------

    876. The Commission acknowledged that the application of penalties 
for late interconnection studies in the context of RTOs/ISOs may raise 
several unique issues.\1646\ However, consistent with the Commission's 
findings in Order No. 890,\1647\ the Commission explained that

[[Page 61137]]

penalties are appropriate in certain circumstances to incentivize 
compliance with tariff deadlines, notwithstanding the RTO's/ISO's 
status as a not-for-profit entity. To ensure that RTOs/ISOs would be 
able to pay any such penalties, the Commission proposed to require 
RTOs/ISOs to propose tariff provisions that would require the RTO/ISO 
to submit requests to recover the costs of specific interconnection 
study penalties under FPA section 205. The Commission explained that, 
similar to the ability of RTOs/ISOs to seek to directly assign monetary 
penalties for violations of reliability standards to other responsible 
entities, RTOs/ISOs could include a provision that the RTO/ISO may make 
an FPA section 205 filing seeking to allocate such penalties to the 
appropriate transmission owner that is responsible for, or contributed 
to, the delay.\1648\ However, the Commission sought comment on whether 
there was a more appropriate method for assigning such penalties in 
RTOs/ISOs. More generally, the Commission sought comment on whether 
penalties would effectively incentivize more timely completion of 
interconnection studies in RTOs/ISOs, and/or whether monetary penalties 
could have adverse consequences (e.g., compromising accuracy or 
increasing waiver requests as transmission providers strive to meet 
deadlines).
---------------------------------------------------------------------------

    \1646\ Id. P 171.
    \1647\ Preventing Undue Discrimination & Preference in 
Transmission Serv., Order No. 890, 118 FERC ] 61,119, 72 FR 12226, 
order on reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on 
reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g, 
Order No. 890-C, 126 FERC ] 61,228, order on clarification, Order 
No. 890-D, 129 FERC ] 61,126 (2009).
    \1648\ NOPR, 179 FERC ] 61,194 at P 172.
---------------------------------------------------------------------------

    877. Additionally, the Commission sought comment on: (1) the 
proposed penalty structure, including whether the penalty amount for a 
cluster study should be $500 per business day or whether an approach 
that accounts for the number of interconnection customers affected, 
such as $100 per business day per customer in the delayed study, would 
be more appropriate; (2) how and when the Commission should require 
transmission providers to communicate to interconnection customers the 
status of studies that may be delayed; (3) whether to include 
exceptions to the penalty other than force majeure, and if so, what 
those exceptions should be; and (4) whether Commission staff should 
issue periodic reports summarizing the status of transmission 
providers' interconnection queues and timeliness of interconnection 
studies based on information collected through existing reporting 
requirements, and whether this periodic report should be in addition to 
or a substitute for the proposed monetary penalties discussed 
above.\1649\
---------------------------------------------------------------------------

    \1649\ Id. P 173.
---------------------------------------------------------------------------

b. Comments
i. Comments in Support
    878. Many commenters support the NOPR proposal to eliminate the 
reasonable efforts standard and establish firm interconnection study 
deadlines by imposing financial penalties when transmission providers 
fail to meet study deadlines.\1650\ Multiple commenters explain that 
interconnection studies are often substantially delayed, which creates 
uncertainty and risk in the process of bringing new generating 
facilities online,\1651\ and ultimately results in an unreasonable 
market barrier for new generating facilities.\1652\ NARUC contends that 
the timely provision of interconnection service is critical to 
maintaining just and reasonable rates.\1653\
---------------------------------------------------------------------------

    \1650\ ACE-NY Initial Comments at 11-12; ACE-NY Reply Comments 
at 2; ACORE Initial Comments at 4; Affected Interconnection 
Customers Initial Comments at 23-25; CESA Initial Comments at 11; 
Clean Energy Associations Initial Comments at 43; Clean Energy 
States Initial Comments at 9; Consumers Energy Initial Comments at 
5; CREA and NewSun Initial Comments at 83; CREA and NewSun Reply 
Comments at 56; Cypress Creek Initial Comments at 23; ELCON Initial 
Comments at 7; EPSA Initial Comments at 10-11; Evergreen Action 
Initial Comments at 2; Fervo Energy Initial Comments at 5; Fervo 
Energy Reply Comments at 7; Google Initial Comments at 5; Google 
Reply Comments at 3, 5; Illinois Commission Initial Comments at 9; 
Individual Signatories Initial Comments at 1; Interwest Initial 
Comments at 8; Invenergy Initial Comments at 29-30; Iowa Commission 
Initial Comments at 5; Navajo Utility Initial Comments at 12; New 
Jersey Commission Initial Comments at 13-14; New Jersey Commission 
Reply Comments at 1; Northwest and Intermountain Initial Comments at 
14; [Oslash]rsted Initial Comments at 14; Pine Gate Initial Comments 
at 38; Public Interest Organizations Initial Comments at 33; SEIA 
Initial Comments at 30; TAPS Initial Comments at 3; UMPA Initial 
Comments at 6-7.
    \1651\ ELCON Initial Comments at 7; EPSA Initial Comments at 11; 
Fervo Energy Initial Comments at 5; NARUC Initial Comments at 13-14; 
Navajo Utility Initial Comments at 12; SEIA Initial Comments at 33.
    \1652\ Pennsylvania Commission Initial Comments at 4; see also 
AEE Reply Comments at 21, 30; Fervo Energy Reply Comments at 7; 
Public Interest Organizations Initial Comments at 33 (explaining 
that the slow pace of interconnection has discouraged incorporation 
of new generation and stunted the transition of the transmission 
system).
    \1653\ NARUC Initial Comments at 13-14.
---------------------------------------------------------------------------

    879. Some commenters argue that the interconnection queue backlogs 
indicate that the reasonable efforts standard has not been effective in 
ensuring timely access to the transmission system for new generating 
facilities \1654\ nor in imposing consequences when transmission 
providers fail to meet study deadlines.\1655\ Some commenters argue 
that the Order No. 845 reporting data supports the conclusion that the 
reasonable efforts standard has failed to ensure transmission providers 
complete interconnection studies on time.\1656\ AEE argues that the 
broad definition of ``reasonable efforts'' presents a high bar to prove 
that interconnection study delays were unreasonable.\1657\
---------------------------------------------------------------------------

    \1654\ AEE Reply Comments at 20-21; Clean Energy Associations 
Initial Comments at 43; CREA and NewSun Initial Comments at 84; Iowa 
Commission Initial Comments at 5; New Jersey Commission Reply 
Comments at 3; Public Interest Organizations Initial Comments at 34.
    \1655\ ACE-NY Reply Comments at 3; Affected Interconnection 
Customers Initial Comments at 23; CREA and Newsun Initial Comments 
at 83; EPSA Initial Comments at 10; Fervo Energy Initial Comments at 
5; Pennsylvania Commission Initial Comments at 2.
    \1656\ ACE-NY Initial Comments at 11-12; AEE Reply Comments at 
18; Affected Interconnection Customers Initial Comments at 23-24; 
Pennsylvania Commission Initial Comments at 2-3; UMPA Initial 
Comments at 6-7.
    \1657\ AEE Initial Comments at 28.
---------------------------------------------------------------------------

    880. Some commenters assert that the reasonable efforts standard 
results in an insufficient allocation of transmission provider 
resources to process the interconnection queue \1658\ and that the risk 
of penalties will provide a needed incentive for transmission providers 
to complete interconnection studies on time.\1659\ Some commenters 
argue that penalizing transmission providers is appropriate because 
they control the staffing and study process and are in the best 
position to ensure that studies are timely and accurate.\1660\ CREA and 
NewSun assert that the volume of interconnection requests is unlikely 
to decrease, so transmission providers need to ensure that they hire 
adequate staff to meet this need.\1661\ Google cautions against taking 
``implicit threats of reduced cooperation or assertions that 
transmission providers cannot do any better'' seriously, noting that 
any major reform to interconnection processes will entail growing 
pains.\1662\

[[Page 61138]]

AEE argues that some transmission providers have improved their 
generator interconnection process, which underscores that it is 
feasible to hold all transmission providers to higher standards.\1663\
---------------------------------------------------------------------------

    \1658\ ELCON Initial Comments at 7; Fervo Energy Initial 
Comments at 5; Invenergy Initial Comments at 29-30; Northwest and 
Intermountain Initial Comments at 14; see also Clean Energy 
Associations Initial Comments at 43-44; NARUC Initial Comments at 
14; SEIA Initial Comments at 33.
    \1659\ ACE-NY Initial Comments at 12; ACE-NY Reply Comments at 
3; ELCON Initial Comments at 7; EPSA Initial Comments at 11; 
Evergreen Action Initial Comments at 2-3; Fervo Energy Initial 
Comments at 5; Google Initial Comments at 16; Individual Signatories 
Initial Comments at 1; New Jersey Commission Reply Comments at 2; 
Northwest and Intermountain Initial Comments at 14; Pine Gate 
Initial Comments at 38; Public Interest Organizations Initial 
Comments at 34; SEIA Initial Comments at 33; TAPS Initial Comments 
at 3.
    \1660\ Invenergy Initial Comments at 30; SEIA Initial Comments 
at 32; see also Iowa Commission Initial Comments at 5-6 (``RTOs/ISOs 
need to prioritize interconnection studies and need to hold their 
employees and/or outside entities responsible for delays'').
    \1661\ CREA and NewSun Reply Comments at 56.
    \1662\ Google Reply Comments at 4.
    \1663\ AEE Reply Comments at 26.
---------------------------------------------------------------------------

    881. Some commenters point out that the NOPR proposal resolves an 
imbalance between interconnection customers, which are held to strict 
deadlines, and transmission providers, which are currently not required 
to meet study deadlines.\1664\ Some commenters assert that the proposed 
penalties complement the stricter financial and readiness requirements 
that the NOPR proposed to apply to interconnection customers \1665\ or 
that the firm study deadlines and penalty structure are necessary to 
ensure that the other NOPR proposals are successful.\1666\
---------------------------------------------------------------------------

    \1664\ ACE-NY Initial Comments at 12; CREA and NewSun Initial 
Comments at 83-84; ELCON Initial Comments at 8; Fervo Energy Reply 
Comments at 7-8; Pennsylvania Commission Initial Comments at 2-3; 
Public Interest Organizations Reply Comments at 10; SEIA Reply 
Comments at 13.
    \1665\ AEE Reply Comments at 19-21; APPA-LPPC Initial Comments 
at 21; Clean Energy Associations Initial Comments at 43.
    \1666\ ACE-NY Initial Comments at 12; EPSA Initial Comments at 
11; Evergreen Action Initial Comments at 2-3; Fervo Energy Initial 
Comments at 5; Individual Signatories Initial Comments at 1; New 
Jersey Commission Reply Comments at 2; Pine Gate Initial Comments at 
38; SEIA Initial Comments at 33.
---------------------------------------------------------------------------

    882. Multiple commenters note that long interconnection delays have 
economic costs for consumers, so transmission providers should also 
face economic costs for failing to meet deadlines.\1667\ Navajo Utility 
asserts that interconnection delays prevent it from using 100 MW of 
transmission rights that it was granted through settlement, which 
leaves it with an obligation to pay for transmission rights without the 
ability to use them.\1668\
---------------------------------------------------------------------------

    \1667\ AEE Reply Comments at 18, 30; Consumers Energy Initial 
Comments at 7 (explaining that interconnection delays could create 
additional costs to end-use customers because LSEs may invest in 
continued operation of existing assets set to retire while new 
generating facilities are delayed); Evergreen Action Initial 
Comments at 2; Interwest Initial Comments at 8; Iowa Commission 
Initial Comments at 5-6 (asserting that ``[d]elayed studies result 
in denial of likely low-cost generation to consumers''); Navajo 
Utility Initial Comments at 12 (explaining that study delays 
postpone important generation, tax revenue, and construction jobs 
for Navajo Nation); Northwest and Intermountain Initial Comments at 
14; Public Interest Organizations Reply Comments at 10; SEIA Initial 
Comments at 32; SEIA Reply Comments at 13.
    \1668\ Navajo Utility Initial Comments at 12.
---------------------------------------------------------------------------

ii. Comments in Opposition
    883. Many commenters, particularly transmission providers, oppose 
the NOPR proposal to eliminate the reasonable efforts standard and 
impose financial penalties on transmission providers for late 
studies.\1669\ Further, some commenters assert that the Commission 
cannot support a statutory finding under FPA section 206 to justify the 
NOPR proposal \1670\ or that the NOPR proposal is not based on 
substantial evidence and fails to consider important aspects of the 
problem.\1671\
---------------------------------------------------------------------------

    \1669\ AECI Initial Comments at 6; AEP Initial Comments at 25-
29; Alliant Energy Initial Comments at 6; Ameren Initial Comments at 
20-21; Avangrid Initial Comments at 9; Bonneville Initial Comments 
at 15; Dominion Initial Comments at 34; EEI Initial Comments at 14-
15; Indicated PJM TOs Initial Comments at 5, 36; Longroad Energy 
Reply Comments at 14; MISO Initial Comments at 13, 71; MISO TOs 
Initial Comments at 14; NextEra Initial Comments at 6, 29-30; North 
Dakota Commission Initial Comments at 5; NYISO Initial Comments at 
25-26; NYTOs Reply Comments at 2; Omaha Public Power Initial 
Comments at 11; OMS Initial Comments at 15; Pacific Northwest 
Utilities Initial Comments at 9; PacifiCorp Initial Comments at 32-
34; PG&E Initial Comments at 3-5; PJM Initial Comments at 7, 55; PPL 
Initial Comments at 19; Puget Sound Initial Comments at 9; SDG&E 
Reply Comments at 1; Southern Initial Comments at 5; SPP Initial 
Comments at 11; Tri-State Initial Comments at 17-18; U.S. Chamber of 
Commerce Initial Comments at 9; Vermont Electric and Vermont Transco 
Initial Comments at 2; WAPA Initial Comments at 10; WIRES Initial 
Comments at 9-10; Xcel Initial Comments at 38.
    \1670\ Indicated PJM TOs Initial Comments at 38.
    \1671\ Dominion Reply Comments at 20; MISO TOs Initial Comments 
at 23; NYISO Reply Comments at 4-5; PG&E Reply Comments at 2-3.
---------------------------------------------------------------------------

    884. Many commenters argue that it is inequitable to penalize 
transmission providers for study delays because those delays are 
largely due to factors outside the transmission provider's control, 
including high volumes of speculative interconnection requests, a 
shortage of qualified engineers, delayed data from interconnection 
customers, affected system coordination, cascading restudies caused by 
withdrawals, and the increasing complexity of studies due to new types 
of generating facilities.\1672\ Some commenters contend that the record 
supports retaining the reasonable efforts standard because third-party 
forces are common to most study delays.\1673\
---------------------------------------------------------------------------

    \1672\ AEP Initial Comments at 25-26; Ameren Initial Comments at 
20; Avangrid Initial Comments at 9-10, 29; Dominion Reply Comments 
at 19; Indicated PJM TOs Reply Comments at 22-24; ISO-NE Initial 
Comments at 35-36; ISO/RTO Council Initial Comments at 3-4; MISO 
Initial Comments at 73-74; MISO TOs Initial Comments at 15-16, 23-
24; National Grid Initial Comments at 30; NESCOE Reply Comments at 
11-12; NRECA Initial Comments at 9, 33-34; NYISO Initial Comments at 
26-27; OMS Initial Comments at 15; Pacific Northwest Utilities 
Initial Comments at 9-10; PacifiCorp Initial Comments at 32-35; PG&E 
Initial Comments at 7; PG&E Reply Comments at 3-4; Puget Sound 
Initial Comments at 9; SDG&E Reply Comments at 1; Southern Initial 
Comments at 5, 30; State Agencies Initial Comments at 12-14; Tri-
State Initial Comments at 17-18; U.S. Chamber of Commerce Initial 
Comments at 10; WIRES Initial Comments at 9; Xcel Initial Comments 
at 38.
    \1673\ Eversource Initial Comments at 28; MISO TOs Reply 
Comments at 13; PacifiCorp Initial Comments at 33; Southern Initial 
Comments at 30; U.S. Chamber of Commerce Initial Comments at 10.
---------------------------------------------------------------------------

    885. Some commenters argue that data from reports required by Order 
No. 845 does not support the NOPR proposal.\1674\ AEP notes that the 
data referenced in the NOPR represents only one year and does not 
support the conclusion that transmission providers are intentionally 
slow in interconnection queue processing.\1675\ MISO notes that its 
Order No. 845 reports show that the majority of delays are caused by 
the need to wait for affected systems studies.\1676\ NYISO states that 
its August 2022 Order No. 845 report, and other recent RTO/ISO reports, 
detail the various drivers of delays, which are typically outside their 
control.\1677\ NYISO argues that it would not be reasoned decision-
making for the Commission to ignore these reports and draw an overly 
simplistic conclusion that the reasonable efforts standard is to blame 
for study delays. PG&E and Southern note that their Order No. 845 data 
indicates that they have no delayed studies.\1678\
---------------------------------------------------------------------------

    \1674\ AEP Initial Comments at 25; MISO Initial Comments at 72.
    \1675\ AEP Initial Comments at 25-27.
    \1676\ MISO Initial Comments at 14, 72.
    \1677\ NYISO Initial Comments at 27-29.
    \1678\ PG&E Initial Comments at 4-6; Southern Initial Comments 
at 30-31.
---------------------------------------------------------------------------

    886. Conversely, AEE and Public Interest Organizations respond that 
commenters that claim that study delays are caused by factors beyond 
transmission providers' control fail to acknowledge the availability of 
potential solutions, such as increasing expenditures to attract and 
retain staff and policy and process improvements.\1679\ ACE-NY asserts 
that, while other parties can cause delays, transmission providers are 
also responsible for delays.\1680\ SEIA argues that interconnection 
request withdrawals are often similarly outside interconnection 
customers' control.\1681\ AEE contends that accepting high 
interconnection queue volumes as a legitimate cause for delays would 
amount to providing a permanent free pass to transmission providers to 
exceed study deadlines.\1682\
---------------------------------------------------------------------------

    \1679\ AEE Reply Comments at 34-35; MISO TOs Initial Comments at 
18; Public Interest Organizations Reply Comments at 2-4.
    \1680\ ACE-NY Reply Comments at 3.
    \1681\ SEIA Reply Comments at 16.
    \1682\ AEE Reply Comments at 27.
---------------------------------------------------------------------------

    887. Several commenters who oppose the NOPR proposal assert that 
transmission providers engage in good

[[Page 61139]]

faith efforts to process the interconnection queue in a timely manner 
\1683\ and that there is no evidence to the contrary.\1684\ Commenters 
argue that transmission providers already have sufficient motivation to 
process the interconnection queue in a timely manner because: (1) their 
own interconnection requests are processed in the exact same manner as 
third parties; (2) they need to ensure an adequate amount of generation 
to meet load and reserve margin requirements; and (3) they have to file 
reports with the Commission and can face complaints or enforcement 
action for poor performance.\1685\ Commenters assert that penalties 
will be ineffective in speeding interconnection queue processing time 
because the main causes of study delays will remain.\1686\ MISO TOs 
contend that the Commission proposes to compound the problem of study 
delays by requiring transmission owners and providers to manage delays 
that are out of their control, while simultaneously proposing to 
require transmission providers to offer additional studies.\1687\
---------------------------------------------------------------------------

    \1683\ AEP Initial Comments at 26; Avangrid Initial Comments at 
29; Dominion Initial Comments at 34; EEI Initial Comments at 15; 
Eversource Initial Comments at 21-22; Indicated PJM TOs Initial 
Comments at 5-6, 38; MISO TOs Initial Comments at 15-17; NextEra 
Initial Comments at 29; NYISO Initial Comments at 26-27; OMS Initial 
Comments at 15; Puget Sound Initial Comments at 9-10; State Agencies 
Initial Comments at 12; Vermont Electric and Vermont Transco Initial 
Comments at 2.
    \1684\ AEP Initial Comments at 26; Avangrid Initial Comments at 
29; Dominion Initial Comments at 34; EEI Initial Comments at 15; 
Eversource Initial Comments at 21-22; Indicated PJM TOs Initial 
Comments at 5-6, 38; MISO TOs Initial Comments at 15-17; NextEra 
Initial Comments at 29; NYISO Initial Comments at 26-27; Puget Sound 
Initial Comments at 9-10; State Agencies Initial Comments at 12.
    \1685\ AEP Initial Comments at 26; Dominion Initial Comments at 
36; Indicated PJM TOs Initial Comments at 37-38; MISO TOs Initial 
Comments at 16; PJM Initial Comments at 56; Puget Sound Initial 
Comments at 10.
    \1686\ Ameren Initial Comments at 20; Bonneville Initial 
Comments at 15; Dominion Initial Comments at 34-35; Eversource 
Initial Comments at 20-21; Indicated PJM TOs Initial Comments at 39-
40; MISO Initial Comments at 13, 71; NextEra Initial Comments at 30; 
NextEra Reply Comments at 11; North Dakota Commission Initial 
Comments at 5; PacifiCorp Initial Comments at 34; PG&E Reply 
Comments at 3; PJM Initial Comments at 7-8, 56; R Street Initial 
Comments at 14; Southern Initial Comments at 30; State Agencies 
Initial Comments at 12.
    \1687\ MISO TOs Reply Comments at 12.
---------------------------------------------------------------------------

    888. NextEra argues that penalties will be counterproductive if not 
paired with constructive guidance to transmission providers on how to 
perform interconnection studies in a timelier manner because penalties 
could either divert resources away from interconnection studies and 
lead to conflict about allocating penalties in RTOs/ISOs or be accepted 
as a cost of doing business.\1688\
---------------------------------------------------------------------------

    \1688\ NextEra Initial Comments at 29-30.
---------------------------------------------------------------------------

    889. Indicated PJM TOs contest the NOPR's citation to testimony 
provided by Utah Public Service Commission Chairman Thad LeVar, noting 
that Chairman LeVar also acknowledged that best practices vary between 
RTO/ISO and non-RTO/ISO regions and that penalties do not always result 
in the best consequences.\1689\
---------------------------------------------------------------------------

    \1689\ Indicated PJM TOs Initial Comments at 38 (citing May 
Joint Task Force Tr. 46:11-13, 89:17-18 (Thad LeVar)).
---------------------------------------------------------------------------

    890. Some commenters argue that the NOPR proposal is an unsupported 
shift from recent precedent.\1690\ Commenters note that the Commission 
expressly declined to impose penalties for study delays in Order No. 
845 and argue that there is no change in circumstance or concrete 
evidence to justify reversal of that prior finding.\1691\
---------------------------------------------------------------------------

    \1690\ EEI Initial Comments at 14; MISO Reply Comments at 21.
    \1691\ MISO TOs Initial Comments at 21-22; NYISO Initial 
Comments at 26; PG&E Initial Comments at 6; PG&E Reply Comments at 
3.
---------------------------------------------------------------------------

    891. Commenters also note that, although the Commission based its 
penalty proposal on Order No. 890, there are significant 
differences.\1692\ First, commenters explain that the Order No. 890 
penalties only apply when a transmission provider fails to meet 
multiple study deadlines, whereas the NOPR proposes to impose penalties 
each time a study deadline is missed.\1693\ Second, commenters point 
out that the Order No. 890 penalty structure protects due process 
through an opportunity to present evidence that delays were outside the 
transmission provider's control or due to extenuating circumstances, 
whereas the NOPR proposal does not.\1694\ Third, PacifiCorp explains 
that interconnection studies are more complex, numerous, and 
susceptible to delays than the transmission service studies at issue in 
Order No. 890.\1695\ Affected Interconnection Customers argue that the 
Commission's comparison to Order No. 890's penalty structure for 
transmission service requests is misplaced because the size and scale 
of the current interconnection queue backlog is significantly different 
than transmission queues when Order No. 890 was issued.\1696\ 
Similarly, Invenergy notes that the reference to transmission service 
requests is inapplicable because the interconnection process uses a 
cluster study.\1697\
---------------------------------------------------------------------------

    \1692\ MISO TOs Initial Comments at 19; PacifiCorp Initial 
Comments at 33-34.
    \1693\ MISO TOs Initial Comments at 19; MISO Reply Comments at 
21; Tri-State Initial Comments at 18.
    \1694\ Eversource Initial Comments at 30; MISO Reply Comments at 
21; MISO TOs Initial Comments at 19-21.
    \1695\ PacifiCorp Initial Comments at 33-34.
    \1696\ Affected Interconnection Customers Initial Comments at 
25.
    \1697\ Invenergy Initial Comments at 30.
---------------------------------------------------------------------------

    892. EEI and Eversource state that the NOPR proposal represents a 
departure from the good utility practice standard, which the Commission 
uses in many other contexts and is part of the definition of reasonable 
efforts.\1698\ EEI and Eversource assert that the Commission has not 
adequately explained why reliance on good utility practice remains 
sufficient in other situations, but not for interconnection studies.
---------------------------------------------------------------------------

    \1698\ EEI Initial Comments at 15; Eversource Initial Comments 
at 22-24.
---------------------------------------------------------------------------

    893. Commenters contend that firm study deadlines are not 
reasonable or feasible because interconnection studies are complex and 
each study is different in scope, size, and needed coordination.\1699\ 
Some commenters also note that the current deadlines were established 
almost 20 years ago, when the transmission providers had significantly 
fewer interconnection requests to study.\1700\ SPP contends that 
cluster studies are more prone to study delays given the 
interdependencies between interconnection requests and number of 
parties that need to cooperate.\1701\ Commenters also assert that the 
other NOPR proposals, including the optional resource solicitation 
study, informational studies, and evaluation of advanced transmission 
technologies, add significant burdens to the study process that will 
make it even more challenging to comply with strict deadlines.\1702\
---------------------------------------------------------------------------

    \1699\ AECI Initial Comments at 6; Avangrid Initial Comments at 
28-29; Bonneville Initial Comments at 15; Clean Energy States 
Initial Comments at 10-11; Eversource Initial Comments at 27; Idaho 
Power Initial Comments at 10; ISO-NE Initial Comments at 35-36; ISO/
RTO Council Reply Comments at 2; MISO TOs Initial Comments at 15; 
National Grid Initial Comments at 30; PJM Initial Comments at 58; 
Puget Sound Initial Comments at 10; SPP Initial Comments at 13; U.S. 
Chamber of Commerce Initial Comments at 10; WIRES Initial Comments 
at 10.
    \1700\ Eversource Initial Comments at 27; Indicated PJM TOs 
Initial Comments at 37-38.
    \1701\ SPP Initial Comments at 11-12.
    \1702\ Id. at 13; Indicated PJM TOs Initial Comments at 36; MISO 
Reply Comments at 7; PPL Initial Comments at 24.
---------------------------------------------------------------------------

    894. Some commenters express concern that the penalties could 
reduce coordination between transmission providers, interconnection 
customers, and affected systems.\1703\ Commenters

[[Page 61140]]

note that the enforcement of deadlines could be expensive, involve 
contentious disputes, and disrupt ongoing studies.\1704\ Commenters 
state that transmission providers will also likely provide less 
flexibility to interconnection customers to remedy deficiencies or 
modify interconnection requests.\1705\ MISO TOs assert that this could 
threaten reliability.\1706\ NESCOE points out that firm penalties may 
impede the interconnection of emerging technologies by limiting 
flexibility to work on modeling and data requirements.\1707\
---------------------------------------------------------------------------

    \1703\ Alliant Energy Initial Comments at 6; EEI Initial 
Comments at 15; Eversource Initial Comments at 25-26; MISO Reply 
Comments at 21; North Dakota Commission Initial Comments at 6.
    \1704\ Clean Energy Associations Initial Comments at 45; EEI 
Initial Comments at 15; MISO Initial Comments at 13, 71; MISO TOs 
Initial Comments at 24; MISO TOs Reply Comments at 10; National Grid 
Initial Comments at 30; NextEra Initial Comments at 30; OMS Initial 
Comments at 15; PacifiCorp Initial Comments at 35; R Street Initial 
Comments at 14; SPP Initial Comments at 14.
    \1705\ Dominion Reply Comments at 21; EEI Initial Comments at 
15; Eversource Initial Comments at 25-26; NYISO Initial Comments at 
38-39; WIRES Initial Comments at 10.
    \1706\ MISO TOs Reply Comments at 18-19.
    \1707\ Id.; NESCOE Initial Comments at 17.
---------------------------------------------------------------------------

    895. PJM argues that using penalties to offset study costs for 
interconnection customers introduces perverse incentives for the 
interconnection customer to dispute and thereby delay its study reports 
to receive the penalty money.\1708\ In response, however, AEE notes 
that interconnection customers bear greater costs due to delays, which 
creates an incentive to move forward as quickly as possible.\1709\
---------------------------------------------------------------------------

    \1708\ PJM Initial Comments at 57.
    \1709\ AEE Reply Comments at 35-36.
---------------------------------------------------------------------------

    896. Commenters note that the same engineers that conduct 
interconnection studies also have other responsibilities such as 
transmission planning \1710\ and responding to extreme weather 
events.\1711\ Ameren states that penalties could motivate transmission 
providers to redirect resources towards interconnection studies to the 
detriment of other necessary functions.\1712\ Some commenters argue 
that penalties will deprive transmission providers of financial 
resources or harm work environments and employee morale, making it more 
difficult to recruit and retain personnel qualified to perform the 
studies.\1713\
---------------------------------------------------------------------------

    \1710\ Indicated PJM TOs Initial Comments at 6.
    \1711\ National Grid Initial Comments at 30.
    \1712\ Ameren Initial Comments at 21.
    \1713\ Eversource Initial Comments at 25-26; Indicated PJM TOs 
Initial Comments at 24, 40; MISO TOs Initial Comments at 24; Pacific 
Northwest Utilities Initial Comments at 12; PJM Initial Comments at 
57.
---------------------------------------------------------------------------

    897. A number of commenters express concern that the NOPR proposal 
may result in less accurate studies because transmission providers may 
prioritize meeting deadlines over accuracy and identification of the 
most efficient solutions.\1714\ Some commenters further assert that 
penalties may impair system reliability because the study timelines are 
too short to carry out sufficient analysis.\1715\ Some commenters argue 
that the penalties could force transmission providers to complete 
studies without necessary data, which could also lead to inaccurate 
results and cause restudy.\1716\ Some commenters state that less 
accurate studies would harm interconnection customers because 
interconnection customers cannot rely on them to make sound business 
decisions.\1717\ Avangrid states that transmission providers could use 
more conservative assumptions and ``stock solutions'' to streamline 
studies, which could increase interconnection costs.\1718\ However, in 
response to these comments, AEE states that the implementation of 
timelines and penalties does not inherently determine the evaluation 
process for clusters.\1719\ AEE notes that inaccurate study results 
occur today without firm deadlines and that accuracy can be improved 
even with deadlines.\1720\ New Jersey Commission disagrees that there 
is an inherent tradeoff between system reliability and holding 
transmission providers accountable, arguing that failing to bring 
sufficient new generating facilities online can create considerable 
reliability and economic risks.\1721\
---------------------------------------------------------------------------

    \1714\ AECI Initial Comments at 6; Alliant Energy Initial 
Comments at 6; Avangrid Initial Comments at 9-10, 30; Bonneville 
Initial Comments at 15-16; CESA Reply Comments at 8; Clean Energy 
Buyers Initial Comments at 10-11; Enel Initial Comments at 48; 
Indicated PJM TOs Reply Comments at 26; ISO/RTO Council Initial 
Comments at 8; Longroad Energy Reply Comments at 14; MISO Initial 
Comments at 13, 71, 77-78; MISO TOs Initial Comments at 14, 24; 
National Grid Initial Comments at 30; NESCOE Reply Comments at 13; 
NextEra Reply Comments at 11; North Dakota Commission Initial 
Comments at 6; NRECA Initial Comments at 34; NYISO Initial Comments 
at 38-39; NYTOs Initial Comments at 24-28; Omaha Public Power 
Initial Comments at 12; OMS Initial Comments at 15; [Oslash]rsted 
Initial Comments at 15; PacifiCorp Reply Comments at 6; PJM Initial 
Comments at 8, 56-57; PPL Initial Comments at 19; SPP Initial 
Comments at 11-12; Tri-State Initial Comments at 18; Xcel Initial 
Comments at 38.
    \1715\ AEP Initial Comments at 28; Dominion Reply Comments at 
21; NYISO Initial Comments at 39; PJM Initial Comments at 8, 56-57.
    \1716\ Ameren Initial Comments at 21; MISO Initial Comments at 
78; SPP Initial Comments at 12-13.
    \1717\ Enel Initial Comments at 48-49; MISO Initial Comments at 
78; OMS Initial Comments at 15; SPP Initial Comments at 12.
    \1718\ Avangrid Initial Comments at 30.
    \1719\ AEE Reply Comments at 33.
    \1720\ Id. at 31-32.
    \1721\ New Jersey Commission Reply Comments at 3.
---------------------------------------------------------------------------

    898. Commenters express concern that the cost of penalties and 
compliance mechanisms may be passed down to customers and increase 
transmission costs.\1722\ Clean Energy Buyers argue that the penalties, 
if they flow through to interconnection customers, could outweigh the 
benefits gained from other reforms and lead to disputes over the 
allocation of penalty amounts.\1723\ R Street points out that the 
Commission will have to ensure that transmission providers cannot 
translate penalties into cost recovery at either the Federal or retail 
level.\1724\
---------------------------------------------------------------------------

    \1722\ Alliant Energy Initial Comments at 6-7; NARUC Initial 
Comments at 19; NYISO Reply Comments at 6-7, 9; R Street Initial 
Comments at 14; SEIA Reply Comments at 17; State Agencies Initial 
Comments at 12; Tri-State Initial Comments at 18; Vermont Electric 
and Vermont Transco Initial Comments at 2.
    \1723\ Clean Energy Buyers Initial Comments at 10.
    \1724\ R Street Initial Comments at 15; see also SEIA Reply 
Comments at 17.
---------------------------------------------------------------------------

    899. Some commenters characterize the NOPR proposal as a strict 
liability approach to penalties and argue that it is unjust and 
unreasonable, arbitrary and capricious, and a violation of due process 
rights and the Administrative Procedures Act to impose penalties 
without a fact-based finding of fault.\1725\ Some commenters emphasize 
that the NOPR proposal provides no possibility for the transmission 
provider to explain the circumstances for the delay, even though the 
delay is often outside of the transmission provider's control.\1726\ 
Dominion argues that there are three practical concerns with the NOPR 
proposal: (1) how disputes about who is at fault will be resolved; (2) 
who decides fault; and (3) whether the interconnection study should be 
delayed while the dispute is resolved.\1727\
---------------------------------------------------------------------------

    \1725\ MISO Initial Comments at 13, 71; MISO Reply Comments at 
19-20; MISO TOs Initial Comments at 18; SPP Initial Comments at 14; 
NYISO Initial Comments at 40 (citing Motor Vehicle Mfrs. Ass'n of 
U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 
(1983); Enforcement of Statutes, Reguls. & Orders, 123 FERC ] 
61,156, at PP 50-71 (2008)); WIRES Initial Comments at 10.
    \1726\ ISO-NE Initial Comments at 35; ISO/RTO Council Initial 
Comments at 2; MISO Initial Comments at 7.
    \1727\ Dominion Reply Comments at 24.
---------------------------------------------------------------------------

    900. Some commenters argue that the reasonable efforts standard is 
the right approach considering the complex dynamics of the 
interconnection study process and constantly changing 
circumstances.\1728\ EEI asserts that the reasonable efforts standard 
is the best approach to govern the interconnection process, which is 
flexible to allow for the optimum exercise of engineering judgement 
while ensuring

[[Page 61141]]

accountability for egregious delays or what is not consistent with good 
utility practice.\1729\ MISO TOs note that, in Order No. 2003, the 
Commission explained that the reasonable efforts standard was a high 
standard because parties use it when protecting their own interests and 
applying this standard to all parties would ``ensure comparable 
treatment.'' \1730\
---------------------------------------------------------------------------

    \1728\ Avangrid Initial Comments at 10, 30-31; Bonneville 
Initial Comments at 16; Indicated PJM TOs Initial Comments at 36; 
NYISO Initial Comments at 30-31; PG&E Reply Comments at 3-4; WIRES 
Initial Comments at 10.
    \1729\ EEI Reply Comments at 16.
    \1730\ MISO TOs Reply Comments at 6-7 (citing Order No. 2003, 
104 FERC ] 61,103 at P 69).
---------------------------------------------------------------------------

    901. NYISO contends that the reasonable efforts standard and Order 
No. 845 reporting requirements provide the Commission and stakeholders 
with information to evaluate the length of time taken by RTOs/ISOs to 
finish studies, compare their performance, and identify and investigate 
when a particular entity is systematically delaying studies, which will 
allow the Commission and stakeholders to take appropriate action.\1731\ 
SPP proposes that the Commission retain the reasonable efforts standard 
and make improvements to it or enforce it more strictly.\1732\
---------------------------------------------------------------------------

    \1731\ NYISO Initial Comments at 31.
    \1732\ SPP Initial Comments at 15.
---------------------------------------------------------------------------

    902. WAPA notes that, as a Federal power marketing administration, 
it has statutory duties that take precedence over deliverables 
established by the Commission and cannot be subject to monetary 
penalties without a waiver of sovereign immunity.\1733\ Avangrid notes 
that many transmission providers and transmission owners do not earn 
rates of return for interconnection facilities or network upgrades and 
do not profit from interconnection studies, so penalties would reduce 
shareholder return on equity.\1734\
---------------------------------------------------------------------------

    \1733\ WAPA Initial Comments at 10.
    \1734\ Avangrid Initial Comments at 30.
---------------------------------------------------------------------------

iii. Comments on Specific Proposal
    903. Some commenters support eliminating the reasonable efforts 
standard but do not support the proposed financial penalties.\1735\ 
CAISO argues that the Commission should simply prohibit late studies 
and mandate firm study deadlines because the proposed penalties will 
enable transmission providers to continue completing studies late if 
they are willing to pay the price.\1736\ CAISO explains that, if a 
transmission provider cannot meet its study deadlines, it should be 
required to amend its tariff.\1737\ Other commenters, as described 
below, have various comments on the specific penalty proposal.
---------------------------------------------------------------------------

    \1735\ CAISO Initial Comments at 25-26; Clean Energy Buyers 
Initial Comment at 9-10; MISO Initial Comments at 13, 71, 79; Shell 
Initial Comments at 10.
    \1736\ CAISO Initial Comments at 25-26; PG&E Reply Comments at 
4.
    \1737\ CAISO Initial Comments at 25-26.
---------------------------------------------------------------------------

(a) Penalty Amount
    904. Some commenters advocate for larger penalties than the NOPR 
proposal.\1738\ Some commenters contend that the proposed penalty 
amount is de minimis \1739\ or that a $500 per business day penalty is 
likely too small to prompt a change in behavior.\1740\ Cypress Creek 
argues that penalties should be commensurate with the magnitude of 
liquidated damages that interconnection customers face if they do not 
meet their contractual deadlines.\1741\ ACE-NY proposes a penalty of 
$5,000 to $25,000 per day, depending on cluster size, if the Commission 
chooses a per-cluster-per-day penalty structure.\1742\ Affected 
Interconnection Customers propose that the Commission adopt a penalty 
of $2,500 per day capped at $2 million.\1743\ Public Interest 
Organizations state that there is not sufficient consensus in the 
record to move forward with the $500 per day penalty amount and suggest 
that the Commission hold a technical conference to determine the final 
amount.\1744\
---------------------------------------------------------------------------

    \1738\ ACE-NY Initial Comments at 12; Affected Interconnection 
Customers Initial Comments at 25-26; CESA Initial Comments at 11; 
CESA Reply Comments at 9; Consumers Energy Initial Comments at 6; 
CREA and NewSun Reply Comments at 56; Cypress Creek Initial Comments 
at 24; EPSA Initial Comments at 11; Fervo Energy Initial Comments at 
6; Invenergy Initial Comments at 29; Pine Gate Initial Comments at 
39.
    \1739\ CESA Reply Comments at 8; Invenergy Initial Comments at 
29; NARUC Initial Comments at 14.
    \1740\ ACE-NY Initial Comments at 12; Affected Interconnection 
Customers Initial Comments at 24-26; CESA Initial Comments at 11; 
Clean Energy Associations Initial Comments at 44; Consumers Energy 
Initial Comments at 6; ELCON Initial Comments at 7-8; Pine Gate 
Initial Comments at 39.
    \1741\ Cypress Creek Initial Comments at 24.
    \1742\ ACE-NY Initial Comments at 12.
    \1743\ Affected Interconnection Customers Initial Comments at 5, 
26; CESA Reply Comments at 9.
    \1744\ Public Interest Organizations Reply Comments at 5-6.
---------------------------------------------------------------------------

    905. Some commenters argue that the penalties should increase 
through the study process because later-stage study delays have greater 
impacts on interconnection customers, which are required to make 
increasing commitments throughout the study process.\1745\ Invenergy 
recommends penalty amounts of $5,000 per day for cluster studies, 
$6,000 per day for cluster restudies, and $7,000 per day for facilities 
studies.\1746\
---------------------------------------------------------------------------

    \1745\ CESA Initial Comments at 11; Clean Energy Associations 
Initial Comments at 44; CREA and NewSun Reply Comments at 57; 
Invenergy Initial Comments at 30.
    \1746\ Invenergy Initial Comments at 30.
---------------------------------------------------------------------------

    906. Pine Gate expresses concern that the proposed penalty amounts 
do not correspond to the costs imposed on interconnection customers as 
a result of the late study results, explaining that the penalty amount 
is dwarfed by the overall cluster study cost and that the low daily 
rate would require an interconnection study to be delayed years before 
the amounts would approach the study deposit amounts.\1747\ As an 
example, Pine Gate refers to the most recent MISO interconnection queue 
submissions: MISO received 956 interconnection requests, totaling 170.8 
GW of new generation, and collected $687,980,000 in study deposits. 
Pine Gate notes that, under a late study fee of $500 per day, a study 
would have to be delayed 1,375,960 days--or 3,770 years--before 
equaling the cost of study deposits. Further, Pine Gate explains that 
the daily carrying cost on the study deposit cost at the prevailing 
development loan interest rate of 10% is approximately $188,487.67. 
Thus, Pine Gate states that, before the proposed 10-day grace period 
has elapsed, interconnection customers will have spent $1,884,876 in 
additional interest costs.
---------------------------------------------------------------------------

    \1747\ Pine Gate Initial Comments at 39-40.
---------------------------------------------------------------------------

    907. In response to requests for higher penalties, some commenters 
argue that there is no legal or policy justification for making the 
proposed penalty scheme harsher and more inequitable.\1748\ MISO argues 
that NERC reliability penalties are typically assessed at under $500 
per day, if at all, and NERC non-critical infrastructure protection 
penalties are also assessed at far lower values. MISO contends that, 
because these ``moderate risk'' violations merit such low penalties, 
there is no support for $500 per day penalties for delayed 
interconnection studies.\1749\
---------------------------------------------------------------------------

    \1748\ MISO TOs Reply Comments at 19; NYISO Reply Comments at 1.
    \1749\ MISO Reply Comments at 23.
---------------------------------------------------------------------------

    908. NARUC supports the proposal to cap the penalty amount at 100% 
of the total study deposit received.\1750\ Several commenters argue 
that the penalty amount should be capped at an amount greater than 100% 
of the total study deposit received.\1751\ Invenergy requests that the 
Commission clarify that the cap is not reduced by any withdrawal 
penalties.\1752\ Public Interest

[[Page 61142]]

Organizations propose that transmission providers that reach the cap 
issue a compliance statement explaining in detail the source of the 
delay and use penalty amounts above the cap to hire third-party 
consultants to conduct interconnection studies.\1753\
---------------------------------------------------------------------------

    \1750\ NARUC Initial Comments at 15.
    \1751\ Interwest Initial Comments at 8; Invenergy Initial 
Comments at 31; Northwest and Intermountain Initial Comments at 14.
    \1752\ Invenergy Initial Comments at 31.
    \1753\ Public Interest Organizations Initial Comments at 36.
---------------------------------------------------------------------------

    909. Several commenters argue that the penalty amount should not be 
capped.\1754\ Some commenters note that financial penalties for 
interconnection customers are not capped at their study deposits.\1755\ 
Other commenters argue that the study deposit amount cap is not 
commensurate with the harm late studies cause interconnection 
customers.\1756\
---------------------------------------------------------------------------

    \1754\ Id. at 35-36; ACE-NY Initial Comments at 13; AEE Reply 
Comments at 37; Consumers Energy Initial Comments at 6; CREA and 
NewSun Initial Comments at 84; Cypress Creek Initial Comments at 23-
24; SEIA Initial Comments at 34.
    \1755\ AEE Initial Comments at 31; Northwest and Intermountain 
Initial Comments at 15.
    \1756\ CREA and NewSun Initial Comments at 84; SEIA Initial 
Comments at 34.
---------------------------------------------------------------------------

(b) Penalty Structure
    910. Some commenters suggest a per-customer per-day penalty 
structure, rather than the NOPR proposal for a per-cluster per-day 
structure.\1757\ AEE suggests that the Commission assess penalties 
based on the higher value of $500 per day or $100 per customer per 
day.\1758\ Multiple commenters oppose a penalty structure based on the 
number of interconnection customers because transmission providers have 
no control over the number of interconnection requests they receive and 
higher request volumes lead to more complex studies with more potential 
for delay.\1759\
---------------------------------------------------------------------------

    \1757\ ACE-NY Initial Comments at 13; SEIA Initial Comments at 
34. PG&E seeks clarification on whether the penalties will apply 
per-customer per-day or per-cluster per-day. PG&E Initial Comments 
at 8.
    \1758\ AEE Initial Comments at 31.
    \1759\ CAISO Initial Comments at 27; MISO Reply Comments at 24; 
Xcel Initial Comments at 38.
---------------------------------------------------------------------------

    911. Some commenters suggest a penalty structure based on the 
cluster's characteristics.\1760\ Public Interest Organizations suggest 
a penalty structure set as a percentage of the total study deposit 
received per day.\1761\ Google recommends the penalty structure take 
into account both the size of the interconnection request and the 
magnitude of a study delay's impact on other interconnection requests 
in the interconnection queue, which would focus penalties on delays 
that have the most impact on overall processing of the interconnection 
queue.\1762\ NARUC explains that the penalty should not be targeted at 
the number of interconnection customers in a cluster that are delayed 
but at the desirable characteristics of the generating facilities being 
delayed.\1763\
---------------------------------------------------------------------------

    \1760\ Google Initial Comments at 17; NARUC Initial Comments at 
20-21; Public Interest Organizations Initial Comments at 34.
    \1761\ Public Interest Organizations Initial Comments at 34.
    \1762\ Google Initial Comments at 17.
    \1763\ NARUC Initial Comments at 20-21.
---------------------------------------------------------------------------

    912. Some commenters suggest that the Commission require 
transmission providers to discount study costs for delayed studies by 
the percentage of time they are delayed in completing such study, 
subject to a maximum discount set by the Commission.\1764\ Clean Energy 
States propose that, if an interconnection study is late, the 
transmission provider could not charge the interconnection customers 
for the cost of the study, providing the interconnection customer a 
modest amount of compensation for the delay.\1765\ PacifiCorp argues 
that neither the host transmission provider nor affected system 
operator should be penalized if either party delays the work of the 
other, especially if the delays are caused by transmission providers 
that are not public utilities.\1766\
---------------------------------------------------------------------------

    \1764\ AEE Initial Comments at 28-29; AEE Reply Comments at 36-
37; Clean Energy Associations Initial Comments at 45 (explaining 
that, under their preferred approach, if a study took 30 calendar 
days past a 150-calendar day deadline, that would result in a 20% 
discount on study costs); Longroad Energy Reply Comments at 14; Pine 
Gate Initial Comments at 40; SEIA Reply Comments at 17.
    \1765\ Clean Energy States Initial Comments at 10-11.
    \1766\ PacifiCorp Initial Comments at 37.
---------------------------------------------------------------------------

    913. NRECA and Tri-State assert that the final rule should allow 
transmission providers to stop or reset the clock in the event of 
interconnection customer-initiated delays.\1767\ Similarly, APPA-LPPC 
state that the clock should not start running on study deadlines until 
after the interconnection customer submits all necessary information, 
including curing any deficiencies.\1768\ Tri-State asserts that a delay 
should not be penalized if it is caused by a higher-queued cluster 
going through a restudy.\1769\ Tri-State also suggests that, if the 
Commission moves forward with penalties for late studies, additional 
language should be added requiring interconnection customers to provide 
needed information within a specified time frame in order to complete 
the studies. R Street claims that transmission providers can game 
requirements that trigger penalties, such as by forcing requesting 
parties to resubmit specifications to restart the processing 
clock.\1770\
---------------------------------------------------------------------------

    \1767\ NRECA Initial Comments at 34; Tri-State Initial Comments 
at 19.
    \1768\ APPA-LPPC Initial Comments at 21.
    \1769\ Tri-State Initial Comments at 18.
    \1770\ R Street Initial Comments at 15.
---------------------------------------------------------------------------

(c) Penalty Allocation and Distribution
    914. Many commenters agree that transmission providers, including 
RTOs/ISOs, must not pass on penalty costs to ratepayers.\1771\ Public 
Interest Organizations support enabling transmission providers to 
allocate penalty costs to responsible parties but recommend maintaining 
presumption of fault with the transmission providers themselves and 
disallowing transmission providers from recovering penalty 
amounts.\1772\
---------------------------------------------------------------------------

    \1771\ Clean Energy Associations Initial Comments at 44; 
Consumers Energy Initial Comments at 6; Cypress Creek Initial 
Comments at 24; Google Initial Comments at 18; Illinois Commission 
Initial Comments at 9; NARUC Initial Comments at 15; New Jersey 
Commission Initial Comments at 13-14; OPSI Initial Comments at 8-9; 
SEIA Initial Comments at 34; see also Ohio Commission Consumer 
Advocate Initial Comments at 13 (``Although FERC states that the 
proposed penalties would not be recoverable in transmission rates, 
we believe such imposition will inevitably impact ratepayers, and 
not rightfully so, unless it can be clearly demonstrated that the 
proposed $500/day penalty is not passed along[.]''). But see Iowa 
Commission Initial Comments at 5-6 (``[I]t is not correct to assume 
that the penalties would result in ultimate costs to the customers/
ratepayers as some of the stakeholders contend[.]'').
    \1772\ Public Interest Organizations Reply Comments at 6, 8-9.
---------------------------------------------------------------------------

    915. Several commenters support distributing the penalties 
collected from transmission providers to the impacted interconnection 
customers.\1773\ PG&E seeks clarification on how the penalty would be 
distributed (i.e., equal distribution to each interconnection 
customers, equal distribution among interconnection requests, or 
distributed based on project size).\1774\ Fervo Energy supports the 
proposal to require transmission providers to provide quarterly public 
reports on total amounts of penalties and the highest penalty for a 
single interconnection request.\1775\ Google argues that transmission 
providers should make such a report available annually to state 
commissions to ensure penalties are not paid by consumers.\1776\
---------------------------------------------------------------------------

    \1773\ ACE-NY Initial Comments at 12; Interwest Initial Comments 
at 9; NARUC Initial Comments at 14-15; Northwest and Intermountain 
Initial Comments at 15.
    \1774\ PG&E Initial Comments at 8.
    \1775\ Fervo Energy Initial Comments at 6.
    \1776\ Google Initial Comments at 20.
---------------------------------------------------------------------------

    916. National Grid argues that the Commission should allow 
transmission providers to recover penalties from an interconnection 
customer if the customer is responsible for the delay.\1777\
---------------------------------------------------------------------------

    \1777\ National Grid Initial Comments at 33.

---------------------------------------------------------------------------

[[Page 61143]]

(d) Penalty Recovery in RTOs/ISOs
    917. Some commenters support the proposal to allow RTOs/ISOs to 
recover the cost of specific interconnection study penalties from 
transmission owners responsible for study delays through FPA section 
205 filings.\1778\ ACORE recommends that RTOs/ISOs provide explicit 
criteria for how they will determine which parties are responsible for 
or contributed to study delays.\1779\ AEE suggests that the Commission 
assign RTO/ISO penalties to transmission owners by default.\1780\ In 
response to AEE's proposal, MISO TOs assert that imposing penalties on 
transmission owners that did not have control over the causes of study 
delays does not follow cost causation principles.\1781\
---------------------------------------------------------------------------

    \1778\ ACE-NY Initial Comments at 12; CESA Reply Comments at 8-
9; Google Initial Comments at 19; NARUC Initial Comments at 17; 
Public Interest Organizations Initial Comments at 35; SEIA Initial 
Comments at 34.
    \1779\ ACORE Initial Comments at 8.
    \1780\ AEE Initial Comments at 30.
    \1781\ MISO TOs Reply Comments at 20-21 (citing K N Energy, Inc. 
v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992)).
---------------------------------------------------------------------------

    918. Some commenters express concerns about how RTOs/ISOs will pay 
penalties if no member is found responsible.\1782\ OPSI contends that, 
because RTOs/ISOs rely on transmission owners to process 
interconnection queues, they may be reluctant to seek penalty recovery 
from them.\1783\
---------------------------------------------------------------------------

    \1782\ Alliant Energy Initial Comments at 6-7; APPA-LPPC Initial 
Comments at 22; NARUC Initial Comments at 18; NESCOE Initial 
Comments at 16.
    \1783\ OPSI Initial Comments at 9.
---------------------------------------------------------------------------

    919. Several commenters oppose the proposal to allow RTOs/ISOs to 
recover the cost of specific interconnection study penalties from 
transmission owners responsible for study delays through FPA section 
205 filings.\1784\ Such commenters assert that the proposal does not 
provide sufficient detail on how penalties will work in RTO/ISO 
regions.\1785\ Some commenters contend that imposing penalties on RTOs/
ISOs will not expedite interconnection studies because the penalties 
will not address the actual source of study delays and will disrupt 
processing of interconnection queues.\1786\ ISO-NE and MISO note that 
delays may not be the fault of the RTO/ISO because transmission owners 
often conduct the studies.\1787\
---------------------------------------------------------------------------

    \1784\ AEP Initial Comments at 27-28; CAISO Initial Comments at 
26; Dominion Initial Comments at 35-36; EEI Initial Comments at 17; 
ISO-NE Initial Comments at 34-36; SPP Initial Comments at 15; TAPS 
Initial Comments at 3.
    \1785\ Eversource Initial Comments at 29; PJM Initial Comments 
at 57.
    \1786\ ISO/RTO Council Initial Comments at 2; WIRES Initial 
Comments at 11.
    \1787\ ISO-NE Initial Comments at 35; MISO Initial Comments at 
14, 73-74.
---------------------------------------------------------------------------

    920. Commenters argue that the proposed penalty system would impose 
administrative and litigative burden on RTOs/ISOs and the 
Commission.\1788\ Indicated PJM TOs argue that the process before the 
Commission will need to be a complete de novo review.\1789\ SoCal 
Edison and New York State Department note that the penalty system would 
likely require additional resources to track and allocate penalties, 
which could increase the cost of administering interconnection 
queues.\1790\ The ISO/RTO Council claims that, under the NOPR proposal, 
RTOs/ISOs will need to act as fact-finding tribunals to fairly assign 
penalties before making an FPA section 205 filing, which would be a 
time- and resource-consuming process at odds with the goal of reducing 
interconnection study delays.\1791\ TAPS avers that RTOs/ISOs would 
need precise and well-supported cases to successfully assign penalties 
to responsible transmission owners.\1792\
---------------------------------------------------------------------------

    \1788\ Avangrid Reply Comments at 8; CAISO Initial Comments at 
26; Indicated PJM TOs Reply Comments at 27; ISO-NE Initial Comments 
at 35; ISO/RTO Council Initial Comments at 3-4; MISO Initial 
Comments at 16, 77; MISO TOs Reply Comments at 21-22; New York State 
Department Initial Comments at 10-11; NYISO Initial Comments at 33; 
PJM Initial Comments at 57-58; SoCal Edison Initial Comments at 19.
    \1789\ Indicated PJM TOs Initial Comments at 44.
    \1790\ New York State Department Initial Comments at 10-11; 
SoCal Edison Initial Comments at 19.
    \1791\ ISO/RTO Council Initial Comments at 5; see also Indicated 
PJM TOs Initial Comments at 37 (explaining that it would be 
difficult for RTOs to determine who is at fault for study delays).
    \1792\ TAPS Initial Comments at 6-7.
---------------------------------------------------------------------------

    921. Commenters contend that having RTOs/ISOs assign penalties to 
responsible entities would harm coordination or create tension between 
RTOs/ISOs, transmission owners, interconnection customers, and other 
parties.\1793\ AEP and TAPS assert that the proposal could discourage 
RTO/ISO participation.\1794\
---------------------------------------------------------------------------

    \1793\ AEP Initial Comments at 27; Dominion Initial Comments at 
35-36; Indicated PJM TOs Reply Comments at 6-7, 27; NextEra Initial 
Comments at 30; NYISO Initial Comments at 39-40; PJM Initial 
Comments at 57-58.
    \1794\ AEP Initial Comments at 27-28; TAPS Initial Comments at 
6.
---------------------------------------------------------------------------

    922. Commenters express concern around imposing penalties on non-
profit RTOs/ISOs, which have no ability to pay fines without collecting 
them from another party.\1795\ MISO contends that, for RTOs/ISOs, 
penalties without specified payees are effectively a tax on LSEs.\1796\
---------------------------------------------------------------------------

    \1795\ MISO Initial Comments at 13, 71; MISO TOs Reply Comments 
at 20; NYISO Reply Comments at 10.
    \1796\ MISO Initial Comments at 13, 72.
---------------------------------------------------------------------------

    923. NYISO contends that penalties would threaten RTOs'/ISOs' 
financial viability.\1797\ NYISO explains that RTO/ISO penalties and 
challenges to penalty recovery have been rare. NYISO claims that there 
are no examples of Commission denials of penalty cost recovery, so 
RTOs/ISOs would be subject to considerable uncertainty about their 
ability to recover study penalties.\1798\ NYISO argues that, if the 
Commission is likely to accept RTO/ISO penalty recovery proposals, then 
the penalties would serve no purpose because they would be passed to 
customers and fail to incentivize RTOs/ISOs to complete studies in a 
more timely manner.
---------------------------------------------------------------------------

    \1797\ NYISO Initial Comments at 32.
    \1798\ Id. at 37.
---------------------------------------------------------------------------

    924. NYISO argues that it is unjust and unreasonable and unduly 
discriminatory to apply the same level of penalties to RTOs/ISOs as 
other transmission providers because they are differently situated than 
other transmission providers.\1799\ NYISO states that an identical 
penalty would be much more punitive on RTOs/ISOs than other 
transmission providers, so any financial penalties imposed on RTOs/ISOs 
should be smaller in size and slower to trigger. NYISO requests that, 
if the Commission requires penalties, it allow RTOs/ISOs to propose in 
their compliance filings appropriate rules for their own regions.
---------------------------------------------------------------------------

    \1799\ Id. at 41.
---------------------------------------------------------------------------

    925. NYISO further argues that Order Nos. 672 \1800\ and 890 do not 
support subjecting RTOs/ISOs to the same penalties as non-independent 
transmission providers.\1801\ NYISO argues that the proposed penalties 
pose a greater risk to RTOs/ISOs than reliability penalties, which have 
been assessed in rare circumstances and are subject to the Commission's 
close scrutiny.\1802\ NYISO also notes that it does not conduct the 
kinds of transmission studies addressed in Order No. 890, so the formal 
applicability of the Order No. 890 penalty regime to RTOs/ISOs does not 
mean that application of penalties to RTOs/ISOs is practicable.\1803\
---------------------------------------------------------------------------

    \1800\ Rules Concerning Certification of the Elec. Reliability 
Org.; & Procs. for the Establishment, Approval, & Enf't of Elec. 
Reliability Standards, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), 
114 FERC ] 61,104 (2006).
    \1801\ NYISO Initial Comments at 32-33.
    \1802\ Id. at 33-34.
    \1803\ Id. at 36.
---------------------------------------------------------------------------

    926. Many commenters express concerns that RTOs/ISOs may pass

[[Page 61144]]

penalty costs through to transmission owners or ratepayers who did not 
contribute to study delays, which they claim is unjust and 
unreasonable.\1804\ New York State Department does not support 
penalties unless they can be recovered from RTO/ISO bonuses or 
shareholder profits.\1805\
---------------------------------------------------------------------------

    \1804\ Id. at 32; Alliant Energy Initial Comments at 6-7; EEI 
Initial Comments 17; Indicated PJM TOs Initial Comments at 37; ISO/
RTO Council Initial Comments at 3-4; NARUC Initial Comments at 18; 
NEPOOL Initial Comments at 16; NESCOE Reply Comments at 11; New York 
State Department Initial Comments at 10; North Dakota Commission 
Initial Comments at 6; Omaha Public Power Initial Comments at 11; 
OMS Initial Comments at 15; R Street Initial Comments at 14; State 
Agencies Initial Comments at 12-13; TAPS Initial Comments at 3-5; 
WIRES Initial Comments at 11.
    \1805\ New York State Department Initial Comments at 10.
---------------------------------------------------------------------------

    927. Some commenters also argue that the proposal to allow RTOs/
ISOs to recover penalties from transmission owners ignores that other 
entities may be responsible for study delays.\1806\ MISO explains, for 
example, that it has no mechanism to recover penalties from affected 
systems and that, even for entities subject to MISO's tariff, consensus 
on a penalty pass through mechanism is likely to be elusive.\1807\ 
Several commenters argue that, because RTOs/ISOs will have to pass 
through the penalty, it will not accomplish the Commission's 
goals.\1808\ NESCOE, however, disagrees that RTOs/ISOs will have to 
pass through penalty costs but notes that the Commission required RTOs/
ISOs to file proposals to recover penalties incurred for reliability 
standard violations case-by-case.\1809\
---------------------------------------------------------------------------

    \1806\ ISO/RTO Council Initial Comments at 3-4; MISO Initial 
Comments at 74.
    \1807\ MISO Initial Comments at 14, 74-75.
    \1808\ AEE Initial Comments at 29; APPA-LPPC Initial Comments at 
22; Clean Energy States Initial Comments at 9-10; ISO/RTO Council 
Initial Comments at 3-4; NESCOE Reply Comments at 12-13; Omaha 
Public Power Initial Comments at 11; Public Interest Organizations 
Initial Comments at 35; WIRES Initial Comments at 11.
    \1809\ NESCOE Reply Comments at 12 n.44 (citing Reliability 
Standard Compliance & Enf't in Regions with Reg'l Transmission Orgs. 
or Indep. Sys. Operators, 122 FERC ] 61,247, at P 16 (2008)).
---------------------------------------------------------------------------

    928. TAPS distinguishes NERC reliability penalties as part of a 
congressionally mandated regimen, whereas the proposed penalties are 
not.\1810\ TAPS notes that, while NERC reliability penalty amounts are 
used to offset operational costs of NERC or other relevant entities, 
the NOPR proposes to distribute penalty costs back to interconnection 
customers, who are not required to use those funds to offset costs for 
consumers or ratepayers.
---------------------------------------------------------------------------

    \1810\ TAPS Initial Comments at 5 (citing 16 U.S.C. 824o).
---------------------------------------------------------------------------

    929. TAPS also seeks clarification because the NOPR proposal 
provided that penalties should not be recoverable in transmission rates 
but also noted that penalties imposed on RTOs/ISOs could be handled 
similarly to NERC reliability penalties, which the Commission has 
previously allowed RTOs/ISOs to recover from ratepayers.\1811\ TAPS 
contends that the Commission should not allow RTOs/ISOs to pass 
penalties through to ratepayers or LSEs; to the extent the Commission 
allows RTOs/ISOs to recover costs through FPA section 205 proceedings, 
TAPS recommends that the Commission automatically waive any penalty 
amount the RTO/ISO would otherwise pass to ratepayers.\1812\
---------------------------------------------------------------------------

    \1811\ Id. at 3-5.
    \1812\ Id. at 7-8.
---------------------------------------------------------------------------

    930. Commenters argue that the proposed penalty structure lacks the 
due process and fact finding associated with the RTO/ISO recovery of 
NERC reliability penalties.\1813\ MISO and ISO/RTO Council explain that 
NERC uses a fact-finding tribunal, which avoids the potential conflicts 
of interest and process disruptions that would stem from requiring the 
transmission provider to judge disputes.\1814\ Indicated PJM TOs 
explain that RTOs/ISOs can only recover NERC reliability penalties from 
another entity if that entity was identified and allowed to participate 
in the NERC process.\1815\ Commenters note that NERC reliability 
penalty amounts are calculated based on specific circumstances and that 
financial penalties are not always imposed.\1816\ Further, the ISO/RTO 
Council argues that the NOPR proposal to allow FPA section 205 filings 
to allocate penalties is unworkable because it assumes the RTO/ISO will 
be able to identify a transmission owner that is responsible for the 
delay.\1817\
---------------------------------------------------------------------------

    \1813\ Indicated PJM TOs Initial Comments at 43-44; ISO/RTO 
Council Initial Comments at 2; MISO Initial Comments at 15, 76; 
NYISO Initial Comments at 35-36.
    \1814\ ISO/RTO Council Initial Comments at 6; MISO Initial 
Comments at 15, 75-76.
    \1815\ Indicated PJM TOs Initial Comments at 43.
    \1816\ ISO/RTO Council Initial Comments at 7; MISO Initial 
Comments at 15, 76-77; NYISO Initial Comments at 36.
    \1817\ ISO/RTO Council Initial Comments at 4.
---------------------------------------------------------------------------

    931. ISO-NE and MISO explain that transmission providers are in no 
position to perform fact-finding, which would require a time- and 
resource-consuming process to hear from all involved parties.\1818\ 
MISO states that it has no procedures beyond its alternative dispute 
resolution process for adjudicating disputes and even these procedures 
call for multi-month processes.\1819\ MISO notes that it is unclear who 
would make the findings and how penalties would be assigned if multiple 
parties contribute to a delay.\1820\ MISO and ISO/RTO Council note that 
the personnel able to determine the cause of a delay are the 
interconnection study engineers, who would need to divert their 
resources from performing studies to provide evidence.\1821\
---------------------------------------------------------------------------

    \1818\ ISO-NE Initial Comments at 36; MISO Initial Comments at 
15, 75.
    \1819\ MISO Initial Comments at 15, 75.
    \1820\ Id. at 76.
    \1821\ Id.; ISO/RTO Council Initial Comments at 7.
---------------------------------------------------------------------------

    932. MISO TOs state that, if the Commission adopts penalties, it 
should also adopt the requirement that RTOs/ISOs make an FPA section 
205 filing before allocating any penalties to a transmission owner in 
order to provide due process to the transmission owner and to be 
consistent with the Commission's approach to RTO/ISO recovery of NERC 
reliability penalty costs.\1822\
---------------------------------------------------------------------------

    \1822\ MISO TOs Initial Comments at 26.
---------------------------------------------------------------------------

    933. Indicated PJM TOs argue that it is unclear whether PJM has the 
authority to recover penalty costs from transmission owners.\1823\ 
Indicated PJM TOs state that the consolidated transmission owners 
agreement (CTOA) specifies that PJM has the right to file ``charges for 
recovery of PJM costs'' under FPA section 205, but they argue that 
penalties are not a cost of operation. Indicated PJM TOs explain that 
the CTOA reserves rights not specifically transferred to PJM to 
transmission owners. Therefore, Indicated PJM TOs conclude that the 
right to recover penalties was not conferred on PJM and that PJM lacks 
the contractual authority to seek recovery of penalties from 
transmission owners under FPA section 205. Indicated PJM TOs add that 
modifying the CTOA would implicate the Mobile-Sierra presumption.\1824\
---------------------------------------------------------------------------

    \1823\ Indicated PJM TOs Initial Comments at 44-45.
    \1824\ Id. at 45 n.126 (citing Morgan Stanley Cap. Grp. Inc. v. 
Pub. Util. Dist. No. 1, 554 U.S. 527 (2008); NRG Power Mktg., LLC v. 
Me. Pub. Utils. Comm'n, 558 U.S. 165 (2010)).
---------------------------------------------------------------------------

    934. Further, Indicated PJM TOs argue that the Commission lacks the 
authority under FPA section 205 to require RTOs/ISOs to seek cost 
recovery of interconnection study penalties.\1825\ SEIA disagrees and 
asks the Commission to establish a regime in which it can recover 
penalties for late studies in Order No. 890.\1826\
---------------------------------------------------------------------------

    \1825\ Id. at 45 (citing Atl. City Elec. Co. v. FERC, 329 F.3d 
856, 859 (D.C. Cir. 2003) (per curiam)).
    \1826\ SEIA Reply Comments at 13.
---------------------------------------------------------------------------

(e) Study Deadline Extension
    935. Several commenters support the NOPR proposal to allow for the

[[Page 61145]]

extension of a study deadline by mutual agreement.\1827\ Some 
commenters argue that this extension will promote cooperation between 
interconnection customers and transmission providers.\1828\ Further, 
AEE argues that the extension option will provide a buffer for studies 
that warrant more time and that the two study cycle transition will 
give transmission providers time to adjust to the cluster model and 
deadlines, to understand possible variability in each cluster, and to 
develop strategies for times when extra bandwidth is needed, such as 
hiring third-party assistance.\1829\ AEE suggests that the Commission 
require that the mutual agreements be publicly available.\1830\
---------------------------------------------------------------------------

    \1827\ Consumers Energy Initial Comments at 6; NEPOOL Initial 
Comments at 16; Pine Gate Initial Comments at 38.
    \1828\ Consumers Energy Initial Comments at 7.
    \1829\ AEE Reply Comments at 30-31.
    \1830\ AEE Initial Comments at 31-32.
---------------------------------------------------------------------------

    936. NARUC supports the proposal so long as the transmission 
provider certifies to the Commission that the extension will not delay 
unrelated interconnection requests outside the cluster.\1831\
---------------------------------------------------------------------------

    \1831\ NARUC Initial Comments at 15.
---------------------------------------------------------------------------

    937. Several commenters propose modifications to the NOPR deadline 
extension proposal. NYISO states that it is unreasonable to allow 
individual interconnection customers to veto extensions and instead 
proposes that 30-day extensions should be available if the RTO/ISO 
notifies the Commission that there is good cause to take additional 
time to complete the study.\1832\ Indicated PJM TOs argue that it will 
be virtually impossible to obtain mutual agreement in a region with a 
large number of interconnection customers and instead propose that the 
transmission provider determine the appropriate extension on 
compliance.\1833\ Tri-State notes that there is no incentive for 
interconnection customers who have agreed to a study deadline to re-
negotiate and mutually agree upon an extended deadline.\1834\ SoCal 
Edison suggests that the Commission allow transmission providers to 
extend study deadlines in the event of a larger than usual 
cluster.\1835\
---------------------------------------------------------------------------

    \1832\ NYISO Initial Comments at 42.
    \1833\ Indicated PJM TOs Initial Comments at 42.
    \1834\ Tri-State Initial Comments at 19.
    \1835\ SoCal Edison Initial Comments at 18.
---------------------------------------------------------------------------

(f) Transition
    938. Duke Southeast Utilities request that the Commission clarify 
that transmission providers already using a cluster study process will 
not be subject to penalties until after the completion of two study 
cycles, which will encourage transmission providers not to employ an 
unnecessary transition process.\1836\ Other commenters argue that 
financial penalties should be in effect during the first transitional 
cluster study.\1837\
---------------------------------------------------------------------------

    \1836\ Duke Southeast Utilities Initial Comments at 11.
    \1837\ ACE-NY Initial Comments at 13; AEE Initial Comments at 
32; Cypress Creek Initial Comments at 24.
---------------------------------------------------------------------------

(g) Force Majeure Exception
    939. Several commenters support the NOPR proposal to only permit 
exceptions to the penalty in instances of force majeure, arguing that 
additional exceptions make the penalty less effective.\1838\ Invenergy 
argues that there should be a process for transmission providers to 
declare force majeure to prevent the overuse of this exception.\1839\ 
CREA and NewSun argue that any force majeure exception should also 
apply to interconnection customers when they fail to meet 
deadlines.\1840\
---------------------------------------------------------------------------

    \1838\ Cypress Creek Initial Comments at 24; Google Reply 
Comments at 3.
    \1839\ Invenergy Initial Comments at 31-32.
    \1840\ CREA and NewSun Initial Comments at 84-85.
---------------------------------------------------------------------------

    940. Many commenters argue that the Commission should extend 
exemptions beyond force majeure, such as to events outside the 
transmission provider's control or for good cause.\1841\ NARUC and 
National Grid argue that transmission providers should have an 
opportunity to request a penalty exemption on a case-by-case 
basis.\1842\ NESCOE argues that the Commission should provide a list of 
presumptive no-fault delays.\1843\
---------------------------------------------------------------------------

    \1841\ Indicated PJM TOs Initial Comments at 42; MISO TOs 
Initial Comments at 25; National Grid Initial Comments at 32; NESCOE 
Initial Comments at 16; NYISO Initial Comments at 42; PPL Initial 
Comments at 19; SoCal Edison Initial Comments at 19; Tri-State 
Initial Comments at 18; WIRES Initial Comments at 10; Xcel Initial 
Comments at 38.
    \1842\ NARUC Initial Comments at 21; National Grid Initial 
Comments at 33.
    \1843\ NESCOE Initial Comments at 16.
---------------------------------------------------------------------------

(h) Requests for Alternatives, Clarification, or Technical Conference
    941. A number of commenters suggest that the Commission evaluate 
whether the other reforms are successful before implementing a penalty 
regime.\1844\ NYTOs and Eversource similarly ask that the Commission 
allow the changes in the ANOPR to take effect before imposing 
penalties.\1845\ Some commenters suggest that the Commission hold a 
technical conference prior to penalties becoming effective to discuss 
experiences with the new cluster study process and focus the penalties 
on the causes of delays.\1846\ SPP and NYISO also note that some 
transmission providers are undergoing their own interconnection queue 
reform efforts; therefore, the Commission should focus on ensuring 
those efforts are successful instead of imposing automatic 
penalties.\1847\ TAPS suggests that the Commission delay implementation 
of penalties by at least five years from the effective date of 
compliance filings to the final rule.\1848\
---------------------------------------------------------------------------

    \1844\ AEP Initial Comments at 29; Avangrid Reply Comments at 
14; Clean Energy Buyers Initial Comments at 10-11; Eversource 
Initial Comments at 30-31; Idaho Power Initial Comments at 10; ISO/
RTO Council Reply Comments at 5; Longroad Energy Reply Comments at 
15; NY Commission and NYSERDA Initial Comments at 6; NYISO Initial 
Comments at 30; Pacific Northwest Utilities Initial Comments at 9-
10; PacifiCorp Initial Comments at 34; Puget Sound Initial Comments 
at 11; State Agencies Initial Comments at 14; TAPS Initial Comments 
at 9.
    \1845\ Eversource Initial Comments at 30-31; NYTOs Initial 
Comments at 23-24.
    \1846\ ISO/RTO Council Initial Comments at 9; NARUC Initial 
Comments at 15-22; NESCOE Reply Comments at 14; PJM Initial Comments 
at 9; TAPS Initial Comments at 9.
    \1847\ NYISO Initial Comments at 30; SPP Initial Comments at 14-
15.
    \1848\ TAPS Initial Comments at 9.
---------------------------------------------------------------------------

    942. NARUC argues that any penalty structure should be applied 
equally to transmission providers delaying interregional affected 
system studies and seeks clarification on how penalties will be 
assessed when delays are caused by affected systems.\1849\
---------------------------------------------------------------------------

    \1849\ NARUC Initial Comments at 14, 17.
---------------------------------------------------------------------------

    943. Some commenters suggest that, instead of or in addition to 
penalties, the Commission could improve reporting by issuing Commission 
staff reports or requiring additional reporting from transmission 
providers.\1850\ Indicated PJM TOs explain that the Commission or an 
interested party could initiate an FPA section 206 proceeding if it 
believes PJM is not exercising due diligence in performing studies 
based on its reporting.\1851\ In response to arguments that entities 
could pursue FPA section 206 filings before the Commission if they 
believe

[[Page 61146]]

reasonable efforts have been violated, New Jersey Commission argues 
that study delays result from systemic failures, so it is inappropriate 
to address such issues through individual FPA section 206 
filings.\1852\
---------------------------------------------------------------------------

    \1850\ Id. at 16; AEE Initial Comments at 32-33; AEE Reply 
Comments at 32; APPA-LPPC Initial Comments at 23; Avangrid Initial 
Comments at 31; Bonneville Initial Comments at 16; Clean Energy 
Associations Initial Comments at 47; Clean Energy Buyers Initial 
Comments at 11; CREA and NewSun Initial Comments at 85-86; EPSA 
Initial Comments at 11; Fervo Energy Initial Comments at 6; Google 
Reply Comments at 4; MISO TOs Initial Comments at 27; National Grid 
Initial Comments at 31-32; NESCOE Reply Comments at 14; NYISO 
Initial Comments at 31, 43; NYISO Reply Comments at 10; NYTOs 
Initial Comments at 23; OMS Initial Comments at 15; PacifiCorp 
Initial Comments at 35; PacifiCorp Reply Comments at 6; Pine Gate 
Initial Comments at 41; PG&E Initial Comments at 4, 9; R Street 
Initial Comments at 14; Shell Initial Comments at 11; TAPS Initial 
Comments at 9; UMPA Initial Comments at 7.
    \1851\ Indicated PJM TOs Initial Comments at 41.
    \1852\ New Jersey Commission Reply Comments at 5.
---------------------------------------------------------------------------

    944. MISO proposes that, if a transmission provider misses a 
deadline by more than a threshold grace period, the transmission 
provider should be required to self-report the circumstances around the 
delay to the Commission, and, in response to that self-report, the 
Commission could issue a show cause order to require the transmission 
provider and any other relevant entities to respond with specific 
information about the causes for the delays and propose a mitigation 
plan.\1853\ MISO states that, at the conclusion of the show cause 
proceeding, the Commission would issue an order that could require 
transmission providers, transmission owners, or other entities to take 
specific actions to mitigate the delay, require process changes, and/or 
impose penalties.\1854\ MISO argues that its proposal has several 
advantages over the NOPR penalty proposal, including providing 
accountability tied to entities actually causing the delay, as 
determined by the Commission. Public Interest Organizations support the 
self-reporting concept but do not support conditioning penalty 
assignment on a show cause proceeding, arguing that this would be 
administratively burdensome.\1855\ AEE also states that MISO's approach 
could be helpful if paired with binding timelines and a clear penalty 
structure.\1856\
---------------------------------------------------------------------------

    \1853\ MISO Initial Comments at 79-80; see also MISO TOs Initial 
Comments at 27 (explaining that targeted intervention through a show 
cause order is more appropriate than broadly applicable penalties).
    \1854\ MISO Initial Comments at 80-81.
    \1855\ Public Interest Organizations Reply Comments at 8-9.
    \1856\ AEE Reply Comments at 38.
---------------------------------------------------------------------------

    945. Clean Energy Associations suggest that, if the Commission does 
not adopt penalties, it should consider requiring remedial action 
plans, including specific staffing plans, for transmission providers 
with persistently late or inaccurate studies.\1857\
---------------------------------------------------------------------------

    \1857\ Clean Energy Associations Initial Comments at 45.
---------------------------------------------------------------------------

    946. Some commenters argue that the Commission should incentivize 
transmission providers to meet deadlines rather than penalize them for 
failing to do so.\1858\ Shell proposes that the Commission provide 
favorable rate treatment for transmission providers that meet study 
timeliness conditions; specifically, Shell suggests that the Commission 
create a rebuttable presumption that transmission providers can recover 
their investments in interconnection queue processing resources if the 
transmission provider satisfies deadlines at least 90% of the time over 
two years.\1859\ Shell further suggests that these costs can be 
eligible for inclusion in transmission rate base, with corresponding 
return on equity, if the transmission provider meets study deadlines at 
least 95% of the time over two calendar years.\1860\ Affected 
Interconnection Customers propose that the Commission allow RTOs/ISOs 
to create a monetary incentive for transmission owners that complete 
their interconnection studies on time.\1861\
---------------------------------------------------------------------------

    \1858\ Id. at 46; ACE-NY Initial Comments at 14 (recommending a 
structure with both penalties and incentives); Affected 
Interconnection Customers Initial Comments at 26 (same); CREA and 
NewSun Reply Comments at 57 (same); Shell Initial Comments at 10; 
Longroad Energy Reply Comments at 14; Vermont Electric and Vermont 
Transco Initial Comments at 2.
    \1859\ Longroad Energy Reply Comments at 14-15; Shell Initial 
Comments at 11.
    \1860\ Shell Initial Comments at 11.
    \1861\ Affected Interconnection Customers Initial Comments at 
29-30.
---------------------------------------------------------------------------

    947. However, R Street notes that rate incentives, like bonuses on 
returns on equity, would induce financial motivation but would require 
a performance baseline that transmission owners could game.\1862\ MISO 
TOs argue that incentives would fail because study delays are caused by 
factors beyond transmission providers' control.\1863\
---------------------------------------------------------------------------

    \1862\ R Street Initial Comments at 15.
    \1863\ MISO TOs Reply Comments at 15-16.
---------------------------------------------------------------------------

    948. ACE-NY requests that the Commission clarify whether a failure 
to meet the pro forma LGIP study deadlines would constitute a tariff 
violation, which could have implications for executive and staff 
compensation.\1864\ MISO TOs argue that such a proposal has no basis 
and would constitute an even stricter standard because penalties for 
tariff violations can amount to over $1 million per day, exceeding the 
proposed $500 per day proposal.\1865\
---------------------------------------------------------------------------

    \1864\ ACE-NY Initial Comments at 13.
    \1865\ MISO TOs Reply Comments at 14 (citing 16 U.S.C. 825o-1).
---------------------------------------------------------------------------

    949. Clean Energy States and TAPS recommend tying executive 
compensation to interconnection queue deadlines,\1866\ noting that SPP 
and MISO currently tie compensation to reliability performance.\1867\ 
However, MISO TOs note that the Commission has previously found that it 
lacks such jurisdiction.\1868\
---------------------------------------------------------------------------

    \1866\ Clean Energy States Initial Comments at 10-11; CREA and 
NewSun Reply Comments at 57; TAPS Initial Comments at 8.
    \1867\ TAPS Initial Comments at 8.
    \1868\ MISO TOs Reply Comments at 15.
---------------------------------------------------------------------------

    950. Some commenters argue that the Commission should allow 
transmission providers to set their own deadlines for interconnection 
studies because the current deadlines are not reasonable or advocate 
for regional flexibility.\1869\ Some commenters recommend allowing 
transmission providers to adjust study deadlines based on 
interconnection queue size.\1870\ Public Interest Organizations and 
Google support such proposals to the extent that the deadlines are 
subject to Commission review.\1871\ AEE does not oppose giving 
transmission providers flexibility to set their study timelines but 
requests that the Commission set a maximum allowable study 
timeline.\1872\
---------------------------------------------------------------------------

    \1869\ APPA-LPPC Initial Comments at 21; Bonneville Initial 
Comments at 16; Indicated PJM TOs Reply Comments at 39; ISO-NE 
Initial Comments at 35-37; NY Commission and NYSERDA Initial 
Comments at 5; NYISO Initial Comments at 29, 33.
    \1870\ Bonneville Initial Comments at 16; Google Reply Comments 
at 5; NYISO Initial Comments at 29; SEIA Reply Comments at 17.
    \1871\ Public Interest Organizations Reply Comments at 9.
    \1872\ AEE Reply Comments at 38.
---------------------------------------------------------------------------

    951. National Grid suggests that the Commission adopt a minimum 
time frame approach, which would start the overall interconnection 
study timeline upon finalizing the base case study models and provide 
minimum study time frames for scope and result reviews.\1873\
---------------------------------------------------------------------------

    \1873\ National Grid Initial Comments at 31.
---------------------------------------------------------------------------

    952. PJM suggests that the transmission provider develop a targeted 
study completion date based on an analysis of that particular 
interconnection queue, with the target completion date available for 
public comment.\1874\ PJM states that, under this approach, as studies 
become delayed further and further past the target date, the 
transmission provider would be required to meet increasing burdens 
(e.g., public posting of the missed date, filing a report with the 
Commission, being subject to FPA section 206 action). PJM states that 
if, despite the FPA section 206 action, the transmission provider 
misses a subsequent study deadline at the same level, then the 
Commission could impose penalties for any proven malfeasance by the 
transmission provider. PJM also suggests that the Commission could 
allow transmission providers to cap the number of interconnection 
requests in a given cluster to an amount commensurate with available 
resources. In response, AEE argues that PJM's

[[Page 61147]]

proposed approach would cause unnecessary administrative burden, which 
could further harm interconnection customers.\1875\
---------------------------------------------------------------------------

    \1874\ PJM Initial Comments at 59-61.
    \1875\ AEE Reply Comments at 38-39.
---------------------------------------------------------------------------

    953. Some commenters claim that the NOPR proposal is vague and 
raises profound implementation issues (e.g., how or whether the penalty 
structure will accommodate different cluster sizes, study complexities, 
or restudies).\1876\ R Street suggests, and ISO/RTO Council agrees, 
that the Commission and stakeholders would benefit from a root cause 
analysis to identify the cause of study delays, which could inform more 
reasonable performance expectations.\1877\
---------------------------------------------------------------------------

    \1876\ EEI Reply Comments at 17; Eversource Initial Comments at 
20, 28.
    \1877\ ISO/RTO Council Reply Comments at 5; R Street Initial 
Comments at 14.
---------------------------------------------------------------------------

    954. Some commenters seek clarity regarding who bears financial 
penalties for late affected system studies and related affected system 
obligations.\1878\ ENGIE states that it is unclear who bears the 
financial penalties for late affected system studies.\1879\ In 
contrast, MISO interprets the NOPR proposal to apply penalties only to 
the affected system operator, though MISO also recommends that the 
Commission recognize that some delays may be beyond the control of the 
affected system operator and recommends that affected system operators 
not be penalized for third-party delays.\1880\ Similarly, Duke 
Southeast Utilities express concern that penalties could be levied 
against affected system operators for delays beyond their control and 
further argue that, instead of unilaterally imposing financial 
penalties on one entity, which, to Duke Southeast Utilities, seems 
arbitrary and unfounded, the Commission should consider imposing 
multilateral penalties on all entities in accordance with their 
individual obligations set forth in the proposed process.\1881\
---------------------------------------------------------------------------

    \1878\ Duke Southeast Utilities Initial Comments at 17-18; ENGIE 
Initial Comments at 9; MISO Initial Comments at 92.
    \1879\ ENGIE Initial Comments at 9. Additionally, ENGIE states 
that transmission owners typically have responsibilities for 
affected system studies and, therefore, argues that the Commission 
should consider language that distributes financial risk and 
penalties to both transmission owners and transmission providers, 
including an ability for transmission providers to recover costs 
from transmission owners. Id.
    \1880\ MISO Initial Comments at 92. WAPA also is generally 
concerned about the imposition of monetary penalties for failure to 
meet deadlines and questions whether federal agencies like WAPA 
should or even can be subject to monetary penalties. See WAPA 
Initial Comments at 10, 14.
    \1881\ Duke Southeast Utilities Initial Comments at 17-18.
---------------------------------------------------------------------------

    955. Cypress Creek suggests that, in addition to financial 
penalties for missed study deadlines, the Commission should also impose 
penalties for inaccurate study results.\1882\ AEE and Clean Energy 
Associations argue that the Commission should provide guidelines and 
reporting requirements regarding acceptable study accuracy.\1883\
---------------------------------------------------------------------------

    \1882\ Cypress Creek Initial Comments at 23.
    \1883\ AEE Initial Comments at 34; Clean Energy Associations 
Initial Comments at 47.
---------------------------------------------------------------------------

    956. CREA and NewSun propose an overall ``reasonableness'' standard 
to ensure the quality of the studies and that there is no ongoing 
failure to provide adequate staffing or to employ reasonable study 
assumptions.\1884\
---------------------------------------------------------------------------

    \1884\ CREA and NewSun Initial Comments at 85.
---------------------------------------------------------------------------

    957. National Grid argues that the Commission should permit 
transmission providers to assign a dedicated person to monitor the 
progress of each entity (i.e., interconnection customer, transmission 
owner, and RTO/ISO) during the interconnection process.\1885\ National 
Grid argues that the cost of this person and any other additional costs 
needed to satisfy the NOPR proposal should be recoverable in rates so 
that transmission providers would be able to recover costs incurred to 
reduce penalty risk.
---------------------------------------------------------------------------

    \1885\ National Grid Initial Comments at 33.
---------------------------------------------------------------------------

    958. Some commenters suggest that the Commission allow third-party 
consultants to complete studies, which would conserve transmission 
provider resources and provide a pathway for interconnection customers 
to move forward.\1886\ Dominion argues in response that there is a 
general lack of qualified professionals to perform interconnection 
studies, so a third party will not have access to the personnel, 
knowledge, or resources to perform them.\1887\
---------------------------------------------------------------------------

    \1886\ AEE Initial Comments at 34; Clean Energy Associations 
Initial Comments at 46; Public Interest Organizations Reply Comments 
at 4; SEIA Initial Comments at 33.
    \1887\ Dominion Reply Comments at 19-20.
---------------------------------------------------------------------------

    959. Pacific Northwest Utilities argue that the reasonable efforts 
standard should not be eliminated for facilities studies, which require 
an individual study, noting that the number of facilities studies 
needed can vary greatly between clusters.\1888\
---------------------------------------------------------------------------

    \1888\ Pacific Northwest Utilities Initial Comments at 11-12.
---------------------------------------------------------------------------

    960. NYISO suggests that the Commission adopt features of the NERC 
model, including the use of non-financial sanctions for minor or 
excusable violations and penalty reductions for cooperative and 
remedial actions.\1889\
---------------------------------------------------------------------------

    \1889\ NYISO Initial Comments at 41-42.
---------------------------------------------------------------------------

    961. Tri-State supports the NOPR proposal not to assess financial 
penalties until one cluster study cycle (that is not a transitional 
study cycle) after the compliance effective date. Tri-State seeks 
clarification on when penalties would be imposed for transmission 
providers already using a cluster study process.\1890\
---------------------------------------------------------------------------

    \1890\ Tri-State Initial Comments at 19.
---------------------------------------------------------------------------

c. Commission Determination
    962. We adopt the NOPR proposal to eliminate the reasonable efforts 
standard set forth in sections 2.2, 3.5.4(i), 7.4, 8.3, and Attachment 
A to Appendix 4 of the pro forma LGIP. In its place, we adopt the NOPR 
proposal, with modification, to add new section 3.9 to the pro forma 
LGIP that imposes study delay penalties, as further discussed below: 
delays of cluster studies beyond the tariff-specified deadline will 
incur a penalty of $1,000 per business day; delays of cluster restudies 
beyond the tariff-specified deadline will incur a penalty of $2,000 per 
business day; delays of affected system studies beyond the tariff-
specified deadline will incur a penalty of $2,000 per business day; and 
delays of facilities studies beyond the tariff-specified deadline will 
incur a penalty of $2,500 per business day.\1891\
---------------------------------------------------------------------------

    \1891\ The penalties that we adopt in this final rule in section 
3.9 of the pro forma LGIP for late affected system studies only 
apply to affected system operators that are public utilities.
---------------------------------------------------------------------------

    963. As explained in greater detail in this section, we adopt the 
following features of the study delay penalty structure for late 
interconnection studies: (1) no study delay penalties will be assessed 
until the third cluster study cycles (including any transitional 
cluster study cycle, but not transitional serial studies) after the 
Commission-approved effective date of the transmission provider's 
filing in compliance with this final rule; (2) there will be a 10-
business day grace period, such that no study delay penalties will be 
assessed for a study that is delayed by 10 business days or fewer; (3) 
deadlines may be extended for a particular study by 30 business days by 
mutual agreement of the transmission provider and all interconnection 
customers with interconnection requests in the relevant study; (4) 
study delay penalties will be capped at 100% of the initial study 
deposits received for all of the interconnection requests in the 
cluster for cluster studies and cluster restudies, 100% of the initial 
study deposit received for the single interconnection request in the 
study for facilities studies, and 100% of the study deposit(s) that the 
transmission provider acting as an affected system operator

[[Page 61148]]

(affected system transmission provider) collects for conducting the 
affected system study; (5) transmission providers will have the ability 
to appeal any study delay penalties to the Commission, with the 
Commission determining whether good cause exists to grant the relief 
requested on appeal; (6) transmission providers must distribute study 
delay penalties to interconnection customers in the relevant study on a 
pro rata per interconnection request basis to offset their study costs; 
(7) non-RTO/ISO transmission providers and transmission-owning members 
of RTOs/ISOs may not recover study delay penalties through transmission 
rates; (8) RTOs/ISOs may submit an FPA section 205 filing to propose a 
default structure for recovering study delay penalties and/or to 
recover the costs of any specific study delay penalties; \1892\ (9) 
transmission providers must pay the penalty for each late study on a 
pro rata basis per interconnection request to all interconnection 
customers or affected system interconnection customers included in the 
relevant study that did not withdraw, or were not deemed withdrawn, 
from the interconnection queue before the missed study deadline; and 
(10) transmission providers must post quarterly on their OASIS or other 
publicly accessible website (a) the total amount of study delay 
penalties from the previous reporting quarter and (b) the highest study 
delay penalty paid to a single interconnection customer in the previous 
reporting quarter. We also add new paragraph (f)(1)(ii) to 18 CFR 35.28 
to specify that any public utility that conducts interconnection 
studies shall be liable for and eligible to appeal penalties following 
that public utility's failure to complete an interconnection study by 
the appropriate deadline. We also decline to adopt the NOPR's proposed 
force majeure penalty exception. We first discuss our overarching 
rationale for this set of reforms, and then discuss each of these 
reforms in greater detail and our rationale for each.
---------------------------------------------------------------------------

    \1892\ We note that the typical standard of review under FPA 
section 205 would apply to these filings: i.e., the filer must show 
that any proposal to recover study delay penalties is just, 
reasonable, and not unduly discriminatory or preferential. See 16 
U.S.C. 824d.
---------------------------------------------------------------------------

    964. We adopt these reforms to remedy the unjust and unreasonable 
rates stemming from interconnection queue backlogs and to ensure that 
interconnection customers are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner. 
Specifically, these reforms will help ensure more timely processing of 
interconnection requests by incentivizing transmission providers to 
meet interconnection study deadlines.\1893\
---------------------------------------------------------------------------

    \1893\ Invenergy Initial Comments at 30; Iowa Commission Initial 
Comments at 5-6 (``RTOs/ISOs need to prioritize interconnection 
studies and need to hold their employees and/or outside entities 
responsible for delays''); SEIA Initial Comments at 32.
---------------------------------------------------------------------------

i. Eliminating the Reasonable Efforts Standard
    965. We adopt the NOPR proposal to eliminate the reasonable efforts 
standard set forth in sections 2.2, 3.5.4(i), 7.4, 8.3, and Attachment 
A to Appendix 4 of the pro forma LGIP. In these revised sections, we 
specifically eliminate the reasonable efforts standard for conducting 
cluster studies, cluster restudies, facilities studies, and affected 
system studies.
    966. The lengthy interconnection study delays and interconnection 
queue backlogs throughout the country support our conclusion that the 
reasonable efforts standard does not provide an adequate incentive for 
transmission providers to complete interconnection studies on time. As 
discussed in section II above, transmission providers are experiencing 
significant interconnection queue backlogs, as evidenced, for example, 
by their Order No. 845 reports.\1894\ There is every reason to believe 
that many of the factors contributing to significant interconnection 
queue backlogs and delay--including the rapidly changing resource mix, 
market forces, and emerging technologies--will persist. In response to 
those ongoing challenges, we find that it is just, reasonable, and not 
unduly discriminatory or preferential to eliminate the reasonable 
efforts standard and adopt a penalty structure that reasonably 
incentivizes transmission providers to ensure the timely processing of 
interconnection requests. We note that we are not finding that 
transmission providers have necessarily acted in bad faith or that 
their actions are the sole reason for the queue delays. Indeed, 
throughout this final rule, we adopt numerous reforms to appropriately 
incentivize interconnection customers to help reduce interconnection 
delays that may result from their conduct. Nevertheless, we find that 
the elimination of the reasonable efforts standard and the adoption of 
penalties for late studies are needed to create an incentive for 
transmission providers, which will help reduce interconnection delays 
and ensure that Commission-jurisdictional rates are just, reasonable, 
and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \1894\ See appendix B to this final rule (showing that over 
2,800 interconnection studies were delayed as of the end of the 
fourth quarter (Q4) 2022 and that over 1,900 interconnection studies 
were delayed as of the end of Q4 2021); see also Queued Up 2023 at 6 
(showing growth in number of interconnection requests from 2013 to 
2022) and Queued Up 2023 at 3 (noting that generating facilities 
built in 2008 spent, on average, less than two years in 
interconnection queues, whereas generating facilities built in 2022 
spent, on average, five years in interconnection queues). Although 
some commenters argue that Order No. 845 data do not provide 
sufficient support (AEP Initial Comments at 25-26; MISO Initial 
Comments at 72), the data demonstrate that interconnection queue 
delays have continued to worsen over recent years and industry 
reports have similarly concluded that interconnection queues are 
seeing increasingly severe delays. We cite evidence that contradicts 
such comments and that, instead, supports our findings. See, e.g., 
supra section II.C.
---------------------------------------------------------------------------

    967. The reasonable efforts standard worsens current-day 
challenges, as it fails to ensure that transmission providers are 
keeping pace with the changing and complex dynamics of today's 
interconnection queues. Contrary to the assertions of some commenters, 
we believe that there are steps within transmission providers' control, 
from deploying transmission providers' resources to exploring 
administrative efficiencies and innovative study approaches,\1895\ to 
better ensure timely processing of interconnection studies to remedy 
existing deficiencies.
---------------------------------------------------------------------------

    \1895\ See Public Interest Organizations Reply Comments at 4 
(``any claim that an individual transmission provider has done 
absolutely everything in its power to improve the processing rate of 
interconnection requests . . . almost certainly comes from a lack of 
imagination''); R Street Initial Comments at 14 (explaining that 
advances in computing fields have the potential to reduce queue 
processing times).
---------------------------------------------------------------------------

    968. As discussed above, we adopt several reforms to address 
speculative interconnection requests by imposing stricter requirements 
on interconnection customers for entering and remaining in the 
interconnection queue (e.g., site control requirements, commercial 
readiness deposits, and withdrawal penalties). We also adopt reforms to 
improve the efficiency of interconnection studies and interconnection 
queue processing for all transmission providers (e.g., first-ready, 
first-served cluster study process). In this section, we adopt reforms 
to ensure that transmission providers are doing their part as well by 
eliminating the reasonable efforts standard and imposing study delay 
penalties on transmission providers when they fail to meet the 
interconnection study deadlines we adopt in this final rule. Based on 
the record, we find that the elimination of the reasonable efforts 
standard and its replacement with firm deadlines and penalties are 
needed to remedy unjust and unreasonable rates

[[Page 61149]]

and ensure that interconnection customers are able to interconnect to 
the transmission system in a reliable, efficient, transparent, and 
timely manner. Thus, we disagree with commenters that contend that the 
reasonable efforts standard continues to be appropriate or that the 
Commission's past orders, including Order No. 845, mean that the 
reasonable efforts standard continues to ensure just and reasonable 
rates.\1896\
---------------------------------------------------------------------------

    \1896\ See, e.g., Avangrid Initial Comments at 10, 30-31; 
Bonneville Initial Comments at 16; EEI Reply Comments at 16; 
Indicated PJM TOs Initial Comments at 36; MISO TOs Reply Comments at 
6-7; NYISO Initial Comments at 30-31; PG&E Reply Comments at 3-4; 
WIRES Initial Comments at 10.
---------------------------------------------------------------------------

    969. We similarly disagree with commenters that support eliminating 
the reasonable efforts standard but that do not support imposing study 
delay penalties on transmission providers for failing to meet 
interconnection study deadlines.\1897\ We do not believe that this 
result would remedy the unjust and unreasonable rates, nor would it 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner by aligning incentives properly.
---------------------------------------------------------------------------

    \1897\ CAISO Initial Comments at 25-26; Clean Energy Buyers 
Initial Comment at 9-10; MISO Initial Comments at 13, 71, 79; Shell 
Initial Comments at 10; see also NARUC Initial Comments at 13-14, 
20; Pennsylvania Commission Initial Comments at 2-3 (supporting the 
proposal to eliminate the reasonable efforts standard but taking no 
position on the need for monetary penalties).
---------------------------------------------------------------------------

    970. As we are eliminating the reasonable efforts standard, we also 
must adopt a replacement rate that remedies the problems just 
described. The sections below set forth a study delay penalty structure 
and why we believe it is justified. In short, we adopt provisions in 
the pro forma LGIP that impose firm interconnection study deadlines and 
corresponding study delay penalties on transmission providers that fail 
to meet those deadlines.
    971. Interconnection customers face financial harm when study 
deadlines are not met, ultimately inhibiting their ability to 
interconnect to the transmission system in a reliable, efficient, 
transparent, and timely manner. We find that holding transmission 
providers to firm interconnection study deadlines is likely to 
accelerate the interconnection study process and provide greater 
certainty to interconnection customers, allowing them to make more 
informed business decisions around whether to proceed with or withdraw 
from the interconnection queue, which will also ultimately improve 
interconnection queue management and remedy the unjust and unreasonable 
rates otherwise created by study delays.
    972. At the same time, we do not believe that the study delay 
penalty structure that we adopt in this final rule is unduly harsh for 
transmission providers, either in penalty amount or the form of its 
application. The study delay penalty structure adopted in this final 
rule balances the harm to interconnection customers of interconnection 
study delays and the associated need to incentivize transmission 
providers to timely complete interconnection studies with the burdens 
on transmission providers of conducting interconnection studies and 
potentially facing penalties for delays, including those that may be 
caused or exacerbated by factors beyond their control. In particular, 
we adopt the following safeguards for transmission providers: (1) a 
transition period rather than imposing study delay penalties as soon as 
transmission providers begin implementing the reforms in this final 
rule; (2) a 10-business day grace period where no study delay penalties 
will be assessed; (3) a provision that allows a 30-business day 
deadline extension upon mutual agreement of the transmission provider 
and interconnection customers; (4) caps on study delay penalties; and 
(5) a transmission provider ability to appeal. We also adopt provisions 
governing distribution of study delay penalties to interconnection 
customers and prohibiting recovery of study delay penalties through 
transmission rates, along with transparency-related posting 
requirements to the benefit of interconnection customers and consumers 
alike. We believe that the study delay penalty structure adopted herein 
aligns transmission provider and interconnection customer incentives 
while providing appropriate built-in flexibility and safeguards for 
transmission providers, thereby achieving a balance that ensures just 
and reasonable rates and ensures that interconnection customers are 
able to interconnect to the transmission system in a reliable, 
efficient, transparent, and timely manner.
ii. Penalty Amount
    973. We modify the pro forma LGIP to adopt a study delay penalty 
structure whereby penalties increase through the interconnection study 
process. Delays of cluster studies beyond the tariff-specified deadline 
will incur a penalty of $1,000 per business day; delays of cluster 
restudies beyond the tariff-specified deadline will incur a penalty of 
$2,000 per business day; delays of affected system studies beyond the 
tariff-specified deadline will incur a penalty of $2,000 per business 
day; and delays of facilities studies beyond the tariff-specified 
deadline will incur a penalty of $2,500 per business day.
    974. We agree with the numerous commenters who argue that the NOPR 
penalty proposal of $500 per business day is too low to create an 
incentive for transmission providers to meet study deadlines.\1898\ We 
find it necessary to modify the NOPR proposal to establish a higher 
penalty amount and a structure of increasing penalties that reflects 
the greater harm caused by delayed studies at later interconnection 
stages.
---------------------------------------------------------------------------

    \1898\ ACE-NY Initial Comments at 12; Affected Interconnection 
Customers Initial Comments at 24-26; CESA Initial Comments at 11; 
CESA Reply Comments at 8-9; Clean Energy Associations Initial 
Comments at 44; Consumers Energy Initial Comments at 6; CREA and 
NewSun Reply Comments at 56; Cypress Creek Initial Comments at 24; 
ELCON Initial Comments at 7-8; EPSA Initial Comments at 11; Fervo 
Energy Initial Comments at 6; Invenergy Initial Comments at 29; 
NARUC Initial Comments at 14; Pine Gate Initial Comments at 39.
---------------------------------------------------------------------------

    975. We reach this conclusion for several reasons. First, we find 
persuasive the comments asserting that a penalty of $500 per business 
day is insufficient to incentivize transmission provider actions that 
will reduce the incidence of study delays.\1899\ At $500 per business 
day, a study that is delayed by six months--or roughly 126 business 
days--would produce a penalty of only $63,000. We view such a penalty 
as insufficient considering that the purpose of the penalty is to 
incentivize timely study completion that may be achieved, for example, 
by hiring additional personnel or investing in new software.
---------------------------------------------------------------------------

    \1899\ See, e.g., Invenergy Initial Comments at 29-30 (``[T]he 
proposed penalty amount is woefully insufficient to create any real 
incentive'' . . . ``While a study that is six months late may 
severely impact an interconnection customer's development efforts, 
it would amount to only a $90,000 penalty, which is de minimis for 
transmission providers which may have annual revenues of $25 billion 
if not more''); Affected Interconnection Customers Initial Comments 
at 24-25 (``[A] $500 per day penalty imposed upon transmission 
providers with hundreds of millions, if not billions of dollars of 
transmission assets, is a drop in the bucket that will be highly 
unlikely to deter continued missed interconnection study 
deadlines''); Cypress Creek Initial Comments at 24 (``[P]enalties 
should . . . be substantially larger so that they serve as 
meaningful deterrents to delayed and inaccurate study results''); 
Pine Gate Initial Comments at 39 (``A daily penalty rate that is too 
low will do little to incentivize transmission providers to complete 
studies in a timely manner, even in a situation where the penalty 
equals the full 100 percent of total study deposits received'').
---------------------------------------------------------------------------

    976. Some commenters advocate for penalty amounts that more closely 
approximate the costs that delays impose in interconnection

[[Page 61150]]

customers,\1900\ while others propose penalty amounts ranging from 
$2,500 per day to $7,000 per day.\1901\ Based on the record before us, 
we believe the $1,000/$2,000/$2,500 per business day penalty structure, 
combined with the transition, grace period, cap on penalties, and 
ability to appeal that we adopt below, strikes an appropriate balance 
because it creates an incentive for transmission providers to meet 
study deadlines while not being overly punitive.
---------------------------------------------------------------------------

    \1900\ Cypress Creek Initial Comments at 24; Pine Gate Initial 
Comments at 39-40.
    \1901\ ACE-NY Initial Comments at 12; Affected Interconnection 
Customers Initial Comments at 5, 26; CESA Reply Comments at 9; 
Invenergy Initial Comments at 30.
---------------------------------------------------------------------------

    977. Second, adopting progressively higher penalty amounts for 
delayed cluster restudies and facilities studies reflects the 
progressively greater harm to interconnection customers of delayed 
studies at those later stages--at which they will have made greater 
investments in advancing their projects toward commercial development 
through steps such as obtaining site control, securing permits, and 
contracting for equipment. This is especially true given the new site 
control requirements, commercial readiness deposits, and withdrawal 
penalties we adopt in this final rule, which also become increasingly 
stringent as the study process progresses. These reforms will require 
that interconnection customers have greater capital at risk at each 
stage to affirm their commitment to reaching commercial operation. We 
find it appropriate that transmission providers face study delay 
penalties structured in a similar manner to provide adequate incentives 
to complete interconnection studies on time.
    978. Third, the penalty structure we adopt here will impose more 
stringent study delay penalties at later stages when reasons for study 
delays should be fewest. That is, we expect the volume of 
interconnection requests to decrease as they progress through the study 
process, with fewer interconnection requests reaching the cluster 
restudy and facilities study stages. This reduction in volume will 
reduce the likelihood transmission providers are unable to complete 
those studies on time. We find it reasonable to hold transmission 
providers most accountable for timely study completion in the stages 
where delays should be most avoidable.
iii. Transition
    979. We modify proposed section 3.9(6) of the pro forma LGIP, which 
provided that no study delay penalties shall be assessed until one 
cluster study cycle (that is not a transitional study cycle) after the 
Commission-approved effective date of the transmission provider's 
filing in compliance with this final rule. Instead, we modify that 
section to provide that no study delay penalties shall be assessed 
until the third cluster study cycle after the Commission-approved 
effective date of the compliance filing (including any transitional 
cluster study cycle, but not transitional serial studies).\1902\ We 
believe that giving transmission providers time to adapt to the new 
processes without imposing study delay penalties immediately will help 
ensure that transmission providers' implementation of this final rule 
has begun to reduce backlogged interconnection queues: i.e., we expect 
transmission providers to meet the interconnection study deadlines once 
they are implementing the cluster study process, with the increased 
requirements on interconnection customers (e.g., site control 
requirements, commercial readiness deposits, and withdrawal penalties) 
to help prevent speculative interconnection requests from entering and 
remaining in the interconnection queue.
---------------------------------------------------------------------------

    \1902\ See supra section III.A.7.c regarding the transition to 
the cluster study process.
---------------------------------------------------------------------------

    980. We adopt Duke Southeast Utilities' request to specify that 
transmission providers already using a cluster study process will not 
be subject to penalties until the third cluster study cycle after the 
Commission-approved effective date of the transmission provider's 
filing in compliance with this final rule.\1903\ We agree that 
transmission providers that already use a cluster study process should 
not be incentivized to employ an unnecessary transition process in 
response to this final rule simply to delay the possibility of study 
delay penalties. Accordingly, we modify the NOPR proposal such that no 
transmission providers will be assessed study delay penalties until the 
third cluster study cycle after the Commission-approved effective date 
of the compliance filing.
---------------------------------------------------------------------------

    \1903\ Duke Southeast Utilities Initial Comments at 11.
---------------------------------------------------------------------------

iv. Grace Period
    981. In addition to adopting a study delay penalty amount that we 
believe balances incentivizing transmission providers while not being 
overly punitive, we adopt in pro forma LGIP section 3.9(4) a 10-
business day grace period, such that no study delay penalties will be 
assessed for a study that is delayed by 10 business days or fewer, and 
if the study is delayed by more than 10 business days, the penalty 
amount will be calculated from the first business day the transmission 
provider exceeds the applicable study deadline. We believe that this 
10-business day grace period will provide an appropriate level of 
flexibility for transmission providers to address unforeseen 
circumstances or complexities that arise in the study process. We also 
believe that this grace period will lessen any administrative burden 
associated with the appeals process or RTO/ISO recovery of study delay 
penalty costs, as studies with short delays will not incur study delay 
penalties that may trigger appeals filings or the need for RTO/ISO 
penalty recovery.
v. Study Deadline Extension
    982. We adopt the NOPR proposal in pro forma LGIP section 3.9(5) to 
allow extensions of the deadline for a particular study by 30 business 
days by mutual agreement of the transmission provider and all 
interconnection customers with interconnection requests in the relevant 
study. We believe that this reform will promote cooperation between 
transmission providers and interconnection customers and incentivize 
transmission providers to keep interconnection customers informed of 
the status of study processes.
    983. We decline to adopt AEE's suggestion to require transmission 
providers to publicly post when a study deadline is extended by mutual 
agreement.\1904\ We do not find it necessary to require such public 
posting because transmission providers are being given sufficient 
incentive to minimize delays and manage all interconnection studies 
fairly. We also decline to adopt NARUC's suggestion to require 
transmission providers to certify that extensions will not delay 
unrelated interconnection requests outside the cluster.\1905\ 
Transmission providers will be sufficiently incentivized to ensure that 
such extensions do not delay other studies because any such delays may 
incur study delay penalties, as described in this section. In response 
to commenters that argue that it will be difficult to obtain mutual 
agreement in large regions, we do not view that as a reason to decline 
to adopt or to modify the proposal.\1906\ If an interconnection study 
is delayed, and mutual agreement cannot be obtained, the transmission 
provider will be assessed the

[[Page 61151]]

corresponding study delay penalties and may file an appeal with the 
Commission to explain any relevant circumstances.
---------------------------------------------------------------------------

    \1904\ AEE Initial Comments at 31-32.
    \1905\ NARUC Initial Comments at 15.
    \1906\ Indicated PJM TOs Initial Comments at 42; Tri-State 
Initial Comments at 19.
---------------------------------------------------------------------------

vi. Cap on Penalties
    984. We modify proposed section 3.9(2) of the pro forma LGIP, which 
capped study delay penalties at 100% of the total study deposit 
received for the late interconnection study, to instead cap penalties 
at: (1) 100% of the initial study deposits received for all of the 
interconnection requests in the cluster for cluster studies and cluster 
restudies; \1907\ (2) 100% of the initial study deposit received for 
the single interconnection request in the study for facilities studies; 
and (3) 100% of the study deposit(s) that the affected system 
transmission provider collects for conducting the affected system 
study. As discussed in the section III.A.2.6.a above, we modify the 
NOPR proposal and require transmission providers to collect a single 
study deposit from interconnection customers only upon entry into the 
cluster (initial study deposit), rather than a study deposit at each 
phase of the study process, as proposed in the NOPR. Accordingly, we 
modify the study delay penalty cap to reflect this change in the study 
deposit requirements. By tying the study delay penalty cap to the study 
deposits, we ensure that the maximum penalty bears a relationship to 
the costs of the study that was late and is not unnecessarily punitive.
---------------------------------------------------------------------------

    \1907\ Under section 3.1.1.1 of the pro forma LGIP, initial 
study deposits will range from $25,000 to $250,000, depending on the 
size of the proposed generating facility.
---------------------------------------------------------------------------

    985. In response to commenters who argue that study delay penalties 
should not be capped,\1908\ or that the cap should be higher than 100% 
of the study deposits for the late interconnection study,\1909\ we 
believe that imposing study delay penalties that exceed the amount of 
the study deposit collected for the late interconnection study will be 
unnecessarily punitive to transmission providers.
---------------------------------------------------------------------------

    \1908\ ACE-NY Initial Comments at 13; AEE Reply Comments at 37; 
Consumers Energy Initial Comments at 6; CREA and NewSun Initial 
Comments at 84; Cypress Creek Initial Comments at 23-24; Public 
Interest Organizations Initial Comments at 35-36; SEIA Initial 
Comments at 34.
    \1909\ Interwest Initial Comments at 8; Invenergy Initial 
Comments at 31; Northwest and Intermountain Initial Comments at 14.
---------------------------------------------------------------------------

    986. In response to Invenergy's request for clarification, we 
confirm that the cap will not be impacted by any withdrawal 
penalties.\1910\
---------------------------------------------------------------------------

    \1910\ Invenergy Initial Comments at 31.
---------------------------------------------------------------------------

vii. Ability To Appeal
    987. We further modify the NOPR proposal to include, in section 
3.9(3) of the pro forma LGIP, the ability for transmission providers to 
appeal any study delay penalties to the Commission.\1911\ Any such 
appeal must be filed no later than 45 calendar days after the late 
study has been completed. The Commission will evaluate whether good 
cause exists to grant relief from the study delay penalty and will 
issue an order granting or denying relief. In evaluating whether there 
is good cause to grant such relief, the Commission may consider, among 
other factors: (1) extenuating circumstances outside the transmission 
provider's control, such as delays in affected system study results; 
(2) efforts of the transmission provider to mitigate delays; and (3) 
the extent to which the transmission provider has proposed process 
enhancements either in the stakeholder process or at the Commission to 
prevent future delays. The filing of an appeal will stay the 
transmission providers' obligation to distribute the study delay 
penalty funds to interconnection customers until 45 calendar days after 
(1) the deadline for filing a rehearing request has ended, if no 
requests for rehearing of the Commission's decision on the appeal have 
been filed, or (2) the date that any requests for rehearing of the 
Commission's decision on the appeal are no longer pending before the 
Commission.
---------------------------------------------------------------------------

    \1911\ We note that these appeals should not be filed under FPA 
section 206. Contra Hanwha Q-CELLS USA Corp., 174 FERC ] 61,013, at 
PP 9-10 (2021) (interpreting CAISO's open access transmission tariff 
provision, which allows market participants that receive specific 
CAISO-imposed sanctions to obtain immediate review of CAISO's 
determination by directly appealing to the Commission ``in 
accordance with [the Commission's] rules and procedures,'' as a 
reference to 18 CFR 385.206 and 385.218); Mission Solar LLC, 174 
FERC ] 61,014, at PP 10-11 (2021); Cal. Indep. Sys. Operator Corp., 
184 FERC ] 61,009, at P 24 (2023).
---------------------------------------------------------------------------

    988. By providing an appeal process, we balance the need to ensure 
that transmission providers have an incentive to meet interconnection 
study deadlines with protections to ensure that any such penalties are 
fair and not triggered if good cause justifies the delay. The 
protections embedded in this appeal process address commenters' 
concerns that there be adequate due process and/or fact-finding before 
imposing a study delay penalty on transmission providers.\1912\
---------------------------------------------------------------------------

    \1912\ Indicated PJM TOs Initial Comments at 43-44; ISO/RTO 
Council Initial Comments at 2; MISO Initial Comments at 15, 76; 
NYISO Initial Comments at 35-36.
---------------------------------------------------------------------------

    989. In response to commenters that oppose study delay penalties 
because interconnection study delays are often caused by factors 
outside transmission providers' control,\1913\ we note that the 
penalties adopted herein are an integral element of a just and 
reasonable replacement rate to ensure that transmission providers are 
properly incentivized to address these factors. We do not find it 
appropriate to impose penalties only where a factor can be conclusively 
demonstrated to be within a transmission provider's control, as this 
would impose significant administrative burden. It may be difficult to 
precisely determine the cause of any given delay, especially where 
delay occurs due to multiple factors. Further, transmission providers' 
concerns are addressed to some extent through the ability to appeal 
described above, which provides an opportunity for relief from any 
study delay penalties. Further, we note that many of the reforms 
adopted in this final rule will help to mitigate factors that may 
prolong the study process, such as the submission of speculative 
interconnection requests. In addition, the reforms adopted regarding 
affected system coordination--discussed later in this final rule--will 
address delays resulting from affected system studies. We disagree with 
Indicated PJM TOs that a complete de novo review is needed to assess 
study delay penalties.\1914\ We find that the good cause standard 
adopted in this final rule \1915\ provides an adequate framework 
through which the Commission can evaluate whether it is appropriate to 
grant relief from any applicable penalties.
---------------------------------------------------------------------------

    \1913\ AEP Initial Comments at 25-26; Ameren Initial Comments at 
20; Avangrid Initial Comments at 9-10, 29; Dominion Reply Comments 
at 19; Indicated PJM TOs Reply Comments at 22-24; ISO-NE Initial 
Comments at 35-36; ISO/RTO Council Initial Comments at 3-4; MISO 
Initial Comments at 73-74; MISO TOs Initial Comments at 15-16, 23-
24; National Grid Initial Comments at 30; NESCOE Reply Comments at 
11-12; NRECA Initial Comments at 9, 33-34; NYISO Initial Comments at 
26-27; OMS Initial Comments at 15; Pacific Northwest Utilities 
Initial Comments at 9-10; PacifiCorp Initial Comments at 32-35; PG&E 
Initial Comments at 7; PG&E Reply Comments at 3-4; Puget Sound 
Initial Comments at 9; SDG&E Reply Comments at 1; Southern Initial 
Comments at 5, 30; State Agencies Initial Comments at 12-14; Tri-
State Initial Comments at 17-18; U.S. Chamber of Commerce Initial 
Comments at 10; WIRES Initial Comments at 9; Xcel Initial Comments 
at 38.
    \1914\ Indicated PJM TOs Initial Comments at 44.
    \1915\ See supra PP 987-988.
---------------------------------------------------------------------------

viii. Distribution of Study Delay Penalties to Interconnection 
Customers
    990. We adopt the NOPR proposal, with modification, set forth in 
pro forma LGIP section 3.9(1), to require transmission providers to 
distribute study delay penalties on a pro rata basis per 
interconnection request to the

[[Page 61152]]

interconnection customers and affected system interconnection customers 
included in the relevant study that did not withdraw, or were not 
deemed withdrawn, from the interconnection queue before the missed 
study deadline. Unless the transmission provider files an appeal to the 
study penalty, the study delay penalty must be distributed no later 
than 45 calendar days after the late study has been completed. 
Specifically, a study delay penalty for a delayed cluster study or 
cluster restudy must be distributed on a pro rata basis per 
interconnection request to all interconnection customers in the 
cluster, per the requirements above. A study delay penalty for a 
delayed facilities study must be distributed to the interconnection 
customer whose facilities were being studied, per the requirements 
above. Further, a study delay penalty for a delayed affected system 
study must be distributed to the affected system interconnection 
customer(s) whose generating facility was being studied by an affected 
system transmission provider, per the requirements above. In response 
to PG&E's request for clarification,\1916\ the study delay penalties 
are on a per business day basis and will be distributed equally to each 
delayed interconnection customer per the requirements above.
---------------------------------------------------------------------------

    \1916\ PG&E Initial Comments at 8.
---------------------------------------------------------------------------

    991. We find the distribution of the study delay penalties imposed 
due to a delay in the study, which defray the study costs of the 
interconnection customers affected by that delay, to be just and 
reasonable, as they will ensure that interconnection customers are able 
to interconnect in a reliable, efficient, transparent, and timely 
manner.
ix. No Recovery in Transmission Rates or From Interconnection Customers
    992. Regarding recovery of study delay penalties, we modify the 
NOPR proposal to prohibit non-RTO/ISO transmission providers and 
transmission-owning members of RTOs/ISOs from recovering study delay 
penalty amounts through transmission rates. This treatment of study 
delay penalties is consistent with the treatment of penalties imposed 
pursuant to Order No. 890 \1917\ and will ensure that the study delay 
penalties have the incentivizing effect discussed above. Because the 
at-fault transmission provider's shareholders will pay the penalty, 
this prohibition addresses commenters' concerns \1918\ that study delay 
penalty costs will ultimately be borne by customers and ratepayers 
through increased transmission costs.\1919\
---------------------------------------------------------------------------

    \1917\ See Order No. 890, 118 FERC ] 61,119 at P 1357 (``We will 
prohibit all jurisdictional transmission providers from recovering 
penalties for late studies from transmission customers.'').
    \1918\ Alliant Energy Initial Comments at 6-7; National Grid 
Initial Comments at 33; NYISO Reply Comments at 6-7, 9; R Street 
Initial Comments at 14; SEIA Reply Comments at 17; State Agencies 
Initial Comments at 12; Tri-State Initial Comments at 18.
    \1919\ See Order No. 2003, 104 FERC ] 61,103 at P 884 
(``[B]ecause liquidated damages liability will not have to be paid 
unless the Transmission Provider is at fault, we conclude that these 
damages will not be considered just and reasonable costs of service 
and will not be recoverable in transmission rates.'').
---------------------------------------------------------------------------

    993. Additionally, we decline to allow any transmission provider to 
recover study delay penalties from interconnection customers to the 
extent the interconnection customers cause delays. If a study delay is 
caused by an interconnection customer, and not the transmission 
provider, that would represent a potentially compelling basis for the 
Commission to find that good cause exists to waive the study delay 
penalties. Further, we note that, in the event that an interconnection 
request is incomplete or an interconnection customer misses a deadline, 
those interconnection requests are subject to the withdrawal provisions 
of pro forma LGIP section 3.7.
x. Penalty Recovery in RTOs/ISOs
    994. We decline to adopt the NOPR proposal to require RTOs/ISOs to 
submit requests to recover the costs of specific study delay penalties 
under FPA section 205. RTOs/ISOs may instead submit an FPA section 205 
filing to propose a default structure for recovering study delay 
penalties and/or make individual FPA section 205 filings to recover the 
costs of any specific study delay penalties. We believe that this 
discretion for RTOs/ISOs will reduce the administrative burden 
associated with study delay penalty cost recovery and will allow RTOs/
ISOs the flexibility to craft rules that work for their region. In 
response to ACORE's recommendation that RTOs/ISOs provide criteria for 
how they will assign study delay penalties, we note that RTOs/ISOs may 
file FPA section 205 proposals to explain how they will recover study 
delay penalties.\1920\
---------------------------------------------------------------------------

    \1920\ ACORE Initial Comments at 8.
---------------------------------------------------------------------------

    995. We modify the NOPR proposal to adopt 18 CFR 35.28(f)(1)(ii) to 
specify that, for RTOs/ISOs in which the transmission-owning members 
perform certain interconnection studies, the study delay penalties 
imposed under the new pro forma LGIP will be imposed directly on the 
transmission-owning member(s) that conducted the late study, thereby 
mooting the issue of how RTOs/ISOs recover those specific penalties. We 
believe that this change will also reduce the administrative burden, as 
RTOs/ISOs will typically not need to seek cost recovery for late 
facilities studies because those studies are often conducted by 
transmission-owning members. This change will also ensure that the 
study delay penalties are imposed on the public utility with the most 
control over whether the study deadline is met, i.e., the public 
utility conducting the study. Doing so aligns the incentive created by 
the study delay penalty with the entity most in control of the study 
timeline. This change also responds to AEE's suggestion to assign RTO/
ISO study delay penalties directly to transmission owners, OPSI's 
contention that RTOs/ISOs may be reluctant to seek cost recovery from 
transmission owners, and TAPS' concern that RTOs/ISOs would need well-
supported cases to assign study delay penalties to transmission 
owners.\1921\
---------------------------------------------------------------------------

    \1921\ AEE Initial Comments at 30; OPSI Initial Comments at 9; 
TAPS Initial Comments at 6-7.
---------------------------------------------------------------------------

    996. In response to commenters concerned about how study delay 
penalties will be assigned if no fault is found among RTO/ISO 
members,\1922\ the study delay penalties are imposed automatically on 
the RTO/ISO under the pro forma LGIP. As explained above, RTOs/ISOs may 
file an FPA section 205 proposal to recover the costs of study delay 
penalties. Concerns about any such proposals are best addressed in the 
relevant FPA section 205 proceedings. For the same reason, we decline 
to adopt TAPS' recommendation that the Commission provide an automatic 
waiver of any study delay penalty amount the RTO/ISO would otherwise 
pass to ratepayers,\1923\ as such determinations are best made on a 
case-by-case basis. In response to Indicated PJM TOs argument that PJM 
lacks the contractual authority to seek recovery of study delay 
penalties from transmission owners,\1924\ PJM's authority to recover 
costs from its transmission-owning members can be properly addressed in 
any future FPA section 205 proceeding.
---------------------------------------------------------------------------

    \1922\ Alliant Energy Initial Comments at 6-7; APPA-LPPC Initial 
Comments at 22; ISO/RTO Council Initial Comments at 4; NARUC Initial 
Comments at 18; NESCOE Initial Comments at 16.
    \1923\ TAPS Initial Comments at 7-8.
    \1924\ Indicated PJM TOs Initial Comments at 45.
---------------------------------------------------------------------------

    997. We acknowledge commenters' concerns that the study delay 
penalty structure may impose an administrative and litigative burden on 
RTOs/ISOs and

[[Page 61153]]

the Commission,\1925\ and that RTOs/ISOs may be in a fact-finding 
position in order to be able to assign study delay penalties not 
attributable to an RTO/ISO transmission owning member.\1926\ As an 
initial matter, we believe that any such burden is outweighed by the 
need to create an incentive to ensure that transmission providers 
timely complete interconnection studies. Also, we find that RTOs/ISOs 
do not face differing or greater burdens that warrant different 
treatment than non-RTO/ISO transmission providers. The pro forma LGIP 
applies to all transmission providers, RTO/ISO and non-RTO/ISO alike. 
To the extent that RTOs/ISOs elect to create a tariff mechanism for 
recovering study delay penalties, rather than relying on individual 
filings, as noted above, the RTO/ISO may submit an FPA section 205 
filing to propose such a default structure. Finally, where the 
transmission-owning members of an RTO/ISO perform interconnection 
studies, there is little-to-no ``fact-finding'' to be done to determine 
to which public utility to assign study delay penalties, as the 
transmission owner will be automatically assigned the penalty pursuant 
18 CFR 35.28(f)(1)(ii).
---------------------------------------------------------------------------

    \1925\ Avangrid Reply Comments at 8; CAISO Initial Comments at 
26; Indicated PJM TOs Reply Comments at 27; ISO-NE Initial Comments 
at 35; ISO/RTO Council Initial Comments at 3-4; PJM Initial Comments 
at 57-58; MISO Initial Comments at 16, 77; MISO TOs Reply Comments 
at 21-22; New York State Department Initial Comments at 10-11; NYISO 
Initial Comments at 33; SoCal Edison Initial Comments at 19.
    \1926\ ISO-NE Initial Comments at 36; ISO/RTO Council Initial 
Comments at 5-6; MISO Initial Comments at 15, 75.
---------------------------------------------------------------------------

    998. In response to concerns that RTOs/ISOs have no ability to pay 
study delay penalties without collecting them from another party,\1927\ 
we note that RTOs/ISOs have several options under this final rule for 
collecting study delay penalties. As discussed above, RTOs/ISOs may 
submit FPA section 205 filings to seek recovery for study delay 
penalties from public utilities contributing to study delays. The FPA 
section 205 filing could propose either to establish a tariff mechanism 
for assigning costs generally or for assigning costs for specific study 
delay penalties. RTOs/ISOs also have other ways to fund study delay 
penalties beyond the revenue they collect for sales of transmission 
service: for example, RTOs/ISOs collect administrative fees from market 
participants.\1928\
---------------------------------------------------------------------------

    \1927\ Alliant Energy Initial Comments at 6-7; EEI Initial 
Comments 17; Indicated PJM TOs Initial Comments at 37; ISO/RTO 
Council Initial Comments at 3-4; MISO Initial Comments at 13, 71; 
MISO TOs Reply Comments at 20; NARUC Initial Comments at 18; NEPOOL 
Initial Comments at 16; NESCOE Reply Comments at 11; New York State 
Department Initial Comments at 10; North Dakota Commission Initial 
Comments at 6; NYISO Initial Comments at 32; Omaha Public Power 
Initial Comments at 11; OMS Initial Comments at 15; R Street Initial 
Comments at 14; State Agencies Initial Comments at 12-13; TAPS 
Initial Comments at 3-5; WIRES Initial Comments at 11.
    \1928\ For example, MISO recovers the costs of providing 
financial transmission rights (FTR) administrative service from FTR 
holders under its Rate Schedule 16 (MISO Tariff, Schedule 16). SPP 
recovers the costs of administering its transmission administration 
service, transmission congestion rights administrative service, and 
integrated marketplace clearing administrative service from 
transmission customers and market participants under its Rate 
Schedule 1-A (SPP Tariff, Schedule 1-A). PJM recovers the costs of 
its control area administration service, which includes ``preserving 
the reliability of the PJM Region and administering Point-to-Point 
Transmission Service and Network Integration Transmission Service'' 
from users of the service under Schedule 9-1 (PJM Tariff, Schedule 
9-1).
---------------------------------------------------------------------------

    999. We disagree with NYISO that study delay penalties would 
threaten the financial viability of RTOs/ISOs or fail to incentivize 
RTOs/ISOs to complete studies by the required deadlines. The evidence 
in this record does not demonstrate that the study delay penalty 
structure that we adopt in this final rule, combined with the multiple 
adopted safeguards, including a total cap on study delay penalty 
amounts, would threaten the financial viability of an RTO/ISO, 
particularly given that RTOs/ISOs may submit FPA section 205 filings to 
recover study delay penalties. Additionally, as noted, we find that it 
is appropriate to incentivize RTOs/ISOs to meet study deadlines in the 
same manner as non-RTO/ISO transmission providers. Thus, we also 
disagree with NYISO that the study delay penalties for RTOs/ISOs should 
be smaller in size and slower to trigger.\1929\ As discussed above, we 
believe that the study delay penalty structure strikes a reasonable 
balance by providing an adequate incentive without being punitive.
---------------------------------------------------------------------------

    \1929\ NYISO Initial Comments at 32, 37, 41.
---------------------------------------------------------------------------

    1000. AEP and TAPS assert that the imposition of study delay 
penalties will disincentivize RTO/ISO participation.\1930\ We are not 
persuaded that any such disincentive outweighs the benefits of adopting 
study delay penalties. We expect that an incentive for transmission 
providers to meet interconnection study deadlines will result in more 
efficient interconnection queue processing, which will benefit 
competition and, in the long run, customers within a transmission 
provider's region, including within RTO/ISO regions. We continue to 
believe that customers are more likely to experience lower overall 
costs if the industry relies on robust wholesale competition to 
determine the appropriate level of generation and related transmission 
development.\1931\
---------------------------------------------------------------------------

    \1930\ AEP Initial Comments at 27-28; TAPS Initial Comments at 
6.
    \1931\ See Order No. 2003-A, 106 FERC ] 61,220 at P 507.
---------------------------------------------------------------------------

    1001. We find that applying study delay penalties to RTOs/ISOs for 
failing to meet interconnection study deadlines is consistent with 
Commission precedent and continues to be appropriate, particularly 
given the extent of interconnection queue backlogs in RTOs/ISOs. We 
disagree with NYISO that, because RTOs/ISOs may be at greater risk of 
being assessed study delay penalties than reliability penalties, this 
meaningfully distinguishes study delay penalties from the Commission's 
findings in Order Nos. 672-A and 890 related to reliability 
penalties.\1932\ In response to NYISO's comment that reliability 
penalties receive the Commission's close scrutiny, we note that 
transmission providers will have an opportunity to seek relief from a 
penalty by filing an appeal, which the Commission will closely 
scrutinize and in response to which the Commission will issue an 
order.\1933\
---------------------------------------------------------------------------

    \1932\ Order No. 672-A, 114 FERC ] 61,328 at P 56 (``it is not 
arbitrary and capricious to treat all operators alike, including 
RTOs and ISOs, in terms of their liability for violation of a 
Reliability Standard.''); Order No. 890, 118 FERC ] 61,119 at P 1357 
(``we believe that all entities administering the tariff should 
operate under the same rules, reporting obligations, and performance 
metrics . . . Non-profit transmission providers have other sources 
of money to pay penalties beyond the revenue they collect for sales 
of transmission service.'').
    \1933\ NYISO Initial Comments at 33-34.
---------------------------------------------------------------------------

xi. Posting Requirements
    1002. For transparency purposes, we adopt the proposed requirements 
in pro forma LGIP section 3.9(7) that transmission providers must post 
on their OASIS or other publicly accessible website on a quarterly 
basis, within 30 calendar days of the end of the calendar quarter, (1) 
the total amount of study delay penalties from the previous reporting 
quarter, and (2) the highest amount of such study delay penalties 
repaid to a single interconnection customer during the previous 
reporting quarter. We also adopt the proposed requirements in pro forma 
LGIP section 3.9(7) that transmission providers must maintain the 
quarterly measures posted on their OASIS or website for three calendar 
years, with the first required posting to be the third cluster study 
cycle (including any transitional cluster study cycle, but not 
transitional serial studies) after the transmission provider 
transitions to the cluster study process. We believe that this 
additional

[[Page 61154]]

information will be helpful to the public and the Commission in 
tracking the status of interconnection queue delays and that the burden 
on transmission providers of posting this information will be minimal.
xii. Force Majeure Exception
    1003. We decline to adopt the NOPR proposal to exempt transmission 
providers from study delay penalties where force majeure applies. We 
believe that this exemption is unwarranted: transmission providers may 
explain in any appeal to the Commission any circumstances that caused 
the delay, including any events that qualify as force majeure, and the 
Commission will consider such circumstances as part of its evaluation 
of whether good cause exists to grant relief from the otherwise 
applicable study delay penalties.
xiii. Transmission Provider Resources
    1004. In response to commenters that raise concerns about 
transmission provider resources to complete studies on time, we first 
emphasize that the overall set of reforms in this final rule should 
significantly streamline and reduce the number of interconnection 
studies that a transmission provider must conduct, easing the burden on 
transmission providers. With the benefit of fewer studies and fewer 
speculative generating facilities in the interconnection queue, we 
expect that a transmission provider that faces the potential of a study 
delay penalty for failing to meet interconnection study deadlines will 
be able to allocate sufficient resources to conduct interconnection 
studies, in addition to implementing reforms to ensure that its study 
process is efficient. In this final rule, we adopt interconnection 
study deadlines for a transmission provider to complete cluster 
studies, cluster restudies, facilities studies, and affected system 
studies. As discussed above, we believe that the interconnection study 
deadlines will give transmission providers sufficient time to conduct 
the relevant studies, e.g., 150 calendar days for the completion of the 
cluster study, and we have demonstrated that the existing pro forma 
generator interconnection procedures and agreements are insufficient to 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner.\1934\ We therefore believe that the record supports the 
imposition of study delay penalties for failure to meet those 
deadlines.
---------------------------------------------------------------------------

    \1934\ See supra section II.C.
---------------------------------------------------------------------------

    1005. Some commenters argue that other NOPR proposals, such as the 
optional resource solicitation studies, optional informational 
interconnection studies, and evaluation of advanced transmission 
technologies, will consume transmission provider resources otherwise 
dedicated to interconnection studies.\1935\ Similarly, other commenters 
argue that imposing firm study deadlines will force transmission 
providers to redirect resources and personnel away from other necessary 
functions such as transmission planning or deprive them of financial 
resources and make it harder to retain qualified personnel.\1936\ We 
note that we do not adopt the NOPR proposals to implement optional 
informational interconnection studies or optional resource solicitation 
studies and adopt a modified version of the NOPR proposal to require 
evaluation of certain enumerated advanced transmission technologies, 
which should reduce the burden on transmission providers as compared to 
that under the NOPR. Further, to these arguments, we note that it is 
the transmission provider's responsibility to manage its organizational 
resources--including attracting and retaining sufficient qualified 
personnel to meet its responsibilities--and that it is within the 
transmission provider's ability to improve how it manages its internal 
resources. If, for whatever reason, the transmission provider is not 
able to meet firm study deadlines, that is an issue the transmission 
provider is free to raise in appealing any penalties it incurs. While 
we are not persuaded that transmission providers will necessarily need 
to reassess their organizational needs to meet study deadlines, given 
the suite of reforms adopted in the final rule, to the extent that such 
steps are required, they are warranted to fulfill our responsibility 
under the FPA to ensure just and reasonable rates and to ensure that 
interconnection customers are able to interconnect in a reliable, 
efficient, transparent, and timely manner.
---------------------------------------------------------------------------

    \1935\ Indicated PJM TOs Initial Comments at 36; MISO Reply 
Comments at 7; PPL Initial Comments at 24; SPP Initial Comments at 
13.
    \1936\ Ameren Initial Comments at 21; Eversource Initial 
Comments at 25-26; Indicated PJM TOs Initial Comments at 6, 24, 40; 
MISO TOs Initial Comments at 24; National Grid Initial Comments at 
30; Pacific Northwest Utilities Initial Comments at 12; PJM Initial 
Comments at 57.
---------------------------------------------------------------------------

    1006. We disagree with SoCal Edison and New York State Department 
that transmission providers will require additional resources to track 
and allocate study delay penalties, potentially increasing the cost of 
administering interconnection queues.\1937\ We note that transmission 
providers already track the progress of their interconnection queues 
and should be aware of study deadlines, especially as their tariffs 
currently require reasonable efforts to meet such deadlines. As a 
result, determining when study delay penalties apply will be as 
straightforward as determining how many studies are late and past the 
10-business day grace period from the applicable study deadline. As 
explained above, we anticipate that other provisions of this final rule 
will result in improved interconnection queue management and 
processing, which should ease the burden on transmission providers over 
time.
---------------------------------------------------------------------------

    \1937\ New York State Department Initial Comments at 10-11; 
SoCal Edison Initial Comments at 19.
---------------------------------------------------------------------------

    1007. We also disagree with commenters that firm study deadlines 
with study delay penalties will necessarily reduce interconnection 
study flexibility \1938\ and accuracy,\1939\ as well as system 
reliability.\1940\ We reiterate that it is within transmission 
providers' ability to improve interconnection study processes and 
policies and take other measures, such as hiring additional staff, to 
efficiently process interconnection queues without sacrificing 
accuracy, flexibility, or reliability. Study delay penalties will 
incentivize these actions, especially given transmission providers' 
independent responsibilities to deliver accurate studies and to ensure 
system reliability. Thus, we agree with the New Jersey Commission that 
there is not an inherent tradeoff between holding

[[Page 61155]]

transmission providers accountable and transmission system reliability. 
In addition, we further agree that the failure to bring new generating 
facilities online in a timely manner can also create reliability and 
economic risk.\1941\ Moreover, interconnection customers, rather than 
transmission providers, ultimately bear the costs of interconnection 
studies. To the extent that it is more costly to complete studies in a 
timely and accurate fashion, these interconnection study costs will be 
passed on to interconnection customers. Further, as noted above, the 
study delay penalty structure includes significant safeguards for the 
transmission provider, such as the transition period, the 10-business 
day grace period, the penalty cap, the ability to extend deadlines by 
mutual agreement, and the ability to appeal any study delay penalties 
to the Commission.
---------------------------------------------------------------------------

    \1938\ Dominion Reply Comments at 21; EEI Initial Comments at 
15; Eversource Initial Comments at 25-26; NYISO Initial Comments at 
38-39; WIRES Initial Comments at 10.
    \1939\ AECI Initial Comments at 6; Alliant Energy Initial 
Comments at 6; Avangrid Initial Comments at 9-10, 30; Bonneville 
Initial Comments at 15-16; CESA Reply Comments at 8; Clean Energy 
Buyers Initial Comments at 10-11; Enel Initial Comments at 48; 
Indicated PJM TOs Reply Comments at 26; ISO/RTO Council Initial 
Comments at 8; Longroad Energy Reply Comments at 14; MISO Initial 
Comments at 13, 71, 77-78; MISO TOs Initial Comments at 14, 24; 
National Grid Initial Comments at 30; NESCOE Reply Comments at 13; 
NextEra Reply Comments at 11; NYTOs Initial Comments at 24-28; North 
Dakota Commission Initial Comments at 6; NRECA Initial Comments at 
34; NYISO Initial Comments at 38-39; Omaha Public Power Initial 
Comments at 12; OMS Initial Comments at 15; [Oslash]rsted Initial 
Comments at 15; PacifiCorp Reply Comments at 6; PJM Initial Comments 
at 8, 56-57; PPL Initial Comments at 19; SPP Initial Comments at 11-
12; Tri-State Initial Comments at 18; Xcel Initial Comments at 38.
    \1940\ AEP Initial Comments at 28; Dominion Reply Comments at 
21; MISO TOs Reply Comments at 18-19; NYISO Initial Comments at 39; 
PJM Initial Comments at 8, 56-57.
    \1941\ New Jersey Commission Reply Comments at 3.
---------------------------------------------------------------------------

xiv. Coordination Among Transmission Providers, Interconnection 
Customers, and Affected Systems
    1008. Several commenters raise concerns related to affected 
systems, and coordination among transmission providers, interconnection 
customers, and affected systems. In response to NARUC's request for 
clarification regarding affected system studies, we note that new pro 
forma LGIP section 3.9 will apply to all transmission providers when 
they are acting as an affected system operator (affected system 
transmission providers).\1942\ As a result, affected system 
transmission providers are also subject to a study delay penalty for a 
late affected system study. Thus, contrary to commenters' arguments 
that the NOPR proposal ignores that other entities, such as affected 
systems, may be responsible for study delays,\1943\ affected system 
transmission providers will face the same incentive as the host 
transmission provider to timely complete their studies. In addition, 
where a delay for a host transmission provider's cluster or facilities 
studies is caused by affected system study delays, the host 
transmission provider can file an appeal of any applicable study delay 
penalty with the Commission and include such details in its claim of 
good cause for relief.
---------------------------------------------------------------------------

    \1942\ NARUC Initial Comments at 14, 17.
    \1943\ ISO/RTO Council Initial Comments at 3-4; MISO Initial 
Comments at 74.
---------------------------------------------------------------------------

    1009. We disagree with commenters' concerns that the study delay 
penalty structure would decrease or harm coordination between 
transmission providers, interconnection customers, and affected 
systems,\1944\ and/or create tension between RTOs/ISOs, transmission 
owners, developers, or other parties.\1945\ The incentive for 
transmission providers to timely complete interconnection studies 
created by the study delay penalty structure should improve 
coordination among transmission providers and interconnection customers 
to ensure that transmission providers have the information needed to 
complete the studies and, if there is an issue, to pursue a potential 
extension of the deadline via mutual agreement. We note that other 
reforms adopted in this final rule will improve clarity and efficiency 
around affected system studies, which should improve coordination with 
affected systems. In addition, affected system transmission providers 
are also subject to study delay penalties for delayed affected system 
studies, which should encourage better coordination. We also believe 
that an ability to appeal study delay penalties will provide a 
structured forum for parties to dispute claims, placing the Commission 
in the position of decisionmaker when it comes to determining whether 
to excuse study delay penalties.
---------------------------------------------------------------------------

    \1944\ Alliant Energy Initial Comments at 6; EEI Initial 
Comments at 15; Eversource Initial Comments at 25-26; MISO Reply 
Comments at 21; North Dakota Commission Initial Comments at 6.
    \1945\ AEP Initial Comments at 27; Dominion Initial Comments at 
35-36; Indicated PJM TOs Reply Comments at 6-7, 27; NextEra Initial 
Comments at 30; NYISO Initial Comments at 39-40; PJM Initial 
Comments at 57-58.
---------------------------------------------------------------------------

    1010. We disagree with AECI that there is no benefit to imposing 
penalties on affected system transmission providers for failure to 
timely complete affected system studies. These studies equally affect 
interconnection customer certainty and interconnection process 
efficiency, and as such, we believe that the penalty structure 
enumerated above will also incentivize transmission providers to 
complete affected system studies in a timely manner. Indeed, the 
Commission has addressed several instances where affected system 
studies have delayed or otherwise affected interconnection study 
timelines and processes,\1946\ and therefore, without imposing a 
penalty structure, we are not convinced that transmission providers 
will timely complete their affected system studies. In the same vein, 
we agree with Interwest that monetary penalties for failure to meet the 
affected system study deadline will incentivize discipline and support 
investment needed to meet affected system study timelines.
---------------------------------------------------------------------------

    \1946\ See, e.g., Tenaska Clear Creek Wind, LLC v. Sw. Power 
Pool, Inc., 177 FERC ] 61,200 (2021); EDF Renewable Energy, Inc. v. 
Midcontinent Indep. Sys. Operator, Inc., 168 FERC ] 61,173 (2019).
---------------------------------------------------------------------------

    1011. In response to ENGIE, MISO, and Duke Southeast Utilities' 
comments on the distribution of study delay penalties for failure to 
timely complete affected system studies, we note that any study delay 
penalties will be distributed on a pro rata basis per interconnection 
request to the affected system interconnection customers included in 
the relevant study that did not withdraw, or were not deemed withdrawn, 
from the interconnection queue before the missed study deadline.
xv. Commission Authority and Precedent
    1012. Some commenters argue that the proposed study delay penalty 
structure is an unjustified shift from precedent established in Order 
No. 845, in which the Commission expressly declined to impose 
penalties.\1947\ We disagree. As we explain above, interconnection 
queue delays in many parts of the country have worsened since Order No. 
845, and the record indicates that the failure of transmission 
providers to timely complete studies is a significant part of the 
reason why. For example, in the single year between 2021 and 2022, 
there was marked increase in the average length of time customers have 
been waiting in the interconnection queue, increasing from roughly 4 to 
5 years, while at the same time seeing the total interconnection queue 
size increased from 1,400 GW to more than 2,000 GW.\1948\ Based on the 
recent interconnection study metrics transmission providers posted in 
compliance with Order No. 845, of the 2,179 interconnection studies 
completed in 2022, 68% were issued late.\1949\ Furthermore, at the end 
of 2022, an additional 2,544 studies were delayed (i.e., ongoing and 
past their deadline).\1950\ All of the RTOs/ISOs except CAISO and 14 
non-RTO/ISO transmission providers reported delayed studies at the end 
of 2022.\1951\ We believe that this large number of delayed studies is 
a significant part of

[[Page 61156]]

the explanation for the extensive delays and growing interconnection 
queues documented above and in the Overall Need for Reform section. 
Accordingly, based on the evidence in this record, we find that study 
delay penalties are an appropriate component of a just, reasonable, and 
not unduly discriminatory or preferential replacement rate to remedy 
these interconnection delays and the consequences they have for 
Commission-jurisdictional rates.\1952\
---------------------------------------------------------------------------

    \1947\ MISO TOs Initial Comments at 21-22; NYISO Initial 
Comments at 26; PG&E Initial Comments at 6; PG&E Reply Comments at 
3.
    \1948\ Queued Up 2022 at 3; Queued Up 2023 at 3, 31.
    \1949\ Based on data provided by transmission providers in 
compliance with Order No. 845. See appendix B to this final rule for 
the underlying data.
    \1950\ Id. Note that the vast majority of these studies (2,211) 
were in PJM.
    \1951\ Id. CAISO revised the interconnection study deadlines of 
their queue cluster 14 to account for the unprecedented increase in 
interconnection requests. Cal. Indep. Sys. Operator Corp., 176 FERC 
] 61,207.
    \1952\ See Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm 
Mut. Auto. Ins. Co., 463 U.S. at 56-57 (``[T]he agency is entitled 
to change its view . . . [if it] explain[s] its reasons for doing 
so.'').
---------------------------------------------------------------------------

    1013. Similarly, in response to commenters who argue that the 
proposed study delay penalty structure differs from the penalty 
structure implemented in Order No. 890 for transmission service 
studies,\1953\ we believe that such differences are warranted by the 
significant and growing interconnection queue backlogs. We agree with 
PacifiCorp that, compared to transmission service requests, 
interconnection studies are more numerous, complex, and susceptible to 
delays.\1954\ Further, as noted above, there is a growing number of 
interconnection customers affected by study delays. We believe that 
these factors underscore the need for transmission providers to meet 
study deadlines and the need to provide an incentive, in the form of 
study delay penalties. We find that the other reforms adopted in this 
final rule will streamline interconnection processes: for example, the 
cluster study process will reduce the number of interconnection studies 
that any transmission provider must conduct at a given time, thus 
reducing the potential for study delay penalties to accumulate relative 
to the serial study process in place today. We find that the 
elimination of the reasonable efforts standard and adoption of the 
study delay penalty structure will incentivize transmission providers 
to take appropriate steps to meet the study deadlines in their tariffs.
---------------------------------------------------------------------------

    \1953\ Eversource Initial Comments at 30; MISO Reply Comments at 
21; MISO TOs Initial Comments at 19-21; PacifiCorp Initial Comments 
at 33-34; Tri-State Initial Comments at 18.
    \1954\ PacifiCorp Initial Comments at 33-34.
---------------------------------------------------------------------------

    1014. We also disagree with TAPS' assertion that reliability 
penalties are permissible because they are part of a congressionally 
mandated regime, whereas the study delay penalties are not.\1955\ We 
find that FPA section 206 provides us with the authority to establish a 
structure to impose study delay penalties because such delays render 
Commission-jurisdictional rates unjust and unreasonable, as explained 
in the Overall Need for Reform section, and we believe that this 
structure reflects a just and reasonable replacement rate.\1956\ As 
discussed above, an RTO/ISO has different options for recovering those 
penalties, and we are not in this final rule dictating which option an 
RTO/ISO must choose. Further, TAPS' argument that reliability penalties 
are used to offset NERC's operation costs but the interconnection study 
delay penalties will not be used to offset costs for consumers or 
ratepayers does not change our conclusion.\1957\ We do not believe that 
our authority to require study delay penalties as part of a just and 
reasonable replacement rate turns on the entity whose costs are offset 
by the penalties collected, and as discussed above, we find it 
appropriate in this circumstance to use study penalties to offset the 
interconnection study costs for interconnection customers that are 
affected by the study delays.
---------------------------------------------------------------------------

    \1955\ TAPS Initial Comments at 5 (citing 16 U.S.C. 824o).
    \1956\ 16 U.S.C. 824e.
    \1957\ TAPS Initial Comments at 5.
---------------------------------------------------------------------------

    1015. Moreover, automatic tariff-based penalty mechanisms similar 
to that which we adopt in this final rule exist in a variety of other 
contexts. For example, RTO/ISO tariffs include penalties for ``traffic 
ticket'' violations that are penalized without referral to the 
Commission.\1958\ In that context, the Commission has approved such 
automatic penalties where (1) the activity is expressly set forth in 
the tariff, (2) the activity involves objectively identifiable 
behavior, and (3) the activity does not subject the actor to sanctions 
or consequences other than those expressly approved by the Commission 
and set forth in the tariff, with the ability to appeal \1959\ to the 
Commission.\1960\ That is the same structure we are adopting here: the 
study delay penalties (1) will be expressly set forth in the tariff, 
(2) will be based on objectively identifiable behavior (i.e., whether a 
study is late), and (3) will only trigger consequences expressly 
approved by the Commission (i.e., the $1,000/$2,000/$2,500 per business 
day penalties with the ability to appeal to the Commission.
---------------------------------------------------------------------------

    \1958\ See, e.g., Cal. Indep. Sys. Operator Corp., 134 FERC ] 
61,050, at PP 34-35 (2011); N.Y. Indep. Sys. Operator, Inc., 131 
FERC ] 61,225, at P 16 (2010). Also, in Order No. 890, the 
Commission approved other tariff-based ``operational penalties'' on 
customers where it similarly did not require notification or review 
by the Commission of the assessed penalty. See Order No. 890, 118 
FERC ] 61,119 at PP 834-36.
    \1959\ See, e.g., Cal. Indep. Sys. Operator Corp., 175 FERC ] 
61,043 (2021) (excusing penalties for late meter data revisions); 
Lathrop Irrigation Dist., 161 FERC ] 61,243 (2017) (denying request 
for waiver of CAISO tariff provisions that impose penalties on late 
submission by LSEs of required information for resource adequacy 
plans).
    \1960\ Cal. Indep. Sys. Operator Corp., 134 FERC ] 61,050 at PP 
34-35.
---------------------------------------------------------------------------

    1016. In response to Indicated PJM TOs' argument that the 
Commission lacks the authority to require RTOs/ISOs to seek cost 
recovery of study delay penalties from transmission owners within the 
RTO/ISO,\1961\ we note that this concern is moot because we are 
declining to adopt the NOPR proposal to require RTOs/ISOs to submit 
requests to recover the costs of specific study delay penalties. 
Further, we modify our proposal to adopt revisions to 18 CFR 
35.28(f)(1)(ii) to automatically apply study delay penalties to 
transmission owners within RTOs/ISOs when those transmission owners 
have conducted the delayed studies. Finally, as discussed above, RTOs/
ISOs may submit an FPA section 205 filing to propose a default 
structure for recovering study delay penalties or make individual FPA 
section 205 filings to recover the costs of any specific study delay 
penalties.
---------------------------------------------------------------------------

    \1961\ Indicated PJM TOs Initial Comments at 44-45.
---------------------------------------------------------------------------

xvi. Miscellaneous
    1017. We also decline to adopt alternative proposals for study 
delay penalty structures. We find the penalty structure that we adopt 
in this final rule to be a just and reasonable replacement rate, which 
is all that the Commission is required to show under FPA section 
206.\1962\
---------------------------------------------------------------------------

    \1962\ Entergy Ark., LLC v. FERC, 40 F.4th 689, 701 (D.C. Cir. 
2022) (explaining that in setting the replacement rate under FPA 
section 206, ``FERC is not required to choose the best solution, 
only a reasonable one'') (quoting Petal Gas Storage, LLC v. FERC, 
496 F.3d 695, 703 (D.C. Cir. 2007)).
---------------------------------------------------------------------------

    1018. In response to EEI's and Eversource's comments concerning why 
the good utility practice standard, which is contained within the text 
of the definition of the reasonable efforts standard in the pro forma 
LGIP, would no longer apply to interconnection processes,\1963\ we 
clarify that the elimination of the reasonable efforts standard does 
not eliminate the requirement that transmission providers act 
consistent with good utility practice when conducting interconnection 
studies. Therefore, we adopt revisions to section 4.2 of the pro forma 
LGIP to indicate that transmission providers must continue to conduct 
interconnection studies consistent with good utility practice.
---------------------------------------------------------------------------

    \1963\ EEI Initial Comments at 15; Eversource Initial Comments 
at 22-24.

---------------------------------------------------------------------------

[[Page 61157]]

    1019. Some commenters argue that interconnection study deadlines 
should be extended in cases of interconnection customer-caused delays 
and that the timeline for completing such studies should not restart 
until after an interconnection customer submits all necessary 
information and cures any deficiencies; they also argue that 
transmission providers should not be penalized if study delays are 
caused by a higher-queued cluster being restudied.\1964\ We decline to 
adopt these modifications. As an initial matter, we note that if an 
interconnection customer fails to adhere to all requirements in the pro 
forma LGIP, except in the case of disputes, the transmission provider 
shall deem the interconnection customer's interconnection request to be 
withdrawn pursuant to section 3.7 of the pro forma LGIP. To the extent 
that study delays result from an interconnection customer's actions or 
higher-queued cluster restudies, transmission providers may record the 
length of those delays and report that information in any appeal of 
study delay penalties filed with the Commission.
---------------------------------------------------------------------------

    \1964\ APPA-LPPC Initial Comments at 21; NRECA Initial Comments 
at 34; Tri-State Initial Comments at 18-19.
---------------------------------------------------------------------------

    1020. We disagree with PJM that interconnection customers will be 
incentivized to delay studies of their interconnection requests in 
order to offset their study costs via study delay penalties being 
allocated to them from the transmission provider.\1965\ We agree with 
AEE that the economic harms of delaying the interconnection process for 
an interconnection customer with a commercially viable interconnection 
request, especially given the reforms adopted in this final rule (e.g., 
increased study deposits, commercial readiness deposits, and withdrawal 
penalties) significantly outweigh any economic incentive for 
interconnection customers to delay the interconnection process in hopes 
of a study delay penalty to offset study costs.\1966\ For example, a 
cluster study delayed by 100 business days would generate $100,000 in 
study delay penalties to be distributed among all interconnection 
customers in the cluster, yet such a lengthy delay could force an 
interconnection customer to withdraw from the interconnection queue due 
to commercial obligations and carries an interconnection customer 
withdrawal penalty risk of two times the study cost.
---------------------------------------------------------------------------

    \1965\ PJM Initial Comments at 57.
    \1966\ AEE Reply Comments at 35-36.
---------------------------------------------------------------------------

    1021. We decline requests to delay implementation of the study 
delay penalty reforms until other reforms in this rulemaking and 
related rulemakings, such as those in Docket No. RM22-17, take 
effect.\1967\ As explained above, our modification to the NOPR's 
proposed transition mechanism for study delay penalties, which will 
allow transmission providers to complete two cluster study cycles 
before being subject to study delay penalties, will provide sufficient 
time for transmission providers to implement the other reforms adopted 
in this final rule. This transition mechanism will also give 
transmission providers currently undergoing their own interconnection 
queue reform efforts, as SPP and NYISO explain they are, time to 
implement those reforms.\1968\ In addition, we find that the study 
delay penalties are just and reasonable based on the record in this 
proceeding and that it would not be appropriate to delay their effect 
until action is taken in other proceedings. To the extent the 
Commission finalizes the proposed reforms in separate proceedings, the 
Commission will consider how to address potential interactions between 
the reforms adopted in this final rule and elsewhere.
---------------------------------------------------------------------------

    \1967\ AEP Initial Comments at 29; Avangrid Reply Comments at 
14; Clean Energy Buyers Initial Comments at 10-11; Eversource 
Initial Comments at 30-31; Idaho Power Initial Comments at 10; ISO/
RTO Council Reply Comments at 5; Longroad Energy Reply Comments at 
15; NY Commission and NYSERDA Initial Comments at 6; NYISO Initial 
Comments at 30; Pacific Northwest Utilities Initial Comments at 9-
10; PacifiCorp Initial Comments at 34; Puget Sound Initial Comments 
at 11; State Agencies Initial Comments at 14; TAPS Initial Comments 
at 9.
    \1968\ NYISO Initial Comments at 30; SPP Initial Comments at 14-
15.
---------------------------------------------------------------------------

    1022. In response to WAPA's comment that Federal agencies should 
not be subject to study delay penalties absent a specific congressional 
waiver of sovereign immunity,\1969\ we clarify that the penalties will 
apply to the extent that a non-public utility has adopted the proposed 
penalty provisions as a part of its reciprocity tariff.\1970\ Under the 
safe harbor procedure set out in Order No. 888, non-public utilities 
may voluntarily submit to the Commission an open access transmission 
tariff; if the Commission finds that the tariff contains terms and 
conditions that substantially conform or are superior to those in the 
pro forma open access transmission tariff, the Commission will deem it 
an acceptable reciprocity tariff and will require public utilities to 
provide open access transmission service to that particular non-public 
utility (safe harbor treatment).\1971\ We find that, where such non-
public utilities voluntarily file a reciprocity tariff, they consent to 
abide by the Commission's open access principles and the various 
provisions of the pro forma tariff, which would include the penalties 
we are adopting in this final rule (unless the Commission were to find 
that a safe harbor tariff without those penalty provisions 
substantially conforms or is superior to the pro forma tariff).\1972\
---------------------------------------------------------------------------

    \1969\ WAPA Initial Comments at 10.
    \1970\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission on Servs. by Pub. Utils.; Recovery of 
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, 
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036, at 31,760-
763 (1996) (cross-referenced at 75 FERC ] 61,080), order on reh'g, 
Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 
31,048 (cross-referenced at 78 FERC ] 61,220), order on reh'g, Order 
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom. 
Transmission Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C. 
Cir. 2000), aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002).
    \1971\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,761.
    \1972\ Where, as here, the Commission makes changes to the pro 
forma tariff, a non-public utility that already has a reciprocity 
tariff and wishes to maintain its safe harbor treatment must amend 
its tariff so that its provisions substantially conform or are 
superior to the revised pro forma tariff. See Order No. 2003, 104 
FERC ] 61,103 at P 842.
---------------------------------------------------------------------------

    1023. WAPA cites to Southwestern Power Admin. v. FERC \1973\ for 
its proposition that, absent a specific waiver of sovereign immunity, 
Federal agencies are not subject to monetary penalties.\1974\ We find 
that case inapposite because the penalties adopted here are not civil 
monetary penalties imposed by the Commission and paid to the U.S. 
Treasury. Instead, they would be penalties imposed pursuant to a 
voluntarily submitted reciprocity tariff and would be distributed to 
the delayed interconnection customer(s) in the relevant study that 
remained in the interconnection queue at the time the penalty would be 
distributed. WAPA and other Federal agencies, if they file reciprocity 
tariffs, would voluntarily choose to abide by the terms of those 
tariffs and thus would consent to any penalty structures contained in 
them.
---------------------------------------------------------------------------

    \1973\ Sw. Power Admin. v. FERC, 763 F.3d 27 (D.C. Cir. 2014).
    \1974\ WAPA Initial Comments at 10 n.12.
---------------------------------------------------------------------------

    1024. We decline to adopt commenters' suggestions to create generic 
exceptions to study delay penalties.\1975\ Not only do we lack record 
support for some of the suggestions, but we also believe that

[[Page 61158]]

transmission provider requests for an exception to a study delay 
penalty are best addressed on a case-by-case basis via the appeal 
process outlined above.
---------------------------------------------------------------------------

    \1975\ Indicated PJM TOs Initial Comments at 42; MISO TOs 
Initial Comments at 25; National Grid Initial Comments at 32; NESCOE 
Initial Comments at 16; NYISO Initial Comments at 42; PPL Initial 
Comments at 19; SoCal Edison Initial Comments at 19; Tri-State 
Initial Comments at 18; WIRES Initial Comments at 10; Xcel Initial 
Comments at 38.
---------------------------------------------------------------------------

    1025. We decline to adopt alternative proposals suggested by 
various commenters. For example, we do not believe that imposing only a 
reporting requirement on study delays is sufficient to resolve the 
problem of interconnection queue backlogs and repeatedly delayed 
interconnection studies. Similarly, we decline to condition study delay 
penalties on the outcome of a show cause proceeding conducted by the 
Commission, as suggested by MISO,\1976\ because it would be 
administratively burdensome and may not create a sufficient incentive 
for transmission providers to meet interconnection study deadlines. We 
also decline to adopt suggestions such as creation of favorable rate 
treatment for transmission providers that meet interconnection study 
deadlines \1977\ or tying interconnection study performance to 
executive compensation,\1978\ which we do not believe would ensure that 
interconnection customers are able to interconnect in a reliable, 
efficient, transparent, and timely manner as effectively as the study 
delay penalty structure that we adopt instead.
---------------------------------------------------------------------------

    \1976\ MISO Initial Comments at 79-80.
    \1977\ Longroad Energy Reply Comments at 14-15; Shell Initial 
Comments at 11.
    \1978\ Clean Energy States Initial Comments at 10-11; CREA and 
NewSun Reply Comments at 57; TAPS Initial Comments at 8.
---------------------------------------------------------------------------

2. Affected Systems
a. Need for Reform
i. NOPR Proposal
    1026. In the NOPR, the Commission preliminarily found that the 
affected system study process lacks consistency between transmission 
providers.\1979\ The Commission stated that, without any requirement 
for a timely cost determination, affected system operators may not 
return study results in time for interconnection customers to make 
informed decisions to facilitate interconnection of their generating 
facilities. The Commission added that, due to this lack of information, 
there may continue to be late-stage withdrawals resulting from 
unexpected high costs for affected system network upgrades that create 
restudies and delays.\1980\ The Commission also noted that 
interconnection customers recommended standardization of the affected 
system study process in both the technical conference in Docket No. 
AD18-8-000 and in comments on the ANOPR in Docket No. RM21-17-000, 
specifically asking for standardization of the timing of study results, 
the amount of study costs, and modeling criteria used in affected 
system studies.\1981\
---------------------------------------------------------------------------

    \1979\ NOPR, 179 FERC ] 61,104 at P 179 (citing May Joint Task 
Force Tr. 67:6-8 (Dan Scripps) (``Specifically, there may be an 
opportunity to create a general framework that would be consistent 
across RTO seams.''); id. 68:12-18 (Ted Thomas) (agreeing with Chair 
Scripps that ``the most effective place that FERC can operate is in 
the area where you have two RTOs and the real issue is getting them 
on the same page'')).
    \1980\ Id. (citing May Joint Task Force Tr. 67:14-17 (Dan 
Scripps) (``[W]e expect the affected systems study process to become 
increasingly critical as more renewable resources come online in 
renewable rich areas and transmission capacity becomes ever more 
scarce.'')).
    \1981\ Id. P 180 (referencing May Joint Task Force Tr. 64:18-24 
(Dan Scripps) (stating that ``FERC may have a larger role to play in 
issues that cross RTO boundaries, particularly, around cross-RTO 
affected system studies where individual RTOs have limited control'' 
and certainty ``around the timing of affected systems studies'')).
---------------------------------------------------------------------------

    1027. The Commission noted that, currently, detailed information 
about any two transmission providers' affected system study processes 
is found in multiple transmission provider documents and is not 
necessarily cohesive, which appears to create confusion and 
uncertainty.\1982\ The Commission further preliminarily found that, 
despite these documents, much of the affected system study process is 
ad hoc and, therefore, unclear to interconnection customers. In 
addition, the Commission explained that affected system study processes 
are highly variable based on region and transmission provider, and they 
may not be uniform even across a single transmission provider's 
footprint.
---------------------------------------------------------------------------

    \1982\ Id. P 181.
---------------------------------------------------------------------------

    1028. The Commission preliminarily found that the lack of an 
affected system study process results in Commission-jurisdictional 
rates that are unjust and unreasonable because an interconnection 
customer cannot evaluate its costs in a timely manner, which increases 
uncertainty and may result in late-stage withdrawals and subsequent 
restudies, delays, and increased costs to the remaining interconnection 
customers in the interconnection queue.\1983\ The Commission stated 
that, without a transparent affected system study process, it appears 
that neither an interconnection customer nor the Commission can 
evaluate whether the affected system operator has acted in an unduly 
discriminatory manner. The Commission further stated that reforms to 
improve transparency and coordination, therefore, may be necessary to 
establish a just, reasonable, and not unduly discriminatory or 
preferential affected system study process.
---------------------------------------------------------------------------

    \1983\ Id. P 182.
---------------------------------------------------------------------------

ii. Comments
    1029. Multiple commenters generally support action to address the 
Commission's identified need to reform affected system study 
processes.\1984\ For example, AEE asserts that existing affected system 
study processes are plagued by uncertainty and a lack of transparency, 
which, in turn, create delays, interconnection queue withdrawals, and 
cost increases.\1985\ Invenergy, Enel, and SEIA assert that current 
misalignments in and lack of coordination of affected system study 
processes can lead to uncertain, duplicative, or unexpected study 
results.\1986\ Some commenters support synchronization and 
harmonization of affected system study processes, with NextEra alleging 
that study processes across several regions lack transparency, 
consistency, coordination, and accountability, which results in errors 
and delays.\1987\ Similarly, Google contends that current affected 
system study processes lack deadlines or structure, which exacerbates 
anticipating interconnection costs and, in turn, stifles 
investments.\1988\ National Grid asserts that host transmission system 
and affected system study processes can be significantly misaligned 
with project development, investment, and financing timelines and 
decision points, resulting in unmanageable risk for interconnection 
customers.\1989\
---------------------------------------------------------------------------

    \1984\ ACE-NY Initial Comments at 8-9; AEE Initial Comments at 
34-35; Enel Initial Comments at 58; Google Initial Comments at 5-6, 
22; Invenergy Initial Comments at 40; Omaha Public Power Initial 
Comments at 12; SEIA Initial Comments at 34-35; Shell Initial 
Comments at 30.
    \1985\ AEE Initial Comments at 34-35; see also ELCON Initial 
Comments at 7; SEIA Initial Comments at 34-35; Shell Initial 
Comments at 30.
    \1986\ Enel Initial Comments at 58; Invenergy Initial Comments 
at 40; SEIA Initial Comments at 34-35. Invenergy states that many 
commenters acknowledge the need for improvements to current affected 
system study processes. Invenergy Reply Comments at 7-8.
    \1987\ APS Initial Comments at 19; ELCON Initial Comments at 7; 
NextEra Initial Comments at 31-32; NextEra Reply Comments at 4; 
Omaha Public Power Initial Comments at 12.
    \1988\ Google Initial Comments at 5-6, 22; U.S. Chamber of 
Commerce Initial Comments at 10-11.
    \1989\ National Grid Initial Comments at 35.
---------------------------------------------------------------------------

    1030. Several commenters highlight the shortcomings of current pro 
forma LGIP requirements and their contribution to affected system study 
process problems.\1990\ ACE-NY emphasizes that nothing in the pro forma 
LGIP binds the affected system

[[Page 61159]]

study process, and, as a result, interconnection customers are open to 
significant impacts and unreasonable timelines.\1991\ OMS highlights 
the limited control that RTOs/ISOs have regarding the timing of 
affected system studies.\1992\ NYISO and Ameren assert that more 
specific requirements regarding roles and responsibilities of parties 
in the affected system study process are needed.\1993\ According to 
Invenergy, the Commission has until now declined to impose any 
organized structure around the affected system study process because 
affected system network upgrades and associated costs were thought to 
be a relatively rare occurrence.\1994\ Invenergy contends that this has 
resulted in transmission providers conducting studies using variable 
study assumptions and standards and assigning significant system 
upgrade costs at any time, even after an interconnecting generating 
facility is already in operation.
---------------------------------------------------------------------------

    \1990\ See, e.g., Clean Energy Associations Initial Comments at 
47-48; UMPA Initial Comments at 5-6.
    \1991\ ACE-NY Initial Comments at 9.
    \1992\ OMS Initial Comments at 16; see also PJM Reply Comments 
at 10 (arguing that an RTO/ISO has no authority to compel other 
RTOs/ISOs to complete interconnection studies on its deadline).
    \1993\ Ameren Initial Comments at 22; NYISO Initial Comments at 
44.
    \1994\ Invenergy Initial Comments at 39 (citing Order No. 2003, 
104 FERC ] 61,103 at P 120).
---------------------------------------------------------------------------

    1031. On the other hand, several commenters doubt whether 
standardization of affected system study processes is warranted and 
argue that adopting the NOPR proposal will cause timeline problems and 
delays.\1995\ SDG&E contends that, based on its experience, affected 
system studies infrequently trigger the need for construction of new 
network upgrades, and thus it does not find the current process 
deficient.\1996\ AECI states that its current coordination process is 
not in need of reform because it effectively coordinates with several 
affected systems and recognizes the unique situations presented at 
different seams.\1997\
---------------------------------------------------------------------------

    \1995\ Dominion Initial Comments at 36-37; PJM Initial Comments 
at 63; SPP Initial Comments at 17; WAPA Initial Comments at 10.
    \1996\ SDG&E Reply Comments at 3.
    \1997\ AECI Initial Comments at 6.
---------------------------------------------------------------------------

iii. Commission Determination
    1032. We affirm the Commission's preliminary findings in the NOPR 
that there is a compelling need for affected system study process 
reforms. The record demonstrates that, absent reforms, affected system 
studies will likely remain ad hoc, continuing to create and increase 
delays in the interconnection process, which leads to increased costs 
for both interconnection customers and consumers, thereby failing to 
ensure just and reasonable rates. As discussed by commenters, the 
existing affected system study processes lack certainty and 
transparency, which, in turn, create interconnection queue delays, 
interconnection customer withdrawals, and cost increases.\1998\ 
Affected system study delays continue to be a major reason for 
interconnection queue delays.\1999\ We concur with commenters that 
better coordination and more specific requirements concerning the role 
and responsibilities of affected system transmission providers are 
required to address the lack of certainty and transparency.\2000\ 
Additionally, we agree with commenters that affected system study 
process reforms will ensure that interconnection customers are able to 
connect in a reliable, efficient, transparent, and timely manner.\2001\ 
We are unpersuaded by comments that standardizing the affected system 
study process will result in timeline problems and delays; \2002\ we 
find such claims to be speculative and contrary to the Commission's 
experience with standardizing host transmission provider study 
processes via the pro forma LGIP.\2003\ We discuss specific aspects of 
the affected system-related NOPR proposals and final rule 
determinations below.
---------------------------------------------------------------------------

    \1998\ AEE Initial Comments at 34-35; ELCON Initial Comments at 
7; SEIA Initial Comments at 34-35; Shell Initial Comments at 30.
    \1999\ See MISO, Informational Report Regarding Interconnection 
Study Delay for 4th Quarter 2022, Docket No. ER19-1960-004, attach. 
A at 8 (filed Feb. 14, 2023).
    \2000\ Ameren Initial Comments at 22; NYISO Initial Comments at 
44.
    \2001\ MISO Initial Comments at 8 n.20, 12.
    \2002\ Dominion Initial Comments at 36-37; PJM Initial Comments 
at 63; SPP Initial Comments at 17; WAPA Initial Comments at 10.
    \2003\ See Order No. 2003, 104 FERC ] 61,103 at PP 10-12; Order 
No. 845, 163 FERC ] 61,043 at PP 4, 8, 39, 221, 239, 559.
---------------------------------------------------------------------------

    1033. In this final rule, an affected system transmission provider 
refers to a public utility transmission provider as the Commission does 
not have jurisdiction over the rates, terms, or conditions of service 
of non-public utility transmission providers. Thus, the requirements 
adopted in this final rule pertaining to affected system transmission 
providers are limited to public utility transmission providers.
b. Affected System Study Process
i. NOPR Proposal
    1034. In the NOPR, the Commission proposed to revise the pro forma 
LGIP to include an affected system study process.\2004\ The proposed 
process includes an initial notification, an affected system scoping 
meeting, a study process, the establishment of interconnection queue 
priority for the purposes of network upgrade cost allocation, the 
presentation of study results and an assessment of those results, and 
imposition of penalties if an affected system transmission provider 
fails to meet a study deadline. The Commission also proposed to add 
several definitions to the pro forma LGIP, including ``affected system 
interconnection customer,'' ``affected system network upgrade,'' 
``affected system scoping meeting,'' and ``affected system study.''
---------------------------------------------------------------------------

    \2004\ NOPR, 179 FERC ] 61,194 at P 183.
---------------------------------------------------------------------------

    1035. The Commission proposed to require that the host transmission 
provider notify the affected system operator of a potential affected 
system impact caused by an interconnection request within 10 business 
days after the close of the first event giving rise to the 
identification of an affected system impact.\2005\ The Commission 
explained that, for host transmission providers using a cluster study 
process, this event could be (1) the cluster request window, (2) the 
customer engagement window, (3) the cluster study, or (4) the cluster 
restudy as part of the first-ready, first-served cluster study process. 
At the same time that the host transmission provider notifies the 
affected system operator, the Commission proposed to require the host 
transmission provider to provide the interconnection customer with a 
list of potential affected systems, along with relevant contact 
information. The Commission also proposed to require the host 
transmission provider to provide the affected system operator with data 
on a monthly basis, or more frequently as needed, about its 
transmission system and generation in its interconnection queue for the 
duration of the affected system study process.
---------------------------------------------------------------------------

    \2005\ Id. P 184.
---------------------------------------------------------------------------

    1036. The Commission proposed several requirements on transmission 
providers acting as an affected system operator, whose transmission 
systems may be impacted by the proposed interconnection of a generating 
facility to a transmission system other than the transmission 
provider's transmission system.\2006\ The Commission proposed to 
require the affected system transmission provider, within 15 business 
days of receiving notification from the host transmission provider of 
an impact on its transmission system, to respond in writing indicating 
whether it intends to perform an affected system study.
---------------------------------------------------------------------------

    \2006\ Id. P 185.

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[[Page 61160]]

    1037. The Commission proposed to require that the affected system 
transmission provider schedule an affected system scoping meeting 
within seven business days after providing written notification that it 
intends to conduct an affected system study.\2007\ The Commission also 
proposed to require that the affected system scoping meeting be held 
within seven business days after it is scheduled. The Commission 
further proposed to require that the affected system transmission 
provider include the affected system interconnection customer in the 
scoping meeting and use best efforts to include the transmission 
provider with whom interconnection has been requested. The Commission 
proposed to require the affected system transmission provider to share 
the schedule to complete the affected system study with all scoping 
meeting attendees within 15 business days after the close of the 
scoping meeting.
---------------------------------------------------------------------------

    \2007\ Id. P 186.
---------------------------------------------------------------------------

    1038. The Commission proposed to require that the affected system 
transmission provider tender an affected system study agreement to the 
affected system interconnection customer within five business days of 
sharing the schedule for the affected system study.\2008\ The 
Commission also proposed to require the affected system interconnection 
customer to return the executed affected system study agreement within 
10 business days of receipt.
---------------------------------------------------------------------------

    \2008\ Id. P 188.
---------------------------------------------------------------------------

    1039. The Commission proposed to require the affected system 
transmission provider to use what it referred to as a ``first-ready, 
first-served interconnection queue priority approach,'' which would 
also determine how affected system network upgrade costs will be 
allocated by that transmission provider amongst interconnection 
customers in separate transmission systems.\2009\ Specifically, the 
Commission explained, in some situations, both affected system 
interconnection customers and interconnection customers on the 
transmission system of the affected system transmission provider cause 
the need for affected system network upgrades; in this case, each 
interconnection customer's relative interconnection queue priority must 
be determined. The NOPR's proposed first-ready, first-served 
interconnection queue priority approach would require the affected 
system transmission provider to assign the affected system 
interconnection customer a queue position in its interconnection queue 
according to when the affected system interconnection customer executes 
an affected system study agreement, rather than when the affected 
system interconnection customer entered its host transmission 
provider's interconnection queue. The Commission explained that such a 
position would be equivalent to that of a transmission provider's own 
interconnection customer that had just received its cluster study 
report. The Commission also proposed to require the affected system 
transmission provider to allocate network upgrade costs among equally 
queued interconnection customers using a proportional impact method.
---------------------------------------------------------------------------

    \2009\ Id. P 189.
---------------------------------------------------------------------------

    1040. The Commission proposed that the affected system transmission 
provider must provide the affected system interconnection customer with 
affected system study results within 90 calendar days after the receipt 
of the executed affected system study agreement.\2010\ The Commission 
proposed to require that the affected system transmission provider 
include in the study results both the estimated costs for any network 
upgrades identified in the study and the timing for the construction of 
those network upgrades.
---------------------------------------------------------------------------

    \2010\ Id. P 190.
---------------------------------------------------------------------------

    1041. The Commission proposed to require that the affected system 
transmission provider provide the affected system interconnection 
customer with an affected system facilities construction agreement 
within 30 calendar days after providing the affected system study 
results.\2011\ The Commission proposed that the affected system 
interconnection customer would then be required to notify the affected 
system transmission provider within five business days of executing the 
generator interconnection agreement with its host transmission provider 
whether it would like to execute the affected system facilities 
construction agreement or request that it be filed unexecuted with the 
Commission. The Commission proposed that the affected system 
transmission provider would then be required to execute, or file 
unexecuted, the affected system facilities construction agreement 
within five business days after receiving such direction from the 
affected system interconnection customer.
---------------------------------------------------------------------------

    \2011\ Id. P 191.
---------------------------------------------------------------------------

    1042. The Commission proposed to impose financial penalties on 
affected system transmission providers that fail to timely complete 
affected system studies.\2012\ The Commission explained that a host 
transmission provider would not be penalized for a late affected system 
study and did not require a host transmission provider to wait on the 
results of an affected system study to conduct its cluster study, so 
that any affected system study delay would not delay such a cluster 
study. The Commission clarified that the affected system transmission 
provider was the only entity that would be penalized for failure to 
timely complete an affected system study.
---------------------------------------------------------------------------

    \2012\ Id. P 192.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1043. Multiple commenters support the NOPR proposal to create a 
standardized affected system study process in the pro forma LGIP.\2013\ 
Consumers Energy asserts that standardization and better 
synchronization of timelines and processes between transmission 
providers will improve the interconnection process,\2014\ and in 
ACORE's opinion, will help to prevent the use of potentially unjust, 
unreasonable, and unduly discriminatory or preferential ad hoc 
approaches.\2015\
---------------------------------------------------------------------------

    \2013\ ACE-NY Initial Comments at 8-9; AEE Initial Comments at 
34-35; AEP Initial Comments at 31; AES Initial Comments at 21; APPA-
LPPC Initial Comments at 23; CREA and NewSun Initial Comments at 86; 
Duke Southeast Utilities Initial Comments at 12; EDF Renewables 
Initial Comments at 10; ELCON Initial Comments at 7; Enel Initial 
Comments at 2, 57; ENGIE Initial Comments at 8; Fervo Energy Initial 
Comments at 6; Google Initial Comments at 5-6; Idaho Power Initial 
Comments at 11; NextEra Initial Comments at 31; Ohio Commission 
Consumer Advocate Initial Comments at 13; PacifiCorp Initial 
Comments at 36; Pattern Energy Initial Comments at 24; Pine Gate 
Initial Comments at 41; PPL Initial Comments at 19; SEIA Initial 
Comments at 34; Shell Initial Comments at 29.
    \2014\ Consumers Energy Initial Comments at 8; see also Clean 
Energy Associations Initial Comments at 47-48; Illinois Commission 
Initial Comments at 9; CREA and NewSun Initial Comments at 86-87; 
ENGIE Initial Comments at 8; U.S. Chamber of Commerce Initial 
Comments at 10-11.
    \2015\ ACORE Initial Comments at 4-5; see also EDF Renewables 
Initial Comments at 11; Invenergy Initial Comments at 41.
---------------------------------------------------------------------------

    1044. Multiple commenters support most or all of the proposed 
reforms.\2016\ Pine Gate strongly supports the NOPR proposal's 
definitive deadlines for affected system study completion and 
associated incentives, arguing that consistent, published criteria will 
help determine whether an affected system study is needed and will 
provide interconnection customers with the opportunity to conduct their 
own engineering analyses applying the criteria in order to better 
determine suitable locations for prospective

[[Page 61161]]

generating facilities.\2017\ AEP supports the deadlines related to 
initiating the affected system study process, stating that deadlines 
would help to provide transparency and ensure that the process is 
initiated in a timely fashion.\2018\ Interwest, National Grid, and 
Invenergy support the proposal to standardize the affected system study 
engagement and participation process, asserting that the reforms are a 
significant improvement over the status quo.\2019\
---------------------------------------------------------------------------

    \2016\ ACE-NY Initial Comments at 9; Google Initial Comments at 
23; Pine Gate Initial Comments at 42.
    \2017\ Pine Gate Initial Comments at 42-43; see also ENGIE 
Initial Comments at 9-10.
    \2018\ AEP Initial Comments at 31.
    \2019\ Interwest Reply Comments at 16-17; Invenergy Initial 
Comments at 40; National Grid Initial Comments at 35.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1045. Multiple commenters oppose the NOPR's affected system study 
process proposal.\2020\ Some commenters assert that the proposed 
process will impose arbitrary and strict deadlines and will be 
unworkable.\2021\ Dominion and SDG&E assert that timing for affected 
system studies should not be standardized because the necessary study 
assumptions depend on timing of studies in the cluster study 
process.\2022\ Dominion contends that, if an affected system study is 
performed too early, modeling assumptions may not yield meaningful 
results, resulting in incorrect cost estimates likely to cause 
restudies and late-stage withdrawals.\2023\ PJM argues that studying 
affected system interconnection requests before all studies have been 
completed, or studying them for ERIS, could cause operational problems, 
require curtailment, or lead to late-stage withdrawals after the full 
scope of necessary network upgrades is known.\2024\ Similarly, SPP 
states that, because the NOPR proposal does not prescribe any 
particular level of precision for the cost and timing estimates 
associated with affected system upgrades, the results received by the 
interconnection customer could lack sufficient detail and lead to 
higher-than-anticipated costs.\2025\
---------------------------------------------------------------------------

    \2020\ Dominion Initial Comments at 36-37; National Grid Initial 
Comments at 37; NextEra Initial Comments at 32; NextEra Reply 
Comments at 4; North Carolina Commission and Staff Initial Comments 
at 24; Pacific Northwest Utilities Initial Comments at 15; PJM 
Initial Comments at 63-64; SDG&E Reply Comments at 3; SPP Initial 
Comments at 17; WAPA Initial Comments at 10-11.
    \2021\ Dominion Initial Comments at 37; NextEra Initial Comments 
at 32; NextEra Reply Comments at 4; PJM Initial Comments at 63; 
SDG&E Reply Comments at 3.
    \2022\ Dominion Initial Comments at 36-37; SDG&E Reply Comments 
at 3.
    \2023\ Dominion Initial Comments at 37.
    \2024\ PJM Initial Comments at 64.
    \2025\ SPP Initial Comments at 17.
---------------------------------------------------------------------------

    1046. Several commenters argue that certain elements of the NOPR 
proposal do not achieve the goal of increased efficiency.\2026\ 
Recognizing that affected system studies require separate case 
preparations and a greater level of coordination between parties, SDG&E 
agrees with CAISO that the proposal has the potential to increase the 
number of affected system studies, with limited benefit.\2027\ National 
Grid cautions that standardizing the affected system study process will 
necessitate host and affected system transmission providers to devote 
more resources to that process, which could cause delays.\2028\ PJM 
contends that, although the NOPR proposal provides that transmission 
providers conducting cluster studies are not required to delay those 
studies by waiting for the results of affected system studies, such 
delays will be inevitable under the proposed process due to the 
additional steps and coordination required and the overlap in personnel 
and deadlines.\2029\ PJM and National Grid both express concerns 
regarding the justness and reasonableness of the NOPR's penalty regime 
given the potential for additional delays in affected system 
studies.\2030\
---------------------------------------------------------------------------

    \2026\ Id.; CAISO Initial Comments at 28; Dominion Initial 
Comments at 36-37; National Grid Initial Comments at 37; PJM Initial 
Comments at 63; SDG&E Reply Comments at 3; WAPA Initial Comments at 
10.
    \2027\ SDG&E Reply Comments at 3.
    \2028\ National Grid Initial Comments at 37.
    \2029\ PJM Initial Comments at 63.
    \2030\ Id.; National Grid Initial Comments at 37.
---------------------------------------------------------------------------

    1047. Other commenters argue that the NOPR proposal does not go far 
enough to improve efficiency in the affected system study process. 
North Carolina Commission and Staff call for more comprehensive 
reforms, recognizing the need for coordination between transmission 
providers to avoid unnecessary expense and system disruption.\2031\ 
WAPA recommends that the Commission consider an alternative strategy in 
which the host transmission provider includes contingencies and 
sensitivity scenarios involving potentially affected systems in its own 
studies.\2032\ PJM suggests that, rather than the NOPR's ``overly 
prescriptive'' approach, the Commission should require a stated 
affected system coordination structure with defined steps and 
checkpoints, similar to the process PJM has been working to implement 
with neighboring systems through its joint operating agreements.\2033\
---------------------------------------------------------------------------

    \2031\ North Carolina Commission and Staff Initial Comments at 
24.
    \2032\ WAPA Initial Comments at 10-11.
    \2033\ PJM Initial Comments at 64.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) Definitions
    1048. PPL argues that the proposed term ``affected system 
interconnection customer'' is confusing and recommends that the 
Commission either remove ``interconnection'' or consider the term 
``direct connect system customer,'' asserting that the affected system 
interconnection customers are not interconnection customers working 
their way through the affected system transmission provider's 
interconnection process.\2034\ PPL states that some transmission 
providers combine interconnection and transmission and argues that 
removing the word ``interconnection'' better accommodates such a 
combined group.
---------------------------------------------------------------------------

    \2034\ PPL Initial Comments at 19-20.
---------------------------------------------------------------------------

    1049. Several commenters ask for clarification or modification of 
the terms ``affected system'' or ``affected system operator.'' National 
Grid asserts that the Commission should clarify whether an affected 
system solely includes transmission owners in each region or also 
includes neighboring RTOs/ISOs or transmission providers in neighboring 
regions.\2035\ NRECA requests that the Commission clarify the scope of 
several definitions so that transmission providers will not overlook a 
proposed interconnection request's impact on an electric cooperative's 
affected system.\2036\
---------------------------------------------------------------------------

    \2035\ National Grid Initial Comments at 35.
    \2036\ NRECA Initial Comments at 9, 36-39. More specifically, 
NRECA contends that because some transmission providers interpret 
the definition of ``Affected System'' to mean a Commission-
jurisdictional transmission system and refuse to recognize that 
other electric systems may be affected systems, under the pro forma 
LGIP and pro forma LGIA, the Commission should provide that an 
``Affected System'' means any affected ``electric system,'' not just 
an affected ``Transmission System,'' and that an ``Affected System 
Operator'' means any ``entity that operates an Affected System,'' 
not just a transmission owner or transmission provider. Id. at 36-
37, 39.
---------------------------------------------------------------------------

(2) Notification of Affected System Impacts
    1050. Regarding the proposed triggering event at the close of (1) 
the cluster request window, (2) the customer engagement window, (3) the 
cluster study, or (4) the cluster restudy for a host transmission 
provider to notify an affected system operator, PacifiCorp argues that 
the 10-business day notification obligation begins with an ill-defined 
standard in the NOPR--the ``close of first event giving rise to the 
identification of an affected system

[[Page 61162]]

impact.'' \2037\ PacifiCorp requests that the Commission clarify this 
standard and further clarify that transmission providers will not be 
penalized if affected system issues are not discovered until later in 
the interconnection process, as such impacts may not always be readily 
apparent.
---------------------------------------------------------------------------

    \2037\ PacifiCorp Initial Comments at 36.
---------------------------------------------------------------------------

    1051. Some commenters oppose the proposed requirement in section 
3.6.1 of the pro forma LGIP that a host transmission provider, within 
10 business days of the triggering event that identifies a potential 
affected system impact, notify an affected system operator of such 
potential impact.\2038\ WAPA states that the initial notification 
requirement could unnecessarily increase costs because the notification 
could be received before the system impact study on the host 
transmission provider's transmission system is complete and thus before 
any potential network upgrades are identified. Duke Southeast Utilities 
assert that the notification time frame should be 15 business days 
because: (1) the host transmission provider may need additional time to 
notify multiple affected system operators of a potential impact within 
the same prescribed time frame; and (2) the host transmission provider 
may need additional time to gather all necessary information and 
compile adequate notification packages, due to the need to include a 
technical basis for the affected system impact.\2039\ CAISO states that 
the Commission should require transmission providers to begin the 
notification process shortly after interconnection customers receive 
their initial study results and face higher financial requirements to 
proceed in the interconnection queue.\2040\ CAISO explains that this is 
when the majority of interconnection customers withdraw their 
interconnection requests because they do not wish to put more money at 
risk. CAISO argues that using this smaller pool of interconnection 
requests will enable faster affected system studies due to decreased 
volume and more realistic study assumptions.
---------------------------------------------------------------------------

    \2038\ Id.; CAISO Initial Comments at 27; Duke Southeast 
Utilities Initial Comments at 12; PG&E Reply Comments at 5; WAPA 
Initial Comments at 11.
    \2039\ Duke Southeast Utilities Initial Comments at 12.
    \2040\ CAISO Initial Comments at 29.
---------------------------------------------------------------------------

    1052. A few commenters provide suggestions on the content of the 
notice that the host transmission provider sends to the affected system 
operator. Specifically, APPA-LPPC propose that pro forma LGIP section 
3.6.1 be revised to include the following: ``Along with notification to 
Interconnection Customer of the list of potential Affected Systems, 
Transmission Provider will notify Interconnection Customer and such 
Affected Systems whether a single set of studies (Feasibility, System 
Impact and Facilities Studies) may be sufficient to manage all related 
impacts. A single set of studies may be undertaken upon agreement of 
all parties.'' \2041\ Duke Southeast Utilities suggest that, in 
addition to such notification, the host transmission provider should 
provide evidence of the potential impact, which they assert will assist 
the affected system operator in: (1) understanding the host 
transmission provider's engineering analysis and assumptions that led 
it to identify the potential impact; and (2) determining whether to 
conduct an affected system study.\2042\
---------------------------------------------------------------------------

    \2041\ APPA-LPPC Initial Comments at 25-26.
    \2042\ Duke Southeast Utilities Initial Comments at 13.
---------------------------------------------------------------------------

    1053. Regarding to whom the host transmission provider should send 
the notification, NRECA argues that the notification requirement should 
extend to all potential affected systems and any affected system 
operators to allow electric cooperative affected system transmission 
providers to coordinate with the transmission provider and 
interconnection customer to timely address any affected system 
impacts.\2043\ Tri-State states that pro forma LGIP section 3.6.1 needs 
clarification as to whom the notice is to be directed.\2044\
---------------------------------------------------------------------------

    \2043\ NRECA Initial Comments at 38-39.
    \2044\ Tri-State Initial Comments at 28.
---------------------------------------------------------------------------

    1054. Other commenters oppose the proposed requirement in sections 
3.6.2 and 9 of the pro forma LGIP that affected system transmission 
providers must respond to the notification of affected system impacts 
within 15 business days.\2045\ Bonneville advocates that the response 
time be flexible and allow for reasonable extensions.\2046\ Bonneville 
argues that, if affected system transmission providers only have 15 
business days to respond, they will need to err on the side of caution, 
which could lead to more affected system studies than necessary, 
resulting in study delays. Duke Southeast Utilities assert that the 
response time frame should be 20 business days, as the affected system 
transmission provider may need additional time if: (1) it has received 
multiple notifications within the same time frame; (2) it needs to 
request additional data to determine if it intends to perform a study; 
(3) its own staff is limited because of deadlines within its own 
interconnection process; or (4) it wishes to perform a more detailed 
review to ensure that performing a study does not become the default 
approach.\2047\ Dominion asserts that a 15-business day requirement 
could be reasonable if all affected system notifications were provided 
at the same time.\2048\ Dominion contends that piecemeal notifications 
make it difficult for an affected system transmission provider to know 
if an affected system study is needed until all requests are received.
---------------------------------------------------------------------------

    \2045\ Bonneville Initial Comments at 18; CAISO Initial Comments 
at 27; PG&E Reply Comments at 5; WAPA Initial Comments at 11.
    \2046\ Bonneville Initial Comments at 18.
    \2047\ Duke Southeast Utilities Initial Comments at 13 (noting 
that PJM often sends notice of multiple potential impacts from a 
single cluster).
    \2048\ Dominion Initial Comments at 37-38.
---------------------------------------------------------------------------

    1055. Additionally, a few commenters contend that the NOPR proposal 
was unclear what would happen if an affected system operator fails to 
respond within 15 business days. Enel and ENGIE contend that it is 
unclear what the consequence is for an affected system transmission 
provider's failure to meet the response deadline.\2049\ Enel encourages 
the Commission to add language to the pro forma LGIP to provide that 
the affected system transmission provider will forfeit its right to 
perform an affected system study if it fails to meet the response 
deadline, as a lack of incentive (and relevant penalty) to respond 
could result in delayed study results.\2050\ ENGIE suggests that the 
affected system transmission provider bear any financial 
consequences.\2051\ Pacific Northwest Utilities note that the non-
jurisdictional affected system operator is not required to respond to 
the requirements under proposed pro forma LGIP section 3.6.1 and may 
not have the mechanisms in place to respond within 15 business 
days.\2052\
---------------------------------------------------------------------------

    \2049\ Enel Initial Comments at 59-60; ENGIE Initial Comments at 
8.
    \2050\ Enel Initial Comments at 59-60; see also Invenergy 
Initial Comments at 42-44.
    \2051\ ENGIE Initial Comments at 8.
    \2052\ Pacific Northwest Utilities Initial Comments at 17.
---------------------------------------------------------------------------

(3) Timing of Affected System Studies
    1056. Several commenters argue that beginning affected system 
studies too early may yield unreliable results that could lead to 
restudies and late-stage withdrawals, among other problems.\2053\ 
NextEra asserts that it is unlikely that the host transmission provider 
could provide useful information to the

[[Page 61163]]

affected system transmission provider at an earlier stage.\2054\ CAISO 
and Idaho Power argue that the proposal to begin the affected system 
study process as soon as potential impacts are identified will slow 
affected system studies or result in unnecessary work for the affected 
system transmission provider because the impacts will be assessed based 
on transmission providers' entire interconnection queues, even though 
many interconnection customers will withdraw early in the 
interconnection process.\2055\
---------------------------------------------------------------------------

    \2053\ CAISO Initial Comments at 28-29; Dominion Initial 
Comments at 37; Enel Initial Comments at 59; Idaho Power Initial 
Comments at 11; NextEra Initial Comments at 32-33; WAPA Initial 
Comments at 11-12.
    \2054\ NextEra Initial Comments at 32-33.
    \2055\ CAISO Initial Comments at 28-29; Idaho Power Initial 
Comments at 11.
---------------------------------------------------------------------------

    1057. CAISO takes issue with the proposed deadlines for completing 
affected system studies and claims that the size of modern 
interconnection queues makes such quick deadlines impossible. According 
to CAISO, such deadlines would result in all affected system 
transmission providers exercising their rights to study every 
interconnection customer because they have no time to determine whether 
studies are necessary.\2056\
---------------------------------------------------------------------------

    \2056\ CAISO Initial Comments at 27-28.
---------------------------------------------------------------------------

    1058. Invenergy argues that affected system transmission providers 
should be subject to a deadline for participation in the process.\2057\
---------------------------------------------------------------------------

    \2057\ Invenergy Initial Comments at 41.
---------------------------------------------------------------------------

    1059. Invenergy asserts that, although the NOPR clearly provides 
that a host transmission provider is not required to pause its 
interconnection process if an affected system transmission provider 
does not timely complete its study, the reality is that this could 
leave interconnection customers in the same position they are in now--
being forced under the host transmission provider's timeline to move 
forward in the study process and to execute an LGIA (and put money at 
risk) without the benefit of affected system study results. Invenergy 
contends that the solution is to establish a clear deadline (e.g., LGIA 
execution) by which time the affected system transmission provider must 
have completed its studies and identified affected system network 
upgrades; otherwise, it loses any right to assign affected system 
network upgrades to an interconnection request in the future. Invenergy 
states that, if the Commission does not impose such a deadline, it 
should at least permit interconnection customers that have been forced 
under host transmission provider's rules to execute LGIAs in the 
absence of affected system study information to: (1) delay posting 
security and funding network upgrades under that LGIA until the 
affected system study results are received; and (2) have the 
opportunity to withdraw without penalty after receiving affected system 
study results if the interconnection customer's assigned costs 
increased by more than 25% compared to costs allocated by the host 
transmission provider.\2058\
---------------------------------------------------------------------------

    \2058\ Id. at 25, 43-44.
---------------------------------------------------------------------------

    1060. Several commenters argue that an affected system study 
timeline should be consistent with the cluster study process on the 
host transmission provider's transmission system because it can impact 
the host transmission provider's study.\2059\ APS requests additional 
clarification on how the proposed affected system study process 
correlates to the host system studies and aligns with the host system's 
requirements.\2060\ Enel acknowledges that the 90-calendar day affected 
system study deadline may be problematic for transmission providers 
that have 150 calendar days to run the same scope of studies for their 
own interconnection requests.\2061\ AEP stresses the need for 
coordination between these studies, which it argues would provide the 
interconnection customer with a more meaningful cost estimate, with 
coordination resulting in affected system and host system study results 
being presented around the same time.\2062\ Enel contends that the 
affected system transmission provider should be required to complete 
any affected system impact studies no later than the host transmission 
provider's deadline to complete the cluster restudy.\2063\ Enel asserts 
that this initial affected system study should be completed before the 
interconnection customer must satisfy requirements to enter the 
facilities study, at which point the interconnection customer faces a 
higher withdrawal penalty. Enel contends that the NOPR proposal could 
result in an affected system transmission provider being notified that 
an affected system study is needed after final results of the cluster 
restudy are complete, meaning that an affected system study may not be 
completed until or even after the execution of an LGIA. Enel argues 
that, after affected system studies are complete, an interconnection 
customer could have its costs double just before (or even after) an 
LGIA is executed, and penalty-free withdrawal under proposed pro forma 
LGIP section 3.7.1 would only apply if assigned interconnection costs 
increase by more than 100%.
---------------------------------------------------------------------------

    \2059\ APPA-LPPC Initial Comments at 26; AEP Initial Comments at 
31; Bonneville Initial Comments at 21; NV Energy Initial Comments at 
11.
    \2060\ APS Initial Comments at 19-20.
    \2061\ Enel Initial Comments at 65.
    \2062\ AEP Initial Comments at 31-32.
    \2063\ Enel Initial Comments at 58.
---------------------------------------------------------------------------

    1061. Several commenters argue that the timing of affected system 
studies should be structured to reduce potential burdens. Idaho Power 
suggests that affected system studies be performed after the initial 
cluster study to minimize unnecessary work and ensure that only 
interconnection requests moving into the cluster restudy have their 
affected system impacts studied.\2064\ Dominion notes that PJM recently 
sought to address timing issues by incorporating affected system 
studies into later phases of its cluster studies.\2065\
---------------------------------------------------------------------------

    \2064\ Idaho Power Initial Comments at 11.
    \2065\ Dominion Initial Comments at 37 (citing PJM 
Interconnection, L.L.C., Tariff Revisions for Interconnection 
Process Reform Transmittal Letter, Docket No. ER22-2110-000, at 55, 
59-60 (filed June 14, 2022)).
---------------------------------------------------------------------------

(4) Affected System Scoping Meeting
    1062. Several commenters express concern about the proposed 
requirement in section 3.6.2 of the pro forma LGIP that the affected 
system transmission provider (1) schedule an affected system scoping 
meeting within seven business days after providing written notification 
that it intends to conduct an affected system study and (2) hold that 
meeting within seven business days after it is scheduled.\2066\ 
Bonneville and Dominion assert that holding the scoping meeting within 
this time frame might not be realistic because these meetings are 
contingent upon the availability of multiple attendees.\2067\ CAISO 
contends that the proposal to schedule affected system scoping meetings 
within seven business days is impossible and that affected system 
transmission providers would simply hold scoping meetings to comply, 
having had no time to prepare anything meaningful for the 
meeting.\2068\ MISO argues that the Commission should allow each pair 
of transmission providers to develop their own schedule for the scoping 
process rather than mandating a one-size-fits-all schedule.\2069\ MISO 
asserts that this is particularly true for RTOs/ISOs with joint 
operating and/or planning agreements, which MISO claims should

[[Page 61164]]

be able to justify their existing procedures on compliance via the 
independent entity variation standard. Bonneville emphasizes 
flexibility and proposes that the phrase ``unless otherwise agreed to'' 
be added to this requirement.\2070\
---------------------------------------------------------------------------

    \2066\ Id. at 38; Bonneville Initial Comments at 18-19; CAISO 
Initial Comments at 28; MISO Initial Comments at 86. WAPA also 
asserts that a meeting after the affected system study is completed 
would be more beneficial than the proposed affected system scoping 
meeting, as the proposed meeting would only provide speculative 
impacts that might be caused by an interconnection request. WAPA 
Initial Comments at 12.
    \2067\ Bonneville Initial Comments at 18-19; Dominion Initial 
Comments at 38.
    \2068\ CAISO Initial Comments at 28.
    \2069\ MISO Initial Comments at 86.
    \2070\ Bonneville Initial Comments at 19.
---------------------------------------------------------------------------

    1063. Pacific Northwest Utilities state that, provided that 
regulated utilities properly invite the non-jurisdictional affected 
system transmission provider to the affected system scoping meeting, 
the Commission should clarify that such steps are sufficient to 
demonstrate that the regulated transmission provider has met its 
requirements under this section.\2071\ Further, Pacific Northwest 
Utilities note that the non-jurisdictional affected system transmission 
provider is not required to respond to the requirements under section 
3.6.2 of the pro forma LGIP and may not be prepared to attend the 
affected system scoping meeting.
---------------------------------------------------------------------------

    \2071\ Pacific Northwest Utilities Initial Comments at 17.
---------------------------------------------------------------------------

(5) Affected System Study Process
    1064. Multiple commenters advocate for changes to the proposed 
requirement in section 3.6.3 of the pro forma LGIP that the 
transmission provider provide data monthly, or more frequently as 
needed, regarding the amount and location of generation in the 
transmission provider's interconnection queue, as well as updated 
information about the transmission provider's transmission system. 
NRECA states that the proposed information sharing requirement is 
essential but should not be limited to notifying or providing data to a 
transmission provider acting as an affected system operator but should 
extend to all potential affected systems and any affected system 
operators to allow electric cooperative affected system operators to 
perform studies and coordinate with the transmission provider and 
interconnection customer to timely address any affected system 
impact.\2072\ MISO argues that the Commission should not impose an 
arbitrary time frame for data reports and suggests that such 
information should be provided only at times when it changes.\2073\ 
MISO asserts that updates are not likely to be helpful to 
interconnection customers until the next study stage has been 
completed. NV Energy requests that the Commission move to quarterly 
reporting because monthly updates would not be helpful and may provide 
dramatic swings in study results, which could trigger the need for an 
affected system study to start over.\2074\ NV Energy also requests that 
assumptions for studies be coordinated between the host transmission 
provider and affected system operator and that updates become quarterly 
after the study has been issued.
---------------------------------------------------------------------------

    \2072\ NRECA Initial Comments at 38-39.
    \2073\ MISO Initial Comments at 86.
    \2074\ NV Energy Initial Comments at 12.
---------------------------------------------------------------------------

    1065. LADWP requests clarification as to what specific data 
``updated information about the transmission provider's transmission 
system'' refers.\2075\
---------------------------------------------------------------------------

    \2075\ LADWP Initial Comments at 4 (citing NOPR, 179 FERC ] 
61,194 at P 187).
---------------------------------------------------------------------------

    1066. Bonneville and Dominion argue that the proposed information 
sharing requirement is duplicative or unnecessary. Bonneville posits 
that the requirement is duplicative of information that is already 
available on OASIS.\2076\ Dominion argues that this requirement is 
overly cumbersome given transmission providers' limited resources and 
numerous obligations and may produce data that the affected system may 
not even want or use.\2077\ Dominion asserts that it would be more 
efficient to require the host transmission provider to provide such 
information upon request.
---------------------------------------------------------------------------

    \2076\ Bonneville Initial Comments at 19.
    \2077\ Dominion Initial Comments at 38.
---------------------------------------------------------------------------

(6) Affected System Queue Position
    1067. Several commenters support the NOPR proposal's first-ready, 
first-served interconnection queue priority approach in proposed 
section 9.2 of the pro forma LGIP.\2078\ OMS and MISO argue that MISO 
and SPP's recently approved changes to their joint operating agreement 
to modify the queue priority and coordination rules for affected system 
studies conform to the NOPR's proposed approach and are an equitable 
means for sharing costs for network upgrades amongst interconnection 
customers in different regions and encourages timely processing of 
affected system impacts.\2079\
---------------------------------------------------------------------------

    \2078\ Alliant Energy Initial Comments at 7; EDF Renewables 
Initial Comments at 11; Invenergy Initial Comments at 40; MISO 
Initial Comments at 11-12; NextEra Reply Comments at 5; OMS Initial 
Comments at 17.
    \2079\ MISO Initial Comments at 88; OMS Initial Comments at 17 
(citing Sw. Power Pool, Inc., 179 FERC ] 61,148 (2022)).
---------------------------------------------------------------------------

    1068. However, Bonneville and NextEra assert that the NOPR does not 
adequately address the important issue of queue priority 
coordination.\2080\ NextEra argues that the notion of interconnection 
customers racing to be the first (or perhaps the last) to sign an 
affected system study agreement as a way of setting queue priority will 
result in conflict.\2081\ NextEra contends that, instead, the goal 
should be to ensure that transmission providers acting as affected 
systems perform affected system studies on a timeline that is 
consistent with the host transmission system's stated schedule so that 
results are delivered in a timely manner and interconnection customers 
can be well-informed in their decision making. NextEra recommends that 
each pair of transmission providers whose interconnection customers 
affect each other's system enter into agreements, to be filed with the 
Commission, specifying how they will ensure appropriate queue priority 
in affected system studies.
---------------------------------------------------------------------------

    \2080\ Bonneville Initial Comments at 20; NextEra Reply Comments 
at 5.
    \2081\ NextEra Reply Comments at 5.
---------------------------------------------------------------------------

    1069. Bonneville argues that the queue priority for affected system 
interconnection requests should be determined by giving priority to an 
interconnection request in an affected system study over any 
interconnection request that has not yet started the cluster study on 
the host transmission system.\2082\ Bonneville contends that if an 
affected system interconnection request receives higher queue priority 
relative to any interconnection requests for which the host 
transmission provider has started the cluster study but has not yet 
provided cluster study reports, then such a queue priority framework 
would introduce uncertainty into the cluster study process, as an 
affected system notification could be received during the cluster study 
process and trigger a restudy, delays, and increased costs to the 
participants of the cluster study.
---------------------------------------------------------------------------

    \2082\ Bonneville Initial Comments at 20.
---------------------------------------------------------------------------

    1070. Other commenters argue for different approaches to affected 
system queue priority or allocation of affected system network upgrade 
costs. ENGIE argues that, although assigning an affected system queue 
position appears beneficial for assigning network upgrade costs, it 
could also create delays for the interconnection customer because it 
would be beholden to two separate interconnection queues.\2083\ ENGIE 
recommends that the Commission allocate network upgrade costs outside 
of the interconnection queue on an ex post basis to avoid the double-
queue situation.
---------------------------------------------------------------------------

    \2083\ ENGIE Initial Comments at 9.
---------------------------------------------------------------------------

    1071. Enel asserts that the NOPR's proposed queue priority 
determination method will result in additional uncertainty about timing 
of affected system studies, incomplete and inaccurate cluster study 
results, and the

[[Page 61165]]

need for restudies.\2084\ Although Enel agrees that establishing queue 
priority between host and affected system interconnection requests is 
essential, Enel disagrees with the NOPR proposal to establish the 
affected system interconnection request's queue priority according to 
when the affected system interconnection customer executes an 
``affected system study.'' \2085\ Enel states that this must be a typo 
that should say ``affected system study agreement.'' Enel also notes 
that proposed pro forma LGIP section 9.2 does not clearly state which 
event establishes the date by which an affected system interconnection 
request receives its queue priority relative to host system 
interconnection requests and requests clarification on this 
point.\2086\ Enel further states that, if affected system queue 
priority is established based on an individual date, transmission 
providers would need to process affected system interconnection 
requests serially rather than by cluster and recommends that the 
Commission adopt a queue priority framework in which affected system 
interconnection requests would be studied in the same cluster grouping 
that the host transmission provider uses.\2087\ Enel also recommends 
that queue priority be assigned based on the deadline for entry into 
the host transmission provider's interconnection queue.
---------------------------------------------------------------------------

    \2084\ Enel Initial Comments at 62-63.
    \2085\ Id. at 61.
    \2086\ Id. at 61-62.
    \2087\ Id. at 62-63.
---------------------------------------------------------------------------

    1072. Several commenters request or propose specific clarifications 
regarding proposed pro forma LGIP section 9.2, including how the 
proposed first-ready, first-served interconnection queue priority 
approach interacts with cluster studies.\2088\ EDF Renewables 
recommends that, to better synchronize the host and affected system 
study processes, the affected system operator should establish queue 
priority between the host and affected system based on the 
interconnection request achieving a certain stage in the host system's 
study process, rather than the date the interconnection request was 
submitted.\2089\ APPA-LPPC ask that the Commission clarify proposed pro 
forma LGIP section 9.2 and the related obligations under pro forma LGIP 
sections 9.8 and 4.2.3.\2090\ APPA-LPPC state that, as drafted, 
proposed pro forma LGIP section 9.2 suggests a queue position for an 
interconnection customer independent of ongoing and pending cluster 
studies while pro forma LGIP section 9.8 and cross-referenced pro forma 
LGIP section 4.2.3 contemplate the allocation of associated costs 
incurred by affected systems in the context of a cluster study.
---------------------------------------------------------------------------

    \2088\ APPA-LPPC Initial Comments at 26; Idaho Power Initial 
Comments at 11; NextEra Initial Comments at 33.
    \2089\ EDF Renewables Initial Comments at 11.
    \2090\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------

    1073. Additionally, MISO recommends that the final rule clarify an 
enforcement mechanism, such as loss of relative queue priority used 
under the MISO-SPP joint operating agreement, for the proposed first-
ready, first-served interconnection queue priority approach.\2091\
---------------------------------------------------------------------------

    \2091\ MISO Initial Comments at 89.
---------------------------------------------------------------------------

(7) Affected System Study Agreement
    1074. Dominion and Duke Southeast Utilities suggest doubling the 
amount of time that transmission providers would have under proposed 
pro forma LGIP section 9.3 to tender an affected system study agreement 
after sharing the schedule for the affected system study.\2092\ Duke 
Southeast Utilities assert that it usually takes more than five 
business days to receive all needed interconnection request information 
to draft an affected system study agreement (an often iterative 
process).\2093\ Duke Southeast Utilities state that more time will help 
affected system transmission providers that may need to draft numerous 
affected system study agreements within the same time frame.
---------------------------------------------------------------------------

    \2092\ Dominion Initial Comments at 38; Duke Southeast Utilities 
Initial Comments at 14.
    \2093\ Duke Southeast Utilities Initial Comments at 14.
---------------------------------------------------------------------------

    1075. Bonneville requests clarification as to whether the failure 
to execute the affected system study agreement, execute the affected 
system facilities construction agreement, or provide the affected 
system study deposit would be grounds for removal from the host 
transmission provider's interconnection queue.\2094\
---------------------------------------------------------------------------

    \2094\ Bonneville Initial Comments at 20-21.
---------------------------------------------------------------------------

(8) Affected System Study Scope and Timeline
    1076. Many commenters, including transmission providers, argue that 
the Commission should clarify the scope of required affected system 
studies by addressing whether an affected system facilities study will 
be required under section 9 of the pro forma LGIP.\2095\ For example, 
Duke Southeast Utilities state that the NOPR proposal is unclear on 
whether ``affected system study results'' is intended to reflect the 
results of a system impact study, a facilities study, or a combination 
thereof.\2096\
---------------------------------------------------------------------------

    \2095\ APPA-LPPC Initial Comments at 26; Duke Southeast 
Utilities Initial Comments at 15; Enel Initial Comments at 65; 
Pattern Energy Initial Comments at 24.
    \2096\ Duke Southeast Utilities Initial Comments at 15.
---------------------------------------------------------------------------

    1077. Several commenters request that the Commission explicitly 
include a facilities study in the affected system study process.\2097\ 
Duke Southeast Utilities, Enel, NV Energy, and SPP assert that 
explicitly including a facilities study in the affected system study 
process would provide both affected system transmission provider and 
affected system interconnection customer with more refined estimated 
costs and construction timelines.\2098\ Pattern Energy argues that a 
facilities study is a useful tool for scoping and pricing network 
upgrades and other facilities necessary to mitigate transmission-
related contingencies,\2099\ and LADWP argues that a facilities study 
would improve the efficiency of the overall process by minimizing 
discrepancies discovered after execution of a construction 
agreement.\2100\ APPA-LPPC request that the Commission confirm that it 
does not intend to foreclose the possibility of affected system 
facilities studies being conducted, as a facilities study is needed to 
ascertain the precise nature of any network upgrades that an 
interconnection customer may cause.\2101\
---------------------------------------------------------------------------

    \2097\ Id.; APPA-LPPC Initial Comments at 26; Enel Initial 
Comments at 65; LADWP Initial Comments at 4; NV Energy Initial 
Comments at 11; Pattern Energy Initial Comments at 25; SPP Initial 
Comments at 16-17.
    \2098\ Duke Southeast Utilities Initial Comments at 15; Enel 
Initial Comments at 65; NV Energy Initial Comments at 11; SPP 
Initial Comments at 16-17.
    \2099\ LADWP Initial Comments at 4; Pattern Energy Initial 
Comments at 24-25.
    \2100\ LADWP Initial Comments at 4.
    \2101\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------

    1078. Shell argues for including further information regarding 
local transmission planning from neighboring transmission providers in 
affected system study results because early identification of all 
transmission-related mitigation will ensure that interconnection 
customers can anticipate affected system network upgrades as early as 
possible.\2102\
---------------------------------------------------------------------------

    \2102\ Shell Initial Comments at 31.
---------------------------------------------------------------------------

    1079. Several commenters, including transmission providers, argue 
that the 90-calendar day time frame for completion of the affected 
system study, from the date an affected system transmission provider 
receives an executed affected system study agreement from the affected 
system interconnection customer to the date the affected system 
transmission provider presents the affected system study report to the 
affected system

[[Page 61166]]

interconnection customer, as proposed in pro forma LGIP section 9.6, 
does not provide affected system transmission providers sufficient time 
to complete the study.\2103\ Bonneville requests that the Commission 
clarify whether the schedule to complete the affected system study 
could include a due date that is in excess of the 90-calendar day 
timeline.\2104\ Tri-State requests the addition of ``and deposit'' to 
proposed pro forma LGIP section 9.6, such that the 90-calendar day 
period would begin after the receipt of the executed affected system 
study agreement and deposit.\2105\ MISO requests that the Commission 
clarify that the study clock would commence only after all necessary 
data has been received.\2106\
---------------------------------------------------------------------------

    \2103\ AEP Initial Comments at 31; WAPA Initial Comments at 13.
    \2104\ Bonneville Initial Comments at 19.
    \2105\ Tri-State Initial Comments at 19.
    \2106\ MISO Initial Comments at 93.
---------------------------------------------------------------------------

    1080. Other commenters support the NOPR proposal or argue that 
affected system interconnection customers should be given the results 
of affected system studies as early as possible. Interwest states that 
it agrees with commenters that the proposed 90-calendar day time limit, 
combined with monetary penalties, will help instill discipline and 
support investments needed to meet the timelines.\2107\ Shell asserts 
that affected system study results must be provided before or in 
conjunction with system impact study results on the host transmission 
system, or at the latest, before interconnection customers are required 
to proceed to the facilities study on the host transmission system, as 
interconnection customers typically pursue financing after receiving 
system impact study results and before advancing to the facilities 
study and doing so will avoid last minute network upgrade costs that 
undermine project viability and cause interconnection queue 
withdrawals.\2108\ Shell supports an option for interconnection 
customers to pause the interconnection study process on the host 
transmission system for an affected system study to ``catch-up'' if 
such an option lowers the risk of receiving late affected system study 
results. Similarly, Interwest asserts that affected system 
interconnection customers should be permitted to delay posting security 
and funding network upgrades, if there are delays in affected system 
studies, which Interwest contends is a reasonable accommodation that 
allows such affected system interconnection customers to reduce 
risks.\2109\
---------------------------------------------------------------------------

    \2107\ Interwest Reply Comments at 17.
    \2108\ Shell Initial Comments at 30-31.
    \2109\ Interwest Reply Comments at 18.
---------------------------------------------------------------------------

    1081. Additionally, WAPA expresses concern about its ability to 
tender an affected system facilities construction agreement to an 
interconnection customer within 30 calendar days of providing the 
affected system study report, as proposed in pro forma LGIP section 
9.9.\2110\
---------------------------------------------------------------------------

    \2110\ WAPA Initial Comments at 13.
---------------------------------------------------------------------------

    1082. Several commenters oppose, ask for clarification, or propose 
alternatives regarding the scope and applicability of the financial 
penalties that would apply if a transmission provider does not meet the 
study completion deadlines set forth in proposed pro forma LGIP section 
9.6. AECI asserts that, so long as affected system transmission 
providers are using good utility practice and appropriate due diligence 
to complete affected system studies, there is no benefit of imposing 
additional penalties on affected system transmission providers.\2111\ 
ENGIE states that it is unclear who bears the financial penalties for 
late affected system studies.\2112\
---------------------------------------------------------------------------

    \2111\ AECI Initial Comments at 7.
    \2112\ ENGIE Initial Comments at 9. Additionally, ENGIE states 
that transmission owners typically have responsibilities for 
affected system studies and, therefore, argues that the Commission 
should consider language that distributes financial risk and 
penalties to both transmission owners and transmission providers, 
including an ability for transmission providers to recover costs 
from transmission owners. Id.
---------------------------------------------------------------------------

    1083. MISO, in contrast, interprets the NOPR proposal as applying 
penalties only to the affected system transmission provider, and 
recommends that the Commission recognize that some delays may be beyond 
the control of the affected system transmission provider and not 
penalize affected system transmission providers for third-party 
delays.\2113\ Similarly, Duke Southeast Utilities express concern that 
penalties could be levied against affected system transmission 
providers for delays beyond their control, and further argue that the 
Commission should consider imposing multilateral penalties on all 
entities in accordance with their individual obligations set forth in 
the proposed process.\2114\
---------------------------------------------------------------------------

    \2113\ MISO Initial Comments at 92. WAPA also is generally 
concerned about the imposition of monetary penalties for failure to 
meet deadlines and questions whether Federal agencies like WAPA 
should, or even can be, subject to monetary penalties. See WAPA 
Initial Comments at 10, 14.
    \2114\ Duke Southeast Utilities Initial Comments at 17-18.
---------------------------------------------------------------------------

    1084. Several commenters state that the cost estimates provided in 
affected system study results should be non-binding, or that certain 
types of cost increases related to affected system study results should 
allow interconnection customers to withdraw their interconnection 
requests without penalty.\2115\ Similarly, Shell asserts that the 
Commission should allow penalty-free withdrawals in the event of late 
affected system network upgrade costs that surpass a certain threshold, 
arguing that such circumstances are beyond the interconnection 
customer's control.\2116\ PacifiCorp states that any cost estimates 
identified by affected system operators should be non-binding, given 
that they could be subject to change.\2117\
---------------------------------------------------------------------------

    \2115\ Invenergy Initial Comments at 25; Shell Initial Comments 
at 31; PacifiCorp Initial Comments at 36.
    \2116\ Shell Initial Comments at 31.
    \2117\ PacifiCorp Initial Comments at 36.
---------------------------------------------------------------------------

    1085. Pattern Energy believes that the Commission should provide 
incentives for transmission providers to provide more reasonable and 
accurate cost estimates for network upgrades and related facilities, 
even for affected system studies.\2118\ Pattern Energy claims that the 
Commission should not adopt ``good faith'' to be the standard on which 
cost estimates are provided in affected system studies, asserting that 
reasonable cost estimates based on defined metrics should be the 
standard.
---------------------------------------------------------------------------

    \2118\ Pattern Energy Initial Comments at 25.
---------------------------------------------------------------------------

(9) Affected System Network Upgrade Cost Allocation
    1086. SEIA supports the NOPR proposal to allocate affected system 
network upgrade costs using a proportional impact method, arguing that 
this method should help to reduce individual interconnection customer 
network upgrade costs by allowing interconnection customers to share 
the cost and, in doing so, reduce the likelihood of cascading 
withdrawals.\2119\
---------------------------------------------------------------------------

    \2119\ SEIA Initial Comments at 35.
---------------------------------------------------------------------------

    1087. Other commenters stress the importance of certainty and 
fairness in cost allocation rules. For example, National Grid contends 
that cost allocation rules should provide certainty to interconnection 
customers at a reasonable point in the interconnection process, while 
also having appropriate rules to allocate changes in cost allocations 
that arise after the date that network upgrade costs are 
finalized.\2120\ National Grid suggests that this could be achieved by 
finalizing network upgrade cost allocations at the facilities study 
phase of the host transmission provider's interconnection study 
process, subject to risk sharing cost allocation rules, whereby later 
changes due to the identification of additional required facilities 
could be

[[Page 61167]]

shared between the interconnection customer and load in a transmission 
provider's footprint based on the principle of beneficiary pays, 
through various particular methodologies, including those used for 
transmission planning upgrades or those based on geography.\2121\
---------------------------------------------------------------------------

    \2120\ National Grid Initial Comments at 35.
    \2121\ Interwest Reply Comments at 17; National Grid Initial 
Comments at 35-36.
---------------------------------------------------------------------------

    1088. Finally, several commenters raise other issues regarding 
affected system cost allocation. Enel seeks clarity regarding whether 
shared network upgrades would apply between host system interconnection 
requests and affected system interconnection requests.\2122\ NV Energy 
asserts that, since the affected system interconnection request is 
queued, if the affected system interconnection customer is allocated 
affected system network upgrade costs based on the proportional impact 
method and subsequentially withdraws, then a restudy could potentially 
be required for a lower-queued cluster, which would result in a 
misalignment with the timeline and withdrawal penalties in the 
transmission provider's cluster study for native interconnection 
requests.\2123\ ACE-NY argues that no project should be assigned 
affected system network upgrade costs after it executes its LGIA and/or 
after the interconnection customer has accepted its cost allocation in 
the class year process in NYISO.\2124\
---------------------------------------------------------------------------

    \2122\ Enel Initial Comments at 67 (citing proposed pro forma 
LGIP sections 9.8 and 3.10).
    \2123\ NV Energy Initial Comments at 11.
    \2124\ ACE-NY Initial Comments at 9.
---------------------------------------------------------------------------

(10) Tender of Affected System Facilities Construction Agreement
    1089. Several commenters argue that the proposed time frame for the 
affected system transmission provider to tender an affected system 
facilities construction agreement to the affected system 
interconnection customer--within 30 calendar days of providing the 
affected system study results to the interconnection customer, as 
proposed in section 9.9 of the pro forma LGIP--should be extended or 
modified. Duke Southeast Utilities argue that this deadline should be 
60 calendar days for various administrative reasons.\2125\ Idaho Power 
suggests that the affected system transmission provider tender the 
affected system facilities construction agreement either within 60 
calendar days after the interconnection customers executes a facilities 
construction agreement with the host transmission provider or within 30 
calendar days after providing the affected system study results to the 
affected system interconnection customer, if the affected system study 
is performed during the interconnection facilities study.\2126\ Idaho 
Power explains that information required in the facilities construction 
agreement is comparable to the information provided by the host 
transmission provider in the interconnection facilities study report, 
which, according to Idaho Power, provides a reasonably accurate timing 
and cost estimate and requires considerable coordination to develop. 
WAPA highlights other constraints, stating that it contracts out many 
of its facilities study tasks, which can take significant time, that it 
must work within the budgetary constraints of its annual appropriation, 
and that it is impractical to have a construction agreement ready for 
any interconnection customer within 30 calendar days.\2127\
---------------------------------------------------------------------------

    \2125\ Duke Southeast Utilities Initial Comments at 15-16 
(citing the possibility of multiple individual agreements, the need 
to refine previously provided cost estimates and necessary 
construction schedule, and the potential for more information and 
updates from the host transmission provider).
    \2126\ Idaho Power Initial Comments at 11.
    \2127\ WAPA Initial Comments at 13.
---------------------------------------------------------------------------

    1090. MISO cautions that providing detailed affected system network 
upgrade cost estimates and construction timelines within 30 calendar 
days of providing the affected system study results may not be feasible 
given that MISO currently only gives high-level cost estimates after 
its affected system study and construction timelines and detailed cost 
estimates are provided in the affected system network upgrade 
facilities study, which is performed by transmission owners.\2128\ MISO 
further argues that it should not be responsible for actions that are 
beyond its control, such as the transmission owner-prepared affected 
system network upgrade facilities study, which it claims would not be 
feasible to include in each affected system study report if it is 
attempting to meet the 90-calendar day study timeline, and thus the 
affected system study and the affected system facilities study should 
be kept separate. MISO further argues that it is unlikely that 
transmission owners could provide cost/schedule detail with +/-20% 
accuracy within 30 calendar days of determination of affected system 
network upgrade obligations, with 90 calendar days being a more 
reasonable time frame.\2129\
---------------------------------------------------------------------------

    \2128\ MISO Initial Comments at 90-91.
    \2129\ Id. at 91-92.
---------------------------------------------------------------------------

(11) Restudy
    1091. Bonneville expresses concern with the restudy timeline 
proposed in pro forma LGIP section 9.10, which would require that a 
restudy of the affected system study take no longer than 60 calendar 
days from the date of notice. Bonneville argues that flexibility is 
warranted due to the complexity of restudies.\2130\
---------------------------------------------------------------------------

    \2130\ Bonneville Initial Comments at 22.
---------------------------------------------------------------------------

(d) Requests for Alternatives
(1) Clustering of Affected System Studies
    1092. Several commenters argue that transmission providers should 
process affected system studies using a clustering approach.\2131\ 
Several commenters argue that mandating use of serial studies for all 
variously situated transmission providers would adversely impact the 
efficiency of the study process and place a significant administrative 
burden on transmission providers that is disproportionate to the 
contemplated benefits.\2132\ NextEra urges the Commission to not 
mandate serial affected system study processing when cluster studies of 
affected system impacts will be more expeditious and efficient, 
contending that this would particularly be the case when 
interconnection requests in large cluster studies impact an adjacent 
system.\2133\ North Carolina Commission and Staff claim that serial 
studies come with substantial costs in the form of network upgrades 
that may not be sufficient to meet future demand.\2134\
---------------------------------------------------------------------------

    \2131\ AECI Initial Comments at 6; Indicated PJM TOs Initial 
Comments at 47; NextEra Reply Comments at 4; North Carolina 
Commission and Staff Initial Comments at 25; PPL Initial Comments at 
19-20; SPP Initial Comments at 15; WAPA Initial Comments at 11.
    \2132\ AECI Initial Comments at 6-7; Indicated PJM TOs Initial 
Comments at 47; NextEra Reply Comments at 4; North Carolina 
Commission and Staff Initial Comments at 24-25 (citing Gajda Aff. ]] 
21-22, 27); SPP Initial Comments at 15-16.
    \2133\ NextEra Reply Comments at 4-5.
    \2134\ North Carolina Commission and Staff Initial Comments at 
25 (noting that Duke Energy Progress, LLC constructed $711,805 in 
affected system network upgrades in 2017 to accommodate a PJM 
cluster and that a current, planned upgrade of the same transmission 
line will eliminate the need for all or some of those affected 
system network upgrades, which should have lasted at least 40 years 
and were paid for by Duke Energy Progress, LLC's customers).
---------------------------------------------------------------------------

    1093. Indicated PJM TOs argue that, for efficiency and consistency, 
affected system studies should be integrated into the cluster study 
process.\2135\ Indicated PJM TOs argue that PJM's proposed approach, 
whereby an affected system study identified by one region would be 
integrated into the cluster study of another region, would be more 
efficient

[[Page 61168]]

and less disruptive than the approach identified in the NOPR.\2136\
---------------------------------------------------------------------------

    \2135\ Indicated PJM TOs Initial Comments at 47-48; Indicated 
PJM TOs Reply Comments at 41.
    \2136\ Indicated PJM TOs Initial Comments at 47 (noting that the 
2022 PJM filing provides that PJM will determine the need for an 
affected system analysis in phase 1 of a study cycle, and when PJM 
is identified by another region as needing to complete an affected 
system analysis, it will place the affected system interconnection 
request in phase 2 of an ongoing study cycle) (referencing PJM, 
Filing, Docket No. ER22-2110-000, Sims Aff. ] 10 (filed June 14, 
2022)).
---------------------------------------------------------------------------

    1094. Some commenters also call for flexibility. AECI argues that 
the Commission should not limit the flexibility yielded by its existing 
process of studying each yearly cluster to determine impacts and 
potential affected system network upgrades, when it is acting as the 
affected system operator coordinating studies with a neighboring RTO/
ISO.\2137\ PPL argues that affected system transmission providers 
should have the option to enter into a study agreement with either an 
individual affected system interconnection customer, a group of 
affected system interconnection customers from the same cluster (that 
share cost and other responsibilities), or the ``direct connect 
system.'' \2138\
---------------------------------------------------------------------------

    \2137\ AECI Initial Comments at 6.
    \2138\ PPL Initial Comments at 20.
---------------------------------------------------------------------------

(2) Coordination Between Host Transmission Provider and Affected System 
Transmission Provider
    1095. NextEra contends that the NOPR proposal gives too little 
attention to complex issues, such as potential interconnection queue 
coordination issues between transmission providers that could arise 
after implementation of the proposed reforms.\2139\ Several commenters 
argue that, for efficiency reasons, host transmission providers--and 
not individual affected system interconnection customers--should be 
required to coordinate affected system study activities with the 
affected system transmission providers.\2140\ Some commenters recommend 
that the Commission adopt the coordination approach used by MISO and 
certain of its neighboring systems, whereby the host transmission 
provider coordinates all technical data, study deposits, and studies 
with the affected system transmission provider rather than the proposed 
direct communication and coordination between interconnection customer 
and affected system transmission provider.\2141\ Enel asserts that this 
would reduce administrative burden, ensure timely compliance with the 
tariff, reduce interconnection costs, and increase accountability. Enel 
also argues that using the host transmission provider's study agreement 
to require the interconnection customer to comply with the affected 
system transmission provider's study process ensures that the 
interconnection customer must meet tariff deadlines and cannot delay 
the affected system transmission provider's studies. In addition, Shell 
states that that the Commission should develop guidance for situations 
in which neighboring transmission providers disagree on the scope and/
or timing of an affected system study.\2142\
---------------------------------------------------------------------------

    \2139\ NextEra Reply Comments at 4.
    \2140\ Enel Initial Comments at 60-61; North Carolina Commission 
and Staff Initial Comments at 25-26; Shell Initial Comments at 30.
    \2141\ Enel Initial Comments at 60-61. Enel further argues that 
affected system studies should be invoiced to the host transmission 
provider and paid out of the interconnection customer's study 
deposits, subject to total study cost true-up, and that host 
transmission providers should be required to share the 
interconnection customer's technical data as needed. Enel reasons 
that through direct connections, host and affected system 
transmission providers would be better able to compare constraints 
and proposed upgrades to coordinate where a single upgrade may 
address constraints on both transmission systems. Id.
    \2142\ Shell Initial Comments at 30.
---------------------------------------------------------------------------

    1096. Several commenters argue that the NOPR proposal should be 
reevaluated or modified regarding whether and when transmission 
providers conducting cluster studies would be required to delay those 
studies to wait for the results of affected system studies. Pattern 
Energy contends that the Commission should consider an approach in 
which host transmission providers are not required to wait for affected 
system studies to be completed, if such delayed action would result in 
a study milestone being missed.\2143\ Pattern Energy seeks to avoid an 
unintentional ``delay loop,'' whereby the affected system is not 
diligently processing an affected system study because the host 
transmission provider is waiting for it.\2144\
---------------------------------------------------------------------------

    \2143\ Pattern Energy Initial Comments at 25.
    \2144\ Id. at 25-26.
---------------------------------------------------------------------------

    1097. In contrast, PacifiCorp requests that the Commission clarify 
that, although host transmission providers performing cluster studies 
are not required to delay those studies by waiting for the results of 
affected system studies, transmission providers will not be prohibited 
from delaying the cluster study process to account for affected system 
study issues if the host transmission provider determines that the 
cluster study cannot progress without the results of the affected 
system studies.\2145\ MISO raises similar concerns about a transmission 
provider proceeding with its cluster studies without affected system 
data, which it asserts is critical information for an interconnection 
customer.\2146\ MISO further asserts that the NOPR proposal will not 
provide useful information to the interconnection customer sooner and 
will increase uncertainty, opportunities for late-stage withdrawals, 
cost shifts, and unscheduled restudies and cascading withdrawals.\2147\
---------------------------------------------------------------------------

    \2145\ PacifiCorp Initial Comments at 36-37.
    \2146\ MISO Initial Comments at 93-94.
    \2147\ Id. at 94-95.
---------------------------------------------------------------------------

    1098. Xcel strongly supports improving affected system study 
interactions, arguing that with common models and processes, in many 
instances, host transmission provider study results can be used to 
identify affected system network upgrades, leaving the affected system 
transmission provider to only identify mitigation solutions.\2148\ 
Noting that many RTO/ISO regions have operating agreements that address 
interface capacity rights and processes to relieve congestion near and 
across seams, Xcel argues that host and affected system transmission 
providers should take those operating agreements into account when 
considering any interconnection-related requirements from the affected 
system transmission provider.
---------------------------------------------------------------------------

    \2148\ Xcel Initial Comments at 38-39.
---------------------------------------------------------------------------

    1099. APPA-LPPC request that transmission providers be able to 
forego a formal affected system study when studies by the host 
transmission provider may be sufficient.\2149\ APPA-LPPC ask the 
Commission to recognize in the pro forma LGIP that there may be 
instances in which separate affected system studies may not be 
necessary or useful because, in their members' experience, particularly 
in the Western Interconnection, feasibility, system impact, and 
facilities studies undertaken by a directly interconnecting 
transmission provider may be adequate in scope to encompass impacts on 
and any necessary upgrades to an affected system.\2150\ In such a case, 
APPA-LPPC state, a unitary study would be less expensive for all 
parties and avoid a complex administrative task of sequencing and 
integrating separate system studies.\2151\
---------------------------------------------------------------------------

    \2149\ APPA-LPPC Initial Comments at 25.
    \2150\ Id. at 23-25.
    \2151\ Id. at 25.
---------------------------------------------------------------------------

    1100. Another alternative proposed by WAPA and Enel is the use of 
an affected system screening process to identify instances where 
affected system studies will be needed.\2152\ WAPA suggests that this 
screening process could be a feasibility-level study, completed for an 
entire cluster, to narrow down which interconnection requests within 
the cluster potentially have impacts on an

[[Page 61169]]

affected system.\2153\ WAPA contends that, without a screening process, 
transmission providers under the NOPR proposal will require affected 
system studies by default. Enel suggests that the affected system 
transmission provider should conduct the screening process during the 
host transmission provider's cluster study so that the affected system 
transmission provider is prepared to perform its affected system study 
during the host transmission provider's initial cluster restudy.
---------------------------------------------------------------------------

    \2152\ Enel Initial Comments at 57-58; WAPA Initial Comments at 
12-13.
    \2153\ WAPA Initial Comments at 12-13.
---------------------------------------------------------------------------

(3) Interregional Transmission Planning
    1101. A few commenters urge the Commission to address affected 
system impacts as a systematic phenomenon and a matter of interregional 
transmission planning, rather than one-off events to be handled 
serially.\2154\ EDF Renewables argues that better interregional 
transmission planning should reduce the frequency and severity of 
affected system impacts, asserting that a system-wide approach is more 
efficient than a piecemeal one.\2155\ NextEra cautions that one issue 
absent from the affected system proposals in the NOPR is that the costs 
for alleviating an existing system condition should not rest with a new 
generating facility interconnecting on an adjacent system that did not 
create the problem.\2156\ NextEra argues that preexisting reliability 
issues should instead be identified and solved through the transmission 
planning processes.
---------------------------------------------------------------------------

    \2154\ EDF Renewables Initial Comments at 11; NextEra Initial 
Comments at 31; North Carolina Commission and Staff Initial Comments 
at 3.
    \2155\ EDF Renewables Initial Comments at 11.
    \2156\ NextEra Initial Comments at 31.
---------------------------------------------------------------------------

(e) Requests for Clarification and Flexibility
    1102. Idaho Power requests clarification regarding whether the 
affected system study process would be required for entities that 
already use the first-ready, first served cluster study process.\2157\
---------------------------------------------------------------------------

    \2157\ Idaho Power Initial Comments at 11.
---------------------------------------------------------------------------

    1103. Regarding timing, Invenergy argues that although many of the 
NOPR's proposed requirements should apply prospectively to new 
interconnection requests, immediate action from the Commission is 
needed to resolve affected system issues. Invenergy requests that the 
Commission clarify that the proposed reforms should apply to all 
pending interconnection requests and active studies.\2158\
---------------------------------------------------------------------------

    \2158\ Invenergy Initial Comments at 41.
---------------------------------------------------------------------------

    1104. Several commenters request clarification regarding how the 
proposed affected system reforms would affect RTO/ISO transmission 
providers and transmission owners in their regions.\2159\ Eversource 
requests that the Commission clarify that the proposed affected system 
reforms are not applicable to intra-RTO/ISO system upgrades.\2160\ 
Similarly, NYTOs request that the Commission clarify that the proposed 
affected system reforms would not apply to neighboring transmission 
owners within a single RTO/ISO, or at least allow such transmission 
owners to demonstrate on compliance that their existing processes 
already address such intra-RTO/ISO issues.\2161\ AEP requests that the 
Commission address what it terms the four primary types of affected 
system scenarios: neighboring transmission owner systems within one 
RTO/ISO; neighboring transmission owner systems in two separate RTOs/
ISOs; a transmission owner system in an RTO/ISO neighboring a non-RTO/
ISO transmission provider; and neighboring transmission providers both 
outside of an RTO/ISO.\2162\ AEP contends that the Commission appears 
to conflate all possible affected system scenarios in the NOPR, even 
though the nature of any affected system study can be impacted by the 
type of scenario.\2163\
---------------------------------------------------------------------------

    \2159\ Eversource Initial Comments at 31-32; NYTOs Initial 
Comments at 29.
    \2160\ Eversource Initial Comments at 31-32.
    \2161\ NYTOs Initial Comments at 29 (citing NYISO, NYISO 
Tariffs, attach. X, section 30.3.5 (16.0.0)).
    \2162\ AEP Initial Comments at 32-33; NextEra Reply Comments at 
4.
    \2163\ AEP Initial Comments at 33.
---------------------------------------------------------------------------

    1105. CREA and NewSun seek clarification on whether the proposed 
affected system reforms apply where QF interconnections under PURPA are 
subject to state jurisdiction.\2164\ CREA and NewSun explain that, 
under existing precedent, the Commission has allowed states to retain 
their historic interconnection jurisdiction under PURPA where the QF 
sells its entire net output to the interconnecting utility.\2165\ CREA 
and NewSun argue, though, that where affected system issues are 
involved, the state's jurisdiction over the sale of the QF's energy to 
a utility regulated by that state would not extend to affected system 
issues with a third-party transmission provider that is not purchasing 
the QF's net output.\2166\ CREA and NewSun urge the Commission to 
clarify that a QF interconnection customer has the option to opt into 
use of the Commission's interconnection procedures, in cases where the 
interconnection requires studies or network upgrades on an affected 
system without loss of queue position. CREA and NewSun also argue that 
the QF should retain the right to elect to proceed through the state 
process in case the QF concludes that it would be less disruptive to do 
so.
---------------------------------------------------------------------------

    \2164\ CREA and NewSun Initial Comments at 86.
    \2165\ Id. at 87 (citing Order No. 2003, 104 FERC ] 61,103 at PP 
813-815; Prior Notice & Filing Requirements Under Part II of the 
Fed. Power Act, 64 FERC ] 61,139, at 61,991-92, order on reh'g, 65 
FERC ] 61,081 (1993)).
    \2166\ Id. at 87-88.
---------------------------------------------------------------------------

    1106. Several commenters request clarification on whether the 
proposed affected system reforms apply to non-Commission-jurisdictional 
transmission providers.\2167\ Invenergy and Interwest state that, if an 
affected system is not a Commission-jurisdictional utility, the 
Commission would be unable to enforce the process or any penalties 
proposed in the NOPR, which would leave the interconnection customer in 
the same bind that currently exists.\2168\ Invenergy, Interwest, Xcel, 
and EEI assert that the Commission should prevent non-jurisdictional 
entities from interfering with completion of jurisdictional 
transmission providers' interconnection processes.\2169\
---------------------------------------------------------------------------

    \2167\ Interwest Reply Comments at 18; Invenergy Initial 
Comments at 42; Pacific Northwest Utilities Initial Comments at 17; 
Puget Sound Initial Comments at 7; Tri-State Initial Comments at 20.
    \2168\ Interwest Reply Comments at 18; Invenergy Initial 
Comments at 42.
    \2169\ EEI Initial Comments at 19; Interwest Reply Comments at 
18; Invenergy Initial Comments at 43; Invenergy Reply Comments at 9; 
Xcel Initial Comments at 39.
---------------------------------------------------------------------------

    1107. Several commenters call for the Commission to explain how 
jurisdictional transmission providers should respond to potential 
delays or inaction by non-jurisdictional transmission providers not 
subject to the affected system study process reforms.\2170\
---------------------------------------------------------------------------

    \2170\ EEI Initial Comments at 19; NextEra Initial Comments at 
34; Pacific Northwest Utilities Initial Comments at 15-16; Xcel 
Initial Comments at 39.
---------------------------------------------------------------------------

    1108. Other commenters argue that the Commission should hold 
jurisdictional transmission providers harmless for delays induced by or 
notifications not sent by non-jurisdictional affected system 
transmission providers.\2171\ Pacific Northwest Utilities and Puget 
Sound ask the Commission to clarify that transmission providers have 
met their obligations in dealing with non-jurisdictional entities if 
the host transmission provider notifies a non-jurisdictional affected 
system transmission provider within 10 business days of identifying a 
potential impact to the transmission system of the non-jurisdictional 
entity, pursuant to pro forma LGIP section 3.6.1, and invites the non-
jurisdictional entity to an affected system scoping meeting,

[[Page 61170]]

pursuant to pro forma LGIP section 3.6.2.\2172\
---------------------------------------------------------------------------

    \2171\ Pacific Northwest Utilities Initial Comments at 16-17; 
Puget Sound Initial Comments at 7.
    \2172\ Puget Sound Initial Comments at 8; Pacific Northwest 
Utilities Initial Comments at 17.
---------------------------------------------------------------------------

    1109. Many commenters emphasize the importance of flexibility for 
transmission providers and argue in favor of granting transmission 
providers compliance flexibility in implementing affected system study 
process reforms.\2173\ Some commenters contend that the Commission 
should allow transmission providers to demonstrate that their existing 
affected system study processes or planned revisions to those processes 
are adequate to address the Commission's concerns.\2174\
---------------------------------------------------------------------------

    \2173\ AEP Initial Comments at 5; Dominion Initial Comments at 
39; National Grid Initial Comments at 37-38; NYISO Initial Comments 
at 44; PacifiCorp Initial Comments at 36; PJM Reply Comments at 10.
    \2174\ AEP Initial Comments at 32; Alliant Energy Initial 
Comments at 7; MISO Initial Comments at 7, 12-13, 83-85, 95; NYISO 
Initial Comments at 44; Omaha Public Power Initial Comments at 12; 
OMS Initial Comments at 17; SPP Initial Comments at 16-18.
---------------------------------------------------------------------------

iii. Commission Determination
    1110. We adopt, with modifications, the NOPR proposal to establish 
an affected system study process in, and add several related 
definitions to, the pro forma LGIP. As explained in the NOPR, a 
detailed affected system study process in the pro forma LGIP will 
prevent the use of ad hoc approaches that may give rise to 
interconnection customers being treated in an unjust, unreasonable, and 
unduly discriminatory or preferential manner. We agree with commenters 
that it will also provide interconnection customers greater certainty 
regarding expectations throughout the interconnection process, 
including greater cost certainty, which will lead to fewer late-stage 
withdrawals and fewer delays. The firm affected system study deadlines 
will also ensure that the affected system study process moves along 
expediently, providing clarity, cost certainty, and increased 
transparency throughout the study process, which will minimize 
opportunities for undue discrimination. For these reasons, we find that 
the affected system study process reforms adopted herein are just, 
reasonable, and not unduly discriminatory or preferential and that they 
remedy the unjust, unreasonable, and unduly discriminatory or 
preferential rates resulting from the status quo with regard to 
affected systems. We further find that such reforms will ensure that 
interconnection customers are able to interconnect to the transmission 
system in a reliable, efficient, transparent, and timely manner.
    1111. We disagree with commenters' concerns that a broadly applied, 
prescriptive affected system study process may not be helpful or may be 
unworkable.\2175\ Instead, we agree with National Grid that the current 
status quo is not working and will likely worsen absent 
intervention.\2176\ Although some transmission providers may already 
have working affected system study processes in place, many do not, 
creating uncertainty and unreasonable delay in the interconnection 
process. Further, as discussed below with regard to specific reforms, 
we adopt several revisions to the NOPR proposal in response to comments 
to ensure the affected system study process deadlines are reasonable 
and support efficient processing of interconnection requests. We 
disagree with commenters who argue that the NOPR proposal does not 
increase efficiency and note that certain modifications will further 
increase efficiency.\2177\ While certain required steps in the affected 
system study process may increase the need for communication and 
coordination between affected system transmission providers, affected 
system interconnection customers, and/or host transmission providers, 
we find that the potential burden of such discrete efforts are 
outweighed by the efficiencies of a standardized and more predictable 
affected system study process. We further find that defining an 
affected system study process in the pro forma LGIP is necessary to 
ensure that affected system interconnection customers are not being 
treated in an unjust, unreasonable, and unduly discriminatory or 
preferential manner, and to ensure that they can evaluate their costs 
and make decisions regarding the viability of their generation 
facilities in a timely manner during the interconnection study process.
---------------------------------------------------------------------------

    \2175\ Dominion Initial Comments at 37; Pacific Northwest 
Utilities Initial Comments at 15; PJM Initial Comments at 63; SDG&E 
Reply Comments at 3.
    \2176\ National Grid Initial Comments at 35.
    \2177\ Dominion Initial Comments at 36-37; SDG&E Reply Comments 
at 3; SPP Initial Comments at 17; WAPA Initial Comments at 10.
---------------------------------------------------------------------------

(a) Definitions and Applicability (Pro Forma LGIP Sections 1 and 9.1)
    1112. We adopt the NOPR proposal, with modification, to include 
several definitions in section 1 of the pro forma LGIP related to the 
affected system reforms, specifically, ``affected system facilities 
construction agreement,'' ``affected system interconnection customer,'' 
``affected system network upgrades,'' ``affected system study,'' 
``affected system study agreement,'' and ``affected system study 
report.'' We find these terms to be necessary to enumerate the affected 
system transmission provider's responsibilities in the affected system 
study process.\2178\ We also add the terms ``multiparty affected system 
study agreement'' and ``multiparty affected system facilities 
construction agreement'' to section 1 of the pro forma LGIP in light of 
our adoption of such agreements as part of this final rule, as 
discussed below. We also add the term ``affected system queue 
position'' to the pro forma LGIP because we find it helpful to 
distinguish between an interconnection customer's queue position on the 
host system versus its queue position on an affected system.
---------------------------------------------------------------------------

    \2178\ We note that, in the affected system context, there are 
certain instances in which we intentionally use lowercase versions 
of defined terms to deviate from their definitions in section 1 of 
the pro forma LGIP. For example, ``generating facility'' is, in pro 
forma LGIP section 1, part of the definition of ``affected system 
interconnection customer.'' In the affected system context, we are 
referring to a generating facility governed by another transmission 
provider's LGIP rather than the affected system transmission 
provider's generating facility as defined in its own LGIP.
---------------------------------------------------------------------------

    1113. We adopt, with modification, the NOPR proposal to add section 
9.1 to the pro forma LGIP, titled ``Applicability.'' We find that pro 
forma LGIP section 9.1 clarifies that the transmission provider's 
obligations in section 9 apply when it is acting as an affected system 
transmission provider, and we have added clarifying language to resolve 
ambiguity therein.\2179\
---------------------------------------------------------------------------

    \2179\ We note that former pro forma LGIP section 9, titled 
``Engineering and Procurement (`E&P') Agreement,'' is now pro forma 
LGIP section 13.7 to accommodate the new affected system study 
process section.
---------------------------------------------------------------------------

    1114. In response to PPL's argument that the term ``affected system 
interconnection customer'' is confusing and that either another term 
should be used or ``interconnection'' should be deleted from the term, 
we reiterate that the pro forma LGIP is written to apply to all 
transmission providers on a generic basis, meaning transmission 
providers studying proposed interconnections to their transmission 
systems (host transmission providers) as well as transmission providers 
studying the impacts on their own transmission system of proposed 
interconnections to other transmission providers' transmission systems 
(affected system transmission providers). In other words, when a 
transmission provider's transmission system is an affected system, the 
interconnection customer creating the affected system impact is 
different from that particular affected system transmission provider's 
own interconnection customers (i.e., those

[[Page 61171]]

that propose to interconnect directly to the transmission provider's 
transmission system) and must be distinguished accordingly in the pro 
forma LGIP. The term ``affected system interconnection customer'' 
achieves this goal by distinguishing between the interconnection 
customer's dual roles in the host transmission provider's study process 
and the affected system transmission provider's study process.
    1115. Further, we disagree with PPL's assertion that some 
transmission providers combine interconnection and transmission 
processes, making ``interconnection'' an unnecessary distinction.\2180\ 
This proceeding involves generic generator interconnection procedures, 
pursuant to which transmission service request studies are performed 
independently from interconnection studies.\2181\ However, we modify 
the definition of ``affected system interconnection customer'' and use 
other defined terms in the pro forma LGIP for additional clarity and 
consistency.
---------------------------------------------------------------------------

    \2180\ PPL Initial Comments at 19-20.
    \2181\ See Tenn. Power Co., 90 FERC ] at 61,761 (finding that 
interconnection is an element of transmission service but that the 
interconnection component of transmission service may be requested 
separately from the delivery component (i.e., interconnection is 
distinct from transmission service)).
---------------------------------------------------------------------------

    1116. As explained below, we do not adopt the NOPR proposal to 
require an affected system scoping meeting and therefore also do not 
adopt the proposed term ``affected system scoping meeting'' in section 
1 of the pro forma LGIP.
    1117. We clarify that the terms ``affected system'' and ``affected 
system operator'' retain their existing definitions in pro forma LGIP 
section 1.\2182\
---------------------------------------------------------------------------

    \2182\ An affected system is an electric system other than the 
transmission provider's transmission system that may be affected by 
the proposed interconnection. An affected system operator is the 
entity that operates an affected system. Pro forma LGIP section 1.
---------------------------------------------------------------------------

    1118. In response to NRECA's request for clarification, we 
reiterate that the final rule applies to transmission providers and, in 
the affected system context, to transmission providers that are acting 
as affected systems per the pro forma LGIP definition. Therefore, we 
decline to expand the scope of several affected systems-related 
definitions as requested by NRECA because we find NRECA's request to be 
outside the scope of this proceeding.\2183\ In response to National 
Grid's request for clarification regarding whether an affected system 
solely includes transmission owners in each region or also includes 
neighboring RTOs/ISOs or transmission providers in neighboring regions, 
we reiterate that an affected system is defined in section 1 of the pro 
forma LGIP as an electric system other than the transmission provider's 
transmission system that may be affected by the proposed 
interconnection.
---------------------------------------------------------------------------

    \2183\ See NRECA Initial Comments at 9, 36-39.
---------------------------------------------------------------------------

(b) Identification and Notification of Affected Systems (Pro Forma LGIP 
Sections 3.6.1, 9.2, and 11.2.1)
    1119. We adopt, with modification, proposed section 3.6.1 of the 
pro forma LGIP, which sets forth the trigger events for identification 
of an affected system impact to begin the affected system study 
process. We modify that section to retain as trigger events the 
completion of the cluster study and cluster restudy but eliminate the 
earlier trigger events--the close of the cluster request window and the 
close of the customer engagement window. While we would expect 
identification of potential affected system impacts to occur upon the 
completion of the cluster study, we recognize that an affected system 
impact may not be identified until a restudy occurs, and we adopt 
language in pro forma LGIP section 3.6.1 to account for such a 
scenario. Thus, as adopted in pro forma LGIP section 3.6.1, we require 
the transmission provider to notify the affected system operator at the 
first instance of an identified potential affected system impact, which 
may occur at the completion of the (1) cluster study or (2) cluster 
restudy. We also move the affected system transmission provider's 
obligations to respond to the initial notification under proposed pro 
forma LGIP section 3.6.1 to a new pro forma LGIP section 9.2. We find 
this bifurcation of duties with respect to initial affected system 
notification for the transmission provider, when acting as host 
transmission provider and affected system transmission provider, 
appropriately sets forth the responsibilities of the transmission 
provider in the sections describing the conditions for each action.
    1120. We also adopt the provision proposed in pro forma LGIP 
section 3.6.1 that provides for the transmission provider to notify an 
affected system operator of a potential affected system impact caused 
by the interconnection request within 10 business days of the first 
trigger event giving rise to the identification of the affected system 
impact. We modify the provision in proposed pro forma LGIP section 
3.6.1 for the affected system transmission provider to respond to such 
notification in writing within 15 business days indicating whether it 
intends to conduct an affected system study to 20 business days, which 
we move to pro forma LGIP section 9.2, as noted above. We further move 
to pro forma LGIP section 9.2 the requirement that, within 15 business 
days of the affected system transmission provider's affirmative 
response of its intent to conduct an affected system study, the 
affected system transmission provider must share a non-binding good 
faith estimate of the cost and schedule to complete the affected system 
study.
    1121. As adopted, the identification and notification process is 
tied to the completion of the cluster study or the cluster restudy. At 
that point, the host transmission provider will have a stronger basis 
for deciding whether an interconnection request will potentially impact 
an affected system. Further, the initiation of the affected system 
study process after the initial study costs are received should lead to 
affected system study results that provide greater cost certainty, as 
the largest number of interconnection request withdrawals will most 
likely occur after receipt of the initial cluster study results, a 
point noted by commenters.\2184\ After receipt of the initial cluster 
study results, those interconnection requests remaining in the host 
system's interconnection queue are more likely to complete the 
interconnection study process. We agree with CAISO that this smaller 
pool of affected system interconnection customers will enable faster 
affected system studies due to a decreased volume of affected system 
interconnection customers and more realistic study assumptions.\2185\ 
Accordingly, we find that beginning the affected system study process 
after the adopted trigger events provides greater certainty to 
interconnection customers regarding affected system network upgrade 
costs while ensuring a faster affected system study process. This is 
because the affected system transmission provider will be using more 
realistic study assumptions and studying a more realistic number of 
affected system interconnection customers, reducing the need for 
restudy.
---------------------------------------------------------------------------

    \2184\ CAISO Initial Comments at 28; Idaho Power Initial 
Comments at 11; NextEra Initial Comments at 32.
    \2185\ CAISO Initial Comments at 29.
---------------------------------------------------------------------------

    1122. We find that notification to an affected system operator of a 
potential impact prior to receipt of cluster study results would be 
administratively burdensome and inefficient and could potentially slow 
the interconnection process because such notification would include 
numerous interconnection

[[Page 61172]]

requests that ultimately do not reach commercial operation.\2186\
---------------------------------------------------------------------------

    \2186\ Id. at 28-29; Enel Initial Comments at 59; Idaho Power 
Initial Comments at 11; NextEra Initial Comments at 32.
---------------------------------------------------------------------------

    1123. In eliminating the first two notification triggers, we 
recognize that the affected system study process will start later and, 
as a result, the interconnection customer could be required to execute, 
or request to be filed unexecuted, its LGIA before it has received its 
affected system study results and cost estimates for any affected 
system network upgrades. To avoid this result and in response to 
commenters' requests that transmission providers should be given the 
option to wait for affected system study results when conducting 
cluster studies,\2187\ we modify the NOPR proposal and add a new 
section 11.2.1 to the pro forma LGIP. Under this section, if the 
interconnection customer does not receive its affected system study 
results pursuant to pro forma LGIP section 9.7, discussed below, before 
the deadline for LGIA execution, or the deadline to request that the 
LGIA be filed unexecuted, in its host system, the host transmission 
provider must, at the interconnection customer's request, delay the 
deadline for the interconnection customer to finalize its LGIA.\2188\ 
The interconnection customer will have 30 calendar days after receipt 
of the affected system study report to execute the LGIA, or request 
that the LGIA be filed unexecuted.
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    \2187\ PacifiCorp Initial Comments at 36-37; Pattern Energy 
Initial Comments at 25; Shell Initial Comments at 30-31.
    \2188\ Any interconnection customer that is not awaiting the 
results of an affected system study must proceed under the timelines 
set forth in pro forma LGIP section 11.1.
---------------------------------------------------------------------------

    1124. As noted above, we find that by adopting pro forma LGIP 
section 11.2.1, we ensure that interconnection customers have adequate 
time to evaluate their costs prior to committing to the cost estimates 
contained in an LGIA. Additionally, if the interconnection customer 
prefers to proceed to the execution of its LGIA, or request that the 
LGIA be filed unexecuted, before it has received its affected system 
study results, it may notify the host transmission provider of its 
intent to proceed with the execution of the LGIA, or request that the 
LGIA be filed unexecuted. If the host transmission provider determines 
that further delay to the LGIA execution date would cause a material 
impact on the cost or timing of an equal- or lower-queued 
interconnection customer, the transmission provider must notify the 
interconnection customer whose deadline to execute the LGIA, or request 
that the LGIA be filed unexecuted, is delayed of such impact and 
establish that the new deadline is 30 calendar days after such notice 
is provided.
    1125. In response to ACE-NY's argument that no interconnection 
customer should be assigned affected system network upgrade costs after 
it executes its LGIA and/or after the interconnection customer has 
accepted its cost allocation in the class year process in NYISO,\2189\ 
we decline to rule on specific transmission provider processes in this 
final rule. We note, however, that, under new pro forma LGIP section 
11.2.1, interconnection customers may negotiate LGIA execution to await 
an affected system study report for greater certainty at the time of 
LGIA execution, or requesting the LGIA to be filed unexecuted, if that 
further delay to the LGIA execution date would not cause a material 
impact on the cost or timing of an equal- or lower-queued 
interconnection customer.
---------------------------------------------------------------------------

    \2189\ ACE-NY Initial Comments at 9.
---------------------------------------------------------------------------

    1126. We decline to require the affected system transmission 
provider to provide affected system study results before the facilities 
study phase, as asserted by Enel and Shell,\2190\ because such a 
requirement would necessitate that the affected system transmission 
provider would have to begin such studies before any interconnection 
customers withdraw from the interconnection queue and would therefore 
involve the study of numerous interconnection requests that do not 
eventually proceed to commercial operation, resulting in additional 
restudies and delays.
---------------------------------------------------------------------------

    \2190\ See Enel Initial Comments at 58; Shell Initial Comments 
at 30-31.
---------------------------------------------------------------------------

    1127. In response to Tri-State's argument that proposed pro forma 
LGIP section 3.6.1 needs to clarify to whom notice is to be 
directed,\2191\ we note the language in pro forma LGIP section 3.6.1 
beginning with ``Transmission Provider must notify Affected System 
Operator of a potential Affected System impact.'' If Tri-State is 
asking to whom the affected system transmission provider should respond 
in writing regarding whether it intends to conduct an affected system 
study, it should respond to the transmission provider who notified the 
affected system operator of a potential affected system impact.
---------------------------------------------------------------------------

    \2191\ Tri-State Initial Comments at 28.
---------------------------------------------------------------------------

    1128. We adopt Pacific Northwest Utilities' requested clarification 
and agree with Puget Sound that, provided that transmission providers 
properly notify a non-public utility affected system operator within 10 
business days under proposed pro forma LGIP section 3.6.1, such steps 
are sufficient to demonstrate that the transmission provider has met 
its obligations under that section.\2192\
---------------------------------------------------------------------------

    \2192\ Pacific Northwest Utilities Initial Comments at 17; Puget 
Sound Initial Comments at 8.
---------------------------------------------------------------------------

    1129. We agree with Interwest and Invenergy that the 
interconnection customer should be permitted to delay posting security 
and funding for network upgrades under its LGIA until affected system 
study results are received in certain situations.\2193\ Specifically, 
an interconnection customer is not required to post security for and 
fund network upgrades pursuant to an LGIA if the deadline for LGIA 
execution, or to request that the LGIA be filed unexecuted, is delayed 
under pro forma LGIP section 11.2.1. We agree with Interwest that this 
would reduce an affected system interconnection customer's risk of 
incurring affected system network upgrade costs after LGIA execution. 
However, if the interconnection customer chooses to proceed to execute 
an LGIA, or request that the LGIA be filed unexecuted, it will be 
responsible for posting security and funding network upgrades as per 
the schedule in its LGIA, regardless of whether it has received 
affected system study results.
---------------------------------------------------------------------------

    \2193\ Interwest Reply Comments at 18; Invenergy Initial 
Comments at 43.
---------------------------------------------------------------------------

    1130. We disagree with commenters that a transmission provider's 
obligation to notify a potential affected system operator of an impact 
in 10 business days is unrealistic or problematic.\2194\ As we are 
eliminating two trigger events, the host transmission provider now has 
the obligation to notify the affected system operator of a potential 
impact to the affected system following the completion of the cluster 
study or restudy, which we find provides a clear timeline contrary to 
PacifiCorp's claims. Furthermore, we do not find any convincing 
evidence that a host transmission provider will be unable to provide a 
notification to an affected system operator of potential impacts within 
10 business days and note that this timeline is supported by 
commenters.\2195\
---------------------------------------------------------------------------

    \2194\ CAISO Initial Comments at 27; Duke Southeast Utilities 
Initial Comments at 12; PacifiCorp Initial Comments at 36; PG&E 
Reply Comments at 5.
    \2195\ See AEP Initial Comments at 31; Pine Gate Initial 
Comments at 42.
---------------------------------------------------------------------------

    1131. However, regarding comments that the affected system 
operator's obligation to respond in 15 business days is 
insufficient,\2196\ particularly

[[Page 61173]]

when numerous potential affected system impacts are identified in a 
single cluster study, as stated above, we extend the affected system 
operator's response obligation time period from 15 business days to 20 
business days to provide the affected system operator with additional 
time to consider whether to study these potential affected system 
impacts on its transmission system, consistent with Duke Southeast 
Utilities' suggestion.\2197\ We find these timelines necessary to 
ensure timely processing of the affected system study process and to 
provide certainty to the interconnection customer regarding the 
processing of the affected system study.
---------------------------------------------------------------------------

    \2196\ Bonneville Initial Comments at 18; CAISO Initial Comments 
at 27; Duke Southeast Utilities Initial Comments at 12; PG&E Reply 
Comments at 5; WAPA Initial Comments at 11-12.
    \2197\ See Duke Southeast Utilities Initial Comments at 12.
---------------------------------------------------------------------------

(c) Affected System Scoping Meeting (Pro Forma LGIP Section 3.6.2) and 
Affected System Study Procedures (Pro Forma LGIP Section 9.7)
    1132. We decline to adopt the proposed requirement in pro forma 
LGIP section 3.6.2 that affected system transmission providers must 
hold an affected system scoping meeting within seven business days 
after providing written notification that it intends to conduct an 
affected system study. We agree with commenters' concerns that the 
difficulties associated with holding an affected system scoping meeting 
within the proposed time frame outweigh its potential benefits.\2198\ 
We also agree with WAPA that a meeting after the affected system study 
is completed would be more beneficial than an affected system scoping 
meeting.
---------------------------------------------------------------------------

    \2198\ Bonneville Initial Comments at 18-19; CAISO Initial 
Comments at 28; Dominion Initial Comments at 38; MISO Initial 
Comments at 86; WAPA Initial Comments at 12.
---------------------------------------------------------------------------

    1133. We adopt, with modifications, the proposed affected system 
study procedures set forth in pro forma LGIP section 9.6, now section 
9.7. In particular, we modify the NOPR proposal to explicitly require 
clustering of affected system interconnection customers for study 
purposes where multiple interconnection requests that are part of a 
single cluster in the host system's cluster study process cause the 
need for an affected system study. We find that clustered affected 
system studies will, consistent with the requirement to use a first-
ready, first-served cluster study process, improve administrative 
efficiency in the affected system study process and reduce 
administrative burden on the affected system transmission provider, 
thereby promoting overall efficiency in the interconnection process. We 
agree with commenters that serial affected system studies would place 
an additional burden on transmission providers to study affected system 
impacts and would further slow the interconnection process.\2199\ We, 
therefore, believe that mandating clustering of affected system studies 
will not place an additional unnecessary burden on transmission 
providers, no matter their size; rather, it should reduce such burdens 
as compared to multiple serial studies and restudies.
---------------------------------------------------------------------------

    \2199\ AECI Initial Comments at 6-7; Indicated PJM TOs Initial 
Comments at 47; NextEra Reply Comments at 4; North Carolina 
Commission and Staff Initial Comments at 24-25 (citing Gajda Aff. ]] 
21-22, 27); SPP Initial Comments at 15-16.
---------------------------------------------------------------------------

    1134. We further modify proposed pro forma LGIP section 9.7, to 
require the affected system transmission provider to complete the 
affected system study and provide the affected system interconnection 
customer with affected system study results within 150 calendar days 
after receipt of the affected system study agreement, rather than the 
proposed 90 calendar days. We agree with commenters that explain that 
90 calendar days may not be adequate time to complete an affected 
system study,\2200\ aligning with our discussion of the potential for 
affected system transmission providers to conduct a facilities study 
under proposed pro forma LGIP section 9.6 below. In recognition of 
that, we extend the proposed maximum time frame to complete an affected 
system study from the NOPR's proposed 90 calendar days to 150 calendar 
days. This extension addresses Bonneville's concern that the proposed 
schedule to complete an affected system study may have included a due 
date in excess of the 90-calendar day timeline.
---------------------------------------------------------------------------

    \2200\ AEP Initial Comments at 31; Enel Initial Comments at 65; 
WAPA Initial Comments at 13.
---------------------------------------------------------------------------

    1135. We also modify pro forma LGIP section 9.7, which, as 
proposed, required the affected system transmission provider to notify 
the affected system interconnection customer that an affected system 
study will be late, to add a requirement for the affected system 
transmission provider to notify the host transmission provider that the 
affected system transmission provider will be unable to timely complete 
the affected system study.
    1136. We adopt Tri-State's request to add the phrase ``and 
deposit'' to pro forma LGIP section 9.7, such that the affected system 
transmission provider must provide the affected system study report to 
the affected system interconnection customer within 150 calendar days 
after the receipt of the affected system study agreement and deposit. 
We find this addition is needed to clarify the affected system 
interconnection customer's obligation to provide an affected system 
study deposit, especially if an affected system interconnection 
customer loses its affected system queue position, discussed below, for 
failure to provide the required deposit under pro forma LGIP section 
9.5. We also add to pro forma LGIP section 9.7 a requirement for the 
affected system transmission provider to provide the affected system 
study report to the host transmission provider at the same time it 
provides the report to the affected system interconnection customer. We 
find that this will enhance transparency in the interconnection study 
process.
    1137. In response to MISO's request for clarification that the 
affected system study clock commences only after all necessary data has 
been provided, we clarify that, because an affected system 
interconnection customer has already submitted all required data to the 
host transmission provider, and the host transmission provider has 
verified that the data submitted is adequate and has conducted at least 
one interconnection study, it is highly unlikely that there will be any 
instances of requiring clarification or further data from 
interconnection customers. Thus, under the modified affected system 
study procedures, the data regarding interconnection requests given to 
the affected system transmission provider should be complete, requiring 
no delay or requests for further data. Nevertheless, we note that the 
affected system interconnection customer is required, under pro forma 
LGIP section 9.5, to provide all required technical data when it 
delivers the affected system study agreement. As discussed below, the 
clock for the affected system transmission provider to complete its 
affected system study begins after the receipt of the executed affected 
system study agreement and study deposit, which would include the 
receipt of all required technical data from the affected system 
interconnection customer.
(d) Affected System Queue Position (Pro Forma LGIP Section 9.3)
    1138. We adopt, with modification, the NOPR proposal to add section 
9.2, now section 9.3, titled ``Affected System Queue Position,'' to the 
pro forma LGIP. Specifically, we adopt the first-ready, first-served 
concept, as proposed in the NOPR,\2201\ along with the affected

[[Page 61174]]

system relative queue priority proposal. Consequently, the 
interconnection requests of affected system interconnection customers 
that have executed an affected system study agreement will be higher-
queued than the interconnection requests of those host system 
interconnection customers that have not yet received their cluster 
study results, and lower-queued than those interconnection customers 
that have already received their cluster study results. We also add 
clarifying language to pro forma LGIP section 9.3 to explain that, 
although queue position is determined based on the date of affected 
system study agreement execution, all affected system interconnection 
requests studied within the same affected system cluster will be 
equally queued.
---------------------------------------------------------------------------

    \2201\ We note that several commenters support the proposed 
first-ready, first-served concept under proposed pro forma LGIP 
section 9.2. See Alliant Energy Initial Comments at 7; MISO Initial 
Comments at 11-12; NextEra Initial Comments at 33; OMS Initial 
Comments at 17.
---------------------------------------------------------------------------

    1139. The affected system interconnection customer's affected 
system queue position is for identification of affected system network 
upgrades along with the affected system transmission provider's own 
interconnection customers. Specifically, the affected system queue 
position determines the order in which the affected system transmission 
provider will study the affected system interconnection customers and 
its own interconnection customers and thus impacts which network 
upgrades may be identified as necessary and assigned to interconnection 
customers, whether its own or affected system interconnection 
customers.
    1140. As an example, if a transmission provider has two cluster 
studies of its own interconnection customers--cluster study 1 for which 
the transmission provider is conducting the facilities studies and 
cluster study 2 for which the transmission provider is conducting the 
cluster study--cluster study 1 would be higher-queued than cluster 
study 2. If that transmission provider receives notice from a 
neighboring transmission provider of interconnection requests that may 
impact its transmission system (i.e., affected system interconnection 
customers), the transmission provider may decide to study those 
affected system interconnection customers to determine if any network 
upgrades are required to mitigate constraints caused by those affected 
system interconnection customers. Once those affected system 
interconnection customers have executed their affected system study 
agreements, the transmission provider must assign them an affected 
system queue position, which will be higher than any cluster study of 
its own interconnection customers that have not received their cluster 
study results. In this example, the cluster study 1 interconnection 
customers would be higher-queued than the cluster of affected system 
interconnection customers because the cluster study 1 interconnection 
customers would have already received their cluster study results and 
decided to proceed with their interconnection requests, and cluster 
study 2 interconnection customers would be lower-queued than the 
cluster of affected system interconnection customers because they would 
not have received their cluster study results and thus are more likely 
to withdraw.
    1141. We find that establishing the affected system queue position 
based on the execution of the affected system study agreement is 
appropriate because, at that point, the affected system interconnection 
customer has demonstrated its intent to proceed with its 
interconnection request by executing the agreement and providing a 
study deposit to the affected system transmission provider as well as 
receiving its cluster study report on its host system and deciding to 
proceed with its interconnection request. Furthermore, allowing these 
affected system interconnection customers to be higher-queued than any 
of its own interconnection customers that have not received their 
cluster study results is appropriate because those interconnection 
customers have not yet received any network upgrade estimates. Thus, 
its own interconnection customers have not yet demonstrated their 
intention to proceed to the facilities study.
    1142. We agree with commenters that establishing queue priority in 
an affected system transmission provider's interconnection queue based 
on when an interconnection request is received by the host transmission 
provider is problematic.\2202\ In part for this reason, we are adopting 
the host system's cluster study results and execution of the affected 
system study agreement as reference points for queue priority \2203\ 
because these points occur after the interconnection customer has made 
demonstrations to indicate intent to progress through the 
interconnection process.
---------------------------------------------------------------------------

    \2202\ EDF Renewables Initial Comments at 11; MISO Initial 
Comments at 11, 87.
    \2203\ See NOPR, 179 FERC ] 61,194 at P 189.
---------------------------------------------------------------------------

    1143. We disagree with NextEra that the NOPR proposal's affected 
system queue priority construct, which we adopt herein, will lead to a 
race among interconnection customers to be first or last to sign an 
affected system study agreement. NextEra's concern may occur under a 
serial affected system study process, but, as explained above, we 
require clustering of affected system studies. Studying affected system 
interconnection requests in clusters mitigates the risk of a race to 
execute affected system study agreements, as affected system 
interconnection customers in the same affected system cluster will be 
equally queued regardless of when they execute their affected system 
study agreement, if it is within the appropriate window for affected 
system study agreement execution. We find this to be a just and 
reasonable queue priority construct for affected system studies.
    1144. We decline to adopt EDF Renewables' suggestion that the 
affected system transmission provider be required to establish queue 
priority between the host and affected systems based on the 
interconnection customer having achieved a certain stage in the host 
system's study process, rather than the date the interconnection 
customer submits an interconnection request. We clarify that we neither 
propose to, nor do we adopt a proposal to, base relative affected 
system queue priority on the date an interconnection customer submits 
its interconnection request.\2204\
---------------------------------------------------------------------------

    \2204\ See NOPR, 179 FERC ] 61,194 at P 189 (providing that the 
affected system transmission provider would assign the affected 
system interconnection customer a queue position in its queue 
according to when the affected system interconnection customer 
executes an affected system study agreement rather than when the 
affected system interconnection customer entered its host 
transmission provider's queue).
---------------------------------------------------------------------------

    1145. We clarify, in response to Idaho Power's request, that the 
affected system study process adopted in this final rule is required 
for all transmission providers, regardless of preexisting use of the 
first-ready, first-served cluster study process.
    1146. We clarify, in response to APPA-LPPC, that establishing the 
affected system queue priority is for identifying the affected system 
network upgrades needed to mitigate constraints on the affected 
system.\2205\ This process will proceed in parallel with the host 
transmission provider's study process and should not result in delays 
to the interconnection customer. As discussed above, we allow 
interconnection customers to delay execution of their LGIAs, or request 
that the LGIA be filed unexecuted, if they have not received their 
affected system study results; however, based on the reforms we adopt

[[Page 61175]]

in this final rule, that should be the exception and not the rule. 
Thus, we find that the affected system queue position is merely 
intended to ensure that affected system interconnection customers are 
assigned the appropriate network upgrade costs according to the 
Commission's interconnection pricing policy, and not as an indicator 
that interconnection customers become part of two separate 
interconnection queues.
---------------------------------------------------------------------------

    \2205\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------

    1147. With respect to requests for clarification regarding proposed 
pro forma LGIP section 9.2 and how the first-ready, first-served queue 
priority approach interacts with cluster studies,\2206\ we clarify that 
all affected system interconnection customers in the same cluster on 
the affected system will have equal queue priority in the affected 
system transmission provider's interconnection queue, which is 
consistent with how the first-ready, first-served approach interacts 
with cluster studies for interconnection customers on the transmission 
provider's transmission system when it is acting as a host system. This 
means that the affected system interconnection customers within a 
cluster have equal queue priority and that queue priority will be 
relative to the affected system transmission provider's own 
interconnection customers. The affected system transmission provider's 
own interconnection customers that already received their cluster study 
results when an affected system interconnection customer or cluster of 
affected system interconnection customers execute an affected system 
study agreement will be higher-queued than that affected system 
interconnection customer. Any of the affected system transmission 
provider's own interconnection customers that receive their cluster 
study results after the affected system interconnection customer or 
cluster of affected system interconnection customers execute their 
affected system study agreement will be lower-queued than that affected 
system interconnection customer or cluster of affected system 
interconnection customers. We clarify in response to APPA-LPPC that a 
transmission provider will assign the costs of network upgrades 
required on its transmission system to interconnection customers in its 
host cluster study process and affected system interconnection 
customers, also studied in their own cluster, based on their relative 
queue priority and in accordance with the proportional impact method as 
described in pro forma LGIP section 4.2.3, and as discussed further in 
the next section.\2207\
---------------------------------------------------------------------------

    \2206\ Id.; Idaho Power Initial Comments at 11; NextEra Initial 
Comments at 33.
    \2207\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------

    1148. With respect to Bonneville's request for clarification, we 
clarify that an affected system interconnection customer will lose its 
affected system queue position if the affected system interconnection 
customer fails to: (1) execute the affected system study agreement or 
request it be filed unexecuted; (2) execute the affected system 
facilities construction agreement or request it be filed unexecuted; 
(3) provide the affected system study deposit; or (4) pay undisputed 
affected system study true-up costs in a timely manner.
(e) Affected System Cost Allocation (Pro Forma LGIP Section 9.9)
    1149. We also adopt the NOPR proposal in pro forma LGIP section 
9.8, now pro forma LGIP section 9.9, titled ``Affected System Cost 
Allocation,'' to allocate affected system network upgrade costs using a 
proportional impact method, in accordance with pro forma LGIP section 
4.2.1(1)(b).
    1150. We agree with SEIA that using a proportional impact method 
will reduce individual affected system network upgrade costs and reduce 
the likelihood of cascading withdrawals, consistent with our discussion 
above on the use of the proportional impact method for the allocation 
of network upgrade costs in a cluster on the host system.
    1151. We disagree with commenters that argue that the Commission 
should provide for penalty-free withdrawal from the host system's 
interconnection queue if affected system study results increase an 
interconnection customer's costs by more than 25% or some other 
threshold compared to costs allocated by the host transmission 
provider.\2208\ First, we find that the final rule's requirement that 
affected system transmission providers use ERIS modeling standard to 
conduct affected system studies should reduce the number and total cost 
of affected system network upgrades assigned to affected system 
interconnection customers, which will reduce instances of ``sticker 
shock'' from affected system network upgrades.\2209\ Second, as 
discussed above, any interconnection customers in a cluster that are 
not waiting for affected system study results must proceed with the 
finalization of their LGIAs, pursuant to pro forma LGIP section 11.1. 
Thus, we find that it would create sufficient uncertainty to allow an 
interconnection customer to withdraw penalty-free when it receives its 
affected system study results if there is a 25% increase in costs, 
which may occur after other interconnection customers in the same 
cluster have finalized their LGIAs. We note that interconnection 
customers inherently assume some risk. Accordingly, we decline to 
explicitly extend penalty-free withdrawal to include increases in 
affected system network upgrade costs beyond a certain threshold.
---------------------------------------------------------------------------

    \2208\ Invenergy Initial Comments at 43-44; Shell Initial 
Comments at 31.
    \2209\ See infra section III.B.2.d.iii.
---------------------------------------------------------------------------

    1152. In response to NV Energy's assertion that use of the 
proportional impact method may lead to restudies when a higher-queued 
affected system interconnection customer withdraws its interconnection 
request, we note that potential outcomes of withdrawal are restudy and 
the reallocation of costs, regardless of the cost allocation 
methodology used.\2210\ We also note that, as described above, 
transmission providers may not need to perform a study if, in their 
engineering judgment, the network upgrades assigned to the withdrawing 
interconnection customer either are not needed or are easily reassigned 
to a remaining interconnection customer. Thus, restudies under the new 
interconnection process due to interconnection request withdrawals 
should be relatively less frequent than under existing processes.
---------------------------------------------------------------------------

    \2210\ NV Energy Initial Comments at 11-12.
---------------------------------------------------------------------------

(f) Information Sharing Among Transmission Providers (Pro Forma LGIP 
Section 3.6.3)
    1153. We decline to adopt proposed section 3.6.3 of the pro forma 
LGIP, which would have required a transmission provider to provide data 
on a monthly basis, or more frequently as needed, to any affected 
system operators regarding the amount and location of proposed 
generation in the transmission provider's interconnection queue, as 
well as updated information about the transmission provider's 
transmission system.\2211\ We agree with commenters' arguments that the 
information sharing requirement is duplicative of what is available on 
OASIS and recognize that such a requirement may be overly 
burdensome.\2212\ The OASIS postings provide transparency regarding the 
host transmission provider's interconnection queue information. 
Further, transmission providers are required to notify neighboring 
transmission

[[Page 61176]]

providers of potential impacts on their systems per section 3.6.1 of 
the pro forma LGIP, as described above.
---------------------------------------------------------------------------

    \2211\ Accordingly, we do not address comments on this section.
    \2212\ Bonneville Initial Comments at 19; Dominion Initial 
Comments at 38.
---------------------------------------------------------------------------

(g) Affected System Study Agreement (Pro Forma LGIP Section 9.4) and 
Execution Thereof (Pro Forma LGIP Section 9.5)
    1154. With regard to tendering of the affected system study 
agreement to the affected system interconnection customer, we modify 
proposed pro forma LGIP section 9.3, now pro forma LGIP section 9.4, to 
require that the transmission provider provide the affected system 
study agreement within 10 business days of sharing the schedule for the 
study with the affected system interconnection customer(s), per pro 
forma LGIP section 9.2, rather than within five business days, as 
proposed. We agree with commenters that five business days is not 
enough time to prepare what could be numerous affected system study 
agreements in the event a number of interconnection customers in a 
large cluster on a neighboring transmission system impact the affected 
system transmission provider's transmission system.
    1155. Consistent with our decision--discussed above--to not adopt 
the proposal to require affected system transmission providers to 
convene a scoping meeting with affected system interconnection 
customers, we remove references to such a meeting in pro forma LGIP 
section 9.4. Accordingly, we modify the NOPR proposal requiring the 
affected system operator to provide a non-binding good faith estimate 
of the cost and time frame for completing an affected system study from 
15 business days after the affected system scoping meeting to 20 
business days from the date that the affected system operator responded 
in writing to the host transmission provider that it intends to conduct 
an affected system study, pursuant to section 3.6.1 of the pro forma 
LGIP, and we also move this requirement to section 9.2 of the pro forma 
LGIP. The time taken to tender an affected system study agreement will 
also be measured from that date. We believe these changes will align 
the study timeline to the lack of an affected system scoping meeting.
    1156. Accordingly, we modify proposed pro forma LGIP section 9.4 so 
that, after the affected system transmission provider responds with its 
intent to conduct an affected system study, the affected system 
transmission provider has 10 business days to tender an affected system 
study agreement from the date of the affected system transmission 
provider sharing the schedule for the study. Again, these changes align 
the affected system study process timeline with the modification to 
remove the affected system scoping meeting.
    1157. We further modify proposed pro forma LGIP section 9.4 to 
include a true-up of the affected system study deposit and actual cost 
of the affected system study. The difference between these amounts must 
be detailed in an invoice and paid by or refunded to the affected 
system interconnection customer within 30 calendar days of the receipt 
of such invoice. An affected system interconnection customer's failure 
to pay the difference between these amounts will result in loss of that 
affected system interconnection customer's affected system queue 
position. We find these modifications necessary to effectuate actual 
payment of affected system study costs and to outline the consequences 
for failure to do so.
    1158. With regard to execution of the affected system study 
agreement, we adopt, with modification, the NOPR proposal to add 
section 9.5 to the pro forma LGIP regarding the timing of the execution 
of the affected system study agreement. As adopted, pro forma LGIP 
section 9.5 states that the affected system interconnection customer 
has 10 business days from the date of receipt of the affected system 
study agreement to execute and deliver it to the affected system 
transmission provider. Pro forma LGIP section 9.5 also provides that, 
if the affected system interconnection customer does not provide all 
required technical data when it delivers the affected system study 
agreement, the affected system transmission provider shall notify the 
affected system interconnection customer of the deficiency within five 
business days of the receipt of the affected system study agreement, 
and the affected system interconnection customer has 10 business days 
to cure the deficiency after receipt of such notice, provided that the 
deficiency does not include failure to deliver the executed affected 
system study agreement or deposit.
    1159. In the same vein, we modify proposed section 9.4 of the pro 
forma LGIP to require the affected system transmission provider to 
notify the host transmission provider of the affected system 
interconnection customer's breach of its obligations under this 
section, should such breach occur. We find that, absent such 
notification, the host transmission provider may be unaware of such a 
breach.
(h) Scope of Affected System Study (Pro Forma LGIP Section 9.6)
    1160. We adopt, with modification, the NOPR proposal in pro forma 
LGIP section 9.5, now pro forma LGIP section 9.6, regarding the scope 
of the affected system study. The affected system study will consider 
the base case as well as all higher-queued generating facilities on the 
affected system transmission provider's transmission system and will 
consist of a power flow, stability, and short circuit analysis. The 
affected system study will provide a list of affected system network 
upgrades that are required because of the affected system 
interconnection customer's proposed interconnection, a non-binding good 
faith estimate of cost responsibility, and a non-binding good faith 
estimated time to construct. We find that these requirements will 
ensure that the affected system study will identify affected system 
network upgrades that are necessary to mitigate the impacts of the 
affected system interconnection customer's proposed generating facility 
on the affected system while providing the affected system 
interconnection customer with estimated costs and a timeline to 
construct necessary network upgrades.
    1161. In response to APPA-LPPC, Duke Southeast Utilities, Enel, and 
Pattern Energy, we modify the NOPR proposal and clarify that pro forma 
LGIP section 9.6 does not preclude affected system transmission 
providers from conducting facilities studies or other relevant studies 
when conducting affected system studies. The affected system study may 
consist of a system impact study, a facilities study, or a combination 
of a system impact and facilities study.
    1162. To address commenters' criticism that the NOPR proposal was 
ambiguous with respect to whether a facilities study is specifically 
contemplated as part of the affected system study process,\2213\ we 
clarify that it is. We agree with commenters that an affected system 
facilities study could provide more refined cost estimates and 
construction timelines to better apprise the affected system 
interconnection customer of expected affected system network upgrade 
costs and timing, thereby improving interconnection process 
efficiency.\2214\ We note that the study requirements for the affected 
system study under pro forma LGIP section 9.6 that we proposed in the

[[Page 61177]]

NOPR, and adopt in this final rule, require the affected system 
transmission provider to produce the same information that a facilities 
study would produce; specifically, the affected system transmission 
provider must provide a list of facilities that are required as a 
result of an affected system interconnection customer's proposed 
interconnection, a non-binding good faith estimate of cost 
responsibility, and a non-binding good faith estimated time to 
construct. Nevertheless, for further clarity, we modify proposed pro 
forma LGIP section 9.6 to indicate that the affected system study may 
consist of a system impact study, a facilities study, or some 
combination thereof. We note that we have modified the proposal to 
provide more time to the transmission provider to conduct such studies 
that they deem necessary, as discussed above.
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    \2213\ APPA-LPPC Initial Comments at 26; Duke Southeast 
Utilities Initial Comments at 15.
    \2214\ Enel Initial Comments at 65; LADWP Initial Comments at 4; 
NV Energy Initial Comments at 11; Pattern Energy Initial Comments at 
24-25.
---------------------------------------------------------------------------

    1163. In response to Duke Southeast Utilities' request for 
clarification that affected system transmission providers conduct a 
series of two affected system studies, we reiterate that nothing 
precludes an affected system transmission provider from conducting an 
affected system facilities study following an affected system impact 
study, just as nothing precludes affected system transmission providers 
from conducting a combined version of such studies, and we believe we 
have provided adequate time for transmission providers to do so.
    1164. We find out of scope Shell's request for inclusion of further 
information on local transmission planning from neighboring public 
utility transmission providers in the affected system study results.
(i) Meeting With Transmission Provider (Pro Forma LGIP Section 9.8) and 
Affected System Facilities Construction Agreement (Pro Forma LGIP 
Section 9.10)
    1165. We adopt proposed section 9.9, now section 9.10, of the pro 
forma LGIP, with modifications. Specifically, we adopt the requirement 
for an affected system transmission provider to tender to the affected 
system interconnection customer an affected system facilities 
construction agreement within 30 calendar days of providing the 
affected system study report. We modify this section to require the 
affected system transmission provider to provide 10 business days--
rather than five business days, as proposed--after receipt of the 
affected system facilities construction agreement for the affected 
system interconnection customer to execute the agreement or have the 
affected system transmission provider file it unexecuted with the 
Commission. While no comments were filed in opposition to the five 
business days to notify the affected system transmission provider of 
the affected system interconnection customer's intent to execute the 
agreement or request it to be filed unexecuted, as proposed in the 
NOPR, we believe that 10 business days gives the affected system 
interconnection customer a more appropriate length of time to review 
the facilities construction agreement and the timelines and costs 
contained therein to make a reasoned decision as to whether to execute 
the agreement or request that it be filed unexecuted with the 
Commission.
    1166. Further, we find that it is appropriate to allow the 
interconnection customer to request that the affected system facilities 
construction agreement be filed unexecuted at the Commission. Similar 
to an interconnection customer's ability pursuant to pro forma LGIP 
section 11.3 to request the unexecuted filing of its LGIA, the ability 
to request the affected system facilities construction agreement be 
filed unexecuted allows an affected system interconnection customer to 
dispute provisions of the affected system facilities construction 
agreement before the Commission.\2215\ Because (1) the existing pro 
forma LGIP section 11.3 permits the interconnection customer to request 
the transmission provider to file the LGIA unexecuted, (2) we base the 
affected system facilities construction agreement on the pro forma 
LGIA, and (3) the affected system facilities construction agreement is 
like a service agreement,\2216\ it is appropriate to include a similar 
provision. We further find that an affected system interconnection 
customer may be in a disadvantageous position to negotiate the terms of 
an affected system facilities construction agreement, as this agreement 
is between the affected system interconnection customer and a 
transmission provider with which it does not directly connect. 
Accordingly, to encourage good faith and fair dealings between the 
parties and to avoid the addition of potentially discriminatory terms 
or conditions to an affected system facilities construction agreement, 
we allow an affected system interconnection customer to request that an 
affected system facilities construction agreement be filed unexecuted 
before the Commission.
---------------------------------------------------------------------------

    \2215\ See Order No. 2003, 104 FERC ] 61,103 at P 233 (stating 
that, if agreement negotiations are at an impasse, the 
interconnection customer could either request termination of 
negotiations and request submission of the unexecuted agreement to 
the Commission or initiate dispute resolution procedures).
    \2216\ See Revised Publ. Util. Filing Requirements, Order No. 
2001, 99 FERC ] 61,107, at PP 196, 200, reh'g denied, Order No. 
2001-A, 100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100 FERC 
] 61,342, order directing filing, Order No. 2001-C, 101 FERC ] 
61,314 (2002), order directing filing, Order No. 2001-D, 102 FERC ] 
61,334, order refining filing requirements, Order No. 2001-E, 105 
FERC ] 61,352 (2003), order on clarification, Order No. 2001-F, 106 
FERC ] 61,060 (2004), order revising filing requirements, Order No. 
2001-G, 120 FERC ] 61,270, order on reh'g and clarification, Order 
No. 2001-H, 121 FERC ] 61,289 (2007), order revising filing 
requirements, Order No. 2001-I, 125 FERC ] 61,103 (2008); see also 
Order No. 2003, 104 FERC ] 61,103 at PP 913-915.
---------------------------------------------------------------------------

    1167. We disagree with commenters' assertions that 30 calendar days 
may be an inadequate length of time to tender an affected system 
facilities construction agreement or that considerable time is needed 
to draft such an agreement.\2217\ This is the same period of time by 
which the transmission provider must tender a draft LGIA to the 
interconnection customer, the timeline of which is set forth in the 
existing pro forma LGIP.\2218\ We believe these timelines should be 
consistent because these agreements include similar provisions and 
similar requirements and the record does not persuade us otherwise.
---------------------------------------------------------------------------

    \2217\ See Duke Southeast Utilities Initial Comments at 15-16; 
Idaho Power Initial Comments at 11; MISO Initial Comments at 91-92; 
WAPA Initial Comments at 13.
    \2218\ Pro forma LGIP section 11.1.
---------------------------------------------------------------------------

    1168. We disagree with Idaho Power's suggestion that the affected 
system transmission provider should tender an affected system 
facilities construction agreement within 60 calendar days of the 
interconnection customer executing a facilities study agreement with 
the host transmission provider because, as the host system and affected 
system study processes are separate, though overlapping and 
interrelated, it is more administratively feasible to tie affected 
system study process deadlines to affected system study process events. 
In response to Idaho Power's suggestion that the affected system 
transmission provider should tender an affected system facilities 
construction agreement within 30 calendar days of providing the 
affected system study results to the affected system interconnection 
customer if the affected system study is performed during the 
facilities study on the host transmission provider's system,\2219\ we 
note that, as proposed in the NOPR, the affected system facilities 
construction agreement tender deadline is within 30 calendar days of 
the tendering of the affected system study report without any 
additional caveats or conditions. This tender timeline is,

[[Page 61178]]

however, not directly linked to the host transmission provider's study 
process.
---------------------------------------------------------------------------

    \2219\ Idaho Power Initial Comments at 11.
---------------------------------------------------------------------------

    1169. We also adopt the NOPR proposal to add section 9.7, now 
section 9.8, to the pro forma LGIP. Section 9.8 of the pro forma LGIP, 
titled ``Meeting with Transmission Provider,'' requires the affected 
system transmission provider and the affected system interconnection 
customer to meet within 10 business days of the affected system 
transmission provider tendering the affected system study report to the 
affected system interconnection customer. We find that such a meeting 
between the affected system transmission provider and affected system 
interconnection customer will facilitate transparency and meaningful 
communication in the affected system study process. We note that WAPA 
stated that a meeting after the affected system study report is 
tendered would be more beneficial than an affected system scoping 
meeting. We agree with WAPA and find that no changes to this section 
are necessary.
(j) Restudy Period (Pro Forma LGIP Section 9.11)
    1170. We adopt the NOPR proposal in section 9.10, now section 9.11, 
of the pro forma LGIP to include a maximum 60-calendar day restudy 
period for any affected system restudies. We find that 60 calendar days 
are adequate to complete an affected system restudy. We disagree that 
affected system restudies are as complex as host system restudies, as 
affected system studies will likely involve fewer interconnection 
requests than cluster studies on the host system. Additionally, as 
discussed further below, we find that standardization of affected 
system study assumptions through ERIS modeling criteria will further 
simplify both affected system studies and restudies. Thus, we find it 
just and reasonable to adopt a 60-calendar day affected system restudy 
period.
    1171. In addition to the 60-calendar day restudy period, we adopt a 
30-calendar day notification requirement for the affected system 
transmission provider to notify the affected system interconnection 
customer of the need for affected system restudy upon discovery of such 
need in pro forma LGIP section 9.11. We find such a notification 
requirement to be consistent with restudy notification on the host 
system, and we find such notification necessary to continue a timely 
affected system study process. Accordingly, we find such a notification 
period to be just and reasonable.
(k) Coordination Between Host Transmission Provider and Affected System 
Transmission Provider
    1172. In response to multiple commenters' assertions that, for 
efficiency reasons, host transmission providers should be required to 
coordinate affected system study activities with affected system 
transmission providers rather than individual interconnection 
customers,\2220\ or that flexibility should be afforded in terms of the 
parties to the affected system study agreement and the affected system 
facilities construction agreement,\2221\ the Commission is not 
persuaded that any potential efficiencies of such coordination outweigh 
the burdens that may be placed on host transmission providers, and we 
decline to require it in this final rule. We note that, in many cases, 
the affected system operator may be a non-public utility transmission 
provider, which would limit the usefulness of such a requirement. 
However, we encourage any such voluntary coordination between 
transmission providers who share transmission system seams and whose 
interconnection customers frequently impact each other's systems. We 
also note that, as NextEra suggests, such transmission providers may 
file seams agreements under FPA section 205.\2222\
---------------------------------------------------------------------------

    \2220\ Enel Initial Comments at 60-61; Shell Initial Comments at 
30.
    \2221\ PPL Initial Comments at 20.
    \2222\ NextEra Reply Comments at 5.
---------------------------------------------------------------------------

    1173. In response to Indicated PJM TOs' argument that affected 
system studies should be integrated into the cluster study process, we 
do not have a record to support such a requirement in the final rule. 
Integrating affected system interconnection customers into a cluster 
that is already proceeding through the study process could meaningfully 
change network upgrade cost estimates which could, in turn, create new 
interconnection request withdrawals, leading to restudies and delays. 
Maintaining the clusters as-is and placing the affected system 
interconnection customers in a lower queue position than any 
interconnection customers that have received cost estimates will ensure 
this situation does not happen.
    1174. In response to APS' request for clarification on how the 
proposed affected system study process correlates to the host system's 
studies and aligns with the host system's requirements,\2223\ we 
explain that the affected system study is predicated on the completion 
of a cluster study in the host transmission provider's interconnection 
queue. Relative queue position for the affected system study is also 
determined based on an interconnection customer's completion of the 
host system cluster study. While the host transmission provider will 
likely complete its facilities study prior to an affected system 
transmission provider's completion of an affected system study, we add 
a requirement for host transmission providers with interconnection 
customers that have not yet received their affected system study 
results to delay the LGIA execution (or unexecuted filing) deadline for 
those interconnection customers. An interconnection customer's failure 
to satisfy its obligations under the pro forma LGIP, including 
coordination with the affected system transmission provider, where 
applicable, will result in the loss of the interconnection customer's 
affected system queue position.
---------------------------------------------------------------------------

    \2223\ APS Initial Comments at 19-20.
---------------------------------------------------------------------------

(l) Non-Public Utility Requests
    1175. We reject requests to impose firm deadlines and requirements 
that prevent non-public utility transmission providers from interfering 
with jurisdictional interconnection agreements because we do not have 
the jurisdiction to do so.\2224\
---------------------------------------------------------------------------

    \2224\ Invenergy Initial Comments at 43; Invenergy Reply 
Comments at 9; Interwest Reply Comments at 18.
---------------------------------------------------------------------------

    1176. In response to concerns regarding a transmission provider's 
liability for delays or inaction by non-public utility transmission 
providers,\2225\ we clarify that transmission providers will not face 
consequences for the inaction of a non-public utility transmission 
provider, as long as the transmission providers fulfill their 
obligations as outlined in their LGIPs. For example, under the pro 
forma LGIP affected system process, a transmission provider would 
satisfy its obligation to a non-public utility affected system operator 
by timely notifying it of an affected system impact per pro forma LGIP 
section 3.6.1.
---------------------------------------------------------------------------

    \2225\ EEI Initial Comments at 19; NextEra Initial Comments at 
34; Pacific Northwest Utilities Initial Comments at 15-16; Xcel 
Initial Comments at 39.
---------------------------------------------------------------------------

(m) Miscellaneous
    1177. We do not address the comments of North Carolina Commission 
and Staff and EDF Renewables that interregional transmission planning 
is a way to address affected system impacts because these comments are 
beyond the scope of this proceeding, which is limited to generator 
interconnection.

[[Page 61179]]

    1178. In response to Eversource's and NYTOs' requests for 
clarification that affected system study process reforms would not 
apply to intra-RTO/ISO system upgrades or would not apply to 
neighboring transmission owners within a single RTO/ISO,\2226\ we 
clarify that, in RTO/ISO regions, the RTO/ISO serves as the 
transmission provider for affected system study purposes, and the RTO/
ISO footprint as the affected system, and thus intra-RTO/ISO 
considerations do not apply in this context and are beyond the scope of 
this final rule.
---------------------------------------------------------------------------

    \2226\ See also AEP Initial Comments at 32-33 (highlighting four 
different types of affected system scenarios and contending that the 
Commission conflates them).
---------------------------------------------------------------------------

    1179. We disagree with Invenergy's argument that affected system 
study process reforms should apply to all pending interconnection 
requests and active studies.\2227\ While we adopt a transition approach 
for serial and cluster study processes in the final rule, as explained 
above, we did not propose a similar transition approach with respect to 
affected system studies in the NOPR. Without consistency between 
transition processes as they pertain to neighboring transmission 
providers and implicate the affected system study process, it would be 
practically infeasible to apply the affected system study process 
reforms to all pending interconnection requests and active studies as 
Invenergy suggests. Accordingly, we decline to apply the affected 
system study process reforms adopted in this final rule to any pending 
interconnection requests and active studies.
---------------------------------------------------------------------------

    \2227\ Invenergy Initial Comments at 41.
---------------------------------------------------------------------------

    1180. In response to CREA and NewSun's request for clarification 
that a QF interconnection customer has the option to opt into use of 
the Commission's interconnection procedures in cases where the 
interconnection requires studies or network upgrades on affected 
systems,\2228\ we decline to implement a jurisdictional toggle option 
for an interconnection customer. Longstanding Commission precedent 
indicates when a QF's interconnection is subject to state jurisdiction 
or Commission jurisdiction.\2229\ Nothing in this final rule is 
intended to revise the Commission's approach under PURPA. Requiring 
affected system studies does not change the sale of a QF's output, 
which is the foundation of the Commission's interconnection analysis 
under PURPA.\2230\ To the extent that affected system studies are 
required due to a QF interconnection, the Commission will address such 
filings upon their receipt.
---------------------------------------------------------------------------

    \2228\ CREA and NewSun Initial Comments at 86-88.
    \2229\ Order No. 2003, 104 FERC ] 61,103 at PP 813-814 (finding 
that, when an electric utility purchases a QF's total output, the 
state exercises jurisdiction over the interconnection and allocation 
of interconnection costs, while the presence of any output sold to a 
third party yields Commission jurisdiction); Fla. Power & Light Co., 
133 FERC ] 61,121, at PP 19-23 (2010). See also 18 CFR 202.303, 
202.306 (2022); Participation of Distributed Energy Res. 
Aggregations in Mkts. Operated by Reg'l Transmission Orgs. & Indep. 
Sys. Operators, Order No. 2222, 85 FR 67094 (Oct. 21, 2020), 172 
FERC ] 61,247, at P 98 (2020), corrected, 85 FR 68540 (Oct. 29, 
2020) (citing Order No. 2003, 104 FERC ] 61,103 at PP 813-815; Order 
No. 2006, 111 FERC ] 61,220 at PP 516-518; Order No. 845, 163 FERC ] 
61,043) (stating that nothing in the final rule revises the 
Commission's jurisdictional approach to interconnections of QFs that 
participate in distributed energy resource aggregations).
    \2230\ Order No. 2003, 104 FERC ] 61,103 at PP 813-814.
---------------------------------------------------------------------------

c. Affected System Pro Forma Agreements
i. Need for Reform
(a) NOPR Proposal
    1181. In the NOPR, the Commission expressed concern that the lack 
of pro forma agreements for affected system studies and the 
construction of network upgrades on affected systems was hindering the 
efficiency of the generator interconnection process through increased 
litigation over such agreements and allowed for potential unduly 
discriminatory behavior against interconnection customers whose 
interconnection requests necessitate affected system network 
upgrades.\2231\ Noting a recent increase in affected system-related 
disputes, the Commission preliminarily found it unjust and unreasonable 
to leave affected system agreements wholly up to individual 
negotiations and proposed standardized pro forma affected system 
agreements that minimize the likelihood for such disputes by (1) 
stipulating how to study the impact of interconnecting generating 
facilities on an affected system to identify network upgrades needed to 
accommodate the interconnection request and (2) standardizing the 
affected system facilities construction agreement to set the terms and 
conditions for the construction of those network upgrades.\2232\
---------------------------------------------------------------------------

    \2231\ NOPR, 179 FERC ] 61,194 at P 194.
    \2232\ Id. PP 194-195.
---------------------------------------------------------------------------

(b) Comments
    1182. Many commenters generally support the proposal to develop 
standardized pro forma affected system agreements.\2233\ Commenters 
state that standardization and better synchronization of timelines and 
processes for affected system studies between host and affected system 
transmission providers will improve the efficiency of the 
interconnection process and reduce opportunities for undue 
discrimination.\2234\ ELCON suggests that standardization of affected 
system study agreements, modeling, and assumptions furthers certainty 
and accountability, resulting in a more transparent, efficient, and 
cost-effective interconnection process.\2235\
---------------------------------------------------------------------------

    \2233\ Alliant Energy Initial Comments at 7; APPA-LPPC Initial 
Comments at 23; Clean Energy Associations Initial Comments at 48; 
ELCON Initial Comments at 8; Interwest Reply Comments at 17; 
Invenergy Initial Comments at 45; ISO-NE Initial Comments at 37-38; 
NARUC Initial Comments at 23-24; NYISO Initial Comments at 44-45; 
Pattern Energy Initial Comments at 26; Pine Gate Initial Comments at 
42; SEIA Initial Comments at 34.
    \2234\ Consumers Energy Initial Comments at 8; Invenergy Initial 
Comments at 45; ISO-NE Initial Comments at 37-38.
    \2235\ ELCON Initial Comments at 8.
---------------------------------------------------------------------------

(c) Commission Determination
    1183. We find that the lack of affected system pro forma study and 
facilities construction agreements hinders the efficiency of the 
generator interconnection process through increased litigation over 
such agreements and allows for potential unduly discriminatory behavior 
against interconnection customers whose interconnection requests 
necessitate affected system network upgrades. Our establishment of pro 
forma affected system agreements is supported by the record.\2236\ We 
agree with commenters that this standardization of timelines and 
processes will improve the efficiency of the interconnection process 
and reduce opportunities for undue discrimination.\2237\ For example, 
in establishing such standardized agreements, affected system 
transmission providers and affected system interconnection customers 
will no longer need to negotiate individual non-standard agreements. 
Also, in requiring affected system transmission providers to adhere to 
a set of pro forma procedures in their tariffs common to all 
jurisdictional transmission providers, we minimize the opportunities 
for undue discrimination.\2238\ The

[[Page 61180]]

standardization of affected system agreements also furthers certainty 
and accountability, resulting in a more transparent, efficient, and 
cost-effective interconnection process by ensuring affected system 
interconnection customers know the standard scope and terms of 
agreements for the affected system interconnection process prior to 
entering the interconnection queue.\2239\
---------------------------------------------------------------------------

    \2236\ See id.; Alliant Energy Initial Comments at 7; APPA-LPPC 
Initial Comments at 23; Clean Energy Associations Initial Comments 
at 48; Invenergy Initial Comments at 45; ISO-NE Initial Comments at 
37-38; NARUC Initial Comments at 23-24; NYISO Initial Comments at 
44-45; Pattern Energy Initial Comments at 26; Pine Gate Initial 
Comments at 42; SEIA Initial Comments at 34.
    \2237\ See Consumers Energy Initial Comments at 8; Invenergy 
Initial Comments at 45; ISO-NE Initial Comments at 37-38.
    \2238\ See, e.g., Order No. 2003, 104 FERC ] 61,103 at P 11 
(explaining that Commission precedent dating back to Order No. 888 
establishes a need for standard procedures and agreements, in part 
to minimize opportunities for undue discrimination).
    \2239\ ELCON Initial Comments at 8.
---------------------------------------------------------------------------

ii. Pro Forma Affected System Study Agreement
(a) NOPR Proposal
    1184. In the NOPR, the Commission proposed to establish a pro forma 
affected system study agreement to improve the efficiency and 
transparency of the interconnection customer's interaction with the 
affected system transmission provider.\2240\ The Commission proposed to 
model the pro forma affected system study agreement on the form of the 
existing pro forma system impact study agreement, with necessary minor 
revisions to the party names.\2241\ Specifically, the affected system 
interconnection customer and affected system transmission provider 
would be parties to the agreement.
---------------------------------------------------------------------------

    \2240\ NOPR, 179 FERC ] 61,194 at P 197.
    \2241\ Id. P 198.
---------------------------------------------------------------------------

    1185. In articles 1, 2, 3, and 4, respectively, of the proposed pro 
forma affected system study agreement, the agreement specifies (1) the 
capitalization of defined terms in the pro forma LGIP, (2) that 
coordination with the host transmission provider shall occur pursuant 
to pro forma LGIP section 9, (3) that study assumptions shall be set 
forth in attachment A to the agreement, and (4) that studies shall be 
based on technical information provided by the affected system 
interconnection customer. In article 5, with regard to the information 
the affected system transmission provider will provide to the affected 
system interconnection customer in a study report upon completion of 
the affected system study, the Commission proposed to require the 
following: identification of any circuit breaker short circuit 
capability limits exceeded as a result of the interconnection; 
identification of any thermal overload or voltage limit violations 
resulting from the interconnection; identification of any instability 
or inadequately damped response to system disturbances resulting from 
the interconnection; a non-binding, good faith estimate of the cost of 
facilities on the affected system required to accommodate the 
interconnection of the affected system interconnection customer's 
project to the host transmission system; and a description of how such 
facilities will address the identified short circuit, instability, and 
power flow issues identified in the affected system study.\2242\ The 
Commission sought comment on whether the information required for the 
study report would provide adequate information to the affected system 
interconnection customer to understand the results of the affected 
system study. Finally, in articles 6 and 7, the Commission specified 
the provision of an affected system study deposit and that standard 
miscellaneous terms would be used consistent with industry best 
practice and with the pro forma LGIP and pro forma LGIA.
---------------------------------------------------------------------------

    \2242\ Id. P 199.
---------------------------------------------------------------------------

(b) Comments
    1186. Some commenters generally support the NOPR proposal to 
develop a pro forma affected system study agreement.\2243\ Others 
generally support the establishment of a pro forma affected system 
study agreement but suggest general changes to the approach proposed in 
the NOPR. For example, MISO states that the requirement to execute an 
agreement with each affected system interconnection customer would 
create a significant amount of work for transmission providers that is 
likely to divert resources from performing studies and coordinating 
with other transmission providers without any greater benefit than 
provided by existing joint operating agreements and other seams 
agreements with neighboring systems.\2244\ SPP adds that requiring 
individualized invoicing for all affected system study requests from 
another transmission provider's cluster study would present a 
significant administrative burden for both transmission providers and 
interconnection customers, which would be required to deal with 
multiple transmission providers, instead of just the host transmission 
provider.\2245\ SPP notes that, in its joint operating agreement with 
MISO, the transmission providers coordinate affected system studies 
following each transmission provider's system impact studies on their 
own systems, and rather than invoicing each interconnection customer 
individually, the transmission providers invoice each other for study 
costs, which allows the host transmission provider to use existing 
study deposits when available, and otherwise collect from its 
interconnection customers as needed.\2246\
---------------------------------------------------------------------------

    \2243\ Ameren Initial Comments at 23; Duke Southeast Utilities 
Initial Comments at 18; North Carolina Commission and Staff Initial 
Comments at 24; U.S. Chamber of Commerce Initial Comments at 10-11.
    \2244\ MISO Initial Comments at 96.
    \2245\ SPP Initial Comments at 19.
    \2246\ Id. at 18-19.
---------------------------------------------------------------------------

    1187. Other commenters suggest specific changes to the language 
proposed in the NOPR. For instance, Tri-State proposes adding language 
to article 9.4 of the pro forma LGIP specifying a protocol if 
deficiencies are not cured, such as, ``shall be deemed withdrawn 
pursuant to Section 3.7 of this LGIP.'' \2247\ PPL argues that the pro 
forma affected system study agreement should: (1) have article 7 
replaced entirely with actual contractual terms; (2) contain a clear 
requirement for affected system interconnection customers to provide 
data in a timely manner; (3) include data ownership and confidentiality 
provisions; and (4) address restudies.\2248\
---------------------------------------------------------------------------

    \2247\ Tri-State Initial Comments at 31-32.
    \2248\ PPL Initial Comments at 20.
---------------------------------------------------------------------------

    1188. Additionally, Tri-State includes an appendix containing a 
redline version of the pro forma affected system study agreement that 
specifies its requested revisions to the agreement. Of note, Tri-State 
proposes changes to article 6, which would require the affected system 
transmission provider to specify the affected system study deposit 
value.\2249\
---------------------------------------------------------------------------

    \2249\ Tri-State Initial Comments, app. B, at 122-124.
---------------------------------------------------------------------------

    1189. In response to whether the information required in the 
affected system study report would provide adequate information to the 
affected system interconnection customer to understand the results of 
the affected system study, Xcel states that the proposed information is 
adequate.\2250\ Duke Southeast Utilities support the information 
required by article 5 of the proposed agreement but suggest that any 
other identified impacts outside of the prescribed information should 
also be included.\2251\ LADWP believes that the study report should 
also include whether modifications to remedial action schemes or other 
special protection systems may be required.\2252\
---------------------------------------------------------------------------

    \2250\ Xcel Initial Comments at 39.
    \2251\ Duke Southeast Utilities Initial Comments at 18.
    \2252\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------

    1190. Enel seeks clarification on whether the affected system study 
scope must include all of ``a short circuit analysis, thermal overload 
or voltage limit identification, and stability analysis, and a power 
flow analysis,'' as proposed in pro forma LGIP section 9.5,

[[Page 61181]]

and requests that transmission providers be allowed to waive portions 
of the study scope if deemed unnecessary.\2253\
---------------------------------------------------------------------------

    \2253\ Enel Initial Comments at 65.
---------------------------------------------------------------------------

    1191. Several entities ask the Commission to allow regional 
variations to avoid conflict with existing affected system coordination 
processes.\2254\
---------------------------------------------------------------------------

    \2254\ Ameren Initial Comments at 23; MISO Initial Comments at 
95; SPP Initial Comments at 18-19.
---------------------------------------------------------------------------

(c) Commission Determination
    1192. We adopt, with modifications, the proposed pro forma affected 
system study agreement set forth in Appendix 9 of the pro forma 
LGIP.\2255\ As discussed below, we make two modifications. First, 
consistent with comments,\2256\ we establish a multiparty pro forma 
affected system study agreement set forth in Appendix 10 of the pro 
forma LGIP. Second, we modify article 6 of the proposed pro forma 
affected system study agreement to make the language therein consistent 
with similar language elsewhere in the pro forma LGIP.\2257\
---------------------------------------------------------------------------

    \2255\ NOPR, 179 FERC ] 61,194 at P 197.
    \2256\ MISO Initial Comments at 96; SPP Initial Comments at 18-
19.
    \2257\ We also make minor consistency edits to article 5 of the 
proposed pro forma affected system study agreement, to conform the 
pro forma affected system study agreement with pro forma LGIP 
section 9.6.
---------------------------------------------------------------------------

    1193. Starting with the multiparty pro forma affected system study 
agreement, as described above, we require affected system transmission 
providers to study affected system interconnection requests in 
clusters. To facilitate this change, we modify the NOPR proposal and 
establish a pro forma multiparty affected system study agreement that 
closely tracks the proposed two-party agreement. Such a pro forma 
multiparty agreement will allow affected system transmission providers 
to enter into the same affected system study agreement with each of the 
affected system interconnection customers that it must study in a 
cluster. We find that a pro forma multiparty affected system study 
agreement will facilitate interactions with the affected system 
transmission provider, making them more efficient and transparent. We 
agree with SPP and MISO that a requirement for an affected system 
transmission provider to sign affected system study agreements with 
each affected system interconnection customer would be 
burdensome.\2258\ In creating a pro forma multiparty affected system 
study agreement, we reduce the administrative burden on transmission 
providers that no longer need to manage several individual affected 
system study agreements.
---------------------------------------------------------------------------

    \2258\ MISO Initial Comments at 96; SPP Initial Comments at 18-
19.
---------------------------------------------------------------------------

    1194. In response to SPP and MISO's suggestion to make the parties 
to the pro forma affected system study agreement the affected system 
transmission provider and the host transmission provider, we decline 
this request. We believe that the interconnection customer, as the one 
responsible for providing necessary information about the proposed 
generating facility as well as funding the affected system study, is 
the appropriate counterparty to the affected system study agreement. We 
note, however, that any transmission providers may propose alternative 
arrangements through joint operating agreements or otherwise pursuant 
to FPA section 205.
    1195. In response to comments from Tri-State and PPL's request 
regarding affected system interconnection customers that fail to 
provide required information,\2259\ we find that sufficient 
requirements for data sharing exist in both the current and newly 
adopted pro forma LGIP requirements. Specifically, as discussed above 
and consistent with comments from Tri-State, we modify pro forma LGIP 
section 9.5 to explicitly state that any affected system 
interconnection customer failing to submit required information and 
failing to cure that deficiency shall lose its affected system queue 
position. We also add to pro forma LGIP section 9.5 a requirement that 
the affected system transmission provider notify the host transmission 
provider in a timely manner of such failure by the affected system 
interconnection customer.
---------------------------------------------------------------------------

    \2259\ PPL Initial Comments at 20; Tri-State Initial Comments at 
18-19.
---------------------------------------------------------------------------

    1196. In response to Tri-State's requested revisions to article 6 
of the pro forma affected system study agreement, we modify the pro 
forma affected system study agreement to add additional language to 
explicitly require affected system interconnection customers to provide 
a study deposit. The deposit will provide for the cost of the affected 
system interconnection study. Moreover, we find that such revisions 
will align the pro forma affected system study agreement with Appendix 
2 (cluster study agreement), Appendix 3 (interconnection facilities 
study agreement), and Appendix 4 (optional interconnection study 
agreement) of the pro forma LGIP.
    1197. In response to PPL's request that article 7, regarding 
standard miscellaneous terms, should be replaced with actual 
contractual terms, we decline to adopt PPL's proposed revisions. We 
adopt article 7 of the pro forma affected system study agreement, with 
modification to eliminate the reference to the LGIA. We note that this 
article 7 is consistent with the existing pro forma interconnection 
system impact study agreement (which the Commission is replacing with 
new cluster study-based agreements adopted in this final rule), 
interconnection facilities study agreement, and optional 
interconnection study agreement, which also provide for standard 
miscellaneous terms. In response to PPL's requests that the pro forma 
affected system study agreement should address data ownership and 
confidentiality requirements as well as restudies, we find such 
revisions to the proposed pro forma affected system study agreement 
unnecessary, as they would be duplicative of existing pro forma LGIP 
provisions regarding confidentiality (section 13.1) and restudies 
(former section 6.4, now contained in sections 7.5, 8.5, and 9.10). 
Regarding the removal of the reference to the LGIA, we find that the 
removal is appropriate as the parties to an interconnection customer's 
LGIA would not be the same parties to an affected system study 
agreement.
    1198. In response to comments on the scope of the pro forma 
affected system study, we agree with Xcel that the scope of the 
affected system study is adequate.\2260\ Consequently, we decline to 
modify the scope of the affected system study contained in article 5 of 
the proposed pro forma affected system study agreement. We note that 
the scope of the affected system studies identified in article 5 is 
consistent with the scope of host system interconnection studies.\2261\ 
In response to comments from Duke Southeast Utilities that entities 
should be able to include other, identified impacts in the affected 
system study report, we clarify that the scope of affected system 
studies must be consistent with the scope listed in article 5 of the 
pro forma affected system study agreement. Affording affected system 
transmission providers flexibility to expand the scope of affected 
system studies on an ad hoc or individual basis creates the potential 
for undue discrimination and a barrier to entry. With respect to 
LADWP's request to include impacts to remedial action schemes and other 
special protection systems within the scope of the affected system 
studies,\2262\ we clarify that such impacts are already contemplated in

[[Page 61182]]

article 5 of the pro forma affected system study agreement.
---------------------------------------------------------------------------

    \2260\ Xcel Initial Comments at 39.
    \2261\ Pro forma LGIP, app. 2, art. 5; app. 3, art. 4.
    \2262\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------

iii. Pro Forma Affected System Facilities Construction Agreement
(a) NOPR Proposal
    1199. In the NOPR, the Commission proposed to revise the pro forma 
LGIP to add a pro forma affected system facilities construction 
agreement.\2263\ The proposed pro forma affected system facilities 
construction agreement includes provisions on the following: terms of 
the agreement; construction of network upgrades; taxes; force majeure; 
information reporting; security, billing, and payments; assignment; 
indemnity; breach, cure, and default; termination; contractors; 
confidentiality; information access and audit rights; dispute 
resolution; and notices.\2264\ Proposed Appendix A to the agreement 
provides for details on identified network upgrades, cost estimates and 
responsibility, the construction schedule for network upgrades, and a 
payment schedule; proposed Appendix B addresses notification of 
completed construction; and proposed Appendix C provides for a 
transmission provider site map, a site plan, a plan and profile for 
network upgrades, and the estimated cost of the network upgrades.
---------------------------------------------------------------------------

    \2263\ NOPR, 179 FERC ] 61,194 at P 200.
    \2264\ Id. P 201.
---------------------------------------------------------------------------

    1200. The Commission proposed that the pro forma affected system 
facilities construction agreement would be entered into by the affected 
system transmission provider and the affected system interconnection 
customer.\2265\ Under the NOPR proposal, the affected system 
transmission provider would be responsible for the design, procurement, 
construction, and installation of all network upgrades identified in 
Appendix A using reasonable efforts to complete construction consistent 
with the schedule identified in Appendix A. The affected system 
interconnection customer would initially fund the cost of any assigned 
network upgrades and be reimbursed by the affected system transmission 
provider.\2266\ Rather, the Commission proposed to require that, 
consistent with Order No. 2003, the affected system interconnection 
customer must enter into an agreement with the affected system 
transmission provider that must specify the terms governing payments to 
be made by the affected system interconnection customer as well as 
payment of refunds by the affected system transmission provider for the 
full cost of network upgrades, plus interest.\2267\
---------------------------------------------------------------------------

    \2265\ Id. P 202.
    \2266\ Order No. 2003, 104 FERC ] 61,103 at P 738.
    \2267\ Id. P 739.
---------------------------------------------------------------------------

    1201. The Commission clarified that the term to be mutually agreed 
upon for payment of refunds to affected system interconnection customer 
funded network upgrades is not to exceed 20 years.\2268\ This term 
mirrors the repayment term in the pro forma LGIA but allows for 
flexibility for the parties to come to another arrangement if they 
prefer. Under the NOPR proposal, within six months of completion of 
construction of any required network upgrades, the affected system 
transmission provider would invoice the affected system interconnection 
customer for the final construction costs, including a true-up of 
estimated and actual costs. The pro forma affected system facilities 
construction agreement would terminate upon the affected system 
transmission provider's final repayment to the affected system 
interconnection customer. Alternatively, the affected system 
interconnection customer could also terminate the affected system 
facilities construction agreement with 60 calendar days' written notice 
to the affected system transmission provider.
---------------------------------------------------------------------------

    \2268\ Id.; see also Order No. 2003-B, 109 FERC ] 61,287 at PP 
32-36 (extending the required repayment period from five years to 20 
years).
---------------------------------------------------------------------------

    1202. The Commission sought comment on the network upgrade funding 
and repayment provisions in the proposed pro forma affected system 
facilities construction agreement, specifically whether the repayment 
time frame and the similarity of the proposal to the repayment terms in 
the pro forma LGIA were appropriate.\2269\ The Commission also sought 
comment on whether any articles or provisions should be added to the 
proposed pro forma affected system facilities construction agreement or 
whether the proposed provisions were sufficient.\2270\
---------------------------------------------------------------------------

    \2269\ NOPR, 179 FERC ] 61,194 at P 203.
    \2270\ Id. P 204.
---------------------------------------------------------------------------

(b) Comments
    1203. Some commenters generally support the proposed pro forma 
affected system facilities construction agreement because it will offer 
uniformity across the country and increase administrative 
efficiency.\2271\ Others argue that the agreement should be structured 
as either an individual network upgrade agreement or a multiparty 
network upgrade agreement.\2272\
---------------------------------------------------------------------------

    \2271\ Ameren Initial Comments at 23; Duke Southeast Utilities 
Initial Comments at 18; SPP Initial Comments at 19-20.
    \2272\ PPL Initial Comments at 20; SPP Initial Comments at 20.
---------------------------------------------------------------------------

    1204. Some commenters request that the Commission allow for 
regional variations to avoid conflict with existing pro forma 
facilities construction agreements.\2273\
---------------------------------------------------------------------------

    \2273\ Ameren Initial Comments at 23; MISO Initial Comments at 
97; NYISO Initial Comments at 45; PPL Initial Comments at 22.
---------------------------------------------------------------------------

(1) Comments on Specific Provisions and Related Proposals
    1205. As a global change, Xcel recommends that the defined term 
``affected system operator'' be used instead of ``transmission 
provider'' when referencing the affected system transmission provider, 
arguing that the use of the terms ``transmission provider'' and 
``transmission provider acting as affected system'' are confusing and 
may conflict with usage of those terms in the LGIP.\2274\
---------------------------------------------------------------------------

    \2274\ Xcel Initial Comments at 40.
---------------------------------------------------------------------------

    1206. With regard to article 2 (Term of Agreement), Tri-State 
proposes the following addition: ``No Transmission Delivery Service. 
The execution of this LGIA does not constitute a request for, nor the 
provision of, any transmission delivery service under Transmission 
Provider's Tariff, and does not convey any right to deliver electricity 
to any specific customer or Point of Delivery.'' \2275\ Additionally, 
Tri-State opposes the option in proposed article 2.2.1 that would allow 
the affected system interconnection customer to terminate the affected 
system facilities construction agreement with 60 calendar days' written 
notice. Tri-State contends that allowing such termination could trigger 
restudies for the affected system transmission provider.\2276\
---------------------------------------------------------------------------

    \2275\ Tri-State Initial Comments at 32.
    \2276\ Id. at 21.
---------------------------------------------------------------------------

    1207. Southern states that the Commission should either reconsider 
or clarify proposed article 2.2.2 (Termination Upon Default) and 
proposed article 5.2 (Notice of Breach, Cure, and Default), which it 
states appears to provide that if a default does not pose a threat to 
the reliability of the affected system transmission provider's 
transmission system, the affected system transmission provider may not 
terminate the agreement if the affected system interconnection customer 
has begun to cure and compensate the transmission provider for any 
damage.\2277\ Southern argues that such provisions should be consistent 
with pro forma LGIA provisions and that, if an affected system 
interconnection customer defaults under the LGIA, the affected system 
operator should not be required to build affected system network 
upgrades. Southern argues that,

[[Page 61183]]

if the provisions are not consistent with the pro forma LGIA, affected 
system transmission providers will build affected system network 
upgrades that are not needed, and there will be different default and 
termination rights applicable to these improvements. Similarly, Tri-
State submits suggested edits to proposed article 2.2.2, which remove 
the provisions Southern comments on, explaining that a default should 
only occur after a breach and failure to cure.\2278\
---------------------------------------------------------------------------

    \2277\ Southern Initial Comments at 18.
    \2278\ Tri-State Initial Comments at 33.
---------------------------------------------------------------------------

    1208. Invenergy opposes proposed article 2.2.3, which provides 
that, upon termination of the affected system facilities construction 
agreement, the affected system interconnection customer would be 
responsible for costs incurred by another affected system 
interconnection customer due to the termination of: (1) its affected 
system facilities construction agreement; (2) that interconnection 
customer's LGIA; or (3) any of that interconnection customer's other 
affected system facilities construction agreements.\2279\ Some 
commenters argue that this requirement is unreasonable and must be 
revised.\2280\ They claim that there is no basis for imposing on the 
affected system interconnection customer broad and potentially 
exorbitant liability for any potential impacts on any other 
interconnection customer within the affected system, which they argue 
exceeds potential liability imposed under the pro forma LGIA for the 
host transmission provider's transmission system.\2281\ Invenergy 
states that the provision appears to be based on a provision in MISO's 
pro forma facilities construction agreement, which it argues does not 
make sense for a generically applicable pro forma agreement.
---------------------------------------------------------------------------

    \2279\ Invenergy Initial Comments at 45.
    \2280\ Id. at 46; Interwest Reply Comments at 18-19; Tri-State 
Initial Comments at 20.
    \2281\ Interwest Reply Comments at 18-19; Invenergy Initial 
Comments at 46; Tri-State Initial Comments at 20.
---------------------------------------------------------------------------

    1209. As for proposed article 3 (Construction of Network Upgrades), 
some commenters object to limiting the right to suspend for force 
majeure events, contained in proposed article 3.1.2.1.\2282\ Southern 
states that proposed article 3.1.2.1 appears to provide that the 
affected system interconnection customer may only suspend its 
interconnection request if there is a force majeure event and that no 
such limitation on suspension rights exists under the pro forma LGIA, 
meaning that an affected system interconnection customer could suspend 
its interconnection request under the pro forma LGIA but still be 
required to move forward with construction of affected system network 
upgrades, if the reason for suspension under the pro forma LGIA is not 
a force majeure event.\2283\ Enel asserts that the Commission has not 
provided justification for limiting the affected system interconnection 
customer's suspension rights to just force majeure events.\2284\ Enel, 
Invenergy, and Southern argue that suspension rights under the pro 
forma affected system facilities construction agreement should be 
consistent with the suspension rights under the pro forma LGIA, with 
Invenergy highlighting that the pro forma LGIA permits suspension for 
up to three years.\2285\ Conversely, Tri-State argues that the same 
force majeure language used in proposed article 3.1.2.1 should be added 
to both the pro forma LGIA and pro forma LGIP.\2286\
---------------------------------------------------------------------------

    \2282\ Enel Initial Comments at 83-84; Invenergy Initial 
Comments at 47; Southern Initial Comments at 18; Tri-State Initial 
Comments at 20.
    \2283\ Southern Initial Comments at 18-19.
    \2284\ Enel Initial Comments at 83-84.
    \2285\ Id. at 83; Invenergy Initial Comments at 47; Southern 
Initial Comments at 18-19.
    \2286\ Tri-State Initial Comments at 33.
---------------------------------------------------------------------------

    1210. MISO suggests that there should be a provision in the pro 
forma affected system facilities construction agreement on cross-
defaults between the affected system facilities construction agreement 
and the interconnection customer's LGIA.\2287\ MISO asserts that, as 
proposed, if the affected system interconnection customer refuses to 
make payments under an affected system facilities construction 
agreement, it is unclear how it would affect the affected system 
interconnection customer's LGIA.
---------------------------------------------------------------------------

    \2287\ MISO Initial Comments at 97.
---------------------------------------------------------------------------

    1211. In response to proposed article 3.2.2.1, which would require 
affected system transmission providers to reimburse affected system 
interconnection customers for their affected system network upgrade 
costs, many commenters support the proposal,\2288\ while many others 
oppose it.\2289\ In support, commenters contend that the reimbursement 
policy is consistent with long-established Commission precedent and 
cost causation, as it ensures that affected system network upgrade cost 
reimbursement is rate-based, such that the transmission customers that 
ultimately benefit from the network upgrades pay for those 
upgrades.\2290\ In contrast, according to these commenters, allowing 
transmission customers of the affected system to receive the benefits 
of an affected system network upgrade, without paying for it, would 
create a ``free-rider'' problem that is inconsistent with the 
``beneficiary pays'' principle.\2291\
---------------------------------------------------------------------------

    \2288\ ACE-NY Initial Comments 9; AES Initial Comments at 22; 
Ameren Initial Comments at 23; APPA-LPPC Initial Comments at 23; 
Enel Initial Comments at 66-67; Shell Initial Comments at 33-34.
    \2289\ AECI Initial Comments at 9; Duke Southeast Utilities 
Initial Comments at 19; EEI Initial Comments at 18-19; North 
Carolina Commission and Staff Initial Comments at 6; PG&E Reply 
Comments at 5-6; PPL Initial Comments at 20; Southern Reply Comments 
at 7-8; Tri-State Initial Comments at 21-22; U.S. Chamber Commerce 
Initial Comments at 11; WAPA Initial Comments at 13-14; Xcel Initial 
Comments at 40.
    \2290\ Enel Initial Comments at 66; Shell Initial Comments at 
35.
    \2291\ ACE-NY Initial Comments 9; Shell Initial Comments at 35-
36.
---------------------------------------------------------------------------

    1212. Other commenters do not fully oppose the proposal but suggest 
changes to proposed article 3.2.2.1. For instance, MISO and Southern 
contend that the repayment provisions for affected system 
interconnection customers should be consistent with how the 
transmission provider repays its internal interconnection 
customers.\2292\ MISO asserts that this will ensure comparability and 
non-discriminatory treatment between affected system interconnection 
customers and ``native'' interconnection customers interconnected to 
the affected system.\2293\ APPA-LPPC argue that the NOPR proposal is 
missing an express, contractual commitment ensuring that an 
interconnection customer will fund network upgrades identified by the 
affected system as a condition of interconnection.\2294\ APPA-LPPC 
state that they believe this to be implicit in the proposal and that 
the provision should specify that the identified affected system 
transmission provider is an intended third-party beneficiary of the 
LGIA. APPA-LPPC contend that the absence of such a contractual 
obligation on the part of the interconnection customer is a particular 
concern for non-public utilities, which have no standing under the FPA 
to seek funding for network upgrades under Commission-jurisdictional 
tariffs. However, according to Southern, in Order No. 2003, the 
Commission declined to make a generic finding on the possibility of 
network upgrade costs being passed onto native load and transmission 
customers and instead allowed transmission providers to make a filing 
if such entities were not being held harmless.\2295\ Southern states 
that

[[Page 61184]]

the Commission should clarify that a transmission provider can make 
such a filing, if warranted, in which it could propose that affected 
system interconnection customers bear the cost responsibility of 
identified affected system network upgrades.\2296\
---------------------------------------------------------------------------

    \2292\ MISO Initial Comments at 97; Southern Initial Comments at 
4.
    \2293\ MISO Initial Comments at 97.
    \2294\ APPA-LPPC Initial Comments at 24-25.
    \2295\ Southern Initial Comments at 17-18; Southern Reply 
Comments at 8 (citing Order No. 2003-A, 106 FERC ] 61,220 at P 586; 
Order No. 2003-B, 109 FERC ] 61,287 at P 56).
    \2296\ Southern Initial Comments at 17-18; Southern Reply 
Comments at 9-10.
---------------------------------------------------------------------------

    1213. Among issues raised by commenters that oppose the proposal, 
one common concern is that the proposal would force affected system 
transmission providers to subsidize interconnection to neighboring 
transmission systems, despite potentially not receiving any energy from 
such interconnection customers, causing increased costs to the affected 
system due to the requirement to mitigate negative thermal, voltage, 
and stability impacts without a corresponding increase in 
benefits.\2297\ North Carolina Commission and Staff also contend that 
the Commission has not provided evidence on this matter that would 
allow the Commission to meet its burden under FPA section 206.\2298\ 
Some commenters assert that the affected system interconnection 
customer should be responsible for the costs of affected system network 
upgrades in exchange for use of the affected system (i.e., via 
transmission service).\2299\ Xcel notes that, for loop flow impacts, 
the affected system interconnection customer may not formally take 
transmission service but may be granted the right to the transmission 
capacity associated with the loop flows they cause, and some 
transmission providers have charged unreserved use for such impacts or 
otherwise required neighbors to pay for the transmission use.\2300\
---------------------------------------------------------------------------

    \2297\ AECI Initial Comments at 9; Duke Southeast Utilities 
Initial Comments at 21-22, 26; EEI Initial Comments at 18-19; North 
Carolina Commission and Staff Initial Comments at 6; PPL Initial 
Comments at 21; Tri-State Initial Comments at 21-22; U.S. Chamber of 
Commerce Initial Comments at 11-12; Xcel Initial Comments at 40.
    \2298\ North Carolina Commission and Staff Initial Comments at 
16.
    \2299\ Tri-State Initial Comments at 20; Xcel Initial Comments 
at 40.
    \2300\ Xcel Initial Comments at 40.
---------------------------------------------------------------------------

    1214. North Carolina Commission and Staff observe that, if the 
Commission were to implement the NOPR proposal and allow RTOs/ISOs to 
obtain independent entity variations from the proposed affected system 
pricing scheme implementing a participant funding model, then North 
Carolina retail and wholesale customers of Duke Energy Carolinas and 
Duke Energy Progress would be paying for affected system network 
upgrade costs when a generating facility interconnects with the PJM-
controlled transmission system in addition to paying for network 
upgrade costs for native interconnection customers when generating 
facilities interconnect with Duke Energy Progress or Duke Energy 
Carolinas-owned transmission facilities, which they argue would be 
patently unjust, unfair, and unduly preferential.\2301\
---------------------------------------------------------------------------

    \2301\ North Carolina Commission and Staff Initial Comments at 
23.
---------------------------------------------------------------------------

    1215. Several commenters argue that the NOPR proposal is contrary 
to important objectives articulated in Order No. 2003.\2302\ For 
instance, Duke Southeast Utilities contend that, if transmission 
providers are required to reimburse affected system interconnection 
customers for costs advanced for affected system network upgrades, such 
transmission providers will seek to obtain rate recovery of their 
reimbursement cost from existing wholesale and retail transmission 
customers, meaning those classes of customers will not be protected 
from adverse rate implications because they will have to absorb all 
affected system network upgrade costs.\2303\ According to Duke 
Southeast Utilities, this is contrary to an important objective 
articulated in Order No. 2003-B of the interconnection pricing policy 
protecting existing transmission customers from adverse rate 
implications associated with interconnection facilities and network 
upgrades required to interconnect a new generating facility.\2304\
---------------------------------------------------------------------------

    \2302\ Duke Southeast Utilities Initial Comments at 23; PPL 
Initial Comments at 20-21.
    \2303\ Duke Southeast Utilities Initial Comments at 23.
    \2304\ Id. (citing Order No. 2003-B, 109 FERC ] 61,287 at P 56).
---------------------------------------------------------------------------

    1216. According to PPL, the pricing policy established in Order No. 
2003 was meant to promote competition in markets ``still dominated by 
non-independent transmission providers.'' \2305\ PPL argues that non-
RTO/ISO transmission providers no longer dominate, and therefore this 
policy is no longer necessary.\2306\ PPL asserts that, contrary to the 
time of Order No. 2003's issuance, and as a result of the size and 
nature of generating facilities being developed in RTO/ISO regions, 
non-RTOs/ISOs might be required to build costly affected system network 
upgrades to accommodate the interconnection of generating facilities in 
adjacent markets. PPL contends that affected system network upgrade 
costs can overwhelm the total network upgrade costs identified for 
reliability or other planning purposes. PPL claims, however, that the 
affected system network upgrade reimbursement proposal in the NOPR is 
directly contrary to the Commission's interconnection pricing policy 
meant to protect existing customers from the rate impacts of 
interconnection-related network upgrades,\2307\ and allows affected 
system interconnection customers to benefit from network upgrades 
without paying for them.\2308\ Thus, PPL asserts that the Commission 
should allow affected system transmission providers the flexibility to 
directly assign affected system network upgrade costs. Duke Southeast 
Utilities concur, asserting that there is ample precedent of the 
Commission accepting, without modification, an affected system 
operating agreement between affected system transmission providers and 
affected system interconnection customers that directly assign network 
upgrade costs to such interconnection customers without 
reimbursement.\2309\
---------------------------------------------------------------------------

    \2305\ PPL Initial Comments at 20 (citing Order 2003-A, 106 FERC 
] 61,220 at P 636).
    \2306\ Id. at 20-21.
    \2307\ Id. at 21 (citing Order 2003-A, 106 FERC ] 61,220 at P 
586; Order 2003-B, 109 FERC ] 61,287 at P 56).
    \2308\ Id. at 21-22.
    \2309\ Duke Southeast Utilities Initial Comments at 24 (citing, 
e.g., Docket No. ER21-1701-000 (involving acceptance of an affected 
system upgrade agreement between Southern and Cooperative Energy)).
---------------------------------------------------------------------------

    1217. Invenergy asserts that the Commission should reject arguments 
challenging the Commission's interconnection pricing policy established 
in Order No. 2003.\2310\ Invenergy contends that this interconnection 
pricing policy was fully litigated in the Order No. 2003 rulemaking 
proceeding and that issues relating to cost causation were fully and 
carefully considered at that time.\2311\ Invenergy also argues that 
Duke Southeast Utilities' reference to Order No. 2003-B is misplaced, 
as the Commission, in Order No. 2003-B, found that the interconnection 
pricing policy fully protected native load customers and that 
transmission providers could make and justify alternative proposals on 
compliance.\2312\
---------------------------------------------------------------------------

    \2310\ Invenergy Reply Comments at 10 (citing Order No. 2003, 
104 FERC ] 61,103 at PP 693-696).
    \2311\ Id. at 11-12 (citing Order No. 2003, 104 FERC ] 61,103 at 
PP 684, 693-696).
    \2312\ Id. at 10-11.
---------------------------------------------------------------------------

    1218. Duke Southeast Utilities and North Carolina Commission and 
Staff assert that the affected system network upgrade reimbursement 
proposal will stifle renewable generating facility

[[Page 61185]]

development.\2313\ For instance, Duke Southeast Utilities argue that 
mandatory reimbursement has the likelihood of chilling development of 
new, mainly renewable, generating facilities in states that consider 
such costs as part of overall development costs when considering 
whether to issue a certificate of public convenience and necessity to 
permit these generating facilities.\2314\
---------------------------------------------------------------------------

    \2313\ Duke Southeast Utilities Initial Comments at 24-25; North 
Carolina Commission and Staff Initial Comments at 21.
    \2314\ Duke Southeast Utilities Initial Comments at 24-25.
---------------------------------------------------------------------------

    1219. Moreover, Duke Southeast Utilities argue that the mandatory 
reimbursement by affected system transmission providers of affected 
system network upgrade costs fails to encourage efficient siting 
decisions by affected system interconnection customers.\2315\ Duke 
Southeast Utilities assert that, if affected system interconnection 
customers are reimbursed for 100% of the costs of network upgrades on 
the affected system plus interest at the Commission-prescribed rate, 
they actually profit financially from such reimbursement.\2316\
---------------------------------------------------------------------------

    \2315\ Id. at 25; Duke Southeast Utilities Reply Comments at 23.
    \2316\ Duke Southeast Utilities Initial Comments at 25.
---------------------------------------------------------------------------

    1220. Invenergy argues that the possibility of certain states 
considering affected system network upgrade costs in permitting 
proceedings does not call the Commission's existing pricing policy into 
question.\2317\ In response to arguments that the NOPR proposal could 
foster inefficient siting, Invenergy asserts that this argument was 
considered and settled in the Order No. 2003 rulemaking 
proceeding.\2318\ Invenergy contends that such comments are speculative 
and ignore other facts, such as that identification of affected system 
network upgrades typically occurs after most siting decisions are made.
---------------------------------------------------------------------------

    \2317\ Invenergy Reply Comments at 12.
    \2318\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 695-
696).
---------------------------------------------------------------------------

    1221. North Carolina Commission and Staff argue that affected 
system costs are no longer incidental or rare and have been escalating 
over time.\2319\ North Carolina Commission and Staff allege that the 
proposed crediting policy will force North Carolina wholesale and 
retail ratepayers to subsidize the policy choices of other states and 
the corporate goals of businesses located in other states.
---------------------------------------------------------------------------

    \2319\ North Carolina Commission and Staff Initial Comments at 
21-22.
---------------------------------------------------------------------------

    1222. Public Interest Organizations urge the Commission to 
disregard North Carolina Commission and Staff's assertions on this 
matter, arguing that the NOPR proposal is unrelated to state and 
corporate policies.\2320\ Public Interest Organizations assert that the 
proposal is meant to address existing gaps in the pro forma LGIP that 
apply to all interconnection customers regardless of fuel type and 
motivation for generating facility development.
---------------------------------------------------------------------------

    \2320\ Public Interest Organizations Reply Comments at 18-19.
---------------------------------------------------------------------------

    1223. WAPA expresses significant concerns with the NOPR proposal, 
emphasizing that it requires the affected system transmission provider 
to reimburse the affected system interconnection customer cash plus 
interest over 20 years for the cost of affected system network 
upgrades.\2321\ WAPA states that, as a Federal agency, it cannot 
provide a cash payment with interest to an interconnection customer 
that does not take transmission service from WAPA.\2322\ According to 
WAPA, per its tariff, it only provides network credits, not cash 
payments, for such customers, and it would need to work with the host 
transmission provider to ensure a mechanism is developed to properly 
credit the affected system interconnection customer.\2323\
---------------------------------------------------------------------------

    \2321\ WAPA Initial Comments at 13.
    \2322\ Id. Specifically, WAPA states that it must deposit all 
revenues received into a reclamation fund and that it would need an 
appropriation from Congress to use the money in the reclamation fund 
to pay interconnection customers. Id. at 13 n.17 (citing 43 
U.S.C.392a). WAPA also notes that its current tariff specifically 
provides that WAPA cannot pay interest on any funds advanced by 
interconnection customers. Id. (citing WAPA, WAPA Open Access 
Transmission Tariff, section 17.3 (1.0.0)).
    \2323\ Id. at 13-14.
---------------------------------------------------------------------------

    1224. Also on proposed article 3 of the pro forma affected system 
facilities construction agreement, Tri-State notes that proposed 
article 3.2.2.1 (Repayment) does not contain a reference to determine 
if affected system network upgrades are unnecessary.\2324\ Separately, 
Tri-State also suggests revisions to state that the repayment period 
should end no later than 20 years from the completion of the 
construction of the affected system interconnection customer's 
generating facility, rather than completion of the construction of the 
affected system network upgrades.\2325\
---------------------------------------------------------------------------

    \2324\ Tri-State Initial Comments at 33.
    \2325\ Id., app. B at 133.
---------------------------------------------------------------------------

    1225. With regard to proposed article 4 (Security, Billing, and 
Payments), PacifiCorp offers suggested revisions to proposed article 
4.1, which PacifiCorp asserts are intended to, among other things, 
clarify that additional security will be required from the affected 
system interconnection customer if the affected system transmission 
provider determines that the costs of facilities may exceed the initial 
estimate provided to the affected system interconnection 
customer.\2326\ PPL also states that affected system interconnection 
customers should be required to meet credit and security 
requirements.\2327\
---------------------------------------------------------------------------

    \2326\ PacifiCorp Initial Comments at 37.
    \2327\ PPL Initial Comments at 20.
---------------------------------------------------------------------------

    1226. As for proposed article 6 (Termination of Agreement), Tri-
State suggests consolidating proposed article 6.3.3 (Pre-construction 
of Installation) with proposed article 2.2.3 and proposes removing some 
language in proposed article 6.4 (Survival Rights) that it argues is 
duplicative of proposed article 2.4.\2328\
---------------------------------------------------------------------------

    \2328\ Tri-State Initial Comments at 33-34.
---------------------------------------------------------------------------

    1227. Commenters also respond to the proposed confidentiality 
provisions. Southern asserts that proposed article 8.1 in the pro forma 
affected system facilities construction agreement, section 13.1 in the 
pro forma LGIP, and article 22 in the pro forma LGIA should be revised 
to reflect the use of backup servers and the obligations of 
transmission providers to share information under NERC Reliability 
Standards.\2329\ Southern asserts that it is administratively difficult 
to meet the requirements in these provisions that specify that 
confidential information be destroyed or returned, arguing that this 
provision should allow information to be stored on backup servers. 
Southern also notes that, under NERC Reliability Standards, which were 
developed after the effective date of Order No. 2003, transmission 
providers must disclose confidential information to neighboring 
transmission providers, and therefore, this language should be updated 
to reflect that the transmission provider must share this confidential 
information.
---------------------------------------------------------------------------

    \2329\ Southern Initial Comments at 19.
---------------------------------------------------------------------------

    1228. Moving to proposed Appendix A, MISO contends that there is no 
need for a commercial operation date to be listed for affected system 
network upgrades in proposed Appendix A.\2330\ MISO argues that 
commercial operation is something that occurs in the LGIA context, 
where the affected system interconnection customer's injection of 
energy onto the host transmission provider is memorialized.
---------------------------------------------------------------------------

    \2330\ MISO Initial Comments at 97.

---------------------------------------------------------------------------

[[Page 61186]]

(2) Requests for Clarification
    1229. Southern explains that the pro forma LGIA and Commission 
policy require that interconnection customers pay for the cost of 
system protection facilities, and Southern requests that the Commission 
clarify that it is not changing this policy.\2331\
---------------------------------------------------------------------------

    \2331\ Southern Initial Comments at 17; Southern Reply Comments 
at 8 (citing pro forma LGIA art. 9.7.4.1; Order No. 845, 163 FERC ] 
61,043 at P 371).
---------------------------------------------------------------------------

(3) Miscellaneous
    1230. Eversource states that the concerns of interconnection 
customers and transmission providers with regard to ISO-NE's related 
facilities agreement (RFA) \2332\ are not addressed by the NOPR 
proposal, which address coordination between different tariffs and 
system operators, and requests that the Commission clarify this 
difference.\2333\
---------------------------------------------------------------------------

    \2332\ ISO-NE's RFA is an intra-RTO/ISO agreement with a 
specific transmission owner.
    \2333\ Eversource Initial Comments at 32.
---------------------------------------------------------------------------

(c) Commission Determination
    1231. We adopt, with modifications, the NOPR proposal to establish 
a pro forma affected system facilities construction agreement in 
Appendix 11 of the pro forma LGIP.\2334\ The pro forma affected system 
facilities construction agreement, as adopted herein, closely tracks 
the NOPR proposal: the affected system transmission provider and the 
affected system interconnection customer(s) will enter into the 
agreement; and the agreement will set forth the terms and conditions by 
which the affected system transmission provider will be responsible for 
the design, procurement, construction, and installation of all network 
upgrades and terms and conditions by which the affected system 
interconnection customer will initially fund, and be reimbursed for, 
the cost of any assigned affected system network upgrades. As described 
below, we modify the following proposed articles in the pro forma 
affected system facilities construction agreement: (1) article 2.2.2 
(Termination Upon Default); (2) article 2.2.3 (Consequences of 
Termination); (3) article 3.1.1 (Transmission Provider Obligations); 
(4) article 3.1.2.1 (Right to Suspend); (5) article 3.1.2.3 (Right to 
Suspend Due to Default); (6) article 5.1 (Events of Breach); (7) 
article 5.2 (Notice of Breach, Cure and Default); (8) article 5.2.1; 
and (9) article 5.2.2.\2335\ Additionally, we establish a pro forma 
multiparty affected system facilities construction agreement set forth 
in Appendix 12 of the pro forma LGIP.
---------------------------------------------------------------------------

    \2334\ NOPR, 179 FERC ] 61,194 at P 197.
    \2335\ We further note that we streamline article 6.2 
(Termination and Removal) of the pro forma affected system 
facilities construction agreement with ministerial revisions, as 
well as add article 5.2 to provide a definition of ``breaching 
party,'' which changes the numbering for proposed article 5.2 
(Notice of Breach, Cure, and Default) to article 5.3 and proposed 
article 5.3 (Rights in the Event of Default) to article 5.4.
---------------------------------------------------------------------------

    1232. We find that a pro forma affected system facilities 
construction agreement will improve the efficiency of the 
interconnection process by reducing delays through improved 
coordination among relevant parties, consistent with the Commission's 
preliminary findings in the NOPR and with record support.\2336\ As Duke 
Southeast Utilities explains, the adoption of a pro forma affected 
system facilities construction agreement will offer uniformity of these 
types of agreements to be tendered by affected system transmission 
providers across the country.\2337\ Such uniformity will help reduce 
the potential for undue discrimination. As the Commission found in 
Order No. 2003, a standard set of procedures as part of the tariff for 
all jurisdictional transmission facilities will minimize opportunities 
for undue discrimination.\2338\
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    \2336\ NOPR, 179 FERC ] 61,194 at P 200; see also Ameren Initial 
Comments at 23; Duke Southeast Utilities Initial Comments at 18; 
Pine Gate Initial Comments at 42; SPP Initial Comments at 19-20.
    \2337\ Duke Southeast Utilities Initial Comments at 18.
    \2338\ Order No. 2003, 104 FERC ] 61,103 at P 11.
---------------------------------------------------------------------------

    1233. We also adopt a pro forma multiparty affected system 
facilities construction agreement.\2339\ Similar to adopting the pro 
forma multiparty affected system study agreement, as discussed earlier, 
we find that the adoption of the pro forma multiparty affected system 
facilities construction agreement will further improve coordination and 
further minimize opportunities for undue discrimination, even relative 
to a two-party agreement. Also, similar to the adoption of the pro 
forma affected system study agreement, the establishment of the pro 
forma multiparty affected system facilities construction agreement 
aligns with the requirement to study affected system interconnection 
requests in clusters. Specifically, such a multiparty agreement will 
allow for a common agreement for the affected system transmission 
provider to enter into with all affected system interconnection 
customers for the construction of affected system network upgrades 
identified by the cluster study that are assigned to more than one 
affected system interconnection customer. Below, in discussing relevant 
article-specific comments, we discuss noteworthy, additional changes 
needed to convert the pro forma affected system facilities construction 
agreement from a two-party agreement to a multiparty agreement.
---------------------------------------------------------------------------

    \2339\ PPL Initial Comments at 20; SPP Initial Comments at 19-
20.
---------------------------------------------------------------------------

    1234. As with the pro forma multiparty affected system study 
agreement, discussed above, the pro forma multiparty affected system 
facilities construction agreement that we adopt in this final rule 
closely follows the two-party agreement, with changes needed to convert 
to a multiparty agreement. In article 2.2.2 (Termination Upon Default), 
we establish that the default by one affected system interconnection 
customer does not allow the non-defaulting affected system 
interconnection customer(s) the right to terminate the agreement and 
that, instead, the defaulting party may be removed from the agreement 
by the affected system transmission provider. In article 3.1.2.1 (Right 
to Suspend), we maintain the affected system interconnection customer's 
right to suspend but only upon the mutual agreement of all affected 
system interconnection customers that are party to the multiparty 
agreement. In article 5.3 (Notice of Breach, Cure, and Default), we 
establish multiparty cure procedures whereby the non-breaching parties 
may cure the other affected system interconnection customer's breach.
    1235. We decline to make changes to the proposed pro forma affected 
system facilities construction agreement and conforming changes to the 
pro forma LGIP, aligning with Xcel's suggestion that the ``affected 
system transmission provider'' should be renamed an ``affected system 
operator.'' Instead, we clarify that the pro forma LGIP is written for 
a specific transmission provider. When a transmission provider is 
fulfilling its obligations as a host transmission provider, the pro 
forma LGIP refers to the host transmission provider's interaction with 
the ``affected system operator.'' However, when the pro forma LGIP 
references a transmission provider and its obligations as the operator 
of an affected system, we use the term ``transmission provider,'' as 
the pro forma LGIP is setting the requirements of the transmission 
provider, whether acting as the host or affected system transmission 
provider, and that is a different perspective from a host transmission 
provider's interaction with a separate ``affected system operator.''
    1236. In response to Tri-State's suggestion to revise proposed 
article 2 of the pro forma affected system facilities construction 
agreement to

[[Page 61187]]

clarify that the execution of an LGIA does not convey transmission 
service, we decline to adopt this request, as it is unnecessary.\2340\ 
However, we accept Tri-State's suggested revisions to article 3.1.1 of 
the pro forma affected system facilities construction agreement to 
clarify that the affected system transmission provider shall not 
undertake any actions inconsistent with its safety practices, material 
and equipment specifications, design criteria and construction 
procedures, labor agreements, or any applicable laws and regulations.
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    \2340\ See Order No. 2003, 104 FERC ] 61,103 at P 118 (stating 
that ``[t]he Commission continues to treat interconnection and 
delivery as separate aspects of transmission service, and an 
Interconnection Customer may request Interconnection Service 
separately from transmission service (delivery of the Generating 
Facility's power output)''); Order No. 2003-A, 106 FERC ] 61,220 at 
P 113 (``reiterat[ing] that Interconnection Service is separate from 
the delivery component of Transmission Service and that the mere 
interconnection of the Generating Facility is unlikely to harm 
reliability on Affected Systems'').
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    1237. We modify proposed articles 2.2.2 and 5.2 (now articles 2.2.2 
and 5.3) of the pro forma affected system facilities construction 
agreement in response to comments from Southern and Tri-State regarding 
termination and cure. Proposed article 2.2.2 establishes that a non-
breaching party has the right to terminate the pro forma affected 
system facilities construction agreement, provided that termination 
does not pose a reliability threat and that the breaching party has not 
undertaken efforts to cure the breach, pursuant to article 5.3 (Notice 
of Breach, Cure and Default). However, consistent with comments from 
Southern,\2341\ we agree that termination and default rights in the pro 
forma affected system facilities construction agreement should be 
consistent with the pro forma LGIA. Accordingly, as adopted, we modify 
articles 2.2.2 and 5.2 (now articles 2.2.2 and 5.3) of the pro forma 
affected system facilities construction agreement to make them 
consistent with the existing default provisions in article 17 of the 
pro forma LGIA (Default), which also establishes default and cure 
provisions in the event of a breach.
---------------------------------------------------------------------------

    \2341\ Southern Initial Comments at 18.
---------------------------------------------------------------------------

    1238. We also modify proposed article 2.2.3 (Consequences of 
Termination) of the pro forma affected system facilities construction 
agreement in response to comments from Tri-State and Invenergy 
suggesting that it would require affected system interconnection 
customers to be responsible for the costs of additional facilities that 
are caused by another interconnection customer terminating its affected 
system facilities construction agreement or that interconnection 
customer's LGIA.\2342\ Specifically, we remove the final sentence from 
proposed article 2.2.3 that an ``affected system interconnection 
customer is responsible for the cost of additional facilities that is 
caused to another interconnection customer due to the termination of 
this Agreement, affected system interconnection customer's LGIA, or any 
affected system interconnection customer's other Affected System 
Facilities Construction Agreement(s).'' We find that deletion of this 
sentence is needed because the affected system interconnection customer 
should not be responsible for any additional facilities that are 
assigned to another interconnection customer under these circumstances. 
As written, the provision implies that an affected system 
interconnection customer could be responsible for any network upgrade 
identified as a result of the agreement's termination, even if the 
newly assigned network upgrade is on a different transmission 
provider's transmission system than the transmission provider that is a 
signatory to the terminated agreement. Additionally, we note that the 
pro forma LGIA contains no similar requirement that upon termination of 
an LGIA that the interconnection customer is responsible for any 
additional costs assigned to another interconnection customer as a 
result of the LGIA's termination and based on the comments received, 
the record does not support including the provision.
---------------------------------------------------------------------------

    \2342\ Invenergy Initial Comments at 45; Tri-State Initial 
Comments at 20.
---------------------------------------------------------------------------

    1239. MISO requests a cross-default provision between the pro forma 
affected system facilities construction agreement and the pro forma 
LGIA because MISO asserts that, if an affected system interconnection 
customer does not meet its obligations under its affected system 
facilities construction agreement, it is unclear how that would affect 
that interconnection customer's LGIA on its host transmission 
system.\2343\ In response, we clarify that a breach under the pro forma 
affected system facilities construction agreement does not constitute a 
breach under the pro forma LGIA. We are unpersuaded that cross-default 
provisions between the pro forma affected system facilities 
construction agreement and the pro forma LGIA are necessary because 
both the pro forma affected system facilities construction agreement 
and the pro forma LGIA individually already contain default provisions.
---------------------------------------------------------------------------

    \2343\ MISO Initial Comments at 97.
---------------------------------------------------------------------------

    1240. In addition, we are concerned that a cross-default provision, 
which could result in the termination of an interconnection customer's 
interconnection service based on actions under a separate agreement, 
could raise contractual complications because the host transmission 
provider will not be a party to the affected system facilities 
construction agreement. We note, however, that any affected system 
interconnection customer that defaults on its obligations under the pro 
forma affected system facilities construction agreement may face 
consequences, including, for example, curtailment. Additionally, we 
find that article 4.1 of the pro forma affected system facilities 
construction agreement already contains sufficient security provisions 
to protect a transmission provider in the situation that the affected 
system interconnection customer defaults on the agreement and which 
discourages non-payment by the interconnection customer.
    1241. We modify proposed article 3.1.2.1 (Right to Suspend for 
Force Majeure Event) of the pro forma affected system facilities 
construction agreement in response to comments that the proposed 
suspension provision is too restrictive and inconsistent with the 
suspension provision in the pro forma LGIA.\2344\ Specifically, we 
revise article 3.1.2.1 to remove the limitation on the right to suspend 
to force majeure events and modify the suspension provision to allow an 
affected system interconnection customer to suspend work required under 
the affected system facilities construction agreement for up to three 
years.\2345\ We also modify article 3.1.2.1 to remove the requirement 
for the affected system interconnection customer, prior to suspension, 
to provide security to the affected system transmission provider of the 
higher of $5 million or the total cost of all affected system network 
upgrades listed in Appendix A of the agreement. We find the requirement 
unnecessary because, under article 4.1 (Provision of Security) of the 
pro forma affected system facilities construction agreement, the 
affected system interconnection customer would have already been 
required to provide security for the applicable portion of the affected 
system network upgrades. With these changes to article 3.1.2.1, the 
suspension provision in the pro forma affected

[[Page 61188]]

system facilities construction agreement will mirror the suspension 
provision in the pro forma LGIA.\2346\
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    \2344\ Pro forma LGIA art. 5.16.
    \2345\ We also make various conforming revisions throughout 
proposed article 3.1.2.1 of the pro forma affected system facilities 
construction agreement, consistent with this modification to the 
suspension provision.
    \2346\ Pro forma LGIA art. 5.16.
---------------------------------------------------------------------------

    1242. Additionally, we revise proposed article 3.1.2.3 (Right to 
Suspend Due to Default) of the pro forma affected system facilities 
construction agreement, which provides for the right to suspend due to 
default. The revisions we adopt to this provision clarify that if an 
affected system interconnection customer defaults, the affected system 
interconnection customer will be responsible for any additional 
expenses incurred by the affected system transmission provider 
associated with the construction and installation of the affected 
system network upgrades, as set forth in article 2.2.3 (Consequences of 
Termination). We find that the revisions will align the language in the 
pro forma affected system facilities construction agreement with 
similar language in the pro forma LGIP, as suggested by 
PacifiCorp.\2347\ However, we reject the proposed revisions suggested 
by Tri-State to article 3.1.2.3 because they would alter the right to 
suspend to allow an affected system transmission provider the right to 
suspend in the event of a breach, rather than in the event of a 
default. Tri-State's suggested changes to article 3.1.2.3 would 
contradict other provisions in the pro forma LGIA and the pro forma 
affected system facilities construction agreement, which allow for the 
breaching party to cure a breach as is appropriate.
---------------------------------------------------------------------------

    \2347\ PacifiCorp Initial Comments, attach. A, at 54.
---------------------------------------------------------------------------

    1243. We adopt article 3.2.2.1 (Repayment) of the pro forma 
affected system facilities construction agreement as proposed, which is 
consistent with existing Commission precedent.\2348\
---------------------------------------------------------------------------

    \2348\ Order No. 2003, 104 FERC ] 61,103 at PP 693-696, 720-739; 
Order No. 2003-A, 106 FERC ] 61,220 at PP 584-586 (stating that the 
transmission system is a cohesive, integrated network that operates 
as a single piece of equipment, and that network facilities benefit 
all transmission customers; further, even if a customer can be said 
to have caused the addition of a grid facility, such addition 
represents a system expansion used by and benefiting all users due 
to the integrated nature of the grid); Order No. 2003-C, 111 FERC ] 
61,401 at P 13; NARUC v. FERC, 475 F.3d 1277, 1285 (D.C. Cir. 2007) 
(affirming the Commission's conclusions); W. Mass. Elec. Co. v. 
FERC, 165 F.3d 922, 927 (D.C. Cir. 1999).
---------------------------------------------------------------------------

    1244. Some commenters are concerned that affected systems repayment 
could force affected system transmission providers to subsidize 
interconnection to neighboring systems, stifle renewable generating 
facility development, or facilitate inefficient siting.\2349\ However, 
in the NOPR, the Commission did not propose to change the Commission's 
affected system repayment policy; instead, the Commission simply 
proposed to memorialize the Commission's existing policy in a pro forma 
agreement for affected systems.\2350\ As a result, we decline to 
address arguments on the merits of the Commission's affected systems 
repayment policy in this final rule.
---------------------------------------------------------------------------

    \2349\ AECI Initial Comments at 9; Duke Southeast Utilities 
Initial Comments at 21-22, 26; EEI Initial Comments at 18-19; North 
Carolina Commission and Staff Initial Comments at 6; PPL Initial 
Comments at 21; Tri-State Initial Comments at 21-22; U.S. Chamber of 
Commerce Initial Comments at 11-12; Xcel Initial Comments at 40.
    \2350\ See Order No. 2003, 104 FERC ] 61,103 at PP 738-739; see 
also pro forma LGIA art. 11.4.
---------------------------------------------------------------------------

    1245. With respect to the concerns raised by WAPA that it is unable 
to repay affected system interconnection customers due to limitations 
based on its Federal status, we decline to rule on the specifics of 
individual transmission provider circumstances and instead find that 
such concerns are better raised in a compliance proceeding, including 
such a proceeding with a reciprocity tariff filing, if WAPA chooses to 
file one.
    1246. In response to requests for clarification from Southern, we 
clarify that, consistent with the Commission's findings in Order No. 
2003, we are not changing our policy requiring the interconnection 
customer, at its expense, to install, operate, and maintain system 
protection facilities as a part of its generating facility or its 
interconnection facilities.\2351\ Also in response to Southern and 
consistent with the Commission's findings in Order No. 2003, 
transmission providers may make a filing to the Commission proposing an 
incremental rate to the affected system interconnection customer, as 
more fully described in Order Nos. 2003-A and 2003-B,\2352\ if native 
load and existing transmission customers are not being held harmless, 
though we reiterate that the transmission provider bears the full 
burden of showing that any such proposal is just, reasonable, and not 
unduly discriminatory or preferential and is appropriate under the 
circumstances.\2353\
---------------------------------------------------------------------------

    \2351\ Pro forma LGIA art. 9.7.4.1; see also Order No. 845, 163 
FERC ] 61,043 at P 371.
    \2352\ Order No. 2003-A, 106 FERC ] 61,220 at P 586; Order No. 
2003-B, 109 FERC ] 61,287 at P 56.
    \2353\ Order No. 2003-B, 109 FERC ] 61,287 at P 56.
---------------------------------------------------------------------------

    1247. We adopt Tri-State's suggested revisions to proposed article 
3.2.2.1 of the pro forma affected system facilities construction 
agreement regarding the terms for repayment of affected system network 
upgrades. Consistent with existing pro forma LGIA provisions,\2354\ the 
parties may mutually agree to a repayment schedule for all applicable 
costs associated with affected system network upgrades, with complete 
repayment not to exceed 20 years from the commercial operation date of 
the affected system interconnection customer's generating facility.
---------------------------------------------------------------------------

    \2354\ Pro forma LGIA art. 11.4.1.
---------------------------------------------------------------------------

    1248. We decline to adopt additions to proposed article 4.1 
(Provision of Security) of the pro forma affected system facilities 
construction agreement suggested by PacifiCorp that would add 
additional security posting requirements, to the extent that costs to 
construct affected system network upgrades increase.\2355\ Proposed 
article 4.1 is consistent with security provisions outlined in pro 
forma LGIA article 11.5 (Provision of Security), and we find that such 
provisions should be consistent across both the pro forma affected 
system facilities construction agreement and the pro forma LGIA. We 
also find that the security provision requirements are already 
sufficiently clear in article 4.1 of the pro forma affected system 
facilities construction agreement. Specifically, article 4.1 of the pro 
forma affected system facilities construction agreement provides that 
``security for payment shall be in an amount sufficient to cover the 
costs for constructing, procuring and installing the applicable portion 
of Affected System Network Upgrades.''
---------------------------------------------------------------------------

    \2355\ PacifiCorp Initial Comments at 37.
---------------------------------------------------------------------------

    1249. In response to comments from PPL asserting that affected 
system interconnection customers should be responsible for meeting the 
affected system transmission provider's creditworthiness 
requirements,\2356\ because the pro forma affected system facilities 
construction agreement is an agreement between the affected system 
transmission provider and the affected system interconnection customer, 
we clarify that affected system interconnection customers are obligated 
to meet the affected system transmission provider's creditworthiness 
and security requirements. We note that this is consistent with the 
parallel requirement for interconnection customers to meet the 
creditworthiness and security requirements of the host transmission 
provider outlined in pro forma LGIA article 11.5.1.
---------------------------------------------------------------------------

    \2356\ PPL Initial Comments at 20.
---------------------------------------------------------------------------

    1250. We revise proposed article 5.1(b) of the pro forma affected 
system facilities construction agreement, consistent with PacifiCorp's 
suggestion, to remove the requirement that a party will be in breach 
for failure to comply with a material term or condition of the 
agreement due to an inaccuracy in a representation, warranty, or 
covenant

[[Page 61189]]

made in the agreement resulting in a breach under the agreement. We 
find that there is no reason why an inaccuracy should lead to a 
potential breach, or even a default, under the agreement. We note that 
the pro forma LGIA contains no similar provision.
    1251. We revise proposed article 5.2.1, now article 5.3.1, of the 
pro forma affected system facilities construction agreement to extend 
the cure period for a breach from 30 calendar days to 60 calendar days 
and proposed article 5.2.2, now article 5.3.2, of the pro forma 
affected system facilities construction agreement to remove the 
additional cure period if the breach remains despite the occurrence of 
good faith steps. We find that the revision will simplify the cure 
requirements while providing breaching party with an extra 30 calendar 
days at the onset to cure its breach. We also revise article 5.3.2 to 
include a reference that if the breaching party defaults, then the non-
defaulting party may terminate the agreement in accordance with article 
6.2 (Termination) of the agreement. We further clarify article 5 of 
both the pro forma affected system facilities construction agreement 
and the pro forma multiparty affected system facilities construction 
agreement that a failure to cure a breach of either agreement will also 
constitute a default.
    1252. We decline to delete proposed article 6.4 (Survival of 
Rights) of the pro forma affected system facilities construction 
agreement, as suggested by Tri-State. Although Tri-State asserts that 
proposed article 6.4 should be deleted because it is duplicative of 
proposed article 2.4 (Survival),\2357\ we find that the contents are 
sufficiently different to merit their separate inclusion. Specifically, 
article 2.4 provides for the survival of the pro forma affected system 
facilities construction agreement until all liabilities incurred prior 
to termination are fulfilled, whereas article 6.4 clarifies the scope 
of the rights of parties following termination to provide for final 
billing, enforcement of liabilities and confidentiality obligations, 
and for potential judicial or administrative action.
---------------------------------------------------------------------------

    \2357\ Tri-State Initial Comments at 34.
---------------------------------------------------------------------------

    1253. In response to comments from Southern regarding updates to 
the confidentiality provisions contained in proposed article 8 
(Confidentiality) of the pro forma affected system facilities 
construction agreement,\2358\ we find that, because we are not 
proposing to revise the confidentiality provision set forth in the pro 
forma LGIA--instead, we are merely adopting it into the pro forma 
affected system facilities construction agreement--article 8, as 
adopted, is just and reasonable. Contrary to Southern's comments, the 
confidentiality provisions in article 8.1.7 of the pro forma affected 
system facilities construction agreement allow for confidential 
information to be destroyed, erased, deleted or, as applicable, 
returned, not for such information to exclusively be ``destroyed or 
returned.'' \2359\ Thus, such language reflects the fact that most 
electronic information is stored in backup servers. Moreover, in 
response to Southern's concern that deleting information stored on 
backup servers is administratively difficult, we find that Southern has 
not provided any evidence or explained why this might be so.
---------------------------------------------------------------------------

    \2358\ Southern Initial Comments at 19.
    \2359\ Id.
---------------------------------------------------------------------------

    1254. In response to MISO's contention that there is no need to 
list a commercial operation date for affected system network upgrades 
in Appendix A of the pro forma affected system facilities construction 
agreement,\2360\ we agree and modify Appendix A, now Attachment A, to 
remove the commercial operation date from tables 1 and 3. However, we 
note that parties may find it useful to memorialize the commercial 
operation date for the affected system interconnection customer's 
generating facility because, under article 2.2.1 of the pro forma 
affected system facilities construction agreement, the parties to the 
agreement may alter the affected system facilities construction 
agreement by mutual consent if the in-service state date for the 
affected system network upgrades or the commercial operation date for 
the generating facility changes. To the extent MISO is concerned that 
there could be different commercial operation dates listed for affected 
system network upgrades in the LGIA and the affected system facilities 
construction agreement, the host transmission provider must update the 
commercial operation date for affected system network upgrades in the 
affected system interconnection customer's LGIA with the host system, 
to avoid discrepancies between the affected system facilities 
construction agreement and the LGIA.
---------------------------------------------------------------------------

    \2360\ MISO Initial Comments at 97.
---------------------------------------------------------------------------

    1255. Finally, in response to comments from Eversource and ISO-
NE,\2361\ we clarify that these pro forma affected system agreements 
are distinct from intra-RTO/ISO agreements, like ISO-NE's RFA, which 
RTOs/ISOs may use to coordinate the construction of necessary network 
upgrades within multiple transmission owner service territories within 
the same RTO/ISO.\2362\
---------------------------------------------------------------------------

    \2361\ Eversource Initial Comments at 32; ISO-NE Initial 
Comments at 38.
    \2362\ Eversource Initial Comments at 31-32.
---------------------------------------------------------------------------

d. Affected System Modeling and Study Assumptions
i. NOPR Proposal
    1256. As the Commission explained in the NOPR, when an 
interconnection customer submits an interconnection request, they must 
choose to be studied as ERIS or NRIS, depending on the level of 
deliverability they seek for the output of their generating facility. 
For interconnection customers seeking to deliver their generating 
facility's electric output using the existing firm or non-firm capacity 
of the transmission provider's system on an as-available basis, the 
interconnection customer will choose an ERIS study. An interconnection 
customer will choose an NRIS study when seeking to integrate their 
generating facility with the transmission provider's system (1) in a 
manner comparable to that in which the transmission provider integrates 
its generating facilities to serve native load customers or (2) in an 
RTO/ISO with market-based congestion management, in the same manner as 
network resources.\2363\ An NRIS study goes beyond the prerequisite 
ERIS study and uses stricter modeling standards \2364\ to assess an 
interconnection request to ensure that the interconnection customer's 
electric output is deliverable to load in aggregate on the host

[[Page 61190]]

transmission provider's system.\2365\ Such a deliverability analysis 
varies regionally but can analyze anything from various stressed 
dispatch scenarios to an additional set of contingencies. As such, an 
NRIS study will likely identify more network upgrades to accommodate 
the interconnection of a generating facility than an ERIS study because 
NRIS provides a higher level of interconnection service than ERIS.
---------------------------------------------------------------------------

    \2363\ ``Network Resource shall mean any designated generating 
resource owned, purchased, or leased by a Network Customer under the 
Network Integration Transmission Service Tariff. Network Resources 
do not include any resource, or any portion thereof, that is 
committed for sale to third parties or otherwise cannot be called 
upon to meet the Network Customer's Network Load on a non-
interruptible basis.'' Pro forma LGIP section 1; pro forma LGIA art. 
1.
    \2364\ NOPR, 179 FERC ] 61,194 at P 210. The term ``modeling 
standard'' refers to the distribution factor threshold on a 
transmission element used by transmission providers, such that 
beyond this threshold an interconnection request will require 
network upgrades. For example, in SPP, if a transmission element is 
found to be overloaded in an interconnection study, and an NRIS 
interconnection request has over a 3% distribution factor on that 
element (3% being SPP's distribution factor threshold for NRIS 
requests), the requesting entity will be assigned network upgrades. 
SPP uses a 19.5% distribution factor threshold for ERIS requests. 
See EDF Renewable Energy, Inc. v. Midcontinent Indep. Sys. Operator, 
Inc., 168 FERC ] 61,173 at P 17. A lower threshold indicates a 
stricter modeling standard because a smaller impact triggers network 
upgrades. Additionally, when conducting an affected system analysis, 
although some RTOs/ISOs (PJM and SPP, for example) use a modeling 
standard associated with the same level of service as requested on 
the host transmission provider's transmission system, the output of 
proposed generating facilities is always sunk into the host 
transmission provider's transmission system by reducing the output 
of other generating facilities on that system. Id. P 85.
    \2365\ See Order No. 2003, 104 FERC ] 61,103 at P 768; Order No. 
2003-A, 106 FERC ] 61,220 at P 500. Specifically, a transmission 
provider studying generating facility for NRIS would study the 
transmission system at peak load, under a variety of severely 
stressed conditions to determine whether, with the generating 
facility operating at full output, the aggregate of generation in 
the local area can be delivered to the aggregate of load, consistent 
with reliability criteria and procedures.
---------------------------------------------------------------------------

    1257. As the Commission also explained in the NOPR, when a host 
transmission provider notifies an affected system operator of a 
possible impact on its system from an interconnection request in the 
host's queue, it must specify whether the interconnection customer 
requested ERIS or NRIS. Currently, there is no requirement for affected 
system transmission providers to apply either ERIS or NRIS modeling 
standards to study interconnection requests made on neighboring 
systems. For example, MISO uses ERIS studies for all affected system 
interconnection requests, while PJM and SPP use the modeling standard 
associated with the level of service requested on the host system. 
(They study ERIS requests as ERIS and NRIS requests as NRIS.) \2366\
---------------------------------------------------------------------------

    \2366\ EDF Renewable Energy, Inc. v. Midcontinent Indep. Sys. 
Operator, Inc., 168 FERC ] 61,173 at PP 75-76.
---------------------------------------------------------------------------

    1258. In the NOPR, the Commission preliminarily found that it was 
unjust and unreasonable for an affected system transmission provider to 
study interconnection requests on other transmission systems using NRIS 
modeling standards, regardless of the level of service requested on the 
host transmission system. The Commission noted that, unlike the host 
transmission provider with which the affected system interconnection 
customer will directly interconnect, an affected system transmission 
provider does not have a continuing obligation to operate its system so 
that NRIS resources will remain deliverable on the host system. Without 
such an obligation, the Commission stated that an affected system 
interconnection customer may be required to construct significant 
network upgrades on the transmission provider's affected system, but 
not be fully deliverable due to curtailment or congestion on the 
affected system. The Commission was concerned that this could result in 
unjust and unreasonable rates by increasing the costs for the 
interconnection customer without a commensurate increase in service.
    1259. The Commission proposed to require, under new pro forma LGIP 
section 9.6,\2367\ the affected system transmission provider to study 
interconnection requests using ERIS modeling standards, regardless of 
the requested level of service on the host transmission provider's 
transmission system.\2368\
---------------------------------------------------------------------------

    \2367\ We note that under the NOPR proposal, this reform was in 
pro forma LGIP section 9.6; however, under the final rule, the 
reform is in pro forma LGIP section 9.7.
    \2368\ NOPR, 179 FERC ] 61,194 at P 211.
---------------------------------------------------------------------------

    1260. The Commission also explained that if an affected system 
transmission provider believed that it was necessary to study an 
interconnection request that is requesting NRIS-level service using 
NRIS modeling standards, such a transmission provider could make a 
filing under FPA section 205. The Commission explained that it would 
evaluate such case-by-case FPA section 205 filings to determine whether 
they were just, reasonable, and not unduly discriminatory or 
preferential.\2369\ The Commission noted that an affected system 
transmission provider making this type of filing should provide 
evidence indicating that using NRIS modeling standards in such a 
scenario would not treat similarly situated customers differently or 
afford similar treatment to dissimilar customers. In addition, this FPA 
section 205 filing could contain, for example, such supporting 
documentation as a reference to a NERC Reliability Standard violation, 
an operational concern such as over-duty breakers, fault current 
violations, impacts on transmission stability, increased loop flows, or 
other concerns that implicate any other critical reliability 
parameters.
---------------------------------------------------------------------------

    \2369\ 16 U.S.C. 824d.
---------------------------------------------------------------------------

    1261. The Commission stated that a modeling standard would create 
consistency in the modeling standards used across all transmission 
regions.\2370\ The Commission also stated that ERIS modeling standards 
generally reduce the number and cost of network upgrades identified 
and, by using ERIS modeling standards, interconnection customers would 
be subject to fewer late-stage cost increases, which would reduce the 
number of potential restudies and withdrawals thereby addressing the 
concerns that the Commission has preliminarily found to result in 
unjust, unreasonable, and unduly discriminatory or preferential 
Commission-jurisdictional rates. The Commission acknowledged that using 
a less stringent modeling standard may result in more frequent 
redispatch or curtailment by not fully capturing all the potential 
impacts of the interconnection generating facility(ies) on an affected 
system.\2371\ Nevertheless, the Commission stated that it believed that 
these risks were limited in nature and any significant impact would be 
captured by an ERIS study, which would ensure that a proposed 
generating facility can safely connect the affected system under the 
expectation it will deliver its electric output using the existing firm 
or non-firm capacity of the affected system transmission provider's 
system on an as-available basis.
---------------------------------------------------------------------------

    \2370\ The Commission noted that, while this proposal would 
standardize the use of ERIS for affected system studies, individual 
transmission providers use different specific thresholds for ERIS 
studies. NOPR, 179 FERC ] 61,194 at P 212 n.292.
    \2371\ Id. P 213.
---------------------------------------------------------------------------

    1262. The Commission sought comment on: (1) how to align the 
possibility for such case-by-case FPA section 205 filings with the 
required timeline for the affected system study and other deadlines 
proposed in the NOPR; (2) whether the proposed reform will adversely 
affect reliability for the affected system transmission provider or the 
host transmission provider; (3) the potential impact of requiring 
affected system transmission providers to use ERIS modeling standards 
when an interconnection customer seeks NRIS on the host transmission 
provider's system; and (4) whether there are modifications to this 
proposal that would reduce the likelihood of curtailment or redispatch 
on the affected system transmission provider's system without requiring 
the affected system interconnection customer to pay network upgrade 
costs that are not commensurate with the level of service it 
receives.\2372\
---------------------------------------------------------------------------

    \2372\ Id. PP 211, 213, 215.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1263. Numerous commenters support the NOPR proposal.\2373\ ELCON 
suggests that standardization of affected system modeling and 
assumptions furthers certainty and accountability, resulting

[[Page 61191]]

in a more transparent, efficient, and cost-effective interconnection 
process.\2374\ Some commenters argue that the NOPR proposal will reduce 
the identification and assignment of unnecessary affected system 
network upgrades under NRIS studies.\2375\ MISO and Shell contend that 
ERIS modeling will adequately cover reliability for affected systems 
and that they have no significant concerns regarding unnecessary 
curtailment or redispatch on affected systems associated with ERIS 
modeling.\2376\ Additionally, commenters contend that there is no need 
to use NRIS modeling standards when the affected system interconnection 
customer requests NRIS-level service on the host system because the 
generating facility's output will not be delivered to the affected 
system, and the NRIS standard serves the exclusive purpose of allowing 
interconnection customers to be designated as a network resource on the 
host system.\2377\ Some commenters claim that the NOPR proposal will 
reduce the time required to conduct affected system study and 
construction processes, as well as the likelihood of withdrawals once 
the affected system necessary upgrades are identified.\2378\
---------------------------------------------------------------------------

    \2373\ ACE-NY Initial Comments at 9; AES Initial Comments at 21; 
Alliant Energy Initial Comments at 7; Clean Energy Associations 
Initial Comments at 48; Clean Energy Associations Reply Comments at 
12; ELCON Initial Comments at 8; Enel Initial Comments at 67-68; 
Fervo Energy Initial Comments at 6; Invenergy Initial Comments at 
44; MISO Initial Comments at 98; NextEra Initial Comments at 34; OMS 
Initial Comments at 17; Pattern Energy Initial Comments at 26; Pine 
Gate Initial Comments at 42; Shell Initial Comments at 31-32; UMPA 
Initial Comments at 6.
    \2374\ ELCON Initial Comments at 8.
    \2375\ Fervo Energy Initial Comments at 6; UMPA Initial Comments 
at 6.
    \2376\ MISO Initial Comments at 98; Shell Initial Comments at 
33.
    \2377\ Fervo Energy Initial Comments at 6; Interwest Reply 
Comments at 18; Invenergy Initial Comments at 44; NextEra Initial 
Comments at 34; NextEra Reply Comments at 6; OMS Initial Comments at 
17.
    \2378\ OMS Initial Comments at 17; Pine Gate Initial Comments at 
42; Public Interest Organizations Initial Comments at 51.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1264. Some commenters oppose the NOPR proposal.\2379\ AECI claims 
that, without increasing the granularity of the redispatch and 
curtailment process in real time to better understand the actual impact 
an affected system interconnection customer has on the affected system 
from a distribution factor standpoint, the NOPR proposal would produce 
disproportionate burdens by reducing otherwise economical and reliable 
generating facilities to accommodate resources that are outside an 
affected system transmission provider's control.\2380\ Idaho Power 
asserts that the NOPR proposal may not sufficiently capture network 
upgrades that are jointly owned by multiple entities.\2381\ 
Specifically, Idaho Power states that the host transmission provider 
``may not be the entity responsible for designing and constructing 
network upgrades and interconnection facilities; therefore, the 
affected party ERIS study may not provide sufficient details to be 
meaningful.'' \2382\
---------------------------------------------------------------------------

    \2379\ AECI Initial Comments at 7; AEP Initial Comments at 34; 
Ameren Initial Comments at 23-24; Duke Southeast Utilities Initial 
Comments at 28; EEI Initial Comments at 19; Illinois Commission 
Initial Comments at 9; LADWP Initial Comments at 5; NRECA Initial 
Comments at 39; Southern Initial Comments at 4, 16; SPP Initial 
Comments at 20.
    \2380\ AECI Initial Comments at 7.
    \2381\ Idaho Power Initial Comments at 12.
    \2382\ Id.
---------------------------------------------------------------------------

    1265. Several commenters claim that the ERIS modeling requirement 
for affected systems will negatively impact reliability.\2383\ AECI 
argues that incentivizing ERIS-only studies would fundamentally affect 
reliability by failing to address systemic de minimis issues that 
become material in the aggregate.\2384\ Some commenters contend that, 
under the NOPR proposal, reliability issues will not arise until the 
operational time horizon, which could, as an example, result in an 
increase in transmission loading relief events and redispatch of 
network resources and native load.\2385\ LADWP asserts that the 
dispatching assumptions of an interconnection request can make a 
significant difference to flow patterns in the host system, and 
parallel paths will inherently absorb the unscheduled flow intended for 
the host system.\2386\ LADWP contends that, as the number of 
interconnection requests continues to grow, these unscheduled flows 
will continue to increase and begin to affect systems downstream of the 
affected system, rather than just the local transmission system that 
the ERIS modeling standard is designed to evaluate. LADWP claims that 
the NOPR proposal would result in approval of generating facilities 
without identification of sufficient network upgrades to accommodate 
requested interconnection service, and affected system transmission 
providers would be responsible for maintaining reliability by 
developing operating procedures, capital projects, or performing 
curtailments from the additional stress of energy that is not being 
delivered to the affected system.
---------------------------------------------------------------------------

    \2383\ AECI Initial Comments at 7; Illinois Commission Initial 
Comments at 9; Southern Initial Comments at 16-17.
    \2384\ AECI Initial Comments at 7.
    \2385\ Ameren Initial Comments at 24; LADWP Initial Comments at 
5; PJM Reply Comments at 10; Southern Initial Comments at 16-17.
    \2386\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------

    1266. AEP, SPP, and Xcel express concern that the proposed ERIS 
modeling standard may harm firm transmission service on the affected 
system.\2387\ AEP, NRECA, and Xcel argue that affected system 
transmission providers should be able to use NRIS in affected system 
studies if the affected system interconnection customer is requesting 
NRIS-level service on the host transmission system to ensure the 
required level of deliverability.\2388\ AEP states that, in the case 
that the interconnection customer is requesting to interconnect to a 
different RTO/ISO or is in a non-RTO/ISO, then an ERIS-only modeling 
standard could result in the failure to construct affected system 
network upgrades to mitigate congestion and/or loop flow once the new 
generating facility commences operation, impacting loads that secured 
and paid for firm transmission service and/or NRIS.\2389\
---------------------------------------------------------------------------

    \2387\ AEP Initial Comments at 34; SPP Initial Comments at 20; 
Xcel Initial Comments at 43.
    \2388\ AEP Initial Comments at 34; NRECA Initial Comments at 39; 
SPP Initial Comments at 20-21; Xcel Initial Comments at 43.
    \2389\ AEP Initial Comments at 34.
---------------------------------------------------------------------------

    1267. SPP is concerned that, if an affected system interconnection 
customer requests NRIS-level service on the host transmission system 
that grants deliverability rights without additional study procedures, 
an affected system may be exposed to impacts that it has not had an 
opportunity to evaluate under an ERIS modeling standard.\2390\ As an 
example, SPP explains that SPP and MISO treat what constitutes firm 
transmission service differently, but SPP's current ability to conduct 
affected system studies under NRIS when the interconnection customer 
has requested NRIS on the host system allows for that difference. In 
response to SPP's concerns, NextEra argues that this issue appears to 
be a problem of SPP's own making based on how SPP implemented ERIS and 
NRIS on its own system and ignores that affected system interconnection 
customers are not seeking deliverability or to be deemed firm on SPP's 
transmission system through any sort of transmission service from 
SPP.\2391\
---------------------------------------------------------------------------

    \2390\ SPP Initial Comments at 20-21.
    \2391\ NextEra Reply Comments at 6-7.
---------------------------------------------------------------------------

    1268. Some commenters note that the proposal may not work in all 
scenarios.\2392\ For instance, Clean Energy Associations state that 
this proposal may not be appropriate for non-RTO/ISO regions, if these 
impacts are not addressed through a coordinated transmission service 
study.\2393\ Xcel believes that the use of ERIS modeling standards for 
affected system studies

[[Page 61192]]

may be appropriate under a joint operating agreement or in areas where 
the impact may be evaluated and mitigated in the transmission service 
study process, but in other areas, if the impact will not be evaluated 
in the transmission service study process, it is appropriate for an 
affected system transmission provider to model the neighbor's NRIS 
requests based on the expected delivery point.\2394\
---------------------------------------------------------------------------

    \2392\ AEP Initial Comments at 34; Clean Energy Associations 
Initial Comments at 48; SPP Initial Comments at 21-22; Xcel Initial 
Comments at 43.
    \2393\ Clean Energy Associations Initial Comments at 48.
    \2394\ Xcel Initial Comments at 43-44.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
    1269. Some commenters ask the Commission to make changes to the 
NOPR proposal to mitigate the negative impacts they discuss in their 
comments. For example, some commenters recommend that, in addition to 
the ERIS modeling standard, the Commission should establish (or allow 
affected system transmission providers to establish) a distribution 
factor or impact threshold for affected system studies to ensure that 
affected system interconnection customers are not assigned unnecessary 
affected system network upgrades.\2395\ NextEra recommends that the use 
of ERIS be included in the pro forma affected system study agreement to 
require any affected system transmission provider proposing to use NRIS 
rather than ERIS to file such agreement with the Commission on a non-
conforming basis.\2396\
---------------------------------------------------------------------------

    \2395\ AES Initial Comments at 8, 21; Clean Energy Associations 
Initial Comments at 48; Enel Initial Comments at 68; Pine Gate 
Initial Comments at 42; SEIA Initial Comments at 35.
    \2396\ NextEra Initial Comments at 34.
---------------------------------------------------------------------------

    1270. Enel states that a critical interconnection issue not 
addressed in the NOPR is the lack of clarification of ERIS and NRIS-
level service and how the different assumptions used by transmission 
providers significantly alter results.\2397\ Enel explains that the 
wide variety of views on what rights interconnection service grants to 
an interconnection customer leads to confusion in the development of 
study practices and requirements, as well as the services and products 
a generating facility can provide. Enel requests that, in a final rule 
or a supplemental notice, the Commission should provide concrete 
direction regarding how these service types should be studied and what 
outcome an interconnection customer should receive for making the 
necessary transmission system improvements to obtain that 
interconnection service. NV Energy requests that affected system 
transmission providers and host transmission providers coordinate 
assumptions for affected system studies and update those assumptions 
quarterly after the affected system study has been issued to provide 
meaningful changes.\2398\
---------------------------------------------------------------------------

    \2397\ Enel Initial Comments at 26-27.
    \2398\ NV Energy Initial Comments at 12.
---------------------------------------------------------------------------

    1271. Some commenters note that a final rule should provide host 
transmission providers with flexibility to work with their neighboring 
regions to address modeling consistencies in transmission system 
representations across regions.\2399\
---------------------------------------------------------------------------

    \2399\ Duke Southeast Utilities Initial Comments at 27-28; NYISO 
Initial Comments at 46.
---------------------------------------------------------------------------

    1272. Some commenters specifically support allowing transmission 
providers to use NRIS modeling standards for affected system studies 
pursuant to separate FPA section 205 filings, as proposed in the 
NOPR.\2400\ Duke Southeast Utilities assert that the Commission should 
remove any negative repercussions, including any financial penalties or 
liability for breaching deadlines of the study process, for affected 
system transmission providers that seek to make such FPA section 205 
filings.\2401\
---------------------------------------------------------------------------

    \2400\ AES Initial Comments at 21; Clean Energy Associations 
Initial Comments at 48; Fervo Energy Initial Comments at 6.
    \2401\ Duke Southeast Utilities Initial Comments at 27-28.
---------------------------------------------------------------------------

    1273. Several commenters argue that affected system transmission 
providers should be able to use NRIS when conducting affected system 
studies without requiring the NOPR's proposed FPA section 205 
filing.\2402\ A few commenters argue that the requirement to make an 
FPA section 205 filing to use NRIS modeling standards will create 
delays and is overly burdensome on affected system transmission 
providers.\2403\ SPP claims that, as proposed in the NOPR, an FPA 
section 205 filing to use NRIS modeling assumptions would require 
supporting documentation amounting to evidence that the affected system 
transmission provider could only obtain if it conducted a study using 
the standards of the heightened level of service, which it could not do 
absent the Commission's grant of a waiver to require such a 
study.\2404\ Invenergy argues that the option for an FPA section 205 
request to conduct an affected system study using NRIS criteria invites 
case-by-case disputes over modeling criteria, potentially delaying the 
affected system study process. Therefore, Invenergy argues that the 
Commission should clarify that any such filing must be limited to only 
the facts of an individual interconnection request.\2405\
---------------------------------------------------------------------------

    \2402\ Id. at 28; AECI Initial Comments at 7; AEP Initial 
Comments at 34; Ameren Initial Comments at 23-24; EEI Initial 
Comments at 19; Illinois Commission Initial Comments at 9; LADWP 
Initial Comments at 5; NRECA Initial Comments at 39; Southern 
Initial Comments at 4, 16; SPP Initial Comments at 20.
    \2403\ AECI Initial Comments at 7; AEP Initial Comments at 34; 
Duke Southeast Utilities Initial Comments at 27; EEI Initial 
Comments at 19; LADWP Initial Comments at 5; MISO Initial Comments 
at 98; Southern Initial Comments at 16; SPP Initial Comments at 20.
    \2404\ SPP Initial Comments at 20.
    \2405\ Invenergy Initial Comments at 44-45.
---------------------------------------------------------------------------

    1274. Xcel states that the Commission should: (1) remove the ERIS 
option in RTO/ISO markets and require all generating facilities in such 
markets to be deliverable; (2) curtail generating facilities that did 
not pay for long-term firm transmission service; or (3) convene a 
technical conference on this topic in this docket.\2406\ Xcel explains 
that ERIS-only generating facilities in RTO/ISO markets may place a bid 
to sell into the market, and the ERIS-only generating facilities will 
be dispatched to the extent a bid clears, while in other areas, the 
ERIS-only generating facilities must acquire transmission service to be 
delivered.\2407\ Xcel concludes that ERIS service in RTO/ISO markets 
results in unjust and unreasonable rates and discriminatory treatment 
because ERIS-level generating facilities do not bear the costs 
necessary to ensure that they are deliverable to load. Xcel claims 
that: (1) the affected system transmission provider should not have to 
assume it will redispatch its own network resources to accommodate an 
affected system interconnection customer taking NRIS-level service; (2) 
the affected system's network resources paid for and expect to receive 
firm transmission service; and (3) there is no process for a host 
transmission provider to require an affected system transmission 
provider to redispatch its transmission system to accommodate a 
generating facility on the host system under the pro forma 
tariff.\2408\
---------------------------------------------------------------------------

    \2406\ Xcel Initial Comments at 16, 41-42.
    \2407\ Id. at 15.
    \2408\ Id. at 43.
---------------------------------------------------------------------------

    1275. NRECA asserts that the final rule should allow a 
``transmission customer'' to propose a different standard through an 
FPA section 206 complaint.\2409\ NextEra and MISO suggest that, to 
avoid delays in the interconnection process, any affected system 
transmission provider submitting an FPA section 205 filing to use NRIS 
modeling in an affected system study should proceed with the affected 
system study, using both the ERIS and NRIS standards, and then the 
appropriate results could be used based on the outcome of the FPA 
section 205

[[Page 61193]]

proceeding.\2410\ MISO also encourages the Commission to recognize that 
this FPA section 205 filing process will add length and delay to the 
affected system study process, which further compounds and demonstrates 
the problems with the Commission's automatic penalty proposal.\2411\
---------------------------------------------------------------------------

    \2409\ NRECA Initial Comments at 40.
    \2410\ MISO Initial Comments at 98; NextEra Initial Comments at 
34.
    \2411\ MISO Initial Comments at 98.
---------------------------------------------------------------------------

iii. Commission Determination
    1276. We adopt the NOPR proposal, with modification, to add section 
9.7 to the pro forma LGIP to require affected system transmission 
providers to study all affected system interconnection requests using 
ERIS modeling standards.\2412\ We decline to adopt the NOPR proposal to 
expressly acknowledge in pro forma LGIP section 9.7 that an affected 
system transmission provider may submit an FPA section 205 filing to 
request to study an affected system interconnection customer using NRIS 
on a case-by-case basis.
---------------------------------------------------------------------------

    \2412\ In relevant part, pro forma LGIP section 9.7 states: 
``Transmission Provider must study an Affected System 
Interconnection Customer using the Energy Resource Interconnection 
Service modeling standard used for Interconnection Requests on its 
own Transmission System, regardless of the level of interconnection 
service that Affected System Interconnection Customer is seeking 
from the host transmission provider with whom it seeks to 
interconnect.''
---------------------------------------------------------------------------

    1277. We find that the use of ERIS in affected system studies is 
just and reasonable, given that the affected system transmission 
provider has no obligation to continually ensure deliverability for an 
affected system interconnection customer that has obtained NRIS on its 
host system. An NRIS study goes beyond the prerequisite ERIS study and 
uses stricter modeling standards to assess an interconnection request 
to ensure that the interconnection customer's electric output is 
deliverable to load in aggregate on the host transmission provider's 
transmission system.\2413\ We find that the use of ERIS for affected 
system studies is consistent with Order No. 2003 because 
interconnection is separate from the deliverability component of 
transmission service.\2414\
---------------------------------------------------------------------------

    \2413\ See Order No. 2003, 104 FERC ] 61,103 at P 768; Order No. 
2003-A, 106 FERC ] 61,220 at P 500. Specifically, a transmission 
provider studying a generating facility for NRIS would study the 
transmission system at peak load, under a variety of severely 
stressed conditions to determine whether, with the generating 
facility operating at full output, the aggregate of generation in 
the local area can be delivered to the aggregate of load, consistent 
with reliability criteria and procedures.
    \2414\ Order No. 2003, 104 FERC ] 61,103 at P 118; Order No. 
2003-A, 106 FERC ] 61,220 at P 113.
---------------------------------------------------------------------------

    1278. We also find that this requirement is likely to prevent an 
affected system interconnection customer from being required to 
construct significant network upgrades on the transmission provider's 
affected system, but not being deliverable due to curtailment or 
congestion on the affected system. Without this reform, rates would 
continue to be unjust and unreasonable because an affected system 
interconnection customer would face increased costs without a 
commensurate increase in service, as explained in the NOPR. This 
mismatch between costs and services received would occur because the 
affected system transmission provider has no obligation to ensure that 
the output from the affected system interconnection customer's 
generating facility is deliverable on the affected system and could 
lead to curtailment of the generating facility, or there could be 
congestion on the affected system preventing deliverability of the 
generating facility's output.
    1279. We also find that, if the affected system transmission 
provider were able to study affected system interconnection customers 
under an NRIS standard, it could require affected system 
interconnection customers to pay significant upfront costs in order to 
construct the required affected system network upgrades, which could 
lead to late-stage interconnection request withdrawals as 
interconnection customers will not receive affected system study 
results until late in the interconnection process. An ERIS standard 
ensures that the assigned affected system network upgrade costs will 
likely be lower and that affected system interconnection customers 
assigned affected system network upgrades will be less likely to 
withdraw at a late stage. This standard will help prevent the cascading 
restudies that commenters have observed \2415\ and will ensure that the 
interconnection process operates more efficiently.
---------------------------------------------------------------------------

    \2415\ OMS Initial Comments at 17; Pine Gate Initial Comments at 
42.
---------------------------------------------------------------------------

    1280. We also find that the use of ERIS in affected system study 
processes across all transmission provider regions will create 
consistency and provide transparency for affected system 
interconnection customers. Currently, similarly situated 
interconnection customers requesting NRIS on their host transmission 
systems could have disparate impacts on affected systems that use 
different modeling standards, and these interconnection customers could 
be assigned dramatically different affected system network upgrade 
costs due to those varying modeling standards, without any factual or 
service differences to justify the discriminatory treatment. Thus, the 
consistent application of ERIS in affected system studies across all 
transmission providers' study processes will ensure that all affected 
system interconnection customers are studied similarly.\2416\ As such, 
we agree with commenters that the use of ERIS on all affected system 
interconnection requests will increase certainty and 
transparency.\2417\
---------------------------------------------------------------------------

    \2416\ Order No. 2003, 104 FERC ] 61,103 at P 11 (stating that a 
standard set of interconnection procedures will, among other things, 
expedite the development of new generation, while protecting 
reliability and ensuring that rates are just and reasonable).
    \2417\ ELCON Initial Comments at 8; Fervo Energy Initial 
Comments at 6; UMPA Initial Comments at 6.
---------------------------------------------------------------------------

    1281. We find outside the scope of this final rule Xcel's request 
that the Commission require all generating facilities in RTO/ISO 
markets to be deliverable and its claim that ERIS-level generating 
facilities do not bear the costs necessary to ensure that they are 
deliverable to load.\2418\ We are not proposing in this final rule to 
alter how an interconnection customer in an RTO/ISO requests its type 
of interconnection service on the host system (i.e., ERIS or NRIS); 
rather, we are standardizing how an affected system transmission 
provider studies an affected system interconnection request.
---------------------------------------------------------------------------

    \2418\ Xcel Initial Comments at 15-16, 41-42.
---------------------------------------------------------------------------

    1282. Regarding AECI's claim that the NOPR proposal would produce 
disproportionate burdens by necessitating curtailment from economical 
and reliable generating facilities to accommodate generating facilities 
on a different transmission system unless overall granularity of the 
redispatch and curtailment process is increased in real time, we find 
no evidence of this concern, from AECI or otherwise.\2419\ Rather, AECI 
appears concerned that generating facilities on its transmission system 
may be redispatched and curtailed, which we have acknowledged may 
occur.\2420\ Additionally, we note the transmission loading relief 
procedures set the priority for curtailing generating facilities as 
necessary, and this final rule is not revising those procedures. 
Finally, to the extent that the costs associated with increasing the 
overall granularity of real-time models is less than any hypothetical 
increase in curtailment and redispatch costs, a transmission provider 
may increase the real-time granularity of its model.
---------------------------------------------------------------------------

    \2419\ AECI Initial Comments at 7.
    \2420\ NOPR, 179 FERC ] 61,194 at P 213.
---------------------------------------------------------------------------

    1283. Further, we find that Idaho Power has not adequately 
explained how this reform will result in

[[Page 61194]]

insufficiently identifying network upgrades that are jointly owned by 
multiple entities.\2421\ Moreover, even if this were a valid concern, 
we find that this concern would be equally present regardless of the 
modeling standard (i.e., ERIS or NRIS) used to conduct the affected 
system study.
---------------------------------------------------------------------------

    \2421\ Idaho Power Initial Comments at 12.
---------------------------------------------------------------------------

    1284. As discussed in the NOPR proposal, using a less stringent 
modeling standard may result in more frequent redispatch or curtailment 
by not fully capturing all the potential impacts of the affected system 
interconnection customer's generating facility(ies) on an affected 
system. Based on the record, we continue to find that these risks are 
limited in nature, particularly in non-RTO/ISO regions where 
interconnection service does not, by itself, allow a generating 
facility's power to flow. In non-RTO/ISO regions, power can only flow 
from a generating facility once transmission service has been requested 
and granted. For example, once point-to-point transmission service has 
been requested to enable a particular generating facility's power to 
flow, either by the generating facility itself or its power sale 
customer, pro forma open access transmission tariff section 21 
(Provisions Relating to Transmission Construction and Services on the 
Systems of Other Utilities) provides a process similar to the affected 
system process in the pro forma LGIP. In summary, pro forma open access 
transmission tariff section 21 makes the transmission customer 
responsible for obtaining any necessary engineering, permitting, and 
construction of transmission or distribution facilities on the 
system(s) of utilities other than the directly connected transmission 
provider, but requires that transmission provider to undertake 
reasonable efforts to assist in that effort. This means that affected 
systems will have another opportunity to study the impact of the 
interconnection customer's generating facility in the context of this 
transmission service request, whether a new point-to-point transmission 
service request or designation as a new network resource under an 
existing transmission customer's network integration transmission 
service, before any power can flow from the generating facility.
    1285. Moreover, we find that any significant impact would generally 
be captured by an ERIS study, which would ensure that any reliability 
impacts on the affected system are mitigated to accommodate the 
interconnection of the affected system interconnection customer's 
proposed generating facility to the host system. That ERIS adequately 
studies an affected system interconnection customer's interconnection 
request for its reliability impacts on the affected system is evidenced 
by MISO's use of only ERIS in affected system studies without adverse 
reliability impacts.\2422\
---------------------------------------------------------------------------

    \2422\ MISO Initial Comments at 98.
---------------------------------------------------------------------------

    1286. Regarding AECI's claim that using only ERIS in affected 
system studies may result in increased de minimis impacts,\2423\ we are 
not setting the implementation of the ERIS standard. Rather, each 
transmission provider determines its own implementation of that 
standard, which could include a de minimis threshold that is best for 
its region. The Commission has found that, if consistently applied, it 
is reasonable for interconnection customers to not bear cost 
responsibility for de minimis impacts on transmission facilities based 
on a threshold.\2424\ Additionally, we expect that any overloads in the 
models due to the accumulation of de minimis impacts will ultimately be 
assigned, pursuant to the transmission provider's tariff, when an 
interconnection customer triggers the need for a network upgrade or 
when the transmission provider's reliability transmission planning 
process identifies the need for mitigation.
---------------------------------------------------------------------------

    \2423\ AECI Initial Comments at 7.
    \2424\ Tenaska Clear Creek Wind, LLC v. Sw. Power Pool, Inc., 
180 FERC ] 61,160, at P 99 (2022).
---------------------------------------------------------------------------

    1287. We disagree with LADWP that the use of ERIS by an affected 
system transmission provider will result in approval of generating 
facilities with insufficient network upgrades identified.\2425\ As 
discussed above, we find that, in general, the use of ERIS is 
sufficient for affected system studies to prevent reliability issues 
from occurring on the affected system. Moreover, as noted earlier, in 
non-RTO/ISO regions, power can only flow from a generating facility 
once transmission service has been requested and granted, meaning that 
affected systems will have another opportunity to study the impact of 
the interconnection customer's generating facility in the context of 
the associated transmission service request before any power can flow 
from that generating facility as explained above.
---------------------------------------------------------------------------

    \2425\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------

    1288. Similarly, we find that commenters' concerns about harm to 
firm transmission service and cost shifting when using ERIS in affected 
system studies are misplaced because those concerns do not arise until 
the interconnection customer seeks to deliver power from its generating 
facility to a customer, which outside of RTO/ISO regions can only 
happen once transmission service is separately secured.\2426\ In Order 
No. 2003, the Commission found that interconnection service is separate 
from the delivery component of transmission service, and, in the 
majority of circumstances, interconnection alone is unlikely to affect 
the reliability of an affected system transmission provider's 
transmission system.\2427\ Additionally, the Commission found that 
holding new interconnection customers responsible for network upgrades 
to all interconnected systems, including not only the transmission 
system to which the generating facility interconnects, but other, more 
distant transmission systems as well would create an unreasonable 
obstacle to the construction of new generation.\2428\ As such, if an 
affected system interconnection customer subsequently seeks 
deliverability on either the host system or an affected system and 
submits a transmission service request to either the host transmission 
provider or the affected system transmission provider, the affected 
system transmission provider will have the opportunity to study the 
request and potentially require the construction of additional network 
upgrades on the affected system to accommodate deliverability. 
Therefore, we find that being assigned significant affected system 
network upgrades under an NRIS study without the obligation for the 
affected system transmission provider to ensure that the output from an 
affected system interconnection customer's generating facility is 
integrated on the affected system similar to generating facilities that 
serve the affected system transmission provider's native load customers 
or network resources results in unjust and unreasonable rates by 
increasing the cost for affected system interconnection customers 
without a commensurate increase in service.\2429\
---------------------------------------------------------------------------

    \2426\ AEP Initial Comments at 34; NRECA Initial Comments at 39; 
SPP Initial Comments at 20-21; Xcel Initial Comments at 43.
    \2427\ Order No. 2003, 104 FERC ] 61,103 at P 118; Order No. 
2003-A, 106 FERC ] 61,220 at P 113.
    \2428\ Order No. 2003, 104 FERC ] 61,103 at P 120.
    \2429\ As stated in section III.A.1, the pro forma LGIP defines 
NRIS service as ``an Interconnection Service that allows the 
Interconnection Customer to integrate its Large Generating Facility 
with the Transmission Provider's Transmission System (1) in a manner 
comparable to that in which the Transmission Provider integrates its 
generating facilities to serve native load customers; or (2) in an 
RTO or ISO with market based congestion management, in the same 
manner as Network Resources. Network Resource Interconnection 
Service in and of itself does not convey transmission service.'' Pro 
forma LGIP section 1.

---------------------------------------------------------------------------

[[Page 61195]]

    1289. Regarding claims that affected system transmission providers 
would need to develop operating procedures or capital projects or 
perform curtailments due to the additional stress on affected systems 
caused by affected system interconnection requests being studied under 
the ERIS modeling standard,\2430\ we find these claims to be 
speculative and that affected system studies are designed to ensure 
that an affected system interconnection customer's proposed generating 
facility can reliably connect to the host system without adversely 
impacting an affected system and are not meant to ensure deliverability 
on either the host or affected system. As mentioned above, an affected 
system transmission provider has no obligation to ensure that an 
affected system interconnection request is fully deliverable.
---------------------------------------------------------------------------

    \2430\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------

    1290. We are unpersuaded by arguments that the NOPR proposal may 
not work in all scenarios \2431\ and note that commenters did not 
provide specific examples of how the proposal would not work under the 
Commission's pro forma LGIP process. Several commenters raise concerns 
that, although the use of ERIS may work in regions with joint operating 
agreements or coordinated transmission service studies, the use of ERIS 
for all affected system studies may not be appropriate if an affected 
system transmission provider's transmission service studies do not 
identify all impacts. Once again, in adopting the ERIS requirement for 
affected system transmission providers, we find that ERIS is sufficient 
to capture reliability impacts of affected system interconnection 
requests on the affected system. We do not address whether individual 
transmission providers have adequate transmission service studies. If a 
transmission provider believes that changes are needed to better 
consider the deliverability of transmission service on its transmission 
system or with its neighboring transmission systems, nothing in this 
final rule prevents transmission providers from addressing those 
concerns.
---------------------------------------------------------------------------

    \2431\ AEP Initial Comments at 34; Clean Energy Associations 
Initial Comments at 48; SPP Initial Comments at 20-21; Xcel Initial 
Comments at 43.
---------------------------------------------------------------------------

    1291. We decline requests for the Commission to set modeling 
standards, to require transmission providers to include their modeling 
standards in their tariffs, or to provide direction on how ERIS and 
NRIS should be studied and what service the interconnection customer 
should receive, and to require neighboring transmission providers to 
coordinate assumptions and update those assumptions quarterly.\2432\ We 
find these requests to be outside the scope of the final rule.
---------------------------------------------------------------------------

    \2432\ AES Initial Comments at 8, 21; Clean Energy Associations 
Initial Comments at 48; Enel Initial Comments at 27, 68; NV Energy 
Initial Comments at 12; Pine Gate Initial Comments at 42; SEIA 
Initial Comments at 35.
---------------------------------------------------------------------------

    1292. Although some commenters request flexibility on whether to 
use ERIS or NRIS in conducting an affected system study,\2433\ we find 
such a request is essentially a request to maintain the status quo, 
which, as discussed above, results in Commission-jurisdictional rates 
that are unjust, unreasonable, and unduly discriminatory or 
preferential and prevents interconnection customers from 
interconnecting in a reliable, efficient, transparent, and timely 
manner.
---------------------------------------------------------------------------

    \2433\ Duke Southeast Utilities Initial Comments at 27-28; NYISO 
Initial Comments at 46.
---------------------------------------------------------------------------

    1293. We decline to adopt the proposal stating that an affected 
system transmission provider may make an FPA section 205 filing to 
request use of an NRIS modeling standard in affected system studies. We 
find that there is no need to expressly provide for the availability of 
an FPA section 205 filing in pro forma LGIP section 9.7 because 
transmission providers always have the right to submit an FPA section 
205 filing.
3. Optional Resource Solicitation Study
a. NOPR Proposal
    1294. In the NOPR, the Commission explained that resource 
solicitation processes inspire a number of interconnection requests, 
but in most cases, state agencies and LSEs implementing state mandates 
do not have the opportunity to request dedicated studies 
themselves.\2434\
---------------------------------------------------------------------------

    \2434\ NOPR, 179 FERC ] 61,194 at P 211.
---------------------------------------------------------------------------

    1295. The Commission proposed to revise the pro forma LGIP to 
require transmission providers to allow resource planning entities, 
i.e., any entity required to develop a resource plan or conduct a 
resource solicitation process, including a state entity or LSE, to 
initiate an optional resource solicitation study.\2435\
---------------------------------------------------------------------------

    \2435\ Id. P 223.
---------------------------------------------------------------------------

    1296. Under the NOPR proposal, the resource planning entity would 
identify the valid interconnection requests associated with its 
qualifying resource solicitation process or qualifying resource plan 
and request that the transmission provider study several combinations 
of those interconnection requests in a resource solicitation 
study.\2436\
---------------------------------------------------------------------------

    \2436\ Id. P 224.
---------------------------------------------------------------------------

    1297. The Commission clarified that under this proposal, the 
resource planning entity would not receive a queue position: 
interconnection customers would maintain their queue position obtained 
through the cluster request window and proceed through the regular 
interconnection queue alongside all other customers.\2437\
---------------------------------------------------------------------------

    \2437\ Id. P 226.
---------------------------------------------------------------------------

    1298. The Commission proposed that the transmission provider must 
evaluate each combination of interconnection requests submitted by the 
resource planning entity as a group, in the same manner it will perform 
cluster studies under the proposed pro forma LGIP.\2438\ The Commission 
proposed a 135-calendar day time limit on the optional resource 
solicitation study (compared to 150 calendar days for the cluster 
study).
---------------------------------------------------------------------------

    \2438\ Id. P 233.
---------------------------------------------------------------------------

    1299. The Commission sought comment on: (1) the NOPR proposal to 
explicitly include state agencies that are required to develop a 
resource plan or conduct a resource solicitation process in the 
definition of a resource planning entity; (2) whether other entities 
should qualify as resource planning entities and therefore be able to 
request initiation of an optional resource solicitation study, and, if 
so, what impact, if any, their inclusion would have on the efficiency 
of the interconnection process and whether their inclusion would raise 
concerns of undue discrimination or preference; (3) whether the 
proposed optional resource solicitation study raises any 
confidentiality concerns, including whether the optional resource 
solicitation study report could be posted on the transmission 
provider's OASIS before the qualifying solicitation process has 
concluded; and (4) what, if any, challenges multistate transmission 
providers--in particular, those RTOs/ISOs that serve large, multi-state 
areas--may face regarding study timing, multiple concurrent studies, or 
other issues in offering an optional resource solicitation study 
option, and any proposals to mitigate such challenges.\2439\
---------------------------------------------------------------------------

    \2439\ Id. PP 236-237.
---------------------------------------------------------------------------

b. Comments
i. Comments in Support
    1300. Many commenters support the NOPR proposal and note that the 
ability to gather holistic information on a range of resource mix 
scenarios from transmission providers would support efforts by states 
and other resource planning entities to meet policy

[[Page 61196]]

objectives.\2440\ The North Dakota Commission notes that resource 
solicitation studies could help improve coordination and make state-
level, bottom-up resource planning processes more efficient and cost-
effective.\2441\ Similarly, [Oslash]rsted argues that resource 
solicitation studies have the potential to reduce the uncertainty 
involving the interconnection cost portion of future state-sponsored 
resource solicitations.\2442\
---------------------------------------------------------------------------

    \2440\ Clean Energy States Initial Comments at 9; Colorado 
Commission Reply Comments at 2; Consumers Energy Initial Comments at 
8; EEI Initial Comments at 5-6; Illinois Commission Initial Comments 
at 11; Iowa Commission Initial Comments at 6; NARUC Initial Comments 
at 25; NESCOE Initial Comments at 17; New Jersey Commission Initial 
Comments at 16-17; North Carolina Commission Initial Comments at 26; 
Northwest and Intermountain Initial Comments at 15; [Oslash]rsted 
Initial Comments at 15; OPSI Initial Comments at 7; Public Interest 
Organizations Initial Comments at 37-38.
    \2441\ North Dakota Commission Initial Comments at 7.
    \2442\ [Oslash]rsted Initial Comments at 15.
---------------------------------------------------------------------------

ii. Comments in Opposition
    1301. AES states that it does not believe reforms on this issue 
should be part of the final rule but does not oppose transmission 
providers submitting optional resource solicitation study proposals to 
the Commission pursuant to separate FPA section 205 filings after 
consultation with stakeholders.\2443\
---------------------------------------------------------------------------

    \2443\ AES Initial Comments at 22.
---------------------------------------------------------------------------

    1302. AEP disagrees with the Commission's conclusion that failure 
to provide for a resource solicitation process leads to unjust and 
unreasonable rates.\2444\ AEP argues that this reasoning only applies 
to ``entities required to conduct a resource plan or resource 
solicitation process'' and that, accordingly, there is no legal basis 
to ``solve'' the problem through a nationwide mandate, as transmission 
providers with no LSEs that are required to ``conduct a resource plan 
or resource solicitation process'' do not need to amend their tariffs 
to include the optional resource solicitation study proposal. AEP 
asserts that there is no evidence that LSEs in RTOs/ISOs need the 
optional resource solicitation study process to perform IRPs 
efficiently and reach appropriate procurement decisions. AECI argues 
that resource planning entities should maintain discretion over their 
portfolios, and that the Commission lacks jurisdiction to mandate 
deployment of any particular resource or to require transmission 
providers to provide preferential treatment towards any specific 
technology.\2445\
---------------------------------------------------------------------------

    \2444\ AEP Initial Comments at 39-40.
    \2445\ AECI Initial Comments at 8.
---------------------------------------------------------------------------

    1303. Several commenters argue that the proposed optional resource 
solicitation study is unnecessary, particularly in regions such as PJM 
and MISO, which have existing or proposed processes for considering 
state objectives.\2446\
---------------------------------------------------------------------------

    \2446\ Dominion Initial Comments at 39; Dominion Reply Comments 
at 24; Indicated PJM TOs Initial Comments at 51; MISO Initial 
Comments at 9, 98-102; MISO Reply Comments at 11; National Grid 
Initial Comments at 39; OMS Initial Comments at 18.
---------------------------------------------------------------------------

    1304. CAISO and SPP argue that the proposed optional resource 
solicitation study may create uncertainty regarding the cost and timing 
of interconnecting to the transmission system.\2447\ CAISO asserts that 
it is impossible to provide meaningful cost data to interconnection 
customers until the transmission provider knows precisely the entire 
make-up of the study cluster.\2448\
---------------------------------------------------------------------------

    \2447\ CAISO Initial Comments at 30; SPP Initial Comments at 22.
    \2448\ CAISO Initial Comments at 31.
---------------------------------------------------------------------------

    1305. Several commenters question the efficacy of the resource 
solicitation study proposal.\2449\ PJM argues that, because the study 
would include only a subset of the clustered interconnection requests, 
the results would not be indicative of the outcome when considering the 
entire cluster, and would not provide information upon which resource 
planning entities could act or base decisions.\2450\ Enel and Indicated 
PJM TOs argue that the studies would not be expected to yield a 
reliable estimate of the total costs of the portfolio of resources 
being contemplated by the resource planner.\2451\ Similarly, Indicated 
PJM TOs argue that optional studies will divert scarce resources away 
from curing the fundamental problem, arguing that such studies may not 
be valuable to resource planners because they would be conducted in a 
vacuum, would not account for other interconnection requests, and would 
not necessarily lead to the most efficient combination of 
resources.\2452\
---------------------------------------------------------------------------

    \2449\ AEE Initial Comments at 35; Enel Initial Comments at 71; 
Indicated PJM TOs Initial Comments at 50.
    \2450\ PJM Initial Comments at 50.
    \2451\ Enel Initial Comments at 71; Indicated PJM TOs Initial 
Comments at 50.
    \2452\ Indicated PJM TOs Initial Comments at 50.
---------------------------------------------------------------------------

    1306. Some commenters assert that prospective interconnection 
customers will have an incentive to lodge speculative interconnection 
requests antithetical to the desired streamlining of the pro forma LGIA 
and pro forma LGIP process contemplated by the NOPR.\2453\ APPA-LPPC 
comment that, to the extent that the generating facilities associated 
with interconnection requests are competing in a resource solicitation 
in which they may not be selected, such interconnection requests could 
constitute the kind of speculative interconnection request that the 
NOPR otherwise discourages.\2454\
---------------------------------------------------------------------------

    \2453\ AECI Initial Comments at 8; Enel Initial Comments at 69.
    \2454\ APPA-LPPC Initial Comments at 27.
---------------------------------------------------------------------------

    1307. Several commenters argue that the optional resource 
solicitation study will result in inefficiencies and delays that 
degrade the quality of the main cluster study.\2455\ Several commenters 
express concern that adding optional resource solicitation studies as a 
pro forma LGIP requirement would hinder the Commission's goal of 
increasing the speed of processing interconnection requests, arguing 
that the additional study requirements are time consuming and would 
require significant resources to complete.\2456\ Enel states that, 
because a transmission provider would be required to evaluate six full 
cluster studies (i.e., one standard plus five sensitivities) with 
different combinations of generating facilities, the optional resource 
solicitation study would inevitably lead to delays, restudies, late-
stage withdrawals, errors, and increased potential for inadequate 
consideration of lower cost and alternative mitigations.\2457\ The 
Colorado Commission argues that the NOPR proposal could materially 
delay the clean energy transition in Colorado given interconnection 
scarcity concerns if it required the elimination of resource 
solicitation clusters as currently implemented by the Colorado 
utilities.\2458\
---------------------------------------------------------------------------

    \2455\ Id.; AECI Initial Comments at 8; Bonneville Initial 
Comments at 22; CAISO Initial Comments 30-31; CREA and NewSun Reply 
Comments at 55; Dominion Initial Comments at 39; Enel Initial 
Comments at 69; Illinois Commission Initial Comments at 11; NARUC 
Initial Comments at 31; NextEra Initial Comments at 35; NYISO 
Initial Comments at 46; PJM Initial Comments at 5-6.
    \2456\ Bonneville Initial Comments at 22; CAISO Initial Comments 
30-31; CREA and NewSun Reply Comments at 55; Enel Initial Comments 
at 69; Illinois Commission Initial Comments at 11; NARUC Initial 
Comments at 31; NextEra Initial Comments at 35; NYISO Initial 
Comments at 46; PJM Initial Comments at 6; SEIA Reply Comments at 
18, 21; SPP Initial Comments at 22.
    \2457\ Enel Initial Comments at 69-71.
    \2458\ Colorado Commission Reply Comments at 3.
---------------------------------------------------------------------------

    1308. Some commenters question whether transmission providers can 
realistically manage interconnection cluster studies and perhaps 
multiple optional resource solicitation studies at the same time.\2459\ 
Indicated PJM TOs

[[Page 61197]]

state that the ability for any resource planning entity to initiate the 
resource solicitation study without warning at any time would be 
especially burdensome.\2460\ MISO warns that multiple resource planning 
entities could request an optional study with different combinations, 
requiring MISO to perform numerous iterations of its system impact 
studies.\2461\ Several commenters argue that instituting an additional 
study will put further strain on transmission providers' limited staff 
resources.\2462\ Bonneville, WAPA, and NRECA assert that most small 
transmission providers are not staffed or organized to accomplish the 
work discussed by the Commission.\2463\
---------------------------------------------------------------------------

    \2459\ Indicated PJM TOs Initial Comments at 50; MISO Initial 
Comments at 101-102; Northwest and Intermountain Initial Comments at 
16-17; NRECA Initial Comments at 41-42; PJM Initial Comments at 6.
    \2460\ Indicated PJM TOs Initial Comments at 50; Indicated PJM 
TOs Reply Comments at 18.
    \2461\ MISO Initial Comments at 102.
    \2462\ Dominion Initial Comments at 39; Indicated PJM TOs 
Initial Comments at 50; National Grid Initial Comments at 38-39; 
NYISO Initial Comments at 46; PJM Initial Comments at 6; SEIA 
Initial Comments at 36.
    \2463\ Bonneville Initial Comments at 22; WAPA Initial Comments 
at 14; NRECA Initial Comments at 41-42.
---------------------------------------------------------------------------

    1309. Several commenters caution the Commission that the optional 
resource solicitation studies could be costly.\2464\ MISO contends that 
mandating a new study activity without a corresponding study deposit 
may result in a situation where study deposit funds run out, halting 
interconnection studies until more funds are provided and leading to 
interconnection queue delays.\2465\ NRECA also argues that requiring 
both the optional informational interconnection studies and the 
optional resource solicitation studies increase costs for transmission 
customers.\2466\ SEIA argues that imposing an optional resource 
solicitation process in the early stages of the interconnection 
process, before interconnection customers receive the cost estimates of 
their network upgrades, means that the results from the study may not 
accurately reflect the costs of the network upgrades for the resources 
in the study.\2467\ Enel argues that, because the resource planning 
entity selects generating facilities for scenarios without any 
knowledge of interconnection results, it is possible that the selected 
generating facilities will end up being built despite large upgrade 
costs.\2468\
---------------------------------------------------------------------------

    \2464\ Clean Energy Associations Initial Comments at 51; 
Illinois Commission Initial Comments at 11; MISO Initial Comments at 
103.
    \2465\ MISO Initial Comments at 103.
    \2466\ NRECA Initial Comments at 41-42.
    \2467\ SEIA Reply Comments at 18-19.
    \2468\ Enel Initial Comments at 72.
---------------------------------------------------------------------------

    1310. Several commenters contend that the proposal is unjust, 
unreasonable, and unduly discriminatory or preferential because it 
gives special treatment to generating facilities selected to fulfill a 
resource plan without full consideration of interconnection 
upgrades.\2469\ Several commenters are concerned that this proposal 
could allow vertically integrated transmission providers or LSEs to use 
the process in a way that would inappropriately favor the 
interconnection of company-owned resources.\2470\ NARUC and SEIA 
explain that an LSE could have a transmission provider identify cost-
saving interconnection options through the optional resource 
solicitation study for company-owned resources but exclude non-company-
owned resources from the analysis, thus tipping the cost evaluation in 
favor of the company's resources.\2471\ Likewise, Interwest and EPSA 
are concerned that priority in interconnection queue processing for 
interconnection requests selected in a resource plan and under contract 
with a utility may provide competitive advantages for vertically 
integrated utilities because of their control over the selection of 
projects and the identification and timing of the installation of 
network upgrades.\2472\
---------------------------------------------------------------------------

    \2469\ Id. at 68, 72; AEE Initial Comments at 35-36; EPSA 
Initial Comments at 12; Interwest Initial Comments at 9; Interwest 
Reply Comments at 8; MISO Initial Comments at 98; OMS Initial 
Comments at 18; PJM Initial Comments at 50-51; SEIA Reply Comments 
at 19-20.
    \2470\ AEE Initial Comments at 36; CREA and NewSun Initial 
Comments at 89; EPSA Initial Comments at 11-12; Interwest Initial 
Comments at 9-10; NARUC Initial Comments at 26-27; Northwest and 
Intermountain Initial Comments at 15-16; Public Interest 
Organizations Initial Comments at 41; SEIA Initial Comments at 36.
    \2471\ NARUC Initial Comments at 26-27; SEIA Initial Comments at 
36; SEIA Reply Comments at 20.
    \2472\ EPSA Initial Comments at 12; Interwest Initial Comments 
at 9-10.
---------------------------------------------------------------------------

    1311. SEIA also argues that an optional resource solicitation study 
in situations where there is a commercial readiness requirement 
presents numerous opportunities for a utility to discriminate against 
independent power producers in favor of that utility's own 
generation.\2473\ AEP argues that, in multi-state RTOs/ISOs, the 
proposal facially discriminates against LSEs that are not eligible 
resource planning entities or are located in states that are not 
eligible resource planning entities themselves, and shifts key RTO/ISO 
resources away from such entities.\2474\ In RTOs/ISOs that allow 
bilateral capacity procurement, AEP argues that the proposal likewise 
discriminates between LSEs with qualifying resource planning entities 
(which may well be themselves) and those without.
---------------------------------------------------------------------------

    \2473\ SEIA Initial Comments at 36.
    \2474\ AEP Initial Comments at 37-38.
---------------------------------------------------------------------------

    1312. Multiple commenters argue that the proposed requirement to 
perform an optional resource solicitation study in multiple states 
imposes a considerable burden on RTOs/ISOs without providing meaningful 
benefits.\2475\ PJM argues that requiring it ``to serve as a de facto 
consultant'' to resource planning entities in addition to its efforts 
to expedite and process the country's largest interconnection queue 
would require PJM to take on a role beyond its authority as a 
transmission provider.\2476\ Similarly, Indicated PJM TOs argue that 
there is no justification for requiring transmission providers to 
provide resource solicitation studies when consultants could do 
so.\2477\
---------------------------------------------------------------------------

    \2475\ Id. at 36-37; AES Initial Comments at 22; CAISO Initial 
Comments at 31; ClearPath Initial Comments at 9; Dominion Initial 
Comments at 39; MISO Initial Comments at 105; NextEra Initial 
Comments at 35; PJM Initial Comments at 51; SEIA Reply Comments at 
21; WAPA Initial Comments at 15.
    \2476\ PJM Initial Comments at 51.
    \2477\ Indicated PJM TOs Reply Comments at 19.
---------------------------------------------------------------------------

    1313. The North Dakota Commission suggests that the Commission 
should consider whether the proposal potentially allows cost-shifting 
from states or localities with significant resource build out mandates 
to other states within the RTO/ISO and how to mitigate such unjust 
cost-shifting.\2478\ Similarly, Interwest cautions that, in bilateral 
and RTO/ISO markets, requiring a ranking in priority between 
interconnection requests may result in setting up competition between 
the utilities, with each vying for space on the constrained 
system.\2479\
---------------------------------------------------------------------------

    \2478\ North Dakota Commission Initial Comments at 7.
    \2479\ Interwest Initial Comments at 10.
---------------------------------------------------------------------------

    1314. Tri-State adds that there are ``timing issues'' regarding the 
optional resource solicitation study, as it does not align with the 
electric resource planning process within Colorado, and potentially 
other states.\2480\ The Colorado Commission is also concerned that, to 
the extent interconnection requests are permitted to be made into non-
resource solicitation cluster studies without strong requirements to 
demonstrate that those requests are for viable generating facilities, 
the cluster study results may render later resource solicitation study 
results inaccurate.\2481\
---------------------------------------------------------------------------

    \2480\ Tri-State Initial Comments at 29.
    \2481\ Colorado Commission Reply Comments at 5 n.10.

---------------------------------------------------------------------------

[[Page 61198]]

iii. Requests for Alternatives and Regional Flexibility
    1315. Public Interest Organizations argue that the Commission 
should grant extra flexibility on the 135-calendar day study 
timeline.\2482\ Several commenters support the implementation of 
boundaries or guardrails to ensure that optional resource solicitation 
studies do not delay the study of other interconnection requests by 
diverting needed resources away from the general interconnection 
queue.\2483\ Several commenters support the proposal so long as 
protections are included to prevent undue discrimination and maintain a 
competitive generation solicitation.\2484\
---------------------------------------------------------------------------

    \2482\ Public Interest Organizations Initial Comments at 38.
    \2483\ Illinois Commission Initial Comments at 11; NESCOE 
Initial Comments at 18; OPSI Initial Comments at 7-8.
    \2484\ CREA and NewSun Initial Comments at 89-90; CREA and 
NewSun Reply Comments at 55; Interwest Initial Comments at 11; 
Northwest and Intermountain Initial Comments at 16; Pine Gate 
Initial Comments at 43; Public Interest Organizations Initial 
Comments at 41; R Street Initial Comments at 15-16.
---------------------------------------------------------------------------

    1316. NARUC asks the Commission to consider going farther than 
requiring the optional resource solicitation study only for purposes of 
transparency and cost estimation; it recommends making the results of 
the studies available for interconnection customers to pursue and a 
basis upon which interconnection customers could seek interconnection 
on an expedited basis.\2485\
---------------------------------------------------------------------------

    \2485\ NARUC Initial Comments at 31.
---------------------------------------------------------------------------

    1317. Xcel, the Colorado Commission, and EEI argue that the 
resource solicitation cluster should have its own queue position.\2486\ 
Enel recommends that the optional resource solicitation study be a 
separate queue cycle with an intermediate queue priority between the 
transmission provider's annual study clusters.\2487\ Several commenters 
argue that resources selected as part of the resource solicitation 
process should be given priority in the interconnection queue.\2488\ 
The Colorado Commission suggests that the Commission modify its 
proposal to prioritize interconnection requests selected to serve 
native and network load within the RTO/ISO.
---------------------------------------------------------------------------

    \2486\ Colorado Commission Initial Comments at 29; Colorado 
Commission Reply Comments at 6; EEI Initial Comments at 5-6; Xcel 
Initial Comments at 11, 14.
    \2487\ Enel Initial Comments at 72.
    \2488\ Arizona Commission Initial Comments at 2; Colorado 
Commission Reply Comments at 2; Public Interest Organizations 
Initial Comments at 43; Xcel Initial Comments at 46.
---------------------------------------------------------------------------

    1318. The Colorado Commission and Xcel encourage the Commission to 
determine that any current resource solicitation cluster processes 
already in place remain just and reasonable or are consistent with/
superior to the final rule.\2489\ SEIA disagrees, noting that PSCo's 
existing resource solicitation study procedures were approved by the 
Commission in 2004 only so long as PSCo did not ``disadvantage or delay 
other Interconnection Requests not involved in the solicitation.'' 
\2490\ SEIA argues that the Colorado Commission's current proposal to 
prioritize interconnection requests selected in the state process 
conflicts with this 2004 order and the Commission's ``longstanding 
prohibition against queue jumping.'' \2491\
---------------------------------------------------------------------------

    \2489\ Colorado Commission Reply Comments at 1; Xcel Initial 
Comments at 11.
    \2490\ SEIA Reply Comments at 20 (citing NOPR, 179 FERC ] 61,194 
at P 298; Xcel Energy Operating Cos., 109 FERC ] 61,072, at P 26 
(2004)).
    \2491\ Id. at 20-21 (citing Xcel Energy Operating Cos., 106 FERC 
] 61,260, at P 22, order on reh'g, 109 FERC ] 61,072).
---------------------------------------------------------------------------

    1319. Multiple commenters request clarification and changes to the 
NOPR's proposal on resource solicitation in multistate transmission 
areas,\2492\ but NARUC and Xcel suggest that facilitated coordination 
of resource planning and interconnection as well as discussion across 
states and LSEs may be the most helpful practice to reduce the burden 
of differing state portfolio requirements on transmission providers in 
multi-state areas.\2493\
---------------------------------------------------------------------------

    \2492\ AEP Initial Comments at 36; CAISO Initial Comments at 31; 
PacifiCorp Initial Comments at 39; PJM Initial Comments at 51; WAPA 
Initial Comments at 15; Xcel Initial Comments at 45-46.
    \2493\ NARUC Initial Comments at 30-31; Xcel Initial Comments at 
45.
---------------------------------------------------------------------------

    1320. Several commenters suggest that the proposed optional 
resource solicitation study should occur outside the tariff 
process.\2494\ NextEra argues that the absence of such a feature from 
the pro forma LGIP is in no way unjust and unreasonable and that, if a 
transmission provider feels the need to customize its LGIP in this way, 
the transmission provider can do so on its own.\2495\ NRECA suggests 
that the Commission require that base cases and support files are 
available for LSEs so the LSE can run these studies outside of the 
tariff process.\2496\ WAPA and Bonneville argue that resource 
solicitation studies should occur at the reliability coordinator level 
and not the transmission provider level.\2497\
---------------------------------------------------------------------------

    \2494\ NextEra Initial Comments at 35; NRECA Initial Comments at 
42.
    \2495\ NextEra Initial Comments at 35.
    \2496\ NRECA Initial Comments at 42.
    \2497\ Bonneville Initial Comments at 22; WAPA Initial Comments 
at 14.
---------------------------------------------------------------------------

    1321. Several commenters argue that the Commission should allow 
transmission providers flexibility in implementing resource 
solicitations.\2498\ NYISO asserts that it has addressed the NOPR's 
aims by permitting state agencies to act as a developer for purposes of 
obtaining a generic interconnection request that they can put out for 
solicitation.\2499\
---------------------------------------------------------------------------

    \2498\ AECI Initial Comments at 8; Dominion Initial Comments at 
39; Interwest Initial Comments at 12; ISO-NE Initial Comments at 38; 
NESCOE Reply Comments at 15; NRECA Initial Comments at 10; NYISO 
Initial Comments at 46; PacifiCorp Initial Comments at 39; PJM 
Initial Comments at 51; Xcel Initial Comments at 14, 45; Xcel Reply 
Comments at 3.
    \2499\ NYISO Initial Comments at 47.
---------------------------------------------------------------------------

c. Commission Determination
    1322. We decline to adopt the NOPR proposal to modify the pro forma 
LGIP to require transmission providers to allow resource planning 
entities to initiate an optional resource solicitation study.\2500\ We 
find that there is insufficient evidence in the record to justify 
establishing the optional resource solicitation study process proposed 
in the NOPR as a generic solution across all regions for coordinating 
state-level resource planning with the interconnection process. As 
commenters explain, many transmission providers do not have LSEs that 
conduct a resource solicitation process. We are also concerned that the 
particular ``one size fits all'' approach proposed in the NOPR would 
create uncertainty regarding the cost and timing of interconnecting to 
the transmission system, because the proposed study would not result in 
useful network upgrade cost estimates. Finally, we agree with 
commenters that the proposal as set forth in the NOPR would divert 
transmission provider resources and potentially lead to delays in the 
processing of the interconnection queue.
---------------------------------------------------------------------------

    \2500\ Because we are not adopting this proposal, we do not 
address comments on specific aspects of the proposal.
---------------------------------------------------------------------------

    1323. Notwithstanding our decision not to adopt the NOPR's resource 
solicitation proposal, we agree with commenters who note that, in 
certain regions, resource solicitation studies have the potential to 
reduce uncertainty, improve coordination, and make resource planning 
more efficient and cost effective. We acknowledge comments arguing that 
a resource solicitation study may be most effective if paired with a 
structure where the resources within the resource solicitation 
structure are granted their own queue position, as this provides the 
relevant resources and soliciting entity with actionable information 
and avoids the uncertainty and delay that may occur if a study is 
conducted only for informational purposes and the

[[Page 61199]]

associated resources do not have a queue position that corresponds to 
the study assumptions.\2501\ We note that our decision not to adopt the 
NOPR's proposal in this final rule in no way prejudges any future 
resource solicitation study proposals that transmission providers may 
choose to file pursuant to FPA section 205.
---------------------------------------------------------------------------

    \2501\ See Colorado Commission Initial Comments at 29; Colorado 
Commission Reply Comments at 6; EEI Initial Comments at 5-6; Xcel 
Initial Comments at 11, 14.
---------------------------------------------------------------------------

C. Reforms To Incorporate Technological Advancements Into the 
Interconnection Process

1. Increasing Flexibility in the Generator Interconnection Process
a. Co-Located Generating Facilities Behind One Point of Interconnection 
With Shared Interconnection Requests
i. Need for Reform and NOPR Proposal
    1324. In the NOPR, the Commission noted that the current pro forma 
LGIP does not address interconnection requests made up of multiple 
generating facilities seeking to co-locate and to share a single point 
of interconnection.\2502\ The Commission preliminarily found that the 
lack of such a process limits the interconnection of generating 
facilities, hindering competition and rendering the Commission's 
existing pro forma LGIP unjust, unreasonable, and unduly discriminatory 
or preferential.\2503\
---------------------------------------------------------------------------

    \2502\ NOPR, 179 FERC ] 61,194 at P 239.
    \2503\ Id. P 240.
---------------------------------------------------------------------------

    1325. The Commission therefore proposed to revise the pro forma 
LGIP and pro forma LGIA to ``require transmission providers to allow 
more than one generating facility to co-locate on a shared site behind 
a single point of interconnection and share a single interconnection 
request.'' \2504\ The Commission explained that this proposed reform 
would ``create a minimum standard that would remove barriers for co-
located resources by creating a standardized procedure for these types 
of configurations to enable them to access the transmission system.'' 
\2505\
---------------------------------------------------------------------------

    \2504\ Id. P 242.
    \2505\ Id.
---------------------------------------------------------------------------

    1326. The Commission proposed to revise the pro forma LGIP to: 
``(1) define `Co-Located Resources' as `more than one resource located 
behind the same point of interconnection'; (2) state that co-located 
resources can share an interconnection request; (3) modify the 
definition of site control such that it allows interconnection 
customers to demonstrate shared land-use for co-located resources.'' 
\2506\ The Commission also proposed to modify the definition of 
interconnection facilities to clarify that multiple generating 
facilities located on the same site may share interconnection 
facilities.\2507\
---------------------------------------------------------------------------

    \2506\ Id. P 243.
    \2507\ Id.; proposed pro forma LGIP section 1.
---------------------------------------------------------------------------

    1327. The Commission also proposed revisions to the pro forma LGIP 
to ``require generating facilities that are co-locating to have 
technology to address differences in terminal voltage between the co-
located generating facilities to ensure that these generating 
facilities have the same voltage levels.'' \2508\ The Commission noted 
that many co-located generating facilities are co-located with electric 
storage resources,\2509\ and proposed to define ``electric storage 
resources'' in the pro forma LGIP as a resource capable of receiving 
electric energy from the grid and storing it for later injection of 
electric energy back to the grid.\2510\
---------------------------------------------------------------------------

    \2508\ NOPR, 179 FERC ] 61,194 at P 245.
    \2509\ Id. P 240.
    \2510\ Id.; proposed pro forma LGIP section 1.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1328. Commenters overwhelmingly support the Commission's 
proposal.\2511\ Eversource conditionally supports the proposal as a 
solid step that will improve the interconnection process.\2512\ 
Avangrid is not opposed to the proposal but does not foresee the reform 
as providing incremental efficiency to transmission providers.\2513\
---------------------------------------------------------------------------

    \2511\ AEE Initial Comments at 38; AES Initial Comments at 23; 
Ameren Initial Comments at 26; APPA-LPPC Initial Comments at 28; 
CAISO Initial Comments at 32; Clean Energy Associations Initial 
Comments at 59; Clean Energy Buyers Initial Comments at 4-5; 
Consumers Energy Company Initial Comments at 8; CREA and NewSun 
Initial Comments at 90; Environmental Defense Fund Initial Comments 
at 5; Environmental Defense Fund Reply Comments at 8; ELCON Initial 
Comments at 10; Enel Initial Comments at 78; Evergreen Action 
Initial Comments at 3; ISO-NE Initial Comments at 39; MISO Initial 
Comments at 107; NARUC Initial Comments at 33; National Grid Initial 
Comments at 39; NextEra Initial Comments at 6; NRECA Initial 
Comments at 44; NY Commission and NYSERDA Initial Comments at 9; 
NYISO Initial Comments at 47; NYTOs Initial Comments at 31-32; OSPA 
Reply Comments at 15; Ohio Commission Initial Comments at 14; Omaha 
Public Power Initial Comments at 13; [Oslash]rsted Initial Comments 
at 18; Pine Gate Initial Comments at 44-45; Public Interest 
Organizations Initial Comments at 43; SEIA Initial Comments at 37; 
SoCal Edison Initial Comments at 19; SPP Initial Comments at 23; 
State Agencies Initial Comments at 14.
    \2512\ Eversource Initial Comments at 32-33.
    \2513\ Avangrid Initial Comments at 34.
---------------------------------------------------------------------------

    1329. Evergreen Action avers that co-location is vital to 
connecting more generation in the short term as transmission providers 
begin to work through large interconnection queue backlogs,\2514\ and 
Evergreen Action and NRECA state that co-locating two or more resources 
will take advantage of technologies like battery storage to more 
efficiently use the transmission system.\2515\ AEE and State Agencies 
argue that, because existing interconnection procedures were designed 
before battery storage and hybrid resource types came into common 
usage, these types of technologies are often underserved under existing 
interconnection procedures despite being well represented in current 
interconnection queues, making this reform timely.\2516\ OSPA urges the 
Commission to implement this proposal as soon as possible.\2517\
---------------------------------------------------------------------------

    \2514\ Evergreen Action Initial Comments at 3.
    \2515\ Id.; NRECA Initial Comments at 44.
    \2516\ AEE Initial Comments at 38; State Agencies Initial 
Comments at 14.
    \2517\ OSPA Reply Comments at 15.
---------------------------------------------------------------------------

    1330. Several commenters argue that the NOPR proposal will likely 
improve the overall efficiency of interconnection processes, result in 
more accurate interconnection queue positions, and help to ensure just 
and reasonable rates.\2518\ Environmental Defense Fund argues that 
combinations of generation and storage on a single site will create 
several benefits, including reducing intermittency, shifting supply to 
better meet demand, responding to grid events, and enabling provision 
of ancillary services.\2519\
---------------------------------------------------------------------------

    \2518\ AEE Initial Comments at 39; AES Initial Comments at 23; 
NARUC Initial Comments at 33; Ohio Commission Initial Comments at 
14.
    \2519\ Environmental Defense Fund Initial Comments at 5.
---------------------------------------------------------------------------

    1331. AEE argues that the greatest value of storage systems is 
their ability to respond rapidly with a high degree of controllability, 
and contends that hybrid resources smooth the output of variable 
resources, allowing for increased land use efficiencies.\2520\ Several 
commenters argue that the proposal will yield interconnection queue 
efficiency because the shared nature of the co-located resources can be 
fully accounted for in a single interconnection request: they contend 
that requiring co-located resources to submit multiple interconnection 
requests increases cost, timing, and complexity, while forgoing 
reliability benefits.\2521\
---------------------------------------------------------------------------

    \2520\ AEE Initial Comments at 39.
    \2521\ Id.; AES Initial Comments at 39; Consumers Energy Company 
Initial Comments at 8; Environmental Defense Fund Initial Comments 
at 5-6; NARUC Initial Comments at 33; Ohio Commission Initial 
Comments at 14; [Oslash]rsted Initial Comments at 19; Public 
Interest Organizations Initial Comments at 44; SEIA Initial Comments 
at 37-38; SoCal Edison Initial Comments at 19.

---------------------------------------------------------------------------

[[Page 61200]]

    1332. In support of the proposal, AEE argues that several 
transmission providers already allow co-located generating facilities 
at the same point of interconnection to submit a single request (e.g., 
CAISO, ISO-NE, and MISO).\2522\ AES contends that the Commission's 
proposed reforms are necessary to ensure parity across all RTOs/ISOs on 
this issue, as some RTOs'/ISOs' practices erect unnecessary and 
unreasonable barriers for generating facilities located behind a single 
point of interconnection to interconnect.\2523\
---------------------------------------------------------------------------

    \2522\ AEE Initial Comments at 39-40.
    \2523\ AES Initial Comments at 23.
---------------------------------------------------------------------------

    1333. Omaha Public Power supports the Commission's proposals to 
facilitate new technologies, specifically the reforms related to co-
located resources, revisions to the modification process, and surplus 
interconnection capacity.\2524\ Omaha Public Power observes, however, 
that many transmission providers have already made progress in this 
area and therefore recommends that the Commission allow existing 
transmission provider processes that are facilitating new technologies 
to continue.
---------------------------------------------------------------------------

    \2524\ Omaha Public Power Initial Comments at 13.
---------------------------------------------------------------------------

(b) Comments on Specific Proposal
    1334. Avangrid asserts that the Commission's proposal should not 
change or supersede any regional metering requirements for market 
participation and contends that co-located resources must have separate 
meters even if they share a point of interconnection.\2525\
---------------------------------------------------------------------------

    \2525\ Avangrid Initial Comments at 34.
---------------------------------------------------------------------------

    1335. NARUC and MISO support the Commission's proposal that co-
located generating facilities must have technology to address 
differences in terminal voltage between the co-located generating 
facilities.\2526\ MISO states that having to study a single co-located 
generating facility with two points of interconnection at different 
voltages would be infeasible, and that co-located generating facilities 
should be required to inject at a single point of interconnection, at a 
single voltage.\2527\ SPP states that it is unclear what the Commission 
intended in the NOPR by proposing to require that generating facilities 
``address differences in terminal voltage between the co-located 
generating facilities to ensure that these generating facilities have 
the same voltage levels.'' \2528\ SPP contends that it would be simpler 
to require that such generating facilities connect at the same point of 
interconnection and leave the details as to how to do that to the 
interconnection customer. Ameren argues that, so long as modeling is 
available to the transmission provider for the types of resources that 
are behind the point of interconnection, co-located resources with 
differences in terminal voltage should not be an issue when performing 
the interconnection studies.\2529\
---------------------------------------------------------------------------

    \2526\ MISO Initial Comments at 107-108; NARUC Initial Comments 
at 33.
    \2527\ MISO Initial Comments at 107-108.
    \2528\ SPP Initial Comments at 23 (citing NOPR, 179 FERC ] 
61,194 at P 245).
    \2529\ Ameren Initial Comments at 26.
---------------------------------------------------------------------------

    1336. [Oslash]rsted supports the Commission's proposed changes to 
the definition of ``interconnection facilities.'' \2530\ Enel states 
that the proposed insertion of the phrase ``by interconnection 
customer'' in the third sentence of the pro forma LGIA/LGIP definition 
of ``interconnection facilities'' should be changed to the phrase ``by 
interconnection customer(s).'' \2531\ Enel further states that the 
proposed new fourth sentence to the definition of ``interconnection 
facilities'' explains that multiple interconnection customers may use a 
single set of interconnection facilities, and thus ``sole use 
facilities'' may have multiple interconnection customer beneficiaries.
---------------------------------------------------------------------------

    \2530\ [Oslash]rsted Initial Comments at 18.
    \2531\ Enel Initial Comments at 81-82.
---------------------------------------------------------------------------

    1337. Southern states that, under the NOPR proposal, co-located 
resources can include different owners of different generating 
facilities.\2532\ Pine Gate and Southern note that the proposal to 
allow interconnection customers to demonstrate shared land-use may 
require interconnection customers to provide transmission providers 
more detailed site maps to demonstrate valid site control for each 
generating facility.\2533\ Southern states that this is appropriate 
because the transmission provider should not be responsible for 
monitoring the legal relationship between the co-owners.\2534\ Southern 
states that co-located resources must either be owned by the same 
owner, or the different owners of the generating facilities must enter 
into an agreement that addresses off-take rights and ownership, and 
they must submit one interconnection request for the entire generating 
facility. Tri-State suggests clarifying that a separate agreement is 
not necessary when both co-located resources belong to the same 
interconnection customer.\2535\
---------------------------------------------------------------------------

    \2532\ Southern Initial Comments at 35.
    \2533\ Id. at 36; Pine Gate Initial Comments at 46.
    \2534\ Southern Initial Comments at 36.
    \2535\ Tri-State Initial Comments at 25.
---------------------------------------------------------------------------

    1338. Clean Energy Associations support allowing multiple 
generating facilities that share a single point of interconnection to 
submit a joint interconnection request as a hybrid or co-located 
resource. Clean Energy Associations argue that interconnection 
customers with proposed generating facilities where the electric 
storage resource and generating facility are co-located, and have two 
``resource IDs,'' should be allowed to choose to have each component 
studied separately.\2536\ Clean Energy Associations also submit that 
the generating equipment for the generating facilities should not be 
required to be located on a shared site. Clean Energy Associations 
further assert that such flexibility would allow, for example, a solar 
facility to obtain a faster ERIS study while the co-located storage 
could get a more detailed study for NRIS.
---------------------------------------------------------------------------

    \2536\ Clean Energy Associations Initial Comments at 59-61.
---------------------------------------------------------------------------

    1339. Southern contends that co-located resources that intend to be 
qualifying facilities should be required to comply with PURPA 
requirements.\2537\
---------------------------------------------------------------------------

    \2537\ Southern Initial Comments at 36.
---------------------------------------------------------------------------

(c) Requests for Clarification and Flexibility
    1340. Pine Gate agrees that co-located generating facilities must 
have technology to address differences in terminal voltage between the 
co-located generating facilities, arguing that such technology is 
likely necessary in instances where a co-located resource is being 
studied under a single interconnection request for a net injection at 
the point of interconnection.\2538\ However, Pine Gate requests that 
the Commission clarify that such technology is not necessary in 
instances in which the interconnection customer elects to submit a co-
located resource using two separate interconnection requests.
---------------------------------------------------------------------------

    \2538\ Pine Gate Initial Comments at 46.
---------------------------------------------------------------------------

    1341. SPP notes that in the NOPR, the Commission proposed to define 
``co-located resources'' as ``more than one resource located behind the 
same point of interconnection,'' whereas the proposed definition in the 
pro forma LGIP reads, ``Co-Located Resource shall mean multiple 
Generating Facilities located on the same site.'' \2539\ SPP states 
that two generating facilities can be located on the same site without 
connecting behind the same point of interconnection. SPP asks the 
Commission to clarify in the final rule which definition of co-located 
resource is required. SPP states that it supports a definition that 
explicitly states that the

[[Page 61201]]

generating facilities must connect at the same point of 
interconnection.
---------------------------------------------------------------------------

    \2539\ SPP Initial Comments at 23.
---------------------------------------------------------------------------

    1342. MISO and Southern request that the Commission clarify that 
co-located resources must be required to share an interconnection 
request.\2540\ According to MISO, its tariff and Order No. 807 \2541\ 
allow for different interconnection requests to share a generator tie 
line and thus share the same point of interconnection. MISO argues that 
failing to amend the definition of co-located resource would conflate 
the two scenarios under the same definition, such that two separate 
noncontiguous generating facilities that share a generator tie line 
would share the same point of interconnection, thus also falling under 
the definition of co-located resources without the intent to do 
so.\2542\ Southern argues that the Commission should clarify that the 
interconnection tie line connecting the co-located resource to the 
transmission system is a radial facility, not a network facility.\2543\
---------------------------------------------------------------------------

    \2540\ MISO Initial Comments at 107; Southern Initial Comments 
at 36.
    \2541\ Open Access & Priority Rights on Interconnection 
Customer's Interconnection Facilities, Order No. 807, 80 FR 17654 
(Apr. 1, 2015), 150 FERC ] 61,211, order on reh'g, Order No. 807-A, 
153 FERC ] 61,047 (2015).
    \2542\ MISO Initial Comments at 107.
    \2543\ Southern Initial Comments at 37.
---------------------------------------------------------------------------

    1343. National Grid asks that the Commission clarify what is 
included in the definition of ``co-located resources.'' \2544\ National 
Grid understands that the term can apply to hybrid technologies owned 
by a single interconnection customer interconnecting to a single point 
of interconnection, such as a solar generating facility coupled with a 
storage facility. National Grid suggests that, to the extent the term 
also is intended to apply to multiple interconnection customers with 
separate generating facilities interconnecting to a single point of 
interconnection, that the proposal might create complexities not 
discussed in the NOPR but may merit consideration.
---------------------------------------------------------------------------

    \2544\ National Grid Initial Comments at 39-40.
---------------------------------------------------------------------------

    1344. SEIA requests clarification on the terminology used in the 
proposal.\2545\ SEIA states that in January 2021, in its order 
directing reports on information related to hybrid resources, the 
Commission used two distinct terms to identify hybrid resource market 
participation.\2546\ SEIA states that ``co-located hybrid resources'' 
are defined as two separate resources sharing a single point of 
interconnection that are modeled and dispatched separately. SEIA states 
that ``integrated hybrid resources'' are defined as sets of resources 
that share a single point of interconnection and are modeled and 
dispatched as a single resource. Tri-State similarly states that the 
``electric storage resource'' definition does not account for resources 
designed to be charged apart from the transmission system, such as 
solar or wind generating facilities that may charge an electric storage 
resource.\2547\ SEIA requests that the Commission adopt the terms co-
located and integrated hybrid resources in the final rule and clarify 
that interconnection customers retain the choice of how to structure 
their interconnection requests to best suit their needs and the needs 
of their customers.\2548\
---------------------------------------------------------------------------

    \2545\ SEIA Initial Comments at 38.
    \2546\ Id. (citing Hybrid Res., 174 FERC ] 61,034, at P 4 
(2021)).
    \2547\ Tri-State Initial Comments at 25.
    \2548\ SEIA Initial Comments at 38.
---------------------------------------------------------------------------

    1345. Some commenters ask that the Commission provide regional 
flexibility as to the types of co-located resources permitted in each 
RTO/ISO and existing processes that may already accomplish the goals of 
the proposed reforms.\2549\ ISO-NE, NYISO, and MISO state that they are 
already in compliance with the proposed reform.\2550\
---------------------------------------------------------------------------

    \2549\ ISO-NE Initial Comments at 39; NY Commission and NYSERDA 
Initial Comments at 9; NYTOs Initial Comments at 31-32.
    \2550\ ISO-NE Initial Comments at 39; MISO Initial Comments at 
107; NYISO Initial Comments at 47.
---------------------------------------------------------------------------

iii. Commission Determination
    1346. We adopt, with modification, the NOPR proposal to revise pro 
forma LGIP section 3.1.2 to require transmission providers to allow 
more than one generating facility to co-locate on a shared site behind 
a single point of interconnection and share a single interconnection 
request. We decline to adopt the proposed definitions of ``co-located 
resource'' and ``electric storage resource,'' and we decline to adopt 
the proposed modifications to the definitions of interconnection 
facilities, and transmission provider's interconnection facilities in 
pro forma LGIP section 1 and pro forma LGIA article 1.\2551\ We find 
that including the definition of co-located resource in the pro forma 
LGIP and pro forma LGIA is not necessary to effectuate the process 
reforms detailed in the NOPR, and thus decline to adopt it here.\2552\ 
Given that Order No. 845 revised the definition of generating facility 
to include electric storage resources,\2553\ we also find it 
unnecessary to define the term electric storage resource in the pro 
forma LGIP and LGIA. We note that declining to adopt the definition of 
electric storage resource moots Tri-State's concern that the proposed 
definition failed to account for electric storage resources that may be 
charged apart from the transmission system.\2554\
---------------------------------------------------------------------------

    \2551\ NOPR, 179 FERC ] 61,194 at P 243; proposed pro forma LGIA 
section 1.
    \2552\ Co-located generating facilities are more than one 
generating facility that are located on the same site and that are 
connected at the same point of interconnection that are operated and 
dispatched as separate generating facilities.
    \2553\ See Order No. 845, 163 FERC ] 61,043, at P 275 (modifying 
the definition of ``Generating Facility'' in the pro forma LGIP and 
pro forma LGIA to include ``and/or storage for later injection'').
    \2554\ Tri-State Initial Comments at 25.
---------------------------------------------------------------------------

    1347. We also decline to adopt the NOPR proposal to modify the 
definitions of interconnection facilities and transmission provider's 
interconnection facilities to specify that interconnection facilities 
may be shared among interconnection customers. We find that such 
specification in the pro forma LGIP and pro forma LGIA is not needed 
because Commission policy does not prohibit interconnection customers 
from sharing interconnection facilities.\2555\ We expect that there may 
be benefits from interconnection customers being able to share 
transmission provider's interconnection facilities and interconnection 
customer's interconnection facilities, particularly in light of the 
Commission's transition in this final rule to a cluster study approach. 
Under a cluster study approach, in which multiple interconnection 
requests are evaluated in a combined study, efficiencies may be gained 
(in cost and time to construct) by allowing interconnection customers 
to share use of, and payment for, interconnection facilities. We note 
that such efficiencies from allowing the interconnection facilities to 
be used by more than one interconnection customer do not exist under 
the Commission's existing pro forma LGIP serial interconnection study 
process because the serial study process does not consider the 
interconnection facilities that would be necessary to accommodate the 
interconnection of more than one interconnection customer. In response 
to [Oslash]rsted and Enel's comments expressing support for the 
revisions to the definitions of interconnection facilities and 
transmission provider's interconnection facilities,\2556\ we state in 
this final rule that the interconnection facilities also may be used by 
more than one interconnection customer.
---------------------------------------------------------------------------

    \2555\ See, e.g., Order No. 807, 150 FERC ] 61,211, at P 3 
(discussing the ability of interconnection customer's 
interconnection facilities owners to make excess capacity available 
to third parties).
    \2556\ [Oslash]rsted Initial Comments at 18; Enel Initial 
Comments at 81-82.

---------------------------------------------------------------------------

[[Page 61202]]

    1348. We also decline to adopt the NOPR proposal to revise the pro 
forma LGIP to require generating facilities that are co-locating to 
have technology to address differences in terminal voltage between the 
co-located generating facilities to ensure that these generating 
facilities have the same voltage levels.\2557\ We find that the 
preexisting language in pro forma LGIP section 3.1 (section 3.1.2 as 
revised by this final rule) is clear that ``[a]n Interconnection 
Request to evaluate one site at two different voltage levels shall be 
treated as two Interconnection Requests.'' This preexisting provision 
makes clear that a set of co-located generating facilities must be at a 
single terminal voltage in order to be treated as a single 
interconnection request. The additional requirement proposed in the 
NOPR is therefore unnecessary to adopt in the final rule. We note that 
declining to adopt the NOPR proposal with respect to this issue 
alleviates SPP's concern with the NOPR proposal.\2558\ In response to 
Pine Gate, we reiterate that preexisting pro forma LGIP section 3.1 
(section 3.1.2 as revised by this final rule) would require co-located 
generating facilities with different terminal voltage levels to submit 
separate interconnection requests.\2559\
---------------------------------------------------------------------------

    \2557\ See NOPR, 179 FERC ] 61,194 at P 245.
    \2558\ See SPP Initial Comments at 23.
    \2559\ See Pine Gate Initial Comments at 46.
---------------------------------------------------------------------------

    1349. As the Commission stated in the NOPR, recent studies 
demonstrate that large numbers of generating facilities currently in 
interconnection queues are seeking to co-locate on a shared site behind 
one point of interconnection and share an interconnection request, 
while operating separately, and that the pro forma LGIP currently lacks 
provisions that explicitly allow them to do so.\2560\ We agree with 
commenters that this type of generating facility configuration, in 
spite of being prevalent in current interconnection queues, faces 
barriers to interconnection under existing interconnection 
procedures,\2561\ and that this reform will effectively remove such 
barriers. We find that requiring transmission providers to allow 
interconnection customers to submit a single interconnection request 
that represents multiple generating facilities that are located behind 
a single point of interconnection is required to ensure just and 
reasonable rates. By doing so, this reform will improve efficiency for 
transmission providers in the study process by reducing the number of 
interconnection requests in the interconnection queue and will reduce 
costs for interconnection customers because they will only submit a 
single set of deposits to enter the interconnection queue.
---------------------------------------------------------------------------

    \2560\ NOPR, 179 FERC ] 61,194 at P 238.
    \2561\ AEE Initial Comments at 38; State Agencies Initial 
Comments at 14.
---------------------------------------------------------------------------

    1350. We also believe that this reform will improve interconnection 
queue efficiency without imposing an adverse impact on the efficacy of 
interconnection study results or other interconnection customers. 
Because of the significant growth of generating facilities seeking to 
interconnect jointly at a single point of interconnection,\2562\ we 
find that allowing co-located generating facilities to submit one 
interconnection request will lessen the delays experienced in many 
interconnection queues. We agree with commenters that transmission 
providers requiring co-located generating facilities to submit separate 
interconnection requests increases the cost and complexity of the 
interconnection process and creates undue delay to the interconnection 
process.\2563\ Allowing co-located generating facilities to share 
interconnection requests will ensure the interconnection queue moves 
along expediently, providing clarity, cost certainty, and increased 
transparency throughout the study process.
---------------------------------------------------------------------------

    \2562\ Currently, 42% (285 GW) of solar and 8% (17 GW) of wind 
projects in the queue are proposed as hybrid resources that would 
include electric storage. Queued Up 2023 at 18.
    \2563\ AEE Initial Comments at 39; Environmental Defense Fund 
Initial Comments at 5-6.
---------------------------------------------------------------------------

    1351. Some commenters suggest that co-located generating facilities 
should always be required to share an interconnection request.\2564\ 
Others request that interconnection customers retain the choice whether 
to share an interconnection request.\2565\ We clarify that 
interconnection customers have the choice to structure their 
interconnection requests according to their preference. We are not 
requiring interconnection customers to share a single interconnection 
request for multiple generating facilities located on the same site.
---------------------------------------------------------------------------

    \2564\ MISO Initial Comments at 107; Southern Initial Comments 
at 36.
    \2565\ Clean Energy Associations Initial Comments at 59-61 
(arguing against such a requirement to enable co-located generating 
facilities to seek ERIS versus NRIS); SEIA Initial Comments at 38.
---------------------------------------------------------------------------

    1352. However, we further clarify in response to Clean Energy 
Associations \2566\ that interconnection customers may submit separate 
interconnection requests to have each device studied separately. We 
find that this clarification also addresses MISO's concern about any 
potential conflict with Order No. 807.\2567\ Additionally, we clarify 
that, where an interconnection customer chooses to submit a single 
interconnection request for multiple generating facilities, the 
generating facilities must be located on the same site in order to 
reduce complexity for the transmission provider.
---------------------------------------------------------------------------

    \2566\ Clean Energy Association Initial Comments at 59-61 
(requesting that generating equipment not be required to be on the 
same site).
    \2567\ MISO Initial Comments at 107-108.
---------------------------------------------------------------------------

    1353. In response to Southern's request that the Commission clarify 
that the interconnection tie line connecting the co-located resource to 
the transmission system is a radial facility, not a network facility, 
we clarify that, as explained in Order No. 807, the Commission now 
refers to tie lines as the interconnection customer's interconnection 
facilities.\2568\ As the Commission stated in Order No. 807, the 
interconnection customer's interconnection facilities ``are sole-use, 
limited and discrete, radial in nature, and not part of an integrated 
transmission network.'' \2569\ Radial facilities located between the 
generating facility and point of interconnection are considered 
interconnection facilities under the pro forma LGIP and pro forma 
LGIA.\2570\
---------------------------------------------------------------------------

    \2568\ The Commission stated that ``[t]he jurisdictional 
interconnection facilities for which this Final rule grants a waiver 
have sometimes in the past been referred to informally as `generator 
tie lines,' but, in the Notice of Proposed Rulemaking, the 
Commission used the term [Interconnection Customer's Interconnection 
Facilities] as defined in the pro forma documents issued with Order 
No. 2003.'' Order No. 807, 150 FERC ] 61,211, at n.1 (citing Order 
No. 2003, 104 FERC ] 61,103).
    \2569\ Order No. 807, 150 FERC ] 61,211 at P 114.
    \2570\ Under the pro forma LGIP, ``Interconnection Facilities 
shall mean Transmission Provider's Interconnection Facilities and 
Interconnection Customer's Interconnection Facilities. Collectively, 
Interconnection Facilities include all facilities and equipment 
between the Generating Facility and the Point of Interconnection, 
including any modification, additions or upgrades that are necessary 
to physically and electrically interconnect the Generating Facility 
to Transmission Provider's Transmission System. Interconnection 
Facilities are sole use facilities and shall not include 
Distribution Upgrades, Stand Alone Network Upgrades or Network 
Upgrades.'' See pro forma LGIP section 1 and pro forma LGIA article 
1.
---------------------------------------------------------------------------

    1354. In response to Omaha Public Power's suggestion that the 
Commission allow existing transmission provider processes that are 
facilitating new technologies to continue unimpeded, we clarify that, 
consistent with section IV of this final rule, to the extent 
transmission providers believe that they already comply with the 
adopted pro forma LGIP provisions, they may demonstrate this in their 
compliance filings.
    1355. In response to concerns about multiple interconnection 
customers using the same interconnection

[[Page 61203]]

request,\2571\ we clarify that co-located generating facilities can be 
owned by a single interconnection customer with multiple generating 
facilities sharing a site, or by multiple interconnection customers 
that have a contract or other agreement that allows for shared land 
use.\2572\ In response to Tri-State,\2573\ we clarify that no such 
agreement is necessary when the generating facilities in question 
belong to the same interconnection customer. In response to 
Southern,\2574\ we clarify that generating facilities that co-locate 
still must adhere to all other applicable laws and regulations, 
including PURPA.
---------------------------------------------------------------------------

    \2571\ National Grid Initial Comments at 39-40; Southern Initial 
Comments at 35-36.
    \2572\ The revised definition of site control in the pro forma 
LGIP adopted in this final rule requires that site control be 
``demonstrated by a contract or other agreement that allows for 
shared land use for all Generating Facilities that are co-located 
and meet the provisions of the Site Control definition.'' Pro forma 
LGIP section 3.4.2.
    \2573\ Tri-State Initial Comments at 25.
    \2574\ Southern Initial Comments at 36.
---------------------------------------------------------------------------

    1356. We find that comments regarding the following issues are 
outside the scope of this proceeding because they pertain to market 
issues and other rules that were not addressed in the NOPR: (1) 
permitting an interconnection customer to specify the co-located 
generating facility's maximum injection level to the point of 
interconnection; \2575\ and (2) metering requirements for co-located 
generating facilities.\2576\
---------------------------------------------------------------------------

    \2575\ Pine Gate Initial Comments at 45.
    \2576\ Avangrid Initial Comments at 34.
---------------------------------------------------------------------------

    1357. We decline SEIA's request that the Commission adopt a more 
expansive definition of ``co-located resources,'' including how the 
resources are modeled and dispatched. Modeling assumptions for electric 
storage resources and co-located or hybrid generating facilities 
containing electric storage resources are addressed elsewhere in this 
final rule.\2577\
---------------------------------------------------------------------------

    \2577\ See infra section III.C.1.d.
---------------------------------------------------------------------------

b. Revisions to the Modification Process To Require Consideration of 
Generating Facility Additions
i. Need for Reform and NOPR Proposal
    1358. In the NOPR, the Commission expressed concern that, because 
certain requests to add a generating facility to an existing 
interconnection request are often deemed material without an 
evaluation, even if the injection amount remains the same, the material 
modification process may result in unjust, unreasonable, and unduly 
discriminatory or preferential outcomes.\2578\ The Commission pointed 
out that, as explained in Order No. 2003, it is inadequate and 
inefficient to solve interconnection issues on a case-by-case 
basis.\2579\ The Commission explained that, in the case of processing 
modification requests, without a standard set of procedures, 
transmission providers have adopted varying strategies for processing 
requests to add electric storage or other generating facilities that do 
not change the requested interconnection service limit to existing 
interconnection requests. The Commission preliminarily found that this 
lack of uniformity leads to disparate outcomes across the country and 
leaves open the potential for undue discrimination.
---------------------------------------------------------------------------

    \2578\ NOPR, 179 FERC ] 61,194 at P 252.
    \2579\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 9-
10).
---------------------------------------------------------------------------

    1359. The Commission explained that the modification provisions in 
the pro forma LGIP do not specify whether an interconnection customer 
can modify its interconnection request to add another generating 
facility at the same point of interconnection without increasing the 
requested interconnection service level.\2580\ The Commission stated 
that many transmission providers treat such a request automatically as 
a material modification, such that the interconnection customer that 
wishes to make this type of change faces a loss of interconnection 
queue position regardless of the actual effect the addition of a 
generating facility to an interconnection request may have on the 
system. The Commission explained that this process is a significant 
barrier to interconnection customers that wish to make this type of 
change and preliminarily found that such a barrier hinders access to 
the transmission system and may render existing interconnection 
processes unjust, unreasonable, and unduly discriminatory or 
preferential.\2581\
---------------------------------------------------------------------------

    \2580\ Id. P 253.
    \2581\ Id. P 254.
---------------------------------------------------------------------------

    1360. In the NOPR, the Commission proposed to revise the pro forma 
LGIP to require transmission providers to evaluate the proposed 
addition of a generating facility to an interconnection request as long 
as the interconnection customer does not request a change to the 
originally requested interconnection service level.\2582\ Under this 
proposed requirement, the transmission provider could not automatically 
consider such a request to be a material modification. Specifically, 
the Commission proposed to require that: (1) transmission providers 
evaluate the proposed addition of a generating facility to an 
interconnection request within 60 calendar days of receiving the 
request for modification if such addition does not change the requested 
interconnection service level; (2) the change cannot be considered an 
automatic material modification and an evaluation (including studying 
the configuration and necessary modeling) must occur prior to 
determining whether the proposed change constitutes a material 
modification of the interconnection request; and (3) if the proposed 
addition does not have a material impact on the cost or timing of any 
interconnection request that is lower or equally queued, and does not 
cause any other reliability concerns, the addition will not be 
considered a material modification.\2583\ The Commission noted that the 
reliability concerns could include, for example, a material impact on 
the transmission system with regard to short circuit capability limits, 
steady-state thermal and voltage limits, or dynamic system stability 
and response.
---------------------------------------------------------------------------

    \2582\ Id. P 255.
    \2583\ Id. P 255.
---------------------------------------------------------------------------

    1361. The Commission sought comment on: (1) whether the addition of 
a generating facility that does not alter an interconnection customer's 
interconnection service limit could nonetheless require a full 
interconnection service study; (2) how transmission providers should 
perform studies required to confirm that there is no adverse impact 
because of the addition of a generating facility to an interconnection 
request, such as confirmation that the electrical characteristics of 
the interconnection customer remain the same; (3) whether and how 
interconnection customers in a later cluster, or interconnection 
customers that are in the same cluster, could be adversely impacted by 
such changes; (4) whether the addition of electric storage when in 
charging mode (in terms of resistance, inductance, and capacitance) may 
change the electrical characteristics of an interconnection request, 
and whether those changes may affect the reliable operation of the 
generating facility related to that interconnection request; and (5) 
whether further specification is needed for the assessment of the 
electrical characteristics due to the addition of a complex load.\2584\
---------------------------------------------------------------------------

    \2584\ Id. PP 256-257.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1362. A diverse group of commenters indicate general support for 
the NOPR proposal.\2585\ NARUC agrees that the

[[Page 61204]]

proposed reform will promote consistency for interconnection customers 
throughout the country, in addition to promoting reliability, economic, 
and administrative efficiency as the generation fleet continues to 
evolve.\2586\ NARUC explains that the loss of interconnection queue 
position as a result of adding a generating facility that does not 
increase the requested service level or cause reliability issues, but 
rather could improve the performance and capability of a generating 
facility to manage reliability or lower the cost of energy to 
customers, is an inefficient and discriminatory outcome the Commission 
should seek to permanently remedy through this proceeding. AEE and 
Public Interest Organizations assert that a restudy would be 
automatically required for adding a generating facility such as 
storage, and that if there were not a restudy related to the addition 
of storage, they could provide numerous benefits, including firming up 
variable renewable generation, avoided curtailment, congestion relief, 
and, in the case of grid-forming inverters and batteries, fast 
frequency response and other grid flexibility services.\2587\ AEE 
contends that the loss of the benefits, primarily from adding storage, 
will harm reliability and result in unjust and unreasonable 
rates.\2588\ SEIA contends that adding an additional generating 
facility (such as storage) that does not increase the interconnection 
service level also should not increase the costs to later 
interconnection requests because it generally would not require 
additional network upgrades and should not delay lower-queued 
interconnection requests.\2589\
---------------------------------------------------------------------------

    \2585\ AEE Initial Comments at 40-41; AEE Reply Comments at 39-
41; AES Initial Comments at 23; Ameren Initial Comments at 27; APS 
Initial Comments at 20; Avangrid Initial Comments at 34-35; CAISO 
Initial Comments at 32; Clean Energy Associations Initial Comments 
at 59-61; CREA and NewSun Initial Comments at 90-91; Cypress Creek 
Initial Comments at 18-19; Environmental Defense Fund Initial 
Comments at 6; Environmental Defense Fund Reply Comments at 8-9; 
ENGIE Initial Comments at 10-11; EPSA Initial Comments at 13; 
Equinor Wind Reply Comments at 5-6; Illinois Commission Initial 
Comments at 13-14; NARUC Initial Comments at 33-35; National Grid 
Initial Comments at 40 (noting qualifications); NRECA Initial 
Comments at 44; NY Commission and NYSERDA Initial Comments at 9; 
NYTOs Initial Comments at 31; Omaha Public Power Initial Comments at 
13; [Oslash]rsted Initial Comments at 8; [Oslash]rsted Reply 
Comments at 7; PacifiCorp Initial Comments at 39-40; Pine Gate 
Initial Comments at 44, 47-49; OPSI Initial Comments at 9-10; Public 
Interest Organizations Initial Comments at 45-47; SEIA Initial 
Comments at 38-39; Shell Initial Comments, app. A at ii; SPP Initial 
Comments at 24; UMPA Initial Comments at 7-9.
    \2586\ NARUC Initial Comments at 33-35.
    \2587\ AEE Initial Comments at 40-41; Public Interest 
Organizations Initial Comments at 45.
    \2588\ AEE Initial Comments at 40-41.
    \2589\ SEIA Initial Comments at 38-39; see also ENGIE Initial 
Comments at 10-11.
---------------------------------------------------------------------------

    1363. Clean Energy Associations and Shell add that a generating 
facility's addition of energy storage capability without increasing the 
power capability upon which its interconnection service level is based 
(e.g., increasing a two-hour battery to a four-hour battery) should not 
automatically be considered a material modification.\2590\ Clean Energy 
Associations also argue that the removal of a generating facility from 
a hybrid or co-located resource interconnection request should not 
automatically be considered a material modification if interconnection 
service levels do not change.\2591\ Clean Energy Associations also 
request that the material modification rules allow for an increase in 
the underlying capability of the generating facility, rather than 
simply an addition of a new resource.
---------------------------------------------------------------------------

    \2590\ Clean Energy Associations Initial Comments at 59-61; 
Shell Initial Comments, app. A at ii.
    \2591\ Clean Energy Associations Initial Comments at 59-61.
---------------------------------------------------------------------------

    1364. Ameren believes that when considering the addition of a 
generating facility to an interconnection request, it is important to 
protect reliability while avoiding unjustly limiting interconnection 
customer changes by automatically deeming them material 
modifications.\2592\ National Grid supports the proposal but asks the 
Commission to acknowledge that there may be instances when a 
determination that the requested generating facility addition is a 
material modification is necessary, such as if: (1) changes in load 
characteristics of the generating facility or in electrical 
characteristics of a resource; or (2) impacts to other interconnection 
customers in the interconnection queue.\2593\ SPP also generally 
supports the proposal but similarly notes there may be instances when a 
request that does not alter the interconnection service amount, it 
could require a full interconnection study and result in additional 
network upgrades (e.g., a request to change a generating facility from 
one type to another where changes to electric characteristics impact 
stability, fault current, or both).\2594\
---------------------------------------------------------------------------

    \2592\ Ameren Initial Comments at 27.
    \2593\ National Grid Initial Comments at 40.
    \2594\ SPP Initial Comments at 24.
---------------------------------------------------------------------------

    1365. AES supports the proposal because it adds flexibility to the 
interconnection process, including the efficient addition of generating 
facilities such as electric storage resources to previously submitted 
interconnection requests.\2595\ UMPA supports the flexibility of a 
generating facility's design if a more commercially viable option could 
be pursued without changing the level of interconnection service or 
causing reliability concerns, in particular when a prospective 
interconnection customer intends to acquire a preexisting 
interconnection queue position in accordance with pro forma LGIP 
section 4.3.\2596\
---------------------------------------------------------------------------

    \2595\ AES Initial Comments at 23.
    \2596\ UMPA Initial Comments at 8.
---------------------------------------------------------------------------

    1366. AEE suggests that the flexibility to adopt ``modest 
modifications'' is important due to the current length of the 
interconnection process, technology changes, price declines, and other 
factors such as supply chain challenges.\2597\ AEE recognizes that some 
modifications may be material and will require restudy but suggests 
that disallowing modest changes like adding energy storage that may be 
beneficial, will harm reliability, and could increase consumer costs by 
limiting the ability to respond to changing opportunities and needs. 
NRECA supports the reform if it results in better use of the 
transmission system but argues that flexibility should not come at the 
expense of the NOPR's overall goal of reducing speculative 
interconnection requests, withdrawals, and restudies.\2598\
---------------------------------------------------------------------------

    \2597\ AEE Initial Comments at 40-41.
    \2598\ NRECA Initial Comments at 44.
---------------------------------------------------------------------------

    1367. Some commenters point out that certain RTOs/ISOs use similar 
approaches to those proposed.\2599\ NARUC highlights that certain 
planning regions have demonstrated that they can reliably accommodate 
generating facility additions that do not increase requested services 
levels without treating the modification as a material change.\2600\ 
NARUC underscores CAISO's flexible process that allows interconnection 
customers to modify the interconnection request and treats fewer 
resource additions as a material modification, which results in more 
consistent and predictable interconnection queue outcomes and 
ultimately more optimized investments.
---------------------------------------------------------------------------

    \2599\ CAISO Initial Comments at 32; NY Commission and NYSERDA 
Initial Comments at 9; NYISO Initial Comments at 48-49; SPP Initial 
Comments at 24.
    \2600\ NARUC Initial Comments at 33-35.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1368. A number of commenters oppose the proposal.\2601\ ISO-NE and

[[Page 61205]]

Idaho Power argue that the Commission should require that 
interconnection requests be fully conceived by the time a cluster 
request window is closed and modifications be proposed in a subsequent 
cluster so it does not delay the cluster.\2602\ ISO-NE contends that 
the flexibility in the proposal is contrary to the NOPR's goal of 
improving study completion timelines and readiness requirements because 
adding a generating facility to an interconnection request could 
introduce major changes to study scope, upgrade results, and delay 
rather than increase study time speed.\2603\
---------------------------------------------------------------------------

    \2601\ Ameren Initial Comments at 27; Cypress Creek Initial 
Comments at 18-19; Eversource Initial Comments at 33-34; Idaho Power 
Initial Comments at 13; Indicated PJM TOs Initial Comments at 52-54; 
Indicated PJM TOs Reply Comments at 36-38, 52-54; ISO-NE Initial 
Comments at 39-40; MISO Initial Comments at 10; NERC Initial 
Comments at 19-20; PacifiCorp Initial Comments at 39-40; PJM Initial 
Comments at 18-19, 51-53; Southern Initial Comments at 37-38; SPP 
Initial Comments at 24.
    \2602\ ISO-NE Initial Comments at 39-40; Idaho Power Initial 
Comments at 13.
    \2603\ ISO-NE Initial Comments at 39-40.
---------------------------------------------------------------------------

    1369. MISO opposes the proposal because it believes that the 
proposal will increase speculative interconnection requests, contrary 
to the stated intention of NOPR, and that the balance is disrupted 
between flexibility to make changes and promoting fairness and 
certainty to other interconnection customers.\2604\ PJM, MISO, and 
Indicated PJM TOs argue that the proposal will cause delays and divert 
resources that would have been used toward processing the 
interconnection queue,\2605\ and MISO states the proposal may enable an 
end-run around its site control deadlines by giving interconnection 
customers more time to obtain site control.\2606\
---------------------------------------------------------------------------

    \2604\ MISO Initial Comments at 108-12 (citing Midcontinent 
Indep. Sys. Operator, Inc., 177 FERC ] 61,234, at P 12 (2021)); see 
also MISO Reply Comments at 9.
    \2605\ Indicated PJM TOs Reply Comments at 38; Indicated PJM TOs 
Initial Comments at 52-54; MISO Initial Comments at 108-12; PJM 
Initial Comments at 6.
    \2606\ MISO Initial Comments at 108-12.
---------------------------------------------------------------------------

    1370. MISO states that, each time an interconnection customer 
requests a fuel change (including the addition of storage), under the 
proposal, MISO would have to determine if a material modification 
exists within 60 days by doing the following: (1) stop processing the 
interconnection queue, create an alternative model, and then run two 
system impact studies based on the different models (original and 
alternate) to determine if there were any changes between the two 
studies; (2) rebuild the models of any lower-queued cycles and run 
alternate system impact studies to determine if that would create any 
impacts for those interconnection requests, which MISO would not be 
able to complete within 60 days; and (3) correct the data that had been 
sent to an affected system operator, noting it is unclear if the 
affected system operator would be able to inform MISO if the change in 
data created a material modification.\2607\ MISO notes that it uses 
fuel-based dispatch in its interconnection modeling, which exacerbates 
the above problems because it models individual fuel types in different 
ways, and includes electric storage in its definition of a different 
fuel type, so the addition of electric storage would result in a 
different type of modeling.\2608\
---------------------------------------------------------------------------

    \2607\ Id.
    \2608\ Id. at 110.
---------------------------------------------------------------------------

    1371. PJM argues that interconnection customers should only be able 
to modify their interconnection requests in certain circumstances, 
pointing to its proposal to allow interconnection customers to make 
changes that meet pre-defined conditions at three decision points, with 
the changes at each decision point restudied together.\2609\ PJM claims 
that even if the maximum generating facility output or capacity 
interconnection rights do not increase, adding a generating facility to 
an interconnection request can affect other interconnection customers. 
PJM and Avangrid assert that substituting battery storage facilities 
for a portion of a solar generating facility or other generating 
facility without changing the generating facility's maximum output or 
capacity interconnection rights would likely be a material modification 
because it would require a light load test or other testing that was 
not performed for the original solar generating facility 
interconnection request.\2610\ Ameren also states that such 
interconnection request changes can present challenges (e.g., when an 
interconnection customer's chosen technology changes due to the passage 
of time) and can raise reliability issues if not properly addressed, 
and therefore it is necessary to evaluate or conduct a restudy to make 
sure that the studies reflect the technologies actually being 
interconnected.\2611\ PacifiCorp similarly argues that requests to 
incorporate grid-charging battery storage technology should be 
processed separately because grid-charging capabilities can alter the 
electrical characteristics of an interconnection request.\2612\
---------------------------------------------------------------------------

    \2609\ PJM Initial Comments at 51-52 (citing PJM 
Interconnection, L.L.C., Filing, Docket No. ER22-2110-000 (filed 
June 14, 2022)); see also SEIA Reply Comments at 23 (supporting 
PJM's suggestion).
    \2610\ PJM Initial Comments at 51-52; Avangrid Initial Comments 
at 34-35.
    \2611\ Ameren Initial Comments at 27.
    \2612\ PacifiCorp Initial Comments at 39-40.
---------------------------------------------------------------------------

    NV Energy states that in these situations more detailed studies may 
be required in areas of the transmission system where the fault duty is 
already high.\2613\
---------------------------------------------------------------------------

    \2613\ NV Energy Initial Comments at 18.
---------------------------------------------------------------------------

    1372. Southern argues that the proposal should not accept 
modifications to interconnection requests without review because these 
requests could affect other interconnection customers in the same 
cluster as well as lower-queued clusters, adding that it may be a 
material modification that impacts the cost or timing of other 
interconnection requests.\2614\
---------------------------------------------------------------------------

    \2614\ Southern Initial Comments at 37-38.
---------------------------------------------------------------------------

    1373. MISO asserts that it is unclear if the NOPR proposal will 
require the interconnection customer to submit evidence of site control 
before making the modification request or after the request is 
granted.\2615\ Idaho Power notes that site control requirements 
(primarily acreage) are based on the technology type used in the 
interconnection request and would require modification if the 
technology is changed.\2616\ Idaho Power therefore argues that changing 
fuel type enables speculative interconnection requests that can affect 
other interconnection customers both in later clusters and in the same 
cluster.
---------------------------------------------------------------------------

    \2615\ MISO Initial Comments at 108-12.
    \2616\ Idaho Power Initial Comments at 13.
---------------------------------------------------------------------------

    1374. Indicated PJM TOs also contend that not treating fuel type 
changes as material modifications would provide gaming opportunities, 
e.g., an interconnection customer could bypass the site control 
demonstration required at the outset of the study process by entering 
the interconnection queue with a proposed storage project with a small 
site footprint and later, without changing the size of the 
interconnection, adding a solar farm with a much larger site 
footprint.\2617\ MISO also notes that the NOPR proposal is contrary to 
a recent Commission-approved MISO tariff revision regarding changing 
fuel types while it the interconnection queue, that went through a 
lengthy stakeholder process.\2618\ MISO states that it uses fuel-based 
dispatch assumptions for interconnection modeling and argues that there 
is not a simple process to determine if changing fuel during the middle 
of the interconnection process could cause harm to lower- or equally 
queued interconnection requests without running a new study based on 
the updated model. MISO explains that it studies storage generating 
facilities differently than renewable generating

[[Page 61206]]

facilities, and this affects the interconnection modeling.\2619\
---------------------------------------------------------------------------

    \2617\ Indicated PJM TOs Initial Comments at 52-54; Indicated 
PJM TOs Reply Comments at 38.
    \2618\ MISO Initial Comments at 112-13.
    \2619\ Id. at 108-12.
---------------------------------------------------------------------------

    1375. Indicated PJM TOs argue that determining the ``materiality'' 
of a particular type of generating facility modification needs to take 
into account the cumulative impact on the cluster studies of all 
similar requests.\2620\ Indicated PJM TOs explain that, even if a type 
of modification sought by a single interconnection customer may have 
modest system impacts and thus not be ``material'' in a particular 
case, the cumulative impact of multiple similar requests in the same 
area could be much larger.
---------------------------------------------------------------------------

    \2620\ Indicated PJM TOs Reply Comments at 38.
---------------------------------------------------------------------------

    1376. Indicated PJM TOs contend, however, that certain 
modifications made behind the point of interconnection have reliability 
impacts requiring restudy and thus amount to material modifications 
(e.g., changing fuel type by adding storage to a generating 
facility).\2621\ Indicated PJM TOs contend that such changes will 
likely affect short circuit capability limits, steady-state thermal and 
voltage limits, or dynamic system stability and response.\2622\ 
Indicated PJM TOs also ask that the Commission recognize that different 
fuel types among resources have very different seasonal characteristics 
and dynamic response, arguing that the overall reliability of the 
transmission system could suffer if certain types of changes are 
incorrectly identified as non-material.\2623\ However, Shell contends 
that studies of the addition of a generating facility to an 
interconnection request should be limited to determining increased 
costs and/or study or construction delays of equal or lower-queued 
interconnection requests.\2624\
---------------------------------------------------------------------------

    \2621\ Id. at 37-38.
    \2622\ Id. at 38 (citing PJM Interconnection, L.L.C., Answer, 
Docket No. ER19-1958-002, at 5 n.16 (filed Apr. 29, 2020)); 
Indicated PJM TOs Initial Comments at 52-54.
    \2623\ Indicated PJM TOs Initial Comments at 52-54; Indicated 
PJM TOs Reply Comments at 38.
    \2624\ Shell Initial Comments, app. A at ii.
---------------------------------------------------------------------------

    1377. Indicated PJM TOs ask that, at a minimum, the Commission 
allow transmission providers to determine the scope of ``material 
modifications'' based on their practical experience on their own 
systems and apply that knowledge as to the types of changes that 
typically affect other customers and that trigger the need for 
restudies.\2625\ Tri-State asserts that, when the performance of a new 
proposed generating facility differs from the existing/incumbent 
generating facility, transient stability analysis would be required but 
steady state analysis (thermal/voltage) would not be required.\2626\
---------------------------------------------------------------------------

    \2625\ Indicated PJM TOs Reply Comments at 39.
    \2626\ Tri-State Initial Comments at 22.
---------------------------------------------------------------------------

    1378. NERC argues that transmission providers should study the 
potential impacts of any material change to the generating facility, 
such as the addition of storage, even when the interconnection service 
level does not change, because material modifications to the generating 
facility could alter stability and the interaction of a resource with 
the transmission system (e.g., adding inverters, which can increase 
short circuit current, and charging batteries from the transmission 
system, which can impact system power flow).\2627\
---------------------------------------------------------------------------

    \2627\ NERC Initial Comments at 19-20.
---------------------------------------------------------------------------

    1379. Eversource argues that transmission providers cannot be 
expected to meet strict deadlines in an adversarial environment while 
interconnection customers may compound these issues by suggesting 
significant (even if not ``material'' by the definition of the revised 
pro forma LGIP) changes to their generating facilities in the middle of 
the interconnection process.\2628\
---------------------------------------------------------------------------

    \2628\ Eversource Initial Comments at 34.
---------------------------------------------------------------------------

(c) Comments on Specific Matters
(1) Comments Seeking Materiality Guidelines
    1380. Public Interest Organizations assert that the lack of a 
standardized definition in the pro forma LGIP of what constitutes a 
material modification, such as the addition of storage, leads to a lack 
of uniformity among transmission providers and disparate outcomes that 
could result in undue discrimination.\2629\ Similarly, Environmental 
Defense Fund asks the Commission to clarify how much flexibility 
transmission providers will be permitted in determining whether adding 
co-located generating facilities changes the service level and becomes 
a material modification, and it suggests that the Commission adopt firm 
guidelines for transmission providers to determine when the addition of 
a generating facility changes the service level to prevent 
discrimination against generating facilities based on their inclusion 
of hybrid resources.\2630\
---------------------------------------------------------------------------

    \2629\ Public Interest Organizations Initial Comments at 45-47. 
See also Clean Energy Associations Initial Comments at 59; ENGIE 
Initial Comments at 10-11; SEIA Initial Comments at 38-39.
    \2630\ Environmental Defense Fund Reply Comments at 8-9.
---------------------------------------------------------------------------

    1381. Pine Gate asks the Commission to require transmission 
providers to publish additional, consistent criteria regarding what 
changes to an interconnection request will and will not be deemed a 
material modification, and that transmission providers publish their 
determinations about previous modification requests.\2631\ Pine Gate 
contends that this information, which certain RTOs/ISOs already provide 
to interconnection customers, will reduce the number of restudies, 
shorten overall interconnection queue processing timelines, and reduce 
costs. Pine Gate, SEIA, and Shell support establishing thresholds, 
arguing that providing guidance of what constitutes a material 
modification will provide certainty to both interconnection customers 
and transmission owners.\2632\
---------------------------------------------------------------------------

    \2631\ Pine Gate Initial Comments at 47-49.
    \2632\ Id. at 48; SEIA Reply Comments at 23; Shell Initial 
Comments, app. A at ii.
---------------------------------------------------------------------------

    1382. OPSI asks the Commission to require transmission providers to 
publish guidance on technologies and generating facility designs that 
would qualify presumptively as minor system modifications.\2633\ 
Indicated PJM TOs ask for ``bright line'' criteria (based on technical 
standards) for material modification to the extent possible, to narrow 
the scope of changes in a service request that need to be 
evaluated.\2634\ However, Indicated PJM TOs also argue that, in regions 
with large interconnection queues, the Commission should give 
transmission providers the flexibility to define ``material 
modification,'' taking into account the cumulative impact of particular 
categories of requested modifications based on the transmission 
provider's past experience regarding the expected number of such 
requests.\2635\
---------------------------------------------------------------------------

    \2633\ OPSI Initial Comments at 9-10.
    \2634\ Indicated PJM TOs Initial Comments at 52-54; Indicated 
PJM TOs Reply Comments at 37.
    \2635\ Indicated PJM TOs Reply Comments at 39.
---------------------------------------------------------------------------

    1383. APS supports the proposal but requests guidelines regarding 
different technology types (e.g., increasing the size of a battery 
while also decreasing the size of a solar generating facility to keep 
the interconnection amount the same).\2636\ APS recommends that each 
technology type be treated independently in relation to requests to 
increase or decrease the sizes in the original interconnection request 
or otherwise be deemed a material modification (e.g., if the 
characteristics of a storage component change, it should be considered 
a different request that may be a material modification).
---------------------------------------------------------------------------

    \2636\ APS Initial Comments at 20.
---------------------------------------------------------------------------

    1384. R Street similarly asks the Commission to consider 
standardized, non-discriminatory conditions that trigger a material 
change to an interconnection request, even if the service limit does 
not change, arguing

[[Page 61207]]

that hybrid resources should not be penalized for their technology 
profile.\2637\ R Street notes, for example, that adding an inverter-
based generating facility to another such facility may not constitute a 
material change, but adding a natural gas turbine to a solar site, even 
with no increase to net output across the interconnection point, could 
create a material shift in interconnection facilities.
---------------------------------------------------------------------------

    \2637\ R Street Initial Comments at 16.
---------------------------------------------------------------------------

    1385. NARUC asks the Commission to clarify the degree of 
flexibility transmission providers have in determining what constitutes 
a material reliability concern on the transmission system.\2638\ 
Cypress Creek asks the Commission to further modify the current 
material modification definition to state that certain equipment 
changes are not material (e.g., changing solar modules, changing 
inverter models, adding storage capacity, or making minor adjustments 
to inverter performance) if planned export and import capacity remains 
the same and the technology changes comport with interconnection 
agreement requirements.\2639\ ClearPath asks: (1) whether under the 
proposed definition a change in equipment that necessitates submitting 
new models and input data is a material modification; and (2) how 
equipment changes for non-synchronous resources will be treated under 
the proposed definition of material modification and the proposed 
deadlines.\2640\
---------------------------------------------------------------------------

    \2638\ NARUC Initial Comments at 33-35.
    \2639\ Cypress Creek Initial Comments at 18-19.
    \2640\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------

    1386. [Oslash]rsted supports the proposed definition of ``material 
modification'' but disagrees with imposing restrictions on when 
material modifications can be submitted (e.g., after the initial 
application).\2641\ [Oslash]rsted asks the Commission to recognize that 
modifications may occur at various stages of the process to reflect the 
use of evolving technology or to meet Federal or state 
requirements.\2642\ [Oslash]rsted acknowledges transmission providers' 
time and effort to conduct studies associated with proposed 
modifications but states that there is also a need to balance the 
interests of the interconnection customer, as there are a number of 
reasons why changes to an interconnection request may be necessary and 
development time for resources must also be considered. [Oslash]rsted 
asserts that transmission providers' differing processes for assessing 
material modifications create regulatory uncertainty for 
interconnection customers seeking to develop generating facilities in 
different regions, which can have significant economic impacts for the 
generating facility.\2643\ [Oslash]rsted states that, if the Commission 
chooses not to make the proposed change to the modification process, 
then, at a minimum, the Commission should encourage development of best 
practices that can be implemented by all the RTOs/ISOs with the goal of 
increasing efficiency and regulatory certainty.
---------------------------------------------------------------------------

    \2641\ [Oslash]rsted Reply Comments at 5 (citing PJM Initial 
Comments at 17).
    \2642\ Id. at 2.
    \2643\ Id. at 6-7.
---------------------------------------------------------------------------

    1387. Shell asks the Commission to define the differences between 
``co-located additive,'' ``co-located non-additive,'' and ``hybrid'' 
resources, and explains that these categories will allow transmission 
providers to develop proper criteria and business practices governing 
additions and/or changes to pending interconnection requests.\2644\ 
Shell argues that, because transmission providers inconsistently apply 
the methods they use to assess which issues qualify as being adverse 
material impacts, the Commission should more clearly define the scope 
of an ``adverse material impact'' to ensure that transmission providers 
consistently determine whether an interconnection request impacts 
equally or lower-queued interconnection customer(s) to a sufficient 
level of harm.
---------------------------------------------------------------------------

    \2644\ Shell Initial Comments, app. A at ii.
---------------------------------------------------------------------------

(2) Comments on Study Timeline
    1388. With respect to the study timeline, while NARUC supports the 
proposal to require transmission providers to evaluate proposed 
generation additions within 60 calendar days because it is a reasonable 
amount of time, it suggests that the Commission allow some flexibility 
because planning regions and the industry may face challenges aligning 
resources and expertise with increasingly aggressive schedules to 
perform complex interconnection studies.\2645\ Public Interest 
Organizations, on the other hand, argue that the 60-day timeline to 
perform an evaluation is critically important for continuing to reduce 
delays in interconnection queue processing.\2646\ Cypress Creek 
supports the concept of expedited study if the request for a 
modification does not change the level of service, there is no impact 
on cost or timing of a request that is lower- or equally queued, and it 
does not cause reliability concerns.\2647\ Tri-State asks how the 60-
day time frame would work with the cluster study process.\2648\ PJM 
opposes the 60-day timeline.\2649\
---------------------------------------------------------------------------

    \2645\ NARUC Initial Comments at 33-35.
    \2646\ Public Interest Organizations Initial Comments at 45-47.
    \2647\ Cypress Creek Initial Comments at 18-19.
    \2648\ Tri-State Initial Comments at 30.
    \2649\ PJM Initial Comments at 51-53.
---------------------------------------------------------------------------

(3) Comments on Control Technologies
    1389. ENGIE suggests that including control technologies in the 
evaluation of the addition of a generating facility to an existing 
interconnection request should confirm the lack of impact on other 
interconnection customers.\2650\ SEIA argues that transmission 
providers should be transparent about requiring specific types of 
control technologies to add an additional resource.\2651\ Clean Energy 
Associations contend that hardware or software controls can also 
address, reliably and cost-effectively, concerns about the impact of 
the use or addition of energy storage on the reliable operation and 
delivery of energy (such as PJM's concern regarding studies for light 
load conditions).\2652\
---------------------------------------------------------------------------

    \2650\ ENGIE Initial Comments at 11.
    \2651\ SEIA Initial Comments at 38-39.
    \2652\ Clean Energy Associations Reply Comments at 10-11.
---------------------------------------------------------------------------

(4) Comments on Impacts of Storage in Charging Mode
    1390. Pine Gate states that the scope of the required studies for 
the addition of storage will vary depending on the proposed 
configuration of the resource, such as whether it charges from the 
grid.\2653\ NV Energy states that any changes in the electrical 
characteristics of the storage system in charging mode versus 
generating mode are most likely negligible and unlikely to 
significantly impact studies.\2654\
---------------------------------------------------------------------------

    \2653\ Pine Gate Initial Comments at 48.
    \2654\ NV Energy Initial Comments at 18.
---------------------------------------------------------------------------

    1391. APS explains that, based on its experience, the introduction 
of new load (not electrical characteristics), such as storage charging 
from the grid in lieu of self-charging, which could require changes to 
the system overall, could affect the results of the existing study and 
other studies.\2655\
---------------------------------------------------------------------------

    \2655\ APS Initial Comments at 21.
---------------------------------------------------------------------------

    1392. Public Interest Organizations state that the transmission 
provider should study whether a storage generating facility's charging 
and discharging load profiles may impact the grid.\2656\ Public 
Interest Organizations argue that the interconnection customer and 
transmission provider should work together to ``identify the temporal 
and

[[Page 61208]]

physical charging characteristics to be agreed upon,'' but that the 
Commission does not need to further assess the details of the storage 
generating facilities charging because those attributes will be tied to 
the unique properties of the transmission system at that location and 
assessed during the interconnection process to ensure that charging 
load and operational profiles do not adversely impact the system.
---------------------------------------------------------------------------

    \2656\ Public Interest Organizations Initial Comments at 45-47.
---------------------------------------------------------------------------

(5) Miscellaneous Comments
    1393. PJM asks the Commission to restrict the ability to modify 
interconnection requests after the initial application by allowing (1) 
an interconnection customer to move its point of interconnection only 
in certain limited instances and (2) other specified modifications only 
at certain specified times to avoid restudies and study delays.\2657\ 
PJM contends that there is no need to study the materiality of a change 
in an interconnection request's point of interconnection because each 
such change requires analysis and the application of engineering 
judgment, which takes time away from processing interconnection 
requests and performing the cluster study. PJM claims that 
interconnection customers making changes are really seeking to optimize 
their generating facilities mid-process rather than performing due 
diligence before entering the interconnection queue.
---------------------------------------------------------------------------

    \2657\ PJM Initial Comments at 17-18.
---------------------------------------------------------------------------

    1394. With respect to the need for system impact studies, Illinois 
Commission argues that, although in some cases additional studies are 
necessary in response to a request to add a generating facility to an 
existing interconnection request to ensure reliability, transmission 
providers should minimize repeating system impact studies to the extent 
possible to avoid slowing down the interconnection queue.\2658\ In 
response to the concern that evaluating modifications is time-
consuming, [Oslash]rsted asks the Commission to allow third-party 
consultants engaged by the interconnection customers to help inform any 
studies related to modifications to reduce the workload on RTO/ISO 
staff.\2659\
---------------------------------------------------------------------------

    \2658\ Illinois Commission Initial Comments at 13-14.
    \2659\ [Oslash]rsted Reply Comments at 7.
---------------------------------------------------------------------------

    1395. PPL suggests that the transmission provider should assign an 
interconnection queue position to the proposed additional generating 
facility.\2660\ PPL recommends the study of the original and additional 
interconnection request together in the initial phase of the 
interconnection process, and if they do not contribute to any network 
upgrades or require any interconnection facilities, PPL suggests they 
should be able to proceed directly to final agreements.
---------------------------------------------------------------------------

    \2660\ PPL Initial Comments at 22.
---------------------------------------------------------------------------

    1396. Pine Gate states that, if addition of a grid-charging storage 
resource is deemed a material modification, the interconnection 
customer should be permitted to propose the addition of a non-grid-
charging electric storage resource as an alternative.\2661\ In order to 
reduce the burden on transmission providers, Pine Gate asks the 
Commission to permit interconnection customers to provide to 
transmission providers engineering analysis applying what Pine Gate 
suggests would be published engineering criteria to the requested 
modification and analyzing the impacts to other interconnection 
customers or reliability, with the transmission provider then 
validating the results and determining if the proposed modification is 
material.
---------------------------------------------------------------------------

    \2661\ Pine Gate Initial Comments at 47-49.
---------------------------------------------------------------------------

    1397. Clean Energy Associations explain that if transmission 
providers study each component of co-located generating facilities 
separately, a wind or solar generating facility could obtain a faster 
study for ERIS while the co-located storage could get a more detailed 
study for NRIS.\2662\ Clean Energy Associations assert that this 
flexibility would provide transmission providers more visibility during 
interconnection processes, reduce requests to retrofit generating 
facilities with additional co-located resources, and enable faster 
interconnection processes for component resources that will accept 
curtailment.
---------------------------------------------------------------------------

    \2662\ Clean Energy Associations Initial Comments at 59-61.
---------------------------------------------------------------------------

(d) Requests for Clarification and Flexibility
    1398. MISO asserts that, if the Commission adopts the proposal, the 
Commission should modify the proposed requirement to allow the 
``proposed addition of a generating facility to an interconnection 
request as long as the interconnection customer does not request a 
change to the originally requested interconnection service level and 
the proposed addition to the generating facility is modeled the same 
way as the original generating facility.'' \2663\
---------------------------------------------------------------------------

    \2663\ MISO Initial Comments at 108-12.
---------------------------------------------------------------------------

    1399. Clean Energy Associations ask the Commission to clarify 
whether (1) generating facility size reductions, which could result in 
upgrade costs being shifted to others in the same cluster, would be a 
material modification and (2) there is a reduction threshold that would 
trigger a material modification.\2664\
---------------------------------------------------------------------------

    \2664\ Clean Energy Associations Initial Comments at 64.
---------------------------------------------------------------------------

    1400. Invenergy asks the Commission to clarify that its proposed 
requirement to evaluate requests to add a generating facility extends 
to requests for surplus interconnection service and that those requests 
cannot automatically be deemed a material modification.\2665\ Invenergy 
argues that, when the surplus interconnection request is below the 
total original LGIA interconnection rights and determined a material 
modification, the interconnection customer should have the opportunity 
to mitigate the identified issue so that it is no longer a material 
modification.
---------------------------------------------------------------------------

    \2665\ Invenergy Initial Comments at 51-52.
---------------------------------------------------------------------------

    1401. Equinor Wind seeks clarification that the proposed definition 
of material modification excludes changes that (1) occur on the 
interconnection customer's side of the point of interconnection and (2) 
do not alter the electrical output or electrical characteristics of a 
generating facility, adding that such changes should not be subject to 
the transmission provider's discretion or evaluation of whether they 
amount to a material modification.\2666\ Equinor Wind argues that these 
clarifications will reduce uncertainty for interconnection customers 
and allow for some appropriate flexibility during generating facility 
development, particularly for offshore wind. Equinor Wind asserts that 
this clarification will not create reliability concerns because these 
changes do not have transmission system impacts.
---------------------------------------------------------------------------

    \2666\ Equinor Wind Reply Comments at 5-6.
---------------------------------------------------------------------------

    1402. Indicated PJM TOs ask the Commission to clarify the 
relationship between the use of the term ``material modification'' in 
the pro forma LGIP and the term ``materially modify'' in NERC 
Reliability Standards FAC-001-3 (Facility Interconnection Requirements) 
and FAC-002-2 (Facility Interconnection Studies), asserting that the 
lack of clarity and overlap between the two terms could cause confusion 
and may result in additional delays to the interconnection 
process.\2667\ UMPA asks the Commission to clarify that adding a 
generating facility includes technology changes beyond electric storage 
resources, such as changing from wind to solar.\2668\
---------------------------------------------------------------------------

    \2667\ Indicated PJM TOs Initial Comments at 52-54 (noting 
NERC's pending petition to change the term from ``materially 
modify'' to ``qualified change'').
    \2668\ UMPA Initial Comments at 8-9.

---------------------------------------------------------------------------

[[Page 61209]]

    1403. With respect to who performs the study to determine the 
impact of adding a generating facility to an existing interconnection 
request, NARUC argues that, because the reliable operation of the bulk-
power system is at issue, the Commission should clarify that the 
transmission providers determine whether (1) the addition of a 
generating facility requires a full interconnection service study and 
(2) the interconnection customers in the same cluster (or subsequent 
clusters) could be adversely impacted.\2669\ NARUC adds that the 
Commission should ensure that these processes are transparent, clearly 
communicated to interconnection customers, and allow interconnection 
customers to mitigate the impacts and revise their modifications 
requests.
---------------------------------------------------------------------------

    \2669\ NARUC Initial Comments at 33-35.
---------------------------------------------------------------------------

    1404. National Grid urges the Commission to allow ISO-NE and NYISO 
to maintain their processes that allow the transmission owner and RTO/
ISO to evaluate the proposed change and the RTO/ISO to make the final 
determination as to whether the change constitutes a material 
modification.\2670\ Indicated PJM TOs argue that the final rule should 
have sufficient flexibility to allow PJM's proposed definition of 
``material modification'' or permit PJM to obtain an independent entity 
variation for its proposed definition.\2671\
---------------------------------------------------------------------------

    \2670\ National Grid Initial Comments at 40.
    \2671\ Indicated PJM TOs Initial Comments at 52-54.
---------------------------------------------------------------------------

    1405. Omaha Public Power asks the Commission to allow transmission 
providers to continue their existing processes of facilitating the use 
of newer technologies such as storage to promote the stability of these 
processes rather than using the proposed process on the NOPR.\2672\
---------------------------------------------------------------------------

    \2672\ Omaha Public Power Initial Comments at 13.
---------------------------------------------------------------------------

iii. Commission Determination
    1406. We adopt, with modifications, the NOPR proposal to revise 
section 4.4.3 of the pro forma LGIP to require transmission providers 
to evaluate the proposed addition of a generating facility at the same 
point of interconnection prior to deeming such an addition a material 
modification, if the addition does not change the originally requested 
interconnection service level. We modify the NOPR proposal regarding 
section 4.4.3 of the pro forma LGIP, as discussed in greater detail 
below, to: (1) remove the 60-calendar day requirement for assessment of 
material modification; (2) limit the requirement that the transmission 
provider analyze a request to add a generating facility to an existing 
interconnection request solely to requests received prior to the 
interconnection customer's return of the executed facilities study 
agreement to the transmission provider; and (3) create an exception for 
transmission providers that employ fuel-based dispatch assumptions from 
these requirements.
    1407. We find that the record demonstrates that automatically 
deeming a request to add a generating facility to an existing 
interconnection request to be a material modification creates a 
significant barrier to access to the transmission system \2673\ and 
renders existing interconnection processes unjust and unreasonable. 
Such default treatment deters interconnection customers from proceeding 
with changes to a proposed generating facility that, after review, may 
be found not to be material, thereby reducing the number of generating 
facilities that can access the transmission system. This creates a 
barrier to the addition of a generating facility to an existing 
interconnection request that may improve the efficient use of the 
transmission system.
---------------------------------------------------------------------------

    \2673\ See, e.g., AEE Initial Comments at 40-41; Public Interest 
Organizations Initial Comments at 45-47; SEIA Initial Comments at 
38-39.
---------------------------------------------------------------------------

    1408. We make several modifications to the NOPR proposal in 
response to concerns reflected in the record. First, we recognize that 
it may be difficult for some transmission providers to complete their 
material modification evaluations within 60 calendar days, depending on 
the details of their individual interconnection processes; therefore, 
we decline to adopt a 60-calendar day requirement. This preserves 
flexibility for transmission providers to address modification requests 
as is most efficient with their overall interconnection queue 
processing.
    1409. Second, we modify the NOPR proposal to limit when an 
interconnection customer may request to add a generating facility to an 
existing interconnection request without such a request automatically 
being deemed a material modification. We are persuaded by commenters' 
arguments that allowing requests for evaluation to occur at any point 
in the interconnection process could impede the ability of the 
transmission provider to timely process its interconnection 
queue.\2674\ Thus, we modify the NOPR proposal, and transmission 
providers will only be required to evaluate whether a request to add a 
generating facility to an existing interconnection request is material 
if it is submitted before the interconnection customer returns the 
executed facilities study agreement to the transmission provider. Once 
the executed facilities study agreement is returned, the transmission 
provider may decide to automatically treat requests to add a generating 
facility to an existing interconnection request as material 
modifications without review.
---------------------------------------------------------------------------

    \2674\ See, e.g., Indicated PJM TOs Initial Comments at 52-54; 
Indicated PJM TOs Reply Comments at 38; MISO Initial Comments at 
108-112; PJM Initial Comments at 6.
---------------------------------------------------------------------------

    1410. We clarify that interconnection customers may continue to 
request changes to proposed generating facilities at any time in the 
interconnection process. Transmission providers that choose to evaluate 
modification requests later in the interconnection process than 
required by this rule (i.e., after the interconnection customer returns 
the executed facilities study agreement to the transmission provider) 
may continue to do so. This final rule does not address how 
transmission providers evaluate modification requests after the 
facilities study agreement, and thus transmission providers are not 
required to include their modification processes after the facilities 
study agreement in their compliance filing with this final rule.
    1411. We acknowledge that, as stated by commenters, transmission 
providers that employ fuel-based dispatch assumptions, such as MISO, 
may experience challenges with the proposal because the interconnection 
study assumptions in a fuel-based dispatch model vary depending on the 
fuel type; thus a request to add a generating facility of a different 
fuel type to an existing interconnection request would always 
constitute a modification that would require a study, thereby affecting 
the interconnection costs or study timing for lower- or equally-queued 
interconnection customers.\2675\ This type of request would most likely 
represent a material modification and would result in the loss of 
interconnection queue position under the tariff. Therefore, we modify 
the proposal to include an exception for transmission providers that 
use fuel-based dispatch assumptions in their interconnection studies.
---------------------------------------------------------------------------

    \2675\ See, e.g., MISO Initial Comments at 108-12.
---------------------------------------------------------------------------

    1412. In response to EPSA's and Equinor Wind's request to provide a 
clearer standard definition of material modification,\2676\ we note 
that we are not changing the definition of material modification in 
this rule and do not believe a more prescriptive definition of material 
modification is reasonable

[[Page 61210]]

given the nuances in transmission providers' processes for assessing 
material modification, as described in the comments.\2677\ With respect 
to NARUC's request to clarify the flexibility transmission providers 
have in determining what constitutes a material reliability concern on 
the transmission system,\2678\ we clarify that this reform only 
requires transmission providers to evaluate interconnection 
modification requests. As stated above, it does not alter the 
definition of material modification.
---------------------------------------------------------------------------

    \2676\ EPSA Initial Comments at 13; Equinor Wind Reply Comments 
at 5-6.
    \2677\ See, e.g., National Grid Initial Comments at 40.
    \2678\ NARUC Initial Comments at 33-35.
---------------------------------------------------------------------------

    Transmission providers may continue to find requests to be material 
if they impact the cost or timing of an equally or lower-queued 
interconnection customers.
    1413. Commenters request clarification about the requirements for 
demonstrating site control when submitting a modification 
request.\2679\ In response, we clarify that, where a modification 
request to add a generating facility to an existing interconnection 
request requires the interconnection customer to adhere to a larger 
footprint to support a modified facility design, the interconnection 
customer must provide evidence of the required site control when 
submitting the modification request to the transmission provider. The 
requirements for site control that the interconnection customer must 
adhere to may depend on the timing of the request for the modification 
as well as the technology type of the requested additional generating 
facility, as discussed in the site control portion of this rule.\2680\
---------------------------------------------------------------------------

    \2679\ See, e.g., Indicated PJM TOs Initial Comments at 52.
    \2680\ See supra section III.A.6.b of this final rule.
---------------------------------------------------------------------------

    1414. Indicated PJM TOs also request that the Commission clarify 
the relationship between the term ``material modification'' in the pro 
forma LGIP and the term ``materially modify'' in NERC Reliability 
Standard FAC-001-3.\2681\ We find that this request to further define 
the relationship between the terms is outside of the scope of this 
rulemaking. As discussed above, this final rule does not alter the 
preexisting definition of a material modification. Moreover, we note 
that the Commission recently approved a change to the NERC FAC 
Reliability Standards to change ``materially modify'' to ``qualifying 
change.'' \2682\
---------------------------------------------------------------------------

    \2681\ Indicated PJM TOs Initial Comments at 52.
    \2682\ See N. Am. Elec. Reliability Corp., 181 FERC ] 61,126 at 
P 9 (2022) (explaining that replacing materially modify with 
qualified change ``removes the possibility of confusion with the 
Commission's defined term `Material Modification' in its pro forma 
interconnection procedures and agreements'').
---------------------------------------------------------------------------

    1415. ClearPath seeks clarification regarding equipment changes, 
specifically whether under the proposed definition of material 
modification, a change in equipment that necessitates submitting new 
models and input data is a material modification and how equipment 
changes for non-synchronous resources will be treated under the 
proposed definition of material modification and the proposed 
deadlines.\2683\ We clarify that an equipment change, whether for 
synchronous or non-synchronous resources, that does not change the 
originally requested interconnection service level and does not qualify 
for evaluation under the transmission provider's technological change 
procedure must be evaluated by the transmission provider to determine 
if it is a material modification.
---------------------------------------------------------------------------

    \2683\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------

    1416. Similarly, Equinor Wind seeks clarification that the proposed 
definition of material modification excludes changes that do not alter 
the electrical output or electrical characteristics of an 
interconnection request, suggesting that such changes should not be 
subject to the transmission provider's discretion or evaluation of 
whether they amount to a material modification.\2684\ We note that the 
definition of material modification is based on whether changes have a 
material impact on the cost or timing of any interconnection request 
with an equal or lower interconnection queue position, and thus we 
decline to categorically exclude certain types of changes from the 
definition.
---------------------------------------------------------------------------

    \2684\ Equinor Wind Reply Comments at 5-6.
---------------------------------------------------------------------------

    1417. Clean Energy Associations ask the Commission to clarify 
whether: (1) generating facility size reductions, which could result in 
upgrade costs being shifted to others in the same cluster, would be a 
material modification; and (2) there is a reduction threshold that 
would trigger a material modification.\2685\ We clarify that, as per 
pro forma LGIP section 4.4.1, prior to the return of the cluster study 
agreement from the transmission provider to the interconnection 
customer, a decrease of up to 60% of electrical output (MW) must not be 
considered a material modification. In addition, per pro forma LGIP 
section 4.4.2, prior to the return of the executed interconnection 
facilities study, an additional 15% decrease of electrical output of 
the proposed project must not be considered a material modification if 
the change occurred either through a decrease in plant size (MW) or a 
decrease in interconnection service level accomplished by applying 
transmission provider-approved injection-limiting equipment.
---------------------------------------------------------------------------

    \2685\ Clean Energy Associations Initial Comments at 64.
---------------------------------------------------------------------------

    1418. Invenergy, in discussing both surplus interconnection and 
material modification, contends that in circumstances where a surplus 
interconnection request is below the total LGIA interconnection rights 
and determined to be a material modification, the interconnection 
customer should have the opportunity to mitigate identified issues such 
that there is no longer a material modification.\2686\ We find this 
request to be outside the scope of this proceeding because the final 
rule is not proposing a process whereby interconnection customers may 
mitigate identified issues to avoid a material modification 
determination. In response to Invenergy's request to clarify that the 
proposed reforms to require evaluation of requests to add a generating 
facility extend to requests for surplus interconnection service, the 
Commission declines to make such a change. The surplus interconnection 
service process is separate from the material modification process, and 
the two processes should not be conflated.
---------------------------------------------------------------------------

    \2686\ Invenergy Initial Comments at 51.
---------------------------------------------------------------------------

    1419. We decline to adopt firm guidelines that transmission 
providers will follow to determine what constitutes a material 
modification when a request to add a generating facility to an existing 
interconnection request involves adding co-located generating 
facilities.\2687\ The varying configurations and varying electrical 
characteristics that interconnection customers may propose through this 
process may alter how they impact equally or lower-queued 
interconnection customers, and therefore we find that transmission 
providers must retain flexibility to evaluate these requests.
---------------------------------------------------------------------------

    \2687\ We consider Shell's request for the Commission to define 
the differences between ``co-located additive,'' ``co-located non-
additive,'' and ``hybrid'' resources, as well as Shell's request to 
specify the approach to charging energy, to be included among the 
requests for firm guidelines.
---------------------------------------------------------------------------

c. Availability of Surplus Interconnection Service
i. Need for Reform and NOPR Proposal
    1420. In the NOPR, the Commission noted that Order No. 845 
established a surplus interconnection service process to enable a new 
interconnection customer to use the unused portion of an existing 
interconnection customer's

[[Page 61211]]

approved interconnection service through the inclusion of an additional 
generating facility behind a single point of interconnection.\2688\ The 
Commission also noted that Order No. 845 did not specify when a 
generating facility is considered to be ``existing,'' and preliminarily 
found that limiting the use of surplus interconnection service to only 
interconnection customers that have achieved commercial operation may 
be unjust, unreasonable, and unduly discriminatory or 
preferential.\2689\
---------------------------------------------------------------------------

    \2688\ NOPR, 179 FERC ] 61,194 at P 262.
    \2689\ Id. P 263.
---------------------------------------------------------------------------

    1421. The Commission proposed to revise the pro forma LGIP to 
require transmission providers to allow interconnection customers to 
access the surplus interconnection service process once the original 
interconnection customer has an executed LGIA or requests the filing of 
an unexecuted LGIA.\2690\
---------------------------------------------------------------------------

    \2690\ Id. P 264.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1422. The vast majority of commenters on this topic either support 
or do not oppose the proposal regarding surplus interconnection 
service, though some seek various clarifications.\2691\ MISO states 
that surplus interconnection requests are the proper method for 
interconnection customers to add storage or a different generating 
facility fuel source to an interconnection request for an unbuilt 
generating facility \2692\ and suggests that the Commission limit when 
the transmission provider must tender a surplus interconnection 
agreement to the interconnection customer to prevent a surplus 
interconnection agreement from being tendered prior to the original 
interconnection agreement becoming effective. MISO explains that its 
generator interconnection procedures allow for a surplus 
interconnection request to be made during the processing of the 
interconnection queue and adds that MISO is not required to tender a 
surplus interconnection agreement until the original interconnection 
agreement has become effective because a surplus interconnection 
agreement is a derivative of the original interconnection agreement. 
According to MISO, under the proposed reform, the surplus 
interconnection agreement could be tendered prior to the original 
interconnection agreement becoming effective if the original 
interconnection agreement is filed unexecuted and becomes the subject 
of a disputed proceeding.
---------------------------------------------------------------------------

    \2691\ AEE Initial Comments at 41; AEP Initial Comments at 5, 
44-45; APS Initial Comments at 21; Clean Energy Associations Initial 
Comments at 61; CREA and NewSun Initial Comments at 91; Elevate 
Initial Comments at 11-12; Enel Initial Comments at 79; Eversource 
Initial Comments at 34; Iowa Commission Initial Comments at 4; NARUC 
Initial Comments at 36; National Grid Initial Comments at 41; 
NextEra Initial Comments at 37; NRECA Initial Comments at 44; Omaha 
Public Power Initial Comments at 13; PacifiCorp Initial Comments at 
40; SEIA Initial Comments at 39; Shell Initial Comments at 36; SPP 
Initial Comments at 24.
    \2692\ MISO Initial Comments at 113-14.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1423. Some commenters either argue that the NOPR proposal is 
inappropriate for their situation or oppose it outright, in some cases 
arguing against the underlying concept of surplus interconnection 
service. For instance, NYISO asserts that it does not provide for the 
use of ``surplus'' interconnection service and the Commission has 
previously granted NYISO an independent entity variation from the 
surplus interconnection service requirement.\2693\ NYISO asserts that 
this independent entity variation remains just and reasonable and 
accomplishes the purposes of Order No. 845 and the instant NOPR to make 
it easier for proposed generating facilities to interconnect without 
costly upgrades.\2694\
---------------------------------------------------------------------------

    \2693\ NYISO Initial Comments at 49 (citing N.Y. Indep. Sys. 
Operator, Inc., 170 FERC ] 61,117, at P 98 (2020)).
    \2694\ Id. at 50.
---------------------------------------------------------------------------

    1424. ISO-NE states that allowing for co-location of generating 
facilities meets the need of allowing surplus interconnection service 
to be available after executing an LGIA, rendering the proposed reform 
unnecessary.\2695\ ISO-NE explains that, unless the existing generating 
facility is already commercial, there is no unused capability available 
at the point of interconnection. ISO-NE asserts that, to the extent the 
interconnection customer wants to co-locate generating facilities, it 
should be required to propose that as part of the original 
interconnection request.
---------------------------------------------------------------------------

    \2695\ ISO-NE Initial Comments at 40.
---------------------------------------------------------------------------

    1425. CAISO disagrees that allowing an interconnection customer to 
request surplus interconnection service after the original 
interconnection customer executes an LGIA would enable interconnection 
customers with unused interconnection capacity to let other generating 
facilities use that capacity earlier than allowed.\2696\ CAISO contends 
that interconnection customers do not request to use surplus 
interconnection service, and further reform is unlikely to have much 
effect because surplus interconnection service is unavailable 
independent of the Commission's definition. CAISO asserts that 
interconnection customers do not oversize their interconnection 
capacity; therefore, other interconnection customers cannot avail 
themselves of any ``surplus'' because it is already subscribed.
---------------------------------------------------------------------------

    \2696\ CAISO Initial Comments at 32-33.
---------------------------------------------------------------------------

    1426. PJM asserts that the current surplus interconnection service 
construct provides no value due to the challenges inherent in assessing 
the dynamic response associated with adding a surplus generating 
facility to the system while not infringing on the rights of the 
interconnection customers in the interconnection queue or available 
``headroom.'' \2697\ Therefore, PJM contends that it sees no benefit in 
expanding its application and that PJM's current surplus 
interconnection service is rarely used. PJM asserts that surplus 
interconnection service imposes overhead costs without providing value 
to interconnection customers wishing to interconnect.
---------------------------------------------------------------------------

    \2697\ PJM Initial Comments at 65.
---------------------------------------------------------------------------

    1427. In response to PJM and CAISO's comments, SEIA replies that 
both PJM and CAISO take an overly narrow approach to surplus 
interconnection service and that past use of surplus interconnection 
service should not bar making the service available to future requests 
to add storage to a generating facility.\2698\
---------------------------------------------------------------------------

    \2698\ SEIA Reply Comments at 23-25.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
    1428. Other commenters argue that, at least in some situations, 
surplus interconnection service should be available even earlier than 
proposed in the NOPR. For instance, Ameren asserts that there is no 
need to restrict the request to an executed, or requested unexecuted, 
LGIA.\2699\ Ameren contends that, under the Commission's proposal, MISO 
and the interconnection customer would have finalized the network 
upgrades and system impact study only to go back to assess what surplus 
interconnection capacity would have been available. Therefore, Ameren 
asks the Commission to allow for regional flexibility. Omaha Public 
Power likewise recommends that the Commission allow existing 
transmission provider processes that are facilitating new technologies 
to continue.\2700\
---------------------------------------------------------------------------

    \2699\ Ameren Initial Comments at 28.
    \2700\ Omaha Public Power Initial Comments at 13.
---------------------------------------------------------------------------

    1429. Pine Gate favorably cites MISO's process for surplus 
interconnection service and asserts that the Commission should expand 
its

[[Page 61212]]

current proposal to permit interconnection customers to access the 
surplus interconnection service process upon completion of the cluster 
restudy phase.\2701\ Invenergy states that the Commission should permit 
requests for surplus interconnection service after an interconnection 
request has an executed facilities study agreement.\2702\ Invenergy 
contends that the Commission could further clarify that an LGIA must be 
in place for the initial facility before any LGIA for the surplus 
interconnection service can be tendered. Invenergy asserts that, if the 
Commission does not modify the NOPR, it should clarify that 
transmission providers like MISO that have existing practices under 
which surplus interconnection service can be requested earlier in the 
process may continue those existing practices in compliance filings 
after any final rule may become effective. Invenergy also states that 
the Commission should reinforce its commitment in Order No. 845 that 
surplus interconnection service is available up to the maximum level 
allowed under the original interconnection agreement.\2703\ According 
to Invenergy, some transmission providers significantly limit an 
interconnection customer's surplus interconnection rights by deeming an 
otherwise permitted request a material modification except in the 
limited situation of direct current (DC)-coupled behind-the-meter 
storage, which effectively precludes surplus interconnection service in 
all other circumstances under a standard that is not well-defined or 
explained.
---------------------------------------------------------------------------

    \2701\ Pine Gate Initial Comments at 49-50.
    \2702\ Invenergy Initial Comments at 50.
    \2703\ Id. at 50-51 (citing Order No. 845, 163 FERC ] 61,043 at 
P 475).
---------------------------------------------------------------------------

    1430. Elevate encourages the Commission to consider modifying the 
duration of the period in which an interconnection customer taking 
surplus interconnection service can continue to operate following the 
original, host generating facility's retirement.\2704\ Elevate contends 
that, although an interconnection customer taking surplus 
interconnection service may operate for up to a year following the 
original generating facility's retirement, a one-year period is too 
short when it may take four years or more to navigate the 
interconnection process. According to Elevate, a surplus 
interconnection customer should be able to operate sufficiently long 
following the original generating facility's retirement that it has the 
ability to obtain permanent interconnection service through the 
submission of a new interconnection request.\2705\ Elevate contends 
that this will ensure that generation capacity that has been fully 
constructed and is contributing to system reliability is not 
unnecessarily forced offline due to interconnection queue backlogs 
beyond their control.
---------------------------------------------------------------------------

    \2704\ Elevate Initial Comments at 11-12.
    \2705\ Id. at 12 (citing Order No. 845, 163 FERC ] 61,043 at P 
506).
---------------------------------------------------------------------------

(d) Requests for Clarification
    1431. Shell contends that the Commission should clarify that 
transmission providers cannot deny surplus interconnection capacity 
except where (1) the total amount of interconnection service, measured 
in MW, at the point of interconnection has increased, or (2) there will 
be a reliability risk to the relevant transmission system.\2706\
---------------------------------------------------------------------------

    \2706\ Shell Initial Comments at 36.
---------------------------------------------------------------------------

    1432. NARUC asks the Commission to clarify in the pro forma LGIP 
that an interconnection customer that has been fully studied and has an 
executed LGIA, or has filed an unexecuted LGIA, should be considered an 
existing facility for purposes of surplus interconnection 
service.\2707\ NARUC asserts that this clarification will increase 
efficiency in interconnection queues throughout the planning regions 
and ensure that available interconnection capacity can be used 
efficiently.
---------------------------------------------------------------------------

    \2707\ NARUC Initial Comments at 36.
---------------------------------------------------------------------------

    1433. Enel requests that the Commission specify that parallel, 
simultaneous operation and injection of two distinct, alternating 
current (AC)-coupled generating facilities is an acceptable 
configuration for surplus interconnection service so long as the total 
injection of energy at the point of interconnection does not exceed the 
interconnection service level.\2708\
---------------------------------------------------------------------------

    \2708\ Enel Initial Comments at 79.
---------------------------------------------------------------------------

    1434. APS and PacifiCorp ask the Commission to clarify that no 
surplus can be provided if the LGIA of the original interconnection 
request is suspended.\2709\ PacifiCorp explains that, if the underlying 
LGIA is suspended, then there is no guarantee that the facilities 
required for interconnection will be installed.\2710\ APS further 
asserts that, if an interconnection customer requests to go into 
suspension after a surplus request is granted, then that would also 
require the surplus interconnection to be suspended.\2711\ PacifiCorp 
asserts that any work the transmission provider were to undertake 
relating to the surplus interconnection service may be wasted effort if 
the LGIA never comes out of suspension.\2712\ PacifiCorp asks the 
Commission to clarify that, if the original surplus interconnection 
request exceeds its permitted suspension period, both the original LGIA 
and any surplus interconnection service shall be terminated.
---------------------------------------------------------------------------

    \2709\ APS Initial Comments at 21; PacifiCorp Initial Comments 
at 40.
    \2710\ PacifiCorp Initial Comments at 40.
    \2711\ APS Initial Comments at 21.
    \2712\ PacifiCorp Initial Comments at 40-41.
---------------------------------------------------------------------------

    1435. Idaho Power requests clarification as to whether the 
Commission intends for the surplus interconnection service process to 
be used for an interconnection customer that owns a generating 
facility, either in-service or with an executed interconnection 
agreement, to add energy storage after the interconnection agreement is 
executed, or if the Commission intends for these additions to be 
evaluated under pro forma LGIA article 5.19 (Modification).\2713\
---------------------------------------------------------------------------

    \2713\ Idaho Power Initial Comments at 14.
---------------------------------------------------------------------------

iii. Commission Determination
    1436. We adopt the NOPR proposal to revise section 3.3.1 of the pro 
forma LGIP to require transmission providers to allow interconnection 
customers to access the surplus interconnection service process once 
the original interconnection customer has an executed LGIA or requests 
the filing of an unexecuted LGIA.
    1437. We find, based on the record, that this reform will enable 
interconnection customers with unused interconnection service to let 
other generating facilities use that interconnection service earlier 
than is currently allowed and, therefore, increases overall efficiency 
of the interconnection queue.\2714\ Because we find this reform to be 
just and reasonable, to remedy the unjust and unreasonable rates caused 
by the limited ability to use surplus interconnection service today and 
ensure that interconnection customers are able to interconnect in a 
reliable, efficient, transparent, and timely manner, we decline to 
adopt alternative proposals suggested by commenters.
---------------------------------------------------------------------------

    \2714\ See, e.g., AEE Initial Comments at 41.
---------------------------------------------------------------------------

    1438. We find unpersuasive the comments from various RTOs/ISOs 
opposing the NOPR proposal.\2715\ To the extent that they oppose the 
surplus interconnection service process approved by the Commission in 
Order No. 845, we find their arguments to be a collateral attack on the 
Commission's findings in Order No. 845 and irrelevant for purposes of 
determining whether the instant proposal is just and reasonable. 
Further, consistent with the NOPR, we

[[Page 61213]]

continue to find that expanding the availability of surplus 
interconnection service beyond those entities that have achieved 
commercial operation will address the Commission's concerns regarding 
undue restrictions on access to this surplus interconnection 
service,\2716\ thereby making it available to a broader group of 
potential interconnection customers and achieving the efficiencies 
discussed above.
---------------------------------------------------------------------------

    \2715\ CAISO Initial Comments at 32-33; ISO-NE Initial Comments 
at 40; NYISO Initial Comments 49-50; PJM Initial Comments at 65.
    \2716\ NOPR, 179 FERC ] 61,194 at P 263.
---------------------------------------------------------------------------

    1439. We are also not persuaded by either Pine Gate's or Ameren's 
arguments \2717\ to alter the NOPR proposal to require transmission 
providers to allow interconnection customers to access the surplus 
interconnection service process prior to the LGIA phase or Invenergy's 
argument to allow requests for surplus interconnection service once 
there is an executed facilities study agreement.\2718\ We find that 
allowing interconnection customers to access the surplus 
interconnection service process once the original interconnection 
customer obtains an executed LGIA, or requests the filing of an 
unexecuted LGIA, is appropriate because prior to that stage, the 
network upgrades necessary to create the identified amount of surplus 
interconnection service may not have been fully identified, let alone 
begun the process of being placed into service.
---------------------------------------------------------------------------

    \2717\ Ameren Initial Comments at 28; Pine Gate Initial Comments 
at 50.
    \2718\ Invenergy Initial Comments at 49.
---------------------------------------------------------------------------

    1440. In response to APS's and PacifiCorp's requests for 
clarification regarding suspensions,\2719\ we clarify that: (1) if the 
LGIA of the original interconnection request is suspended, then any 
submitted requests for surplus interconnection service are likewise 
suspended, and new requests for surplus interconnection service may not 
be submitted, until after the suspension is lifted; and (2) if the 
original LGIA is terminated, including for exceeding the three-year 
suspension period (pursuant to pro forma LGIA article 5.16), any 
related surplus interconnection service allowed as a result of the 
original LGIA will be terminated because surplus interconnection 
service is dependent upon the underlying interconnection service used 
by existing generating facilities.
---------------------------------------------------------------------------

    \2719\ APS Initial Comments at 21; PacifiCorp Initial Comments 
at 40-41.
---------------------------------------------------------------------------

    1441. In response to NARUC's request to clarify that an 
interconnection customer that has been fully studied and has an 
executed LGIA, or that has requested the filing of an unexecuted LGIA, 
should be considered an existing facility for purposes of surplus 
interconnection service, we decline to make such clarification, but 
reiterate that where an interconnection customer has executed the LGIA, 
or requested that the LGIA be filed unexecuted, interconnection 
customers may submit surplus interconnection service requests to the 
transmission provider.
    1442. We find that Enel's and Shell's respective requests \2720\ 
for clarification regarding establishing parameters on surplus 
interconnection service are outside the scope of this proceeding 
because this final rule is not proposing to modify eligibility for 
surplus interconnection service as established in Order No. 845.
---------------------------------------------------------------------------

    \2720\ Enel Initial Comments at 79; Shell Initial Comments at 
36.
---------------------------------------------------------------------------

    1443. We also find that Elevate's request \2721\ for the Commission 
to modify the duration in which an interconnection customer taking 
surplus interconnection service can continue to operate following the 
original, host generating facility's retirement is outside the scope of 
this proceeding because this final rule is not proposing to modify the 
length of time for which surplus interconnection service may be 
provided after the original generating facility retires.
---------------------------------------------------------------------------

    \2721\ Elevate Initial Comments at 11-12.
---------------------------------------------------------------------------

    1444. In response to Idaho Power's request for clarification 
regarding whether the Commission intends for the surplus 
interconnection service process to be used for an interconnection 
customer that owns a generating facility with an executed or unexecuted 
LGIA to later add energy storage,\2722\ the answer depends upon how the 
energy storage facility will be used. If, for example, it is used only 
to firm up the underlying generating facility (e.g., a wind or solar 
power plant) without ever injecting in excess of the original 
interconnection service level, then surplus interconnection service may 
be used.\2723\ If, on the other hand, the new energy storage facility 
and the existing generating facility will be configured to inject 
together and exceed the original interconnection service limit, then 
surplus interconnection service may not be used.
---------------------------------------------------------------------------

    \2722\ Idaho Power Initial Comments at 14.
    \2723\ See Order No. 845, 163 FERC ] 61,043 at P 472 
(``[S]urplus interconnection service cannot exceed the total 
interconnection service already provided by the original 
interconnection customer's LGIA.'').
---------------------------------------------------------------------------

    1445. In response to Invenergy's requests,\2724\ we clarify that 
the original interconnection customer must have an LGIA in place, 
either executed or requested to be filed unexecuted with the 
Commission, prior to tendering any LGIA for surplus interconnection 
service. With respect to Invenergy's request for flexibility for 
transmission providers that currently allow requests for surplus 
interconnection service before the LGIA phase, we note that 
transmission providers can propose deviations from the requirements 
adopted in this final rule and demonstrate how those deviations satisfy 
the standards discussed in section IV of this final rule, which the 
Commission will consider on a case-by-case basis.
---------------------------------------------------------------------------

    \2724\ Invenergy Initial Comments at 50.
---------------------------------------------------------------------------

    1446. In response to Invenergy's request to clarify that proposed 
reforms to require evaluation of requests to add a generating facility 
to an interconnection request extend to requests for surplus 
interconnection service, we clarify that the revisions to the 
modification process do not extend to the surplus interconnection 
service process. We note that the modification process revisions would 
be used by an interconnection customer while undergoing the 
interconnection study process, whereas the surplus interconnection 
process revisions would be used after the interconnection study process 
is complete and the interconnection customer has an executed LGIA, or 
an unexecuted and filed LGIA.
    1447. Invenergy requests that the Commission reiterate and 
reinforce its commitment in Order No. 845 that surplus interconnection 
service is available up to the maximum level allowed under the original 
interconnection agreement. Invenergy contends that, when the surplus 
interconnection service request is below the total LGIA interconnection 
rights and determined to be a material modification, the 
interconnection customer should have the opportunity to mitigate 
identified issues such that there is no longer a material modification. 
We decline Invenergy's request because the final rule does not address 
revisions to how the surplus interconnection service process is 
conducted; rather, the final rule addresses when a request for surplus 
interconnection service may be submitted.
d. Operating Assumptions for Interconnection Studies
i. Need for Reform and NOPR Proposal
    1448. In the NOPR, the Commission stated that, as newer 
technologies with operating parameters that differ from traditional 
generation seek to interconnect, it is necessary for transmission 
providers to use

[[Page 61214]]

assumptions that accurately reflect ``the operating parameters of 
electric storage resources and co-located resources containing electric 
storage resources (including hybrid resources) so that the unique 
operating characteristics of such resources are taken into account 
during the generator interconnection process.'' \2725\ The Commission 
stated that, because the pro forma LGIP includes only general 
requirements regarding the operating assumptions for generating 
facilities in interconnection studies, it was concerned that ``electric 
storage resources, and co-located resources containing electric storage 
resources, may be studied under inappropriate operating assumptions 
that result in assigning unnecessary network upgrades and increased 
costs to interconnection customers.'' \2726\ The Commission therefore 
preliminarily found that ``the lack of realistic operating assumptions 
used in interconnection studies for electric storage resources and co-
located resources containing electric storage resources (including 
hybrid resources) can result in excessive and unnecessary network 
upgrades and may hinder the timely development of new generation, 
thereby stifling competition in the wholesale markets, and resulting in 
rates, terms, and conditions that are unjust and unreasonable.'' \2727\ 
Further, the Commission preliminarily found that ``the lack of 
appropriate operating assumptions used in interconnection studies may 
present an unduly discriminatory or preferential barrier to the 
interconnection of electric storage resources and co-located resources 
containing electric storage resources (including hybrid resources).'' 
\2728\
---------------------------------------------------------------------------

    \2725\ NOPR, 179 FERC ] 61,194 at P 279.
    \2726\ Id.
    \2727\ Id.
    \2728\ Id.
---------------------------------------------------------------------------

    1449. The Commission proposed to revise the pro forma LGIP to 
require transmission providers, at the request of the interconnection 
customer, to use ``operating assumptions for interconnection studies 
that reflect the proposed operation of an electric storage resource or 
co-located resource containing an electric storage resource (including 
hybrid resources)--i.e., whether the interconnecting resource will or 
will not charge during peak load conditions, unless good utility 
practice, including applicable reliability standards, otherwise require 
the use of different operating assumptions.'' \2729\ The Commission 
noted that, under this proposed reform, such operating assumptions 
shall be proposed by the interconnection customer as part of its 
initial interconnection request.
---------------------------------------------------------------------------

    \2729\ Id. P 280.
---------------------------------------------------------------------------

    1450. The Commission further proposed that such operating 
assumptions must be ``reasonably representative of the likely behavior 
of an electric storage resource or co-located resource containing an 
electric storage resource (including hybrid resources) and, in cases 
where available, consistent with the historical performance of such 
resources in the relevant geographic area.'' \2730\ Further, to help 
facilitate alignment between as-studied and real-world conditions, the 
Commission proposed to allow transmission providers to hold 
interconnection customers to the intended operation of their electric 
storage resource or co-located resource containing an electric storage 
resource (including hybrid resources) by: (1) memorializing these 
operating restrictions in the interconnection customer's LGIA; and (2) 
requiring control technologies (software and/or hardware) in cases 
where appropriate, such as for electric storage that wishes to limit 
its operations, with such protection devices included in Appendix C of 
the LGIA.\2731\ The Commission noted that, ``if the interconnection 
customer fails to operate its electric storage resource or co-located 
resource containing an electric storage resource (including hybrid 
resources) in accordance with these conditions as memorialized in the 
LGIA, the interconnection customer may be considered in breach and the 
transmission provider may pursue termination pursuant to article 17 of 
the LGIA.'' \2732\ Additionally, the Commission proposed to ``require 
that any transmission provider that requires electric storage resources 
or co-located resources containing an electric storage resource 
(including hybrid resources) to install control technologies to 
publicly post a list of acceptable control technologies.'' \2733\ 
Furthermore, the Commission proposed revisions to the description of 
the ERIS and NRIS studies in sections 3.2.1.2. and 3.2.2.2 of the pro 
forma LGIP to accommodate this proposed reform.
---------------------------------------------------------------------------

    \2730\ Id.
    \2731\ Id.
    \2732\ Id.
    \2733\ Id.
---------------------------------------------------------------------------

    1451. The Commission proposed to require that interconnection 
customers clearly communicate to the transmission provider ``the 
expected operating patterns of the electric storage resource, or co-
located resource containing an electric storage resource (including 
hybrid resources).'' \2734\ In addition, for ``the electric storage 
resource or co-located resource containing an electric storage resource 
(including hybrid resources) to be studied, the Commission proposed to 
require the interconnection customer to specify, as part of its initial 
interconnection request, the ancillary services that it would or would 
not provide so that the proper operating assumptions may be made in 
interconnection studies.'' \2735\ Under the Commission's proposal, 
regardless of any changes to operating assumptions, ``all electric 
storage resources, or co-located resources containing an electric 
storage resource (including hybrid resources) would be required to 
continue to meet all requirements in the pro forma LGIP and pro forma 
LGIA, as well as all applicable reliability standards.'' \2736\
---------------------------------------------------------------------------

    \2734\ Id. P 281.
    \2735\ Id.
    \2736\ Id.
---------------------------------------------------------------------------

    1452. The Commission noted that, under this proposed reform, each 
transmission provider's operating assumptions used in their 
interconnection studies must take into consideration the services that 
the generating facility would provide and the timing of such services, 
as applicable.\2737\ The Commission further noted that this could be 
done in a variety of ways, and the transmission provider would have 
flexibility to consider services as best fits its transmission system.
---------------------------------------------------------------------------

    \2737\ Id. P 282.
---------------------------------------------------------------------------

    1453. The Commission proposed to clarify that ``this proposed 
reform to study electric storage resources, or co-located resources 
containing an electric storage resource (including hybrid resources) 
according to their planned operating assumptions at the request of the 
interconnection customer as part of its initial interconnection request 
is intended to mean the operating assumptions for withdrawals of energy 
(e.g., the charging of an energy storage resource) in interconnection 
studies.'' \2738\ The Commission proposed to require that the 
interconnection customer include in its initial interconnection request 
any operating assumptions for withdrawals of energy to be used by the 
transmission provider in interconnection studies.
---------------------------------------------------------------------------

    \2738\ Id. P 285.
---------------------------------------------------------------------------

    1454. The Commission sought comment on whether the Commission 
should expand this reform to address operating assumptions for 
additional generating facility technologies that may currently be 
inaccurately modeled, such as variable energy resources.\2739\ For 
example, the Commission sought

[[Page 61215]]

comment on whether to expand this proposal to specify only that, at the 
interconnection customer's request, a transmission provider must not 
study generating facilities in ways that are not physically possible, 
for example studying a solar resource as producing energy at night, or 
a wind resource as producing maximum energy during low wind seasons, or 
other circumstances wherein any resource is studied in ways that are 
not physically possible, subject to the same proposed requirement that 
the generating facility be equipped with sufficient control technology, 
such as special protection systems, and/or subject to penalties for 
deviating from dispatch. The Commission sought comment on whether other 
operating assumptions, in addition to the assumption that electric 
storage resources withdraw energy during peak load periods, should be 
considered as part of this proposed reform.
---------------------------------------------------------------------------

    \2739\ Id. P 286.
---------------------------------------------------------------------------

    1455. The Commission sought comment on how to define the study 
parameters (e.g., should the Commission define the peak load period 
and/or net peak load during which transmission providers must not study 
a generating facility as withdrawing energy, and if so how).\2740\
---------------------------------------------------------------------------

    \2740\ Id. P 287.
---------------------------------------------------------------------------

    1456. The Commission also sought comment on ``whether, and if so 
how, to define firm and non-firm charging for electric storage 
resources and require transmission providers to define study criteria 
and possible ways to interconnect related to both firm and non-firm 
charging.'' \2741\ The Commission sought comment on whether providing 
such options would improve the effectiveness of this proposed reform 
and whether there would be other consequences of implementing such an 
approach. With respect to the definition of firm and non-firm charging, 
the Commission sought comment on whether to: (1) define firm charging 
service as interconnection service that allows the interconnection 
customer to be eligible to receive electric energy in a manner 
comparable to a transmission provider's load; and (2) define non-firm 
charging service as interconnection service that allows the 
interconnection customer to be eligible to receive electric energy 
using the existing firm or non-firm capacity of the transmission system 
on an ``as available'' basis, noting that in an RTO/ISO with market-
based congestion management, a generating facility with non-firm 
charging service must respond to the RTO's/ISO's dispatch instructions, 
including curtailment to manage congestion.\2742\
---------------------------------------------------------------------------

    \2741\ Id. P 288.
    \2742\ Id.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1457. Many commenters support the Commission's proposal to revise 
the pro forma LGIP to require transmission providers, at the request of 
the interconnection customer, to use operating assumptions for 
interconnection studies that reflect the proposed operation of an 
electric storage resource or co-located resource containing an electric 
storage resource (including hybrid resources)--i.e., whether the 
interconnecting generating facility will or will not charge during peak 
load conditions, unless good utility practice, including applicable 
reliability standards, otherwise require the use of different operating 
assumptions.\2743\
---------------------------------------------------------------------------

    \2743\ ACE-NY Initial Comments at 14-15; AEE Initial Comments at 
41-42; AES Clean Energy Initial Comments at 24; Alliant Energy 
Initial Comments at 8; Bonneville Initial Comments at 22-23; CESA 
Initial Comments at 14-15; Clean Energy Associations Initial 
Comments at 52; Clean Energy Associations Reply Comments at 10; CREA 
and NewSun Initial Comments at 91-92; Cypress Creek Initial Comments 
at 9; Environmental Defense Fund Initial Comments at 6; 
Environmental Defense Fund Reply Comments at 8-9; ELCON Initial 
Comments at 10; Elevate Initial Comments at 13; Interwest Reply 
Comments at 15; Longroad Reply Comments at 10-12; Microgrid 
Resources Initial Comments at 6; NARUC Initial Comments at 37; 
NextEra Initial Comments at 36; NESCOE Reply Comments at 18; NRECA 
Initial Comments at 10, 44; NY Commission and NYSERDA Initial 
Comments at 10; Pine Gate Initial Comments at 51; Public Interest 
Organizations Initial Comments at 47; R Street Initial Comments at 
16; SEIA Initial Comments at 40; Shell Initial Comments, app. A at 
iii; Union of Concerned Scientists Reply Comments at 9-10.
---------------------------------------------------------------------------

    1458. Many commenters agree with the Commission that the lack of 
realistic operating assumptions used in interconnection studies for 
electric storage resources and co-located resources containing electric 
storage resources (including hybrid resources) can result in excessive 
and unnecessary network upgrades and hinder the timely development of 
new generation, thereby stifling competition in the wholesale markets, 
and resulting in rates, terms, and conditions that are unjust and 
unreasonable.\2744\ These commenters also agree that using unrealistic 
operating assumptions in interconnection studies creates an unduly 
discriminatory or preferential barrier to the interconnection of 
electric storage resources and co-located resources containing electric 
storage resources (including hybrid resources).
---------------------------------------------------------------------------

    \2744\ AEE Initial Comments at 42; Alliant Energy Initial 
Comments at 8; Clean Energy Associations Initial Comments at 52-53; 
Hydropower Commenters Initial Comments at 21-22; Longroad Reply 
Comments at 10-12; NARUC Initial Comments at 36-37; NESCOE Reply 
Comments at 18; Pine Gate Initial Comments at 51, 54; Public 
Interest Organizations Initial Comments at 47; rPlus Initial 
Comments at 6; SEIA Initial Comments at 40; SEIA Reply Comments at 
27.
---------------------------------------------------------------------------

    1459. Many commenters agree with the Commission that the 
assumptions used in interconnection studies for the charging of 
electric storage resources should closely resemble the expected ``real-
world'' operation of such resources.\2745\ For example, NextEra asserts 
that operating assumptions should reflect the rational economic 
dispatch of electric storage and co-located resources and that 
interconnection customers with electric storage resources should be 
allowed to request a lower maximum allowed charging rate in place of 
being assigned network upgrade cost allocations.\2746\ Shell asserts 
that parameters used to study storage should consider market 
conditions.\2747\
---------------------------------------------------------------------------

    \2745\ Alliant Energy Initial Comments at 8; APPA-LPPC Initial 
Comments at 29; NextEra Initial Comments at 36-37; NY Commission and 
NYSERDA Initial Comments at 10; Pine Gate Initial Comments at 51; 
Shell Initial Comments, app. A at iii.
    \2746\ NextEra Initial Comments at 37.
    \2747\ Shell Initial Comments, app. A at iii.
---------------------------------------------------------------------------

    1460. Many commenters argue that assuming in an interconnection 
study that an electric storage resource will withdraw energy during 
peak demand similar to firm end-use customer demand fails to recognize 
the real-time attributes of electric storage resources, such as the 
ability to respond within seconds to prices and dispatch signals from 
the transmission provider.\2748\ For example, NARUC and NESCOE argue 
that studying electric storage resources using worst-case operating 
assumptions, such as withdrawing energy during peak demand, ignores the 
real-time attributes and benefits of these technologies, such as their 
ability to respond within seconds to prices and dispatch signals from 
transmission providers and inject electricity during peak demand 
conditions.\2749\ Further, Union of Concerned Scientists asserts that 
modeling storage as charging during times of peak demand penalizes 
interconnection customers for trying to locate electric storage 
resources in places where they are most needed (e.g., load pockets) 
because the study inappropriately models electric storage resources as 
contributing to the problem

[[Page 61216]]

of transmission congestion rather than relieving it.\2750\ AEP argues 
that some electric storage resources do occasionally charge during peak 
demand; however, AEP has no objection to electric storage resources 
being studied under a certain set of operating conditions as long as 
operating restrictions are imposed through interconnection agreements 
and the resource owner/operator recognizes that it must abide by 
dispatch orders and bear the consequences of any limitations on its 
operation that result in penalties.\2751\
---------------------------------------------------------------------------

    \2748\ Clean Energy Alliance Initial Comments at 14-15; NARUC 
Initial Comments at 37; PacifiCorp Initial Comments at 41; Pattern 
Energy Initial Comments at 12; Pine Gate Initial Comments at 51; 
SEIA Initial Comments at 40; Union of Concerned Scientists Reply 
Comments at 10-11.
    \2749\ NESCOE Reply Comments at 18 (citing NARUC Initial 
Comments at 36-37).
    \2750\ Union of Concerned Scientists Reply Comments at 10-11.
    \2751\ AEP Initial Comments at 46-47.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1461. Some commenters argue that the proposed reform is overly 
burdensome on transmission providers and could add time and complexity 
to the interconnection process.\2752\ For example, NYISO opposes the 
proposed reform, arguing that it would not streamline the 
interconnection study process and instead would add significantly more 
complexity to the process and increase the time required to complete 
studies.\2753\
---------------------------------------------------------------------------

    \2752\ Avangrid Initial Comments at 35; Enel Initial Comments at 
74; ISO-NE Initial Comments at 40; NYISO Initial Comments at 51; 
PacifiCorp Initial Comments at 41-42; PJM Initial Comments at 67; 
Southern Initial Comments at 33.
    \2753\ NYISO Initial Comments at 51.
---------------------------------------------------------------------------

    1462. Some commenters oppose the proposed reform due to reliability 
concerns.\2754\ PJM argues that the proposal would be extremely 
difficult to police and enforce and would not guarantee that units will 
operate within their studied parameters, putting PJM at operational 
risk.\2755\ Southern opposes the proposed reform, stating that 
transmission providers are ultimately responsible for planning for the 
safety and reliable operation of their transmission systems, which 
includes standard assumptions for interconnection studies.\2756\ 
Southern contends that it may be viable to provide an information-only 
scenario using the assumptions provided by the interconnection 
customer, but it would not be just and reasonable to allow 
interconnection customers to dictate the study assumptions for their 
electric storage, hybrid, or co-located resources. NYISO asserts that 
its interconnection studies are designed to capture extreme system 
scenarios to best maintain the reliability of the system and to be 
prepared for rare extreme conditions and without such planning, the 
interconnection studies could fail to identify essential non-local 
network upgrades.\2757\ SDG&E argues that the reform may introduce 
undue risk into the interconnection study process and could lead to the 
transmission system being operated in an unstudied/unplanned 
state.\2758\
---------------------------------------------------------------------------

    \2754\ Id. at 67; SDG&E Initial Comments at 8; Southern Initial 
Comments at 33.
    \2755\ PJM Initial Comments at 67.
    \2756\ Southern Initial Comments at 33.
    \2757\ NYISO Initial Comments at 51.
    \2758\ SDG&E Initial Comments at 7.
---------------------------------------------------------------------------

    1463. However, several commenters disagree that the proposed reform 
will introduce undue risk into the interconnection study process and 
real-time operations.\2759\ CESA asserts that many transmission 
providers continue to use historical planning standards that do not 
consider the capability of advanced firmware and software controls to 
dispatch resources in accordance with operating assumptions that can 
provide much needed additional capacity to the transmission system, 
which may result in continued delays and inefficiencies in the 
interconnection process.\2760\
---------------------------------------------------------------------------

    \2759\ AEE Initial Comments at 41-42; CESA Reply Comments at 10 
(citing SDG&E Initial Comments at 7); Clean Energy Associations 
Initial Comments at 58; R Street Initial Comments at 16.
    \2760\ CESA Reply Comments at 10.
---------------------------------------------------------------------------

    1464. NARUC suggests that, in RTO/ISO regions, independent market 
monitors may be well-positioned to track deviations from proposed 
operational limits in real-time operations.\2761\ For non-RTO/ISO 
regions, NARUC contends that it may be appropriate for an independent 
transmission monitor or NERC regional reliability entity to serve in 
such a role.
---------------------------------------------------------------------------

    \2761\ NARUC Initial Comments at 38.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
    1465. Some commenters support the flexibility that the proposed 
reform provides on the basis that it would allow for better use of the 
transmission system or help facilitate the interconnection process 
while still allowing for adequate controls.\2762\ NRECA cautions, 
however, that such flexibility should not come at the expense of the 
NOPR's overall goal of reducing speculative interconnection requests, 
withdrawals, and restudies.\2763\ APS also believes that operating 
assumptions used in interconnection studies should be limited to 
factors that can be automatically controlled by the interconnection 
customer; otherwise, system issues may occur when interconnection 
facilities are operating outside of the assumptions used in the 
studies.\2764\ Although AEP generally supports the proposed reform 
because interconnection studies should be as accurate as possible, AEP 
notes that using operating assumptions provided by the interconnection 
customer may complicate studies and thus realistic study time frames 
must be adopted.\2765\
---------------------------------------------------------------------------

    \2762\ APS Initial Comments at 22; Cypress Creek Initial 
Comments at 9; NRECA Initial Comments at 10, 44; rPlus Initial 
Comments at 6.
    \2763\ NRECA Initial Comments at 44.
    \2764\ APS Initial Comments at 22.
    \2765\ AEP Initial Comments at 45.
---------------------------------------------------------------------------

    1466. Many commenters support the proposal to allow transmission 
providers to require the use of controls to ensure compliance with 
planned operation.\2766\ Clean Energy Associations argue that electric 
storage resources are controllable with a level of precision and speed 
unparalleled by conventional generating facilities, which provides 
transmission owners and providers and interconnection customers with 
new opportunities to accommodate transmission system reliability needs 
and efficiently use scarce transmission interconnection capacity.\2767\ 
Clean Energy Associations assert that the proposed reform would 
acknowledge the fact that electric storage resources are highly 
controllable through hardware and software controls.\2768\ SEIA asserts 
that power control systems, which electronically limit or control 
steady state currents to a programmable limit, can ensure that electric 
storage resources follow operating assumptions, and that their use is 
growing.\2769\
---------------------------------------------------------------------------

    \2766\ AEE Initial Comments at 41-42; APS Initial Comments at 
22; Bonneville Initial Comments at 23; Clean Energy Associations 
Initial Comments at 52-58; ELCON Initial Comments at 10; Eversource 
Initial Comments at 36; NARUC Initial Comments at 38; PPL Initial 
Comments at 23; Public Interest Organizations Initial Comments at 
49-50; SEIA Initial Comments at 40.
    \2767\ Clean Energy Associations Initial Comments at 52.
    \2768\ Clean Energy Associations Reply Comments at 10.
    \2769\ SEIA Reply Comments at 26-27 (citing IREC Initial 
Comments, app. A at 43-48, 56, 159).
---------------------------------------------------------------------------

    1467. Idaho Power states that it currently has a generator control 
and monitoring technology that can be leveraged for monitoring and 
controlling electric storage charging.\2770\ However, Idaho Power 
asserts that it will need to implement a control scheme for operators 
to view and control interconnection facilities in order to 
intermittently interrupt discharge and charging due to system 
conditions and related outages, which would likely require upfront and 
ongoing costs for both Idaho Power and interconnection customers. Idaho 
Power requests that the Commission consider including additional 
language to ensure that the

[[Page 61217]]

transmission provider can disconnect, or take other action, including 
seeking damages, in the event that the charging electric storage 
resource does not follow its schedule.
---------------------------------------------------------------------------

    \2770\ Idaho Power Initial Comments at 15-16.
---------------------------------------------------------------------------

    1468. Eversource states that it is essential for system operators 
and transmission planners to have sufficient visibility and controls in 
place to ensure that the transmission system is not placed in unstudied 
and potentially insecure N-1 contingency states.\2771\ Eversource 
suggests that this issue, as well as other issues of grid dispatch, 
should be the subject of its own proceeding. Alternatively, Eversource 
requests that the Commission require that interconnection customers 
with proposed operational study assumptions have technological controls 
in place that automatically limit the electric storage facility's 
operation to the proposed operational parameters. Eversource further 
requests that the Commission reflect these requirements in the body of 
the pro forma LGIA, and not only the appendices.
---------------------------------------------------------------------------

    \2771\ Eversource Initial Comments at 35-36.
---------------------------------------------------------------------------

    1469. NARUC and Public Interest Organizations support the proposed 
requirement to consider resources to be in breach of their LGIA if they 
fail to operate as intended.\2772\ NARUC asserts that such a 
consequence, in combination with technology and software that can limit 
the operations of an electric storage resource, should sufficiently 
mitigate behavior that deviates from planned.\2773\ Public Interest 
Organizations contend that installing control technologies would allow 
the transmission provider and interconnection customer to engage in an 
interactive dialogue to develop a set of operating assumptions that 
both satisfy the interconnection customer's operational desires and 
align with ``good utility practice.'' \2774\
---------------------------------------------------------------------------

    \2772\ NARUC Initial Comments at 37; Public Interest 
Organizations Initial Comments at 48-50.
    \2773\ NARUC Initial Comments at 37-38.
    \2774\ Public Interest Organizations Initial Comments at 48.
---------------------------------------------------------------------------

    1470. rPlus generally supports the proposal but argues that the 
proposed termination requirements for the interconnection customer 
should the operational characteristics not be met are too stringent and 
restrictive.\2775\ rPlus agrees that it is important to memorialize the 
studied operational assumptions in the interconnection agreement but 
asserts that it would benefit from the inclusion of additional language 
should deviation from the originally defined operational assumptions be 
beneficial.
---------------------------------------------------------------------------

    \2775\ rPlus Initial Comments at 6.
---------------------------------------------------------------------------

    Therefore, rPlus suggests that the Commission remove any explicit 
or implied requirement for electric storage resources not to charge 
during peak load periods and add language to retain the possibility of 
altering the operational characteristics when these changes would 
benefit the reliable and efficient operation of the transmission system 
or benefit ratepayers.
    1471. Invenergy supports the proposed reform to accommodate study 
assumptions that more reasonably approximate anticipated actual 
operations, but opposes requiring the studied operating conditions to 
be memorialized in the interconnection agreement.\2776\ Invenergy 
states that, if there are concerns that an unexpected event may require 
a facility to occasionally operate outside those conditions, those 
concerns should be addressed through the regional transmission planning 
process, rather than forcing interconnection customers to fund upgrades 
that are rarely if ever needed.\2777\
---------------------------------------------------------------------------

    \2776\ Invenergy Initial Comments at 59-61.
    \2777\ Id. at 61-62.
---------------------------------------------------------------------------

    1472. Several commenters suggest modifications to the proposal to 
better achieve the Commission's goal. For example, Pine Gate suggests 
that the Commission require transmission providers to use a uniform set 
of minimum interconnection study requirements (e.g., by eliminating the 
use of extreme contingency scenarios and overly conservative 
operational characteristics and strategies) to facilitate effective, 
efficient interconnection queue processing, which is an essential 
prerequisite of consumer protection.\2778\ With respect to the 
provision of ancillary services, Pine Gate requests that the 
interconnection customer not be required to definitively indicate the 
specific ancillary services that it would or would not provide in the 
initial interconnection request because it is not possible for the 
interconnection customer to know with certainty which ancillary 
services it may be eligible to provide when it is ultimately placed in 
service.\2779\ For this reason, Pine Gate requests that the Commission 
require the interconnection customer to list in the original 
interconnection request only whether it intends to provide ancillary 
services generally.\2780\
---------------------------------------------------------------------------

    \2778\ Pine Gate Initial Comments at 55.
    \2779\ Id. at 52.
    \2780\ Id. at 53.
---------------------------------------------------------------------------

    1473. Union of Concerned Scientists urges the Commission to direct 
in the final rule that technical capabilities offered by an 
interconnection customer be appropriately recognized and used in the 
modeling of transmission impacts and their mitigation, including the 
ability to respond to contingencies and provide dynamic real or 
reactive power, which if omitted could lead to millions of dollars of 
costs to customers to provide such capability by other means.\2781\
---------------------------------------------------------------------------

    \2781\ Union of Concerned Scientists Reply Comments at 13-14.
---------------------------------------------------------------------------

    1474. Interwest supports allowing interconnection customers to 
request that transmission providers apply certain study assumptions to 
better approximate realistic operations and requiring transmission 
providers to apply congestion management practices to unusual events, 
developed through regional transmission planning processes, rather than 
building in assumptions assuming worst-case operations scenarios.\2782\
---------------------------------------------------------------------------

    \2782\ Interwest Reply Comments at 15.
---------------------------------------------------------------------------

    1475. Public Interest Organizations recommend that, if a 
transmission provider finds an interconnection customer's proposed 
operating assumptions to be in conflict with ``good utility practice,'' 
the transmission provider should be required to provide the 
interconnection customer with a clear explanation of why the submitted 
operating assumptions are insufficient or inappropriate, and allow the 
interconnection customer to revise and resubmit the proposed operating 
assumptions as necessary, within a reasonable time period.\2783\
---------------------------------------------------------------------------

    \2783\ Public Interest Organizations Initial Comments at 47-48, 
49.
---------------------------------------------------------------------------

    1476. Clean Energy Associations urge the Commission to define study 
parameters such as ``peak load'' and ``net peak load.'' \2784\ Clean 
Energy Associations request that the Commission define ``net peak 
load'' as the period during which transmission providers must not study 
a facility as withdrawing energy. Clean Energy Associations note that 
in regions with high solar penetration, the net peak load hour diverges 
from the peak load hour and migrates to later in the day and, under 
these conditions, low prices during the peak load hour may create 
incentives for storage to charge, whereas prices would be high during 
the net peak load hour creating incentives to discharge. Therefore, 
Clean Energy Associations contend that using the net peak load as the 
period of study will ensure that studies continue to accurately reflect 
expected economic price response of storage as system conditions 
evolve.
---------------------------------------------------------------------------

    \2784\ Clean Energy Associations Initial Comments at 53-54.

---------------------------------------------------------------------------

[[Page 61218]]

    1477. NextEra and Clean Energy Associations urge the Commission to 
require transmission providers to use additional study assumptions 
beyond just whether electric storage and co-located resources 
(including hybrid resources) should charge during peak load periods. 
Both NextEra and Clean Energy Associations argue that transmission 
providers should not study electric storage resources as injecting 
energy during low load and shoulder periods because that does not 
reasonably reflect the rational economic behavior and typical 
operations of such resources.\2785\
---------------------------------------------------------------------------

    \2785\ NextEra Initial Comments at 37; Clean Energy Associations 
Initial Comments at 53.
---------------------------------------------------------------------------

    1478. In contrast, MISO argues against requiring additional study 
assumptions for electric storage resources.\2786\ MISO notes that there 
may be times in the future when renewable resources are constrained or 
unavailable due to the lack of fuel (e.g., no wind or sun) such that 
the MISO transmission system will need to call upon electric storage 
resources for injection: but, if these resources are not permitted to 
discharge due to their operational assumptions, then the transmission 
system's reliance on those resources could lead to reliability risks.
---------------------------------------------------------------------------

    \2786\ MISO Initial Comments at 116.
---------------------------------------------------------------------------

    1479. Several other commenters urge the Commission not to define 
study parameters, such as ``peak load'' or ``net peak load,'' and 
instead allow for regional flexibility.\2787\ For example, rather than 
define peak load, Microgrid Resources states that the Commission should 
require individual evaluation of the expected operating assumptions for 
the resource(s) being studied.\2788\ Enel asserts that it does not 
believe clear and transparent criteria regarding the peak load period 
could be developed such that the limitations on a generating facility 
could appropriately be modeled with only a few power flow model 
``snapshots in time'' serving as the basis for the restriction.\2789\
---------------------------------------------------------------------------

    \2787\ Ameren Initial Comments at 29; Enel Initial Comments at 
74; Idaho Power Initial Comments at 16; Microgrid Resources Initial 
Comments at 8; Shell Initial Comments, app. A at iii.
    \2788\ Microgrid Resources Initial Comments at 8.
    \2789\ Enel Initial Comments at 74.
---------------------------------------------------------------------------

    1480. Several commenters support eliminating unrealistic 
interconnection study assumptions for resource types other than 
electric storage resources, such as assuming that a solar facility will 
operate a night, or that a wind resource will produce maximum output 
during low-wind seasons.\2790\ Ameren, Cypress Creek, Microgrid 
Resources, NARUC, Pine Gate, and rPlus all request that the Commission 
extend this reform to allow any resource type, not just electric 
storage or co-located resources, to request that interconnection 
studies be based on their particular operating assumptions and 
characteristics.\2791\ NARUC further asserts that it is reasonable to 
allow interconnection customers to request that transmission providers 
not study interconnecting generating facilities in ways that are not 
physically possible, subject to the same proposed requirement that the 
generating facility be equipped with sufficient control technologies 
and penalties for deviations.\2792\ Microgrid Resources urges the 
Commission to define microgrid in the tariff, noting particularly the 
inclusion of load, and to make clear that interconnection studies must 
be based on operating assumptions for the microgrid as a whole.\2793\
---------------------------------------------------------------------------

    \2790\ Id.; AES Clean Energy Initial Comments at 24-25; Ameren 
Initial Comments at 29; CREA and NewSun Initial Comments at 92; 
Cypress Creek Initial Comments at 9-10; Invenergy Initial Comments 
at 59-61; Microgrid Resources Initial Comments at 7-8; Pine Gate 
Initial Comments at 54; Public Interest Organizations Initial 
Comments at 48-49; R Street Initial Comments at 16; rPlus Initial 
Comments at 6.
    \2791\ Ameren Initial Comments at 29; Cypress Creek Initial 
Comments at 9-10; Microgrid Resources Initial Comments at 7; NARUC 
Initial Comments at 38; Pine Gate Initial Comments at 54; rPlus 
Initial Comments at 6.
    \2792\ NARUC Initial Comments at 38.
    \2793\ Microgrid Resources Initial Comments at 7.
---------------------------------------------------------------------------

    1481. Pattern Energy asserts that transmission providers should be 
required to update their operating assumptions annually, after 
stakeholder input.\2794\ Pattern Energy asserts that some transmission 
providers require light-load reliability analysis for wind resources 
but not for natural gas plants, which is unduly discriminatory.\2795\
---------------------------------------------------------------------------

    \2794\ Pattern Energy Initial Comments at 13.
    \2795\ Id. (referencing PJM Manual 14B at 47, section 2.3.1.1).
---------------------------------------------------------------------------

    1482. Some commenters support expanding the proposed reforms to the 
entire facility of hybrid or co-located resources. For instance, ENGIE 
recommends that interconnection customers submitting hybrid or co-
located resources should be able to specify operating parameters across 
the entire generating facility, including variable energy resources, 
within their interconnection request to allow interconnection customers 
to reflect parameters such as solar-based charging of the electric 
storage resource more accurately.\2796\ Pine Gate states that co-
located resources are typically studied independently, which requires 
studying the combined maximum injection of the two generating 
facilities that are co-located, despite the fact that studying in this 
manner overestimates the impact on the transmission system and could 
trigger unnecessary network upgrades.\2797\ Pine Gate asserts that, 
consistent with the NOPR's proposals regarding operating assumptions 
for electric storage resources and co-located resources, the Commission 
should permit an interconnection customer to specify the proposed 
operation of all components of a co-located resource in its 
interconnection request.
---------------------------------------------------------------------------

    \2796\ ENGIE Initial Comments at 11.
    \2797\ Pine Gate Initial Comments at 45.
---------------------------------------------------------------------------

    SEIA contends that studying two, co-located resources as a single 
resource would be more accurate, as this would reflect the actual 
electrical impact to the transmission system.\2798\
---------------------------------------------------------------------------

    \2798\ SEIA Initial Comments at 38.
---------------------------------------------------------------------------

    1483. Although not entirely opposed to the proposed reform, 
PacifiCorp asserts that this proposed reform should not be extended to 
co-located and hybrid resources because monitoring and enforcing 
operational limitations could be complex, and incorporating operational 
limitations could complicate the cluster study process.\2799\ 
Nevertheless, PacifiCorp encourages the Commission to permit 
transmission providers to opt-in to extending this type of reform to 
hybrid resources if appropriate for their systems.
---------------------------------------------------------------------------

    \2799\ PacifiCorp Initial Comments at 41-42.
---------------------------------------------------------------------------

    1484. Several other commenters urge the Commission to go further 
and require transmission providers to use more realistic operating 
assumptions without requiring the interconnection customer to request 
that transmission provider do so.\2800\ Public Interest Organizations 
argue that extending the reforms to all generation technologies would 
help prevent unduly discriminatory treatment.\2801\ Therefore, Public 
Interest Organizations recommend that the Commission require 
transmission providers to work with interconnection customers to ensure 
operating assumptions reflect physical, operational, and market 
realities, ``good utility practice,'' and applicable reliability 
standards. AES Clean Energy argues that the Commission should require 
transmission providers to establish a process to revisit and update 
operating assumptions of different resource types in consultation with 
stakeholders to ensure that these operating assumptions are realistic 
and approximately reflect

[[Page 61219]]

the expected actual operation of these resources.\2802\
---------------------------------------------------------------------------

    \2800\ AES Clean Energy Initial Comments at 24-25; CREA and 
NewSun Initial Comments at 92; R Street Initial Comments at 16.
    \2801\ Public Interest Organizations Initial Comments at 49.
    \2802\ AES Clean Energy Initial Comments at 24-25.
---------------------------------------------------------------------------

    1485. Shell supports the use of accurate modeling assumptions, 
including for variable energy resources, but argues that electric 
storage and renewable resources should not be treated in the same way 
because electric storage is dispatchable and renewable resources 
generally are not dispatchable.\2803\ Further, Shell asserts that the 
Commission should not assume all wind and solar resources are the same 
(and not dispatchable).
---------------------------------------------------------------------------

    \2803\ Shell Initial Comments, app. A at iii.
---------------------------------------------------------------------------

    1486. AECI and NextEra oppose extending the proposed reform to 
other resources types.\2804\ NextEra opposes extending customized 
operating assumptions to wind and solar energy resources because doing 
so could unduly complicate subsequent operational decisions for the 
system operator and possibly restrict the system operator's ability to 
call on resources when needed.\2805\ AECI proposes to continue studying 
wind and solar resources as NRIS facilities that are dispatched at 100% 
to avoid potential reliability issues at the worst times.\2806\ MISO 
explains that it currently requires interconnection customers to be 
responsible for limiting and controlling their own dispatch in some 
conditions, but that it has no ability to monitor in real time if an 
interconnection customer violates its operating limits.\2807\ MISO 
states that it is unaware of any plant side control device or 
operational tool that MISO could use to prevent a generating facility's 
injection to enforce an electric storage resource's operating 
assumptions regarding discharging. Idaho Power states that it is 
unclear how a cluster study with multiple interconnection requests 
could be performed when accounting for numerous and potentially 
conflicting study parameters, such as ``low wind season'' for one 
interconnection customer but not for another.\2808\ Idaho Power seeks 
clarification of the definition of study parameters such as ``low wind 
season.''
---------------------------------------------------------------------------

    \2804\ AECI Initial Comments at 8; NextEra Initial Comments at 
37.
    \2805\ NextEra Initial Comments at 37.
    \2806\ AECI Initial Comments at 8.
    \2807\ MISO Initial Comments at 116.
    \2808\ Idaho Power Initial Comments at 16.
---------------------------------------------------------------------------

    1487. Some commenters support the Commission defining the terms 
firm and non-firm charging service for electric storage resources and 
requiring transmission providers to define study criteria to 
interconnect related to both firm and non-firm charging.\2809\ For 
example, Clean Energy Associations support enabling interconnection 
customers with electric storage resources and hybrid resources to 
request non-firm transmission service for their charging energy, 
provided that transmission providers update study criteria and 
interconnection processes for such service accordingly and provide 
definitions of firm and non-firm charging service for electric storage 
resources.\2810\ CESA argues that electric storage resources should not 
be forced to use one type of charging service over another since some 
resources may find it sufficient to take advantage of charging capacity 
as it is available whereas others may want or need greater assurances 
of charging capacity and are willing to pay for the requisite network 
upgrades.\2811\ CESA urges the Commission to set requirements as to how 
partial or full firm charging services should be offered on a flexible, 
as-requested basis, such that an interconnection customer can seek firm 
charging service for specific time windows or for a portion of the 
electric storage resource's nameplate or interconnection capacity. CESA 
asserts that, as discussed in the NOPR, accommodating firm and as-
available charging service options should reflect the operating 
capabilities of the storage resource (i.e., price responsive, 
dispatchable), achieve efficient market outcomes, and avoid expensive 
and unnecessary upgrades.\2812\
---------------------------------------------------------------------------

    \2809\ CESA Initial Comments at 12-13; Clean Energy Associations 
Initial Comments at 54-56; ENGIE Initial Comments at 12.
    \2810\ Clean Energy Associations Initial Comments at 54.
    \2811\ CESA Initial Comments at 12-13.
    \2812\ Id. at 12.
---------------------------------------------------------------------------

    1488. Clean Energy Associations assert that the Commission should 
direct transmission providers to use the following criteria for 
studying interconnection requests that opt for non-firm charging 
service: (1) the electric storage resource should have the option to 
receive electric energy using the existing firm or non-firm capacity of 
the transmission system on an ``as available'' basis; (2) any study of 
an electric storage resource charging should allow the interconnection 
customer to elect to use a lower charging level or a control technology 
to mitigate any identified constraints in lieu of being assigned 
network upgrades to address such constraints; and (3) the electric 
storage resource should receive information relative to any network 
upgrades, charging restrictions, or control requirements in advance of 
signing an interconnection agreement.\2813\ Clean Energy Associations 
urge the Commission to direct transmission owners to indicate 
conditions under which charging energy could be curtailed in 
interconnection agreements that include non-firm service for charging 
energy. Clean Energy Associations also caution that the Commission 
should avoid recategorizing charging energy of electric storage 
resources as a wholesale load, which would be contrary to the 
Commission's findings in Order No. 841.
---------------------------------------------------------------------------

    \2813\ Clean Energy Associations Initial Comments at 55-56.
---------------------------------------------------------------------------

    1489. AEP suggests that clarifications would be needed for the 
proposed definitions of firm and non-firm charging to be effective. For 
example, AEP asserts that the proposed definitions for firm and non-
firm charging service conflate different products and services required 
to charge an electric storage resource.\2814\ AEP argues that charging 
service is not a form of interconnection service, nor is 
interconnection service referred to in the industry as firm or non-
firm. According to AEP, it is the delivery service (i.e., transmission 
and wholesale distribution service) that can be firm or non-firm and 
therefore the relevant question is whether, in the interconnection 
process, an electric storage resource can or needs to request to be 
studied as a ``firm'' or ``non-firm'' load for delivery purposes. AEP 
asserts that the Commission should recognize that, for electric storage 
resources, the interconnection cluster study process should include an 
analysis of transmission service. AEP notes that the Commission has 
permitted the California utilities to study the need for wholesale 
distribution upgrades required for charging on a firm basis as part of 
the interconnection study process. AEP argues that, if it is 
technically possible to distinguish loads, a load that affects human 
safety, health, and welfare directly should have priority over the 
charging of an electric storage resource, unless for example, if the 
electric storage resource will be used for blackstart after an outage, 
adding that the final rule does not need to interfere with emergency 
load shedding protocols.
---------------------------------------------------------------------------

    \2814\ AEP Initial Comments at 48-50.
---------------------------------------------------------------------------

    1490. Shell asserts that the need for firm or non-firm transmission 
service will vary by generating facility, as well as by the usage 
pattern of the electric storage resource (e.g., whether the electric 
storage resource is standalone or part of a hybrid resource that is AC-
coupled, DC-coupled, or DC-tight-

[[Page 61220]]

coupled).\2815\ Shell states that, if an electric storage resource is 
charging from the transmission system as non-firm load, and the 
resource owner is required to comply with the transmission provider's 
real-time dispatch orders to cease charging from the transmission 
system due to reliability concerns, then there is no need for long-term 
firm transmission service reservations to serve the electric storage 
resource. Shell contends that non-firm electric storage load should not 
be required to acquire transmission service prior to charging from the 
transmission system, as such charging will be captured by the revenue 
meter and can be billed at the transmission provider's non-firm point-
to-point transmission rate at the end of the billing period.
---------------------------------------------------------------------------

    \2815\ Shell Initial Comments, app. A at iii.
---------------------------------------------------------------------------

    1491. Xcel suggests that the evaluation of non-firm charging must 
assume a price and then the electric storage resource should be bound 
to that price.\2816\ Xcel contends that, if an electric storage 
resource is studied as non-firm load but ends up offering to buy energy 
in the market above average market prices, the study will not represent 
the resulting dispatch. Therefore, Xcel recommends that electric 
storage resources and other non-firm load should be required to have a 
maximum bid price that is included in Attachment C of the pro forma 
LGIA.
---------------------------------------------------------------------------

    \2816\ Xcel Initial Comments at 46.
---------------------------------------------------------------------------

    1492. Some commenters oppose the Commission defining firm and non-
firm charging or requiring transmission providers to define study 
criteria as part of this rulemaking.\2817\ For example, PPL asserts 
that the Commission should leave defining such study parameters to the 
transmission providers.\2818\
---------------------------------------------------------------------------

    \2817\ Ameren Initial Comments at 29; Idaho Power Initial 
Comments at 16; PPL Initial Comments at 23.
    \2818\ PPL Initial Comments at 23.
---------------------------------------------------------------------------

    1493. Several commenters suggest clarifications to the proposed 
reform regarding the timing of submitting operating assumptions.\2819\ 
Clean Energy Associations and ENGIE recommend that the Commission 
define a clear decision point in the interconnection study process 
before which interconnection customers may adjust operating assumptions 
and after which inputs remain constant.\2820\ APS suggests that the 
Commission modify the proposal to specify that any changes to the 
operating assumptions initially provided by the interconnection 
customer would be considered a material modification.\2821\
---------------------------------------------------------------------------

    \2819\ AES Clean Energy Initial Comments at 24; APS Initial 
Comments at 22; Clean Energy Associations Initial Comments at 56-57; 
ENGIE Initial Comments at 11.
    \2820\ Clean Energy Associations Initial Comments at 56-57; 
ENGIE Initial Comments at 11.
    \2821\ APS Initial Comments at 22.
---------------------------------------------------------------------------

(d) Alternative Proposals and Requests for Further Process
    1494. Enel argues that using power flow studies and assuming 
extreme transmission system conditions matches the concept of a firmer 
product well (e.g., for NRIS or transmission service studies), but 
applied to ERIS studies it implies that an ERIS resource cannot or will 
not curtail, absorb congestion costs, or be redispatched to mitigate 
transmission system disturbances, which goes beyond ``as available'' 
service and does not allow for lower-cost mitigation options.\2822\ For 
these reasons, Enel recommends that the Commission direct transmission 
providers to replace power flow studies with Security Constrained 
Economic Dispatch analysis for ERIS service studies instead of the 
Commission's proposed reform,\2823\ or in the alternative, require 
appropriately supported fuel-based dispatch assumptions in ERIS and, 
where appropriate, NRIS study models.\2824\
---------------------------------------------------------------------------

    \2822\ Enel Initial Comments at 75.
    \2823\ Id. at 73, 75.
    \2824\ Id. at 77-78.
---------------------------------------------------------------------------

    1495. Several other commenters support requiring transmission 
providers to apply realistic fuel-based dispatch assumptions to all 
resource types.\2825\ Additionally, Invenergy notes that both MISO and 
SPP already use realistic fuel-based dispatch assumptions in their 
interconnection study processes.\2826\ Although MISO believes that a 
fuel-based dispatch methodology would address the concerns stated in 
the NOPR about unrealistic operating assumptions, MISO also believes 
that study methods should be flexible to the unique needs of a region's 
stakeholders and that the Commission should allow flexibility regarding 
how a transmission provider conducts its studies.\2827\ MISO asserts 
that fuel-based dispatch enables more efficient generator 
interconnection because it recognizes that not all generating 
facilities will be dispatched up to their requested interconnection 
service at all times of the year and that some fuels will not be 
dispatched when other fuels are being dispatched.\2828\ MISO explains 
that its current fuel dispatch method also addresses withdrawal for 
electric storage resources and was informed by operational data.\2829\
---------------------------------------------------------------------------

    \2825\ Enel Initial Comments at 77-78; Interwest Reply Comment 
at 15; Invenergy Initial Comments at 60-61.
    \2826\ Invenergy Initial Comments at 60-61.
    \2827\ MISO Initial Comments at 119.
    \2828\ Id. at 117, 119.
    \2829\ Id. at 117-118 (citing MISO, Business Practice Manual-15, 
tbl. 6-1).
---------------------------------------------------------------------------

    1496. Public Interest Organizations encourage the Commission to 
consider a requirement that would ensure operational and market 
realities are appropriately reflected in operating assumptions for the 
purposes of interconnection studies.\2830\ Public Interest 
Organizations state that this could include both operational practices 
and procedures as well as market-based price signals for curtailment 
and congestion management. Furthermore, Public Interest Organizations 
contend that fossil generating facilities should not be expected to 
generate at or near peak output during times when market prices are 
depressed, such as during periods of high renewable generation.\2831\
---------------------------------------------------------------------------

    \2830\ Public Interest Organizations Initial Comments at 48.
    \2831\ Id. at 48-49 (citing Joe Daniel & Sam Gomberg, Union of 
Concerned Scientists, Why Does Wind Energy Get Wasted? (Nov. 16, 
2021), https://www.ucsusa.org/resources/wind-oversupply-myths).
---------------------------------------------------------------------------

    1497. IREC asserts that interconnection application forms for small 
generating facilities should be updated to include information about 
electric storage resources and, where export controls are used, the 
type of export control and the equipment type and settings that will be 
used.\2832\ IREC asserts that, in order for the interconnection process 
to fully recognize the ways electric storage resources can be designed 
and controlled to avoid transmission system constraints, utilities 
should consider operating profiles (which can include operating 
schedules) in their feasibility studies and system impact 
studies.\2833\
---------------------------------------------------------------------------

    \2832\ IREC Initial Comments at 15, attach. A.
    \2833\ Id. at 16, attach. A.
---------------------------------------------------------------------------

    1498. Several commenters urge the Commission to hold a technical 
conference and/or open a new proceeding to sort out the complex details 
of this proposed reform.\2834\ For example, Clean Energy Associations 
note that the Commission could build a further evidentiary record 
regarding parameters for evaluating electric storage and other 
resources via a technical conference, with the aim of developing 
reasonable and consistent assumptions across regions.\2835\ SEIA urges 
the Commission to convene a technical conference in this proceeding

[[Page 61221]]

to increase transmission provider certainty and confidence in the 
capabilities and testing of power control systems.\2836\ ISO-NE 
suggests that its concerns with the proposed reform may be better 
addressed through the establishment of a new category of 
interconnection service for the charging mode of electric storage 
devices as part of a separate proceeding.\2837\
---------------------------------------------------------------------------

    \2834\ Clean Energy Associations Initial Comments at 53; 
Eversource Initial Comments at 35; ISO-NE Initial Comments at 40; 
Puget Sound Initial Comments at 13.
    \2835\ Clean Energy Associations Initial Comments at 53.
    \2836\ SEIA Initial Comments at 27.
    \2837\ ISO-NE Initial Comments at 40.
---------------------------------------------------------------------------

(e) Comments Regarding Transmission Service Request Studies
    1499. Clean Energy Associations note that some RTOs/ISOs determine 
the network upgrades needed to accommodate the charging of electric 
storage resources as part of the interconnection process, whereas other 
transmission providers do so in the transmission service request 
process.\2838\ Similarly, Xcel states that charging from the 
transmission system can be evaluated and approved through the 
designation of a new delivery point as part of a transmission service 
request.\2839\ Xcel further notes that it is unaware of a transmission 
service study process defined in the pro forma tariff that specifically 
evaluates non-firm load. Puget Sound states that it currently studies 
charging outside of the interconnection process and recognizes that 
charging could be considered a retail or a transmission product once 
the load piece is interconnected.\2840\ However, Puget Sound asserts 
that charging should be studied in the interconnection process, and the 
transmission provider should be granted more time to study this 
additional element. Puget Sound seeks clarity as to whether the 
proposed reform means that charging should now be considered part of 
the interconnection process, or if it can be part of the process should 
the transmission provider wish to include it. Further, Puget Sound 
argues that the Commission should standardize the pro forma LGIA to 
include specific operating assumptions to avoid interconnection request 
delays due to needing to file a non-conforming LGIA with the Commission 
and/or interconnection customer hesitancy.
---------------------------------------------------------------------------

    \2838\ Clean Energy Associations Initial Comments at 54-55 
(referencing, e.g., ISO-NE Planning Procedure No. 5-6, at 18 (2022); 
MISO, Business Practice Manual 15-r24, at 53.
    \2839\ Xcel Initial Comments at 46-47.
    \2840\ Puget Sound Initial Comments at 11-12.
---------------------------------------------------------------------------

    1500. In contrast, Tri-State argues that it is inappropriate to 
study charging of electric storage resources within a generator 
interconnection study, and instead asserts that this type of analysis 
is best performed as a part of a transmission service study, which 
covers delivery of energy to load or charging of an electric storage 
resource.\2841\ Similarly, SPP argues that evaluating the impact of an 
electric storage resource's charging on the transmission system is 
better suited to other existing processes designed to assess load 
impact, such as the long-term transmission service study process, the 
short-term transmission service evaluation process, or market 
processes.\2842\
---------------------------------------------------------------------------

    \2841\ Tri-State Initial Comments at 22.
    \2842\ SPP Initial Comments at 25.
---------------------------------------------------------------------------

(f) Requests for Clarification and Flexibility
    1501. Pine Gate requests that the Commission provide additional 
guidance regarding how transmission owners should perform studies and 
what network upgrade costs will be allocated to interconnection 
customers as a result.\2843\ Pine Gate states that transmission 
providers may need to study electric storage or co-located resources 
based on worst-case operating assumptions to understand the potential 
impact these resources would have on the transmission system absent 
operating restrictions being implemented. However, Pine Gate requests 
that the Commission clarify that network upgrade costs will not be 
assigned to the interconnection customer based on the unrealistic 
worst-case scenarios where there is agreement to implement operating 
restrictions.
---------------------------------------------------------------------------

    \2843\ Pine Gate Initial Comments at 52.
---------------------------------------------------------------------------

    1502. Elevate requests that the Commission clarify that the 
proposed reform applies to all study processes related to the 
interconnection of electric storage resources, including generator 
replacement, surplus interconnection, and requests to modify an 
existing generation resource, arguing that there is no reason for the 
Commission to require that transmission providers use realistic study 
parameters only in the context of requests for new interconnection 
service while allowing unrealistic study assumptions in other study 
processes.\2844\
---------------------------------------------------------------------------

    \2844\ Elevate Initial Comments at 13-14.
---------------------------------------------------------------------------

    1503. CAISO is concerned that, if not modified, the proposed reform 
would require transmission providers to provide firm charging options, 
whereas CAISO asserts that it does not currently provide firm charging 
service and stakeholders have never requested such service.\2845\ CAISO 
argues that requiring firm charging service would have a profound 
impact on organized electricity markets and asserts that if the 
Commission proposes to allow electric storage resources to bypass 
economic dispatch and charge whenever they desire--even during stressed 
peak conditions--it should do so expressly and not in the context of a 
rulemaking addressing interconnection. CAISO asserts that the 
Commission should consider a simple clarification and avoid requiring 
transmission providers to offer firm charging, but instead require 
transmission providers that offer firm charging to allow 
interconnection customers to request it at the outset of their 
interconnection request.
---------------------------------------------------------------------------

    \2845\ CAISO Initial Comments at 34-35.
---------------------------------------------------------------------------

    1504. Environmental Defense Fund urges the Commission to clarify 
that an apparent failure to operate in accordance with agreed-upon 
conditions should be treated as a normal alleged default or breach as 
governed by article 17 of the pro forma LGIA, which would not result in 
immediate termination.\2846\ Environmental Defense Fund asserts that 
the requirements of article 17.1 of the pro forma LGIA state that a 
breaching party be given an opportunity to cure the breach and that 
termination is only available if the breaching party fails to cure or 
the breach is not capable of being cured. Similarly, Hydropower 
Commenters generally support the proposal, but believe that the 
proposed requirement that if an interconnection customer fails to 
operate its electric storage resource in accordance with the operating 
assumptions memorialized in the interconnection agreement, the 
interconnection customer may be considered in breach and the 
transmission provider may pursue termination of the interconnection 
agreement, is overly restrictive, will discourage the development of 
pumped storage projects, and should be modified.\2847\ Instead, 
Hydropower Commenters urge the Commission to provide for a standard 
cure period to address deviations, and penalties in the event of 
failure to cure.
---------------------------------------------------------------------------

    \2846\ Environmental Defense Fund Initial Comments at 6-7.
    \2847\ Hydropower Commenters Initial Comments at 23-24.
---------------------------------------------------------------------------

    1505. MISO states that the proposed reform is unclear because the 
text of the NOPR states that the Commission intends operating 
instructions to only apply to an electric storage resource's ability to 
describe how it will withdraw energy from the transmission system 
(i.e., charge a battery), whereas the proposed pro forma LGIP revisions 
state that the operating assumptions can also apply to the manner the 
interconnection request states that the electric storage

[[Page 61222]]

resource will discharge.\2848\ MISO asks that the Commission clarify 
that the text of the NOPR is correct, and that the Commission did not 
intend to propose to allow electric storage resources to define the 
operating assumptions for how they will inject into the transmission 
system because, according to MISO, allowing interconnection requests to 
define operating assumptions regarding discharge would result in 
operational problems and would be discriminatory to other generating 
facilities.
---------------------------------------------------------------------------

    \2848\ MISO Initial Comments at 115.
---------------------------------------------------------------------------

    1506. Hydropower Commenters suggest that the proposed reform be 
modified to include a simplified procedure for amending an 
interconnection customer's interconnection agreement to optimize the 
operating parameters of a pumped storage plant to the extent the 
transmission system is available.\2849\
---------------------------------------------------------------------------

    \2849\ Hydropower Commenters Initial Comments at 24.
---------------------------------------------------------------------------

    1507. Some commenters note that several transmission providers 
already study electric storage resources using more realistic operating 
assumptions and assert that transmission providers should have the 
flexibility to determine the assumptions used when studying generating 
facilities interconnecting to the transmission system, including 
operating assumptions for electric storage resources, while also 
factoring in input from the interconnection customer.\2850\ NESCOE 
argues that the final rule should require transmission providers to 
work with the relevant states, transmission owners, electric storage 
resource interconnection customers, and stakeholders in their region to 
develop modeling assumptions for electric storage resources that are 
reasonable, realistic, and ensure the ability to interconnect is 
offered on a non-discriminatory basis.\2851\
---------------------------------------------------------------------------

    \2850\ APPA-LPPC Initial Comments at 29-30; Bonneville Initial 
Comments at 23; MISO Initial Comments at 117; National Grid Initial 
Comments at 41; NESCOE Reply Comments at 19.
    \2851\ NESCOE Reply Comments at 18.
---------------------------------------------------------------------------

    1508. National Grid recommends that the Commission provide regional 
flexibility to adopt or decline this proposed reform after transmission 
providers receive input from their stakeholders to determine if ad hoc 
proposed operating assumptions for interconnection requests are 
reasonable and appropriate or if certain pre-determined acceptable 
ranges of assumptions are consistent with reliability.\2852\ APPA-LPPC 
argues that the proposal could entail creating entirely new models for 
off-peak scenarios, not just running sensitivity analyses from an 
existing model, and therefore urges the Commission to give transmission 
providers the autonomy to determine whether additional transmission 
studies are needed.\2853\
---------------------------------------------------------------------------

    \2852\ National Grid Initial Comments at 41.
    \2853\ APPA-LPPC Initial Comments at 29-30.
---------------------------------------------------------------------------

iii. Commission Determination
    1509. We adopt the NOPR proposal, subject to modification, to 
revise sections 3.1.2, 3.2.1.2, 3.2.2.2, 3.3.1, 3.4.2, 4.4.3, 7.3, 8.2, 
and Appendix 1 of the pro forma LGIP and article 17.2 and Appendix H of 
the pro forma LGIA to require transmission providers, at the request of 
the interconnection customer, to use operating assumptions in 
interconnection studies that reflect the proposed charging behavior of 
electric storage resources \2854\ (whether standalone, co-located 
generating facilities,\2855\ or part of a hybrid generating facility 
\2856\)--i.e., whether the interconnecting generating facility will or 
will not charge during peak load conditions--unless good utility 
practice, including applicable reliability standards,\2857\ otherwise 
requires the use of different operating assumptions.\2858\ We clarify 
that studying electric storage resources, at the request of the 
interconnection customer, according to their planned operating 
assumptions means only the operating assumptions for withdrawals of 
energy (e.g., the charging of an electric storage resource) in 
interconnection studies.
---------------------------------------------------------------------------

    \2854\ An electric storage resource is a generating facility 
capable of receiving electric energy from the grid and storing it 
for later injection of electricity.
    \2855\ As noted above, co-located generating facilities are more 
than one generating facility that are located on the same site and 
that are connected at the same point of interconnection that are 
operated and dispatched as separate generating facilities. See supra 
section III.C.1.a.iii.
    \2856\ As noted above, a hybrid generating facility is a 
generating facility composed of more than one device of different 
technology types for the production and/or storage for later 
injection of electricity that are located on the same site and are 
operated and dispatched as a single integrated generating facility. 
See supra section III.A.6.b.iii.
    \2857\ Applicable reliability standards means ``the requirements 
and guidelines of the Electric Reliability Organization and the 
Balancing Authority Area of the Transmission System to which the 
Generating Facility is directly interconnected.'' See pro forma LGIP 
section 1 (Definitions).
    \2858\ For clarity, we note that the reforms described in this 
determination section and the related sections of the pro forma LGIP 
apply to all interconnecting electric storage resources, whether 
they are standalone, co-located generating facilities, or part of a 
hybrid generating facility.
---------------------------------------------------------------------------

    1510. We find that by more accurately reflecting the technical 
capabilities of electric storage resources in interconnection studies 
through the use of appropriate operating assumptions, this reform 
ensures the reliable interconnection of new electric storage resources 
without overestimating their impact on the transmission system, thereby 
ensuring just and reasonable rates by avoiding excessive and 
unnecessary network upgrades that may hinder the timely development of 
new generating facilities that stifles competition in the wholesale 
market. We also find that reflecting the technical capabilities of 
electric storage resources through the use of appropriate operating 
assumptions in interconnection studies reduces unduly discriminatory or 
preferential barriers to the interconnection of electric storage 
resources.
    1511. We adopt the proposed revisions, subject to modification, to 
section 3.1.2 of the pro forma LGIP to require transmission providers, 
at the request of the interconnection customer, to use operating 
assumptions that reflect the proposed charging behavior of an electric 
storage resource, allow interconnection customers to resubmit their 
operating assumptions if the transmission provider finds the originally 
proposed operating assumptions are in conflict with good utility 
practice, and allow the transmission provider to require the 
interconnection customer to install additional control technologies. We 
agree with Public Interest Organizations that transparency is necessary 
when a transmission provider finds that an interconnection customer's 
operating assumptions conflict with good utility practice.\2859\ 
Therefore, we modify the proposed revisions to section 3.1.2 of the pro 
forma LGIP to require that, if a transmission provider finds an 
interconnection customer's proposed operating assumptions to be in 
conflict with good utility practice, the transmission provider must 
provide the interconnection customer with a clear explanation in 
writing of why the submitted operating assumptions are insufficient or 
inappropriate by no later than 30 calendar days before the end of the 
customer engagement window and allow the interconnection customer to 
revise and resubmit the proposed operating assumptions one time at 
least 10 calendar days before the end of the customer engagement 
window.
---------------------------------------------------------------------------

    \2859\ Public Interest Organizations Initial Comments at 47-49.
---------------------------------------------------------------------------

    1512. We adopt the proposed revisions to section 3.2.1.2 of the pro 
forma LGIP to require transmission providers to study electric storage 
resources that request ERIS service according to the interconnection 
customer's proposed operating

[[Page 61223]]

assumptions. We adopt the proposed revisions to section 3.2.2.2 of the 
pro forma LGIP to require transmission providers to study electric 
storage resources that request NRIS service according to the 
interconnection customer's proposed operating assumptions.
    1513. We agree with Elevate and clarify that the reform to use 
operating assumptions in interconnection studies, at the request of the 
interconnection customer, that reflect the proposed charging behavior 
of an electric storage resource applies to the operating assumptions 
used in all study processes related to the interconnection of electric 
storage resources. Accordingly, we modify the NOPR proposal to require 
transmission providers, at the request of the interconnection customer, 
to use operating assumptions that reflect the proposed charging 
behavior of an electric storage resource in additional study processes, 
as described below.
    1514. With respect to surplus interconnection service, we modify 
the NOPR proposal to revise section 3.3.1 of the pro forma LGIP to 
require transmission providers, at the request of the interconnection 
customer, to use operating assumptions that reflect the proposed 
charging behavior of an electric storage resource in the surplus 
interconnection service process.
    1515. We adopt the proposed revisions to section 3.4.2 of the pro 
forma LGIP to require interconnection customers to include in their 
interconnection request the proposed operating assumptions that reflect 
the proposed charging behavior of the electric storage resource and a 
description of any control technologies that will limit the operation 
of the electric storage resource to its intended operation.
    1516. To the extent an interconnection customer requests to modify 
a generating facility already in the interconnection queue by adding an 
electric storage resource to the interconnection request, the 
transmission provider shall study such a modification in accordance 
with section 4.4.3 of the pro forma LGIP using operating assumptions 
that reflect the proposed charging behavior of an electric storage 
resource, at the request of the interconnection customer. Accordingly, 
we modify the NOPR proposal to revise section 4.4.3 of the pro forma 
LGIP to require transmission providers, at the request of the 
interconnection customer, to use operating assumptions that reflect the 
proposed charging behavior of an electric storage resource in the 
material modification process.
    1517. We adopt the proposed revisions to section 7.3 of the pro 
forma LGIP to require transmission providers, at the request of the 
interconnection customer, to use operating assumptions that reflect the 
proposed charging behavior of an electric storage resource in the 
cluster study process and to allow, but not require, transmission 
providers to: (1) memorialize the generating facility's operating 
assumptions in Appendix H of the interconnection customer's LGIA; and/
or (2) require control technologies (software and/or hardware) for an 
electric storage resource that wishes to limit its operations during 
peak load conditions, with such protection devices included in Appendix 
C of the interconnection customer's LGIA.
    1518. We adopt the proposed revisions to section 8.2 of the pro 
forma LGIP to require transmission providers, at the request of the 
interconnection customer, to use operating assumptions that reflect the 
proposed charging behavior of an electric storage resource in the 
interconnection facilities study process.
    1519. We adopt the NOPR proposal to revise Appendix 1 of the pro 
forma LGIP to require interconnection customers to provide to the 
transmission provider as part of the initial interconnection request: 
(1) the requested operating assumptions for the interconnecting 
electric storage resource; and (2) a description of any applicable 
control technologies. However, we agree with MISO and Pine Gate that it 
is not necessary, and may not be possible, to specify the specific 
ancillary services that an electric storage resource will provide 
before entering the interconnection queue, particularly because the 
market rules addressing the provision of ancillary services from 
electric storage resources, whether they are standalone, part of co-
located generating facilities, or part of a hybrid generating facility, 
are still being developed in multiple markets and such rules will 
likely change over the coming years.\2860\ Therefore, we decline to 
adopt the proposed revision to require interconnection customers to 
list the specific ancillary services they intend to provide as part of 
the initial interconnection request.\2861\ In addition, we agree with 
MISO and CAISO that control technologies frequently evolve, and 
interconnection customers that choose to specify operating assumptions 
should be responsible for including appropriate control technologies 
with their requests to use such operating assumptions. Therefore, we 
also decline to adopt the proposed revision to require transmission 
providers to publicly post a list of acceptable control technologies.
---------------------------------------------------------------------------

    \2860\ MISO Initial Comments at 118; Pine Gate Initial Comments 
at 52.
    \2861\ NOPR, 179 FERC ] 61,194 at P 281.
---------------------------------------------------------------------------

    1520. We adopt the NOPR proposal to revise Appendix 1 of the pro 
forma LGIP to require interconnection customers to provide to the 
transmission provider any proposed operating assumptions for the 
interconnecting electric storage resource as part of the initial 
interconnection request. This timing ensures that the flexibility 
provided by this reform does not delay the cluster study process by 
ensuring the transmission provider has all necessary information at the 
time interconnection studies commence. In response to commenters that 
request that the Commission define a clear decision point after which 
changes to operating assumptions may be considered a material 
modification,\2862\ we reiterate that the operating assumptions must be 
submitted as part of the initial interconnection request. Further, we 
clarify that such operating assumptions only pertain to the proposed 
charging behavior of an electric storage resource, i.e., whether the 
interconnecting resource will or will not charge during peak load 
conditions.
---------------------------------------------------------------------------

    \2862\ AES Clean Energy Initial Comments at 24; APS Initial 
Comments at 22; Clean Energy Associations Initial Comments at 56-57; 
ENGIE Initial Comments at 11.
---------------------------------------------------------------------------

    1521. We modify the NOPR proposal to add article 17.2 to the pro 
forma LGIA to describe a violation of operating assumptions for 
generating facilities, including for an electric storage resource. We 
also add Appendix H to the pro forma LGIA as the location for the 
interconnection customer to memorialize its operating assumptions. If 
the owner of the generating facility fails to operate the generating 
facility in accordance with its operating assumptions, as memorialized 
in Appendix H of the pro forma LGIA, the transmission provider may 
pursue termination of the LGIA through the breach and cure provisions 
found in article 17 of the pro forma LGIA. As already provided for in 
article 17 of the pro forma LGIA, we agree with Environmental Defense 
Fund that interconnection customers should be given the opportunity to 
cure a breach of the LGIA if possible.\2863\ We clarify that, if an 
interconnection customer fails to operate its electric storage resource 
in accordance with the operating assumptions memorialized in the 
interconnection customer's LGIA, the

[[Page 61224]]

procedure for termination pursuant to articles 17.1.1 and 17.1.2 of the 
pro forma LGIA is appropriate. We believe that repeat violations of the 
operating assumptions memorialized in the LGIA are likely not 
consistent with good utility practice.\2864\ Additionally, we agree 
with rPlus and Idaho Power that there may be unique instances in real-
time operations during which a transmission provider would want an 
electric storage resource to charge during peak load conditions (e.g., 
because the electric storage resource is located in a generation 
pocket). Therefore, we clarify that, if done so at the direction of the 
transmission provider to maintain the reliable and efficient operation 
of the transmission system, an electric storage resource that operates 
contrary to the operating assumptions specified in its LGIA in this 
instance must not be considered in breach of its LGIA by the 
transmission provider.
---------------------------------------------------------------------------

    \2863\ Environmental Defense Fund Initial Comments at 6-7.
    \2864\ The pro forma LGIA states that ``Each Party shall perform 
all of its obligations under this LGIA in accordance with Applicable 
Laws and Regulations, Applicable Reliability Standards, and Good 
Utility Practice, and to the extent a Party is required or prevented 
or limited in taking any action by such regulations and standards, 
such Party shall not be deemed to be in Breach of this LGIA for its 
compliance therewith.'' Pro forma LGIA art. 4.3 (Performance 
Standards).
---------------------------------------------------------------------------

    1522. We believe that, taken together, the revisions to the pro 
forma LGIP and pro forma LGIA will ensure that interconnection 
customers adhere to the operating assumptions used to study their 
electric storage resource and ameliorate concerns about possible 
reliability problems expressed by commenters. We agree with commenters 
that: (1) control devices can prevent electric storage resources from 
charging during peak load conditions; (2) modern electric storage 
resources can respond to signals from the transmission provider within 
seconds; (3) electric storage resources generally do not have an 
economic incentive to charge during peak load conditions; and (4) the 
consequence of being considered in breach of the LGIA provides an 
additional incentive for electric storage resources to follow the 
agreed-upon operating assumptions memorialized in their LGIA. Further, 
we note that some transmission providers already assume in their 
interconnection studies that electric storage resources will not charge 
during peak load conditions.\2865\ We emphasize that, irrespective of 
these changes to operating assumptions, all electric storage resources 
must continue to meet all requirements in the pro forma LGIP and pro 
forma LGIA, as well as all applicable reliability standards.
---------------------------------------------------------------------------

    \2865\ Bonneville Initial Comments at 23; MISO Comments at 117; 
see also PacifiCorp, 182 FERC ] 61,131 (2023) (accepting, subject to 
condition, revisions to PacifiCorp's LGIP and LGIA to allow 
PacifiCorp to study electric storage resources in its 
interconnection study process using operating assumptions that more 
accurately reflect their expected operation).
---------------------------------------------------------------------------

    1523. We agree with commenters that the speed and control with 
which electric storage resources can respond to signals from 
transmission providers sufficiently distinguishes the charging behavior 
of electric storage resources from that of firm customer end-use load. 
Therefore, for purposes of determining any network upgrades necessary 
to accommodate the reliable interconnection of electric storage 
resources, we find that the charging of electric storage resources 
should not be modeled equivalently to firm customer end-use load in 
interconnection studies if the interconnection customer memorializes 
its operating assumptions in the LGIA and installs control 
technologies, if required, to limit its operations as specified.
    1524. For clarity and in response to MISO's concern about 
conflicting descriptions of the reform in the NOPR preamble and the 
proposed revisions to the pro forma LGIP, we modify the proposed 
revisions to the pro forma LGIP to clarify that these requirements 
apply only to the operating assumptions for withdrawals of energy 
(e.g., proposed charging behavior of electric storage resources, 
whether standalone, co-located generating facilities, or part of a 
hybrid generating facility), not to discharging.
    1525. In response to Pine Gate's request for clarification about 
what network upgrade costs will be allocated to interconnection 
customers as a result of the adoption of the revisions related to 
operating assumptions, we clarify that the transmission provider must 
not assign network upgrade costs to the interconnection customer based 
on those worst-case operating assumptions (e.g., charging at maximum 
capacity during peak load conditions) where there is agreement from the 
interconnection customer to, if required, implement operating 
restrictions including installing or demonstrating that the generating 
facility already has control technologies (software and/or hardware) to 
limit its operations during peak load conditions. As addressed above, 
we believe that these conditions sufficiently address any reliability 
concerns associated with the unexpected operation of an electric 
storage resource and thus believe it is appropriate for the 
transmission provider to only assign costs for network upgrades based 
on the proposed charging behavior of the electric storage 
resource.\2866\
---------------------------------------------------------------------------

    \2866\ See, e.g., AEE Initial Comments at 41-42; AEP Initial 
Comments at 46-47; CESA Reply Comments at 10; Clean Energy 
Associations Initial Comments at 52, 56-58; NARUC Initial Comments 
at 37; NESCOE Reply Comments at 18; Public Interest Organizations 
Initial Comments at 48-50; R Street Initial Comments at 16; SEIA 
Reply Comments at 26-27.
---------------------------------------------------------------------------

    1526. Several commenters point out that not all transmission 
providers use the same process to study the charging of electric 
storage resources. Some transmission providers determine the network 
upgrades needed to accommodate the charging of an electric storage 
resource in the interconnection process, whereas other transmission 
providers do so exclusively as part of a transmission service 
request.\2867\ In response to these commenters, we clarify that the 
requirement for transmission providers to use operating assumptions, at 
the request of the interconnection customer, in interconnection studies 
that reflect the proposed charging behavior of an electric storage 
resource applies only to the operating assumptions that transmission 
providers use in the interconnection process. This requirement does not 
apply to transmission service requests and this final rule does not 
propose to modify the process for requesting transmission service. In 
response to Puget Sound,\2868\ we further clarify that this reform does 
not require transmission providers to study charging as part of the 
interconnection process if they do not already do so. If a transmission 
provider does not determine the network upgrades needed to accommodate 
the charging of an electric storage resource through the 
interconnection process, then on compliance the transmission provider 
must demonstrate why this reform does not apply to that particular 
transmission provider.
---------------------------------------------------------------------------

    \2867\ See, e.g., Clean Energy Associations Initial Comments at 
55; Puget Sound Initial Comments at 11-12; SPP Initial Comments at 
25; Tri-State Initial Comments at 22; Xcel Initial Comments at 46-
47.
    \2868\ Puget Sound Initial Comments at 11-12.
---------------------------------------------------------------------------

    1527. In the NOPR, the Commission sought comment on whether to 
define ``peak load period'' and/or ``net peak load'' period.\2869\ 
Given the variation in the scenarios that transmission providers study 
in the interconnection process (e.g., summer peak load, winter peak 
load, shoulder peak load, light load conditions, etc.), we agree with 
commenters that regional flexibility is warranted.\2870\ Therefore, we 
decline to adopt standardized definitions of ``peak

[[Page 61225]]

load period'' and/or ``net peak load'' period.
---------------------------------------------------------------------------

    \2869\ NOPR, 179 FERC ] 61,194 at P 287.
    \2870\ See, e.g., Ameren Initial Comments at 29; Microgrid 
Resources Initial Comments at 8.
---------------------------------------------------------------------------

    1528. In the NOPR, the Commission also sought comment on whether to 
define firm and non-firm charging for electric storage resources and 
require transmission providers to define study criteria and possible 
ways to interconnect related to both firm and non-firm charging.\2871\ 
Further, the Commission sought comment on proposed definitions of firm 
and non-firm charging service. Several commenters express concerns 
about defining firm and non-firm charging service, including whether 
the proposed definitions conflate interconnection and transmission 
service. We believe that, given the other reforms adopted herein 
regarding operating assumptions, the proposed definitions of firm and 
non-firm charging service are not necessary to ensure that transmission 
providers, at the request of the interconnection customer, use more 
realistic operating assumptions to study electric storage resources in 
the interconnection process and to avoid excessive and unnecessary 
network upgrades that may otherwise hinder the timely development of 
new electric storage resources. Therefore, we decline to adopt any 
definitions of firm and non-firm charging service. As a result, we also 
clarify that this final rule does not require transmission providers to 
define conditions under which electric storage resources will be 
curtailed. In response to CAISO's concern that a proposed definition of 
firm charging service would require transmission providers that do not 
currently provide firm charging service to do so, we clarify that this 
final rule does not require transmission providers to provide firm 
charging service.
---------------------------------------------------------------------------

    \2871\ NOPR, 179 FERC ] 61,194 at P 288.
---------------------------------------------------------------------------

    1529. In the NOPR, the Commission sought comment on whether to 
expand this reform to address operating assumptions for additional 
generating facility technologies that may currently be inaccurately 
modeled, such as variable energy resources.\2872\ The Commission also 
sought comment on whether other operating assumptions, in addition to 
the assumption that electric storage resources withdraw energy during 
peak load periods, should be addressed as part of this proposed reform. 
In response to several commenters' concerns about potential reliability 
impacts and the administrative burden of extending the NOPR proposal to 
also address injections of power from electric storage resources or 
other resource types, we decline in this final rule to extend the 
reform to apply to additional generating facility technologies or to 
other operating assumptions. We clarify that this reform does not apply 
to the operating assumptions used to study the injection of power from 
electric storage resources or the injection of power from other 
resource types (e.g., natural gas, solar, wind, etc.). We encourage 
transmission providers to examine on an individual basis what operating 
assumptions used to study the injection of power may be appropriate to 
render the study process more accurate. Similarly, we decline to 
require transmission providers to use fuel-based dispatch assumptions 
to study the injection of power from all resource types in 
interconnection studies at this time, as suggested by some commenters. 
We acknowledge that fuel-based dispatch assumptions may be able to 
address some of the identified challenges associated with inaccurate 
modeling assumptions for all resource types and encourage transmission 
providers to evaluate the merits of adopting it, but we do not believe 
that adopting such a requirement on a generic basis is supported by the 
record.
---------------------------------------------------------------------------

    \2872\ Id. P 286.
---------------------------------------------------------------------------

    1530. We decline to address the potential implications of this 
reform for transmission providers with Commission-approved 
interconnection processes that vary from the pro forma requirements 
adopted in Order Nos. 2003 and 845. As explained in the section IV of 
this final rule, transmission providers with such variations from the 
pro forma LGIP and pro forma LGIA may seek approval as part of the 
compliance process to maintain those variations, which the Commission 
will consider on a case-by-case basis. What we adopt in this final rule 
are requirements that are part of the pro forma LGIP and pro forma 
LGIA, and we therefore only address the interaction of the requirements 
adopted herein with existing requirements that are part of the pro 
forma process and not variations thereto.
    1531. We also decline to require transmission providers to use 
standardized operating assumptions, as some commenters suggest.\2873\ 
In the NOPR, the Commission did not propose to require transmission 
providers to use standardized operating assumptions, and we decline to 
do so here.
---------------------------------------------------------------------------

    \2873\ Puget Sound Initial Comments at 12; Pine Gate Initial 
Comments at 54.
---------------------------------------------------------------------------

    1532. In response to comments from Hydropower Commenters' 
suggestion that the final rule include a simplified procedure for 
amending an executed interconnection agreement to optimize the 
operating parameters of a pumped storage plant already in 
operation,\2874\ we find that such a request is outside the scope of 
this proceeding. In the NOPR, the Commission did not propose a new 
study process for resources already in operation to amend operating 
assumptions memorialized in their interconnection agreements.
---------------------------------------------------------------------------

    \2874\ Hydropower Commenters Initial Comments at 24.
---------------------------------------------------------------------------

    1533. In response to Microgrid Resources' request that the 
Commission explicitly include microgrids in the provisions of this 
rulemaking applied to hybrid resources,\2875\ we find such a request to 
be outside the scope of this proceeding. The Commission did not propose 
to define microgrids or apply specific reforms to microgrids in the 
NOPR, and we decline to do so now. Further, in response to Microgrid 
Resources' and IREC's requests that the Commission extend the proposed 
reforms for hybrid resources to the pro forma SGIP,\2876\ we note that 
the NOPR did not propose to revise the pro forma SGIP to require 
transmission providers to use operating assumptions in interconnection 
studies that reflect the proposed charging behavior of an electric 
storage resource, and we decline to do so here.
---------------------------------------------------------------------------

    \2875\ Microgrid Resources Initial Comments at 7.
    \2876\ Id.; IREC Initial Comments at 15, attach. A.
---------------------------------------------------------------------------

2. Incorporating the Enumerated Alternative Transmission Technologies 
Into the Generator Interconnection Process
a. Consideration of the Enumerated Alternative Transmission 
Technologies in Interconnection Studies Upon Request of the 
Interconnection Customer
i. Need for Reform and NOPR Proposal
    1534. In the NOPR, the Commission stated that alternative 
transmission technologies can provide substantial benefits to optimize 
the transmission system in specific scenarios because they often can be 
deployed both more quickly and at lower costs than other network 
upgrades.\2877\ The Commission stated that, despite these potential 
benefits, alternative transmission technologies often do not receive 
the same consideration during generator interconnection processes as 
other network upgrades.\2878\ The Commission preliminarily found that 
failing to consider alternative transmission technologies that can be 
deployed both more quickly and at lower costs than network upgrades may 
render

[[Page 61226]]

Commission-jurisdictional rates unjust and unreasonable.
---------------------------------------------------------------------------

    \2877\ NOPR, 179 FERC ] 61,194 at P 294.
    \2878\ Id. P 296.
---------------------------------------------------------------------------

    1535. The Commission proposed to revise the pro forma LGIP and pro 
forma SGIP to require transmission providers, upon request of the 
interconnection customer, to evaluate the requested alternative 
transmission solution(s) during the pro forma LGIP cluster study and 
the pro forma SGIP system impact study and facilities study within the 
generator interconnection process.\2879\
---------------------------------------------------------------------------

    \2879\ Id. P 297.
---------------------------------------------------------------------------

    1536. To provide more certainty for evaluation purposes, and focus 
on technologies that serve a transmission function and thus are subject 
to Commission jurisdiction, the Commission proposed to specify the 
technologies that the interconnection customer may request to be 
evaluated.\2880\ Specifically, the Commission proposed revisions to the 
pro forma LGIP and pro forma SGIP to require transmission providers to 
consider the following technologies within the cluster study of the pro 
forma LGIP and within the system impact study and facilities study of 
the pro forma SGIP upon request of the interconnection customer: 
advanced power flow control, transmission switching, dynamic line 
ratings, static synchronous compensators, and static VAR compensators. 
The Commission stated that it believes that the deployment of these 
transmission technologies may reduce interconnection costs by providing 
lower cost network upgrades to interconnect new generating 
facilities.\2881\
---------------------------------------------------------------------------

    \2880\ Id. P 298.
    \2881\ Id.; see also id. PP 294-95, 298.
---------------------------------------------------------------------------

    1537. The Commission explained that, under this proposal, the 
interconnection customer may request, at the relevant scoping meeting, 
that the transmission provider consider a single, multiple, or all 
technologies on this list.\2882\ The Commission proposed that the 
transmission provider would be required to evaluate the transmission 
technologies identified above for feasibility, cost, and time savings 
within the cluster study for the pro forma LGIP and the system impact 
study and facilities study for the pro forma SGIP, upon request of the 
interconnection customer. The Commission explained that the 
transmission provider, upon this request, must evaluate the identified 
transmission technology and, if feasible, determine whether it should 
be used, consistent with good utility practice and other applicable 
regulatory standards. Transmission providers would continue to retain 
discretion regarding whether to use the transmission technology.
---------------------------------------------------------------------------

    \2882\ Id. P 299.
---------------------------------------------------------------------------

    1538. The Commission sought comment on whether the list of 
alternative transmission technologies is sufficient.\2883\ In 
particular, the Commission sought comment on whether storage that 
performs a transmission function, synchronous condensers, and voltage 
source converters should be included in the list of alternative 
transmission technologies. The Commission also sought comment on: (1) 
whether there are software, operational, or other barriers to the use 
of these transmission technologies as proposed; (2) whether the use of 
alternative transmission technologies as supplements for, or in the 
place of, traditional network upgrades is sufficient to guarantee a 
level of service to accommodate an interconnection customer seeking 
NRIS, or whether such a network upgrade can only be used if the 
interconnection customer requested ERIS; (3) whether the existing study 
processes and models in the generator interconnection process remain 
suitable for considering alternative transmission technologies, whether 
additional processes or models are needed, and if so, which entity 
should be responsible for developing them; (4) how costs incurred for 
evaluating alternative transmission technology study requests would be 
allocated among interconnection customers in the cluster; (5) what 
reasonable number of transmission technology study requests from each 
interconnection customer would be workable, the burden (in terms of 
both time and resources) on transmission providers required to evaluate 
such requests, and whether interconnection study deadlines may need to 
be extended to account for time needed to evaluate the alternative 
transmission technology study requests; and (6) whether provisional 
interconnection service consideration for transmission technologies 
should be mandatory.\2884\
---------------------------------------------------------------------------

    \2883\ Id. P 300.
    \2884\ Id. P 301.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1539. Numerous commenters support the Commission's proposal because 
they believe that it could reduce interconnection costs, increase 
flexibility, increase the speed of interconnections, and improve 
reliability.\2885\ Commenters assert that the proposed alternative 
transmission technologies in the NOPR can reduce costs.\2886\ With 
respect to reducing interconnection costs, SEIA contends that, by 
decreasing the costs of network upgrades, the proposal will reduce the 
number of withdrawals from the interconnection queue, creating a more 
stable and efficient interconnection process.\2887\ SEIA also claims 
that decreasing these costs will reduce the interconnection costs for 
interconnection customers, who may then reflect those savings in power 
purchase agreements or integrated resource plan submissions.\2888\ 
Commenters contend that, if the Commission were to not adopt this 
proposal, the failure to lower interconnection costs by evaluating 
alternative transmission technologies would impose unjust and 
unreasonable costs on interconnection customers.\2889\
---------------------------------------------------------------------------

    \2885\ ACORE Reply Comments at 3-4; AEE Initial Comments at 42; 
AEE Reply Comments at 41; AES Initial Comments at 25; Amazon Initial 
Comments at 5-6; Clean Energy Associations Initial Comments at 61-
62; Clean Energy Associations Reply Comments at 9; Clean Energy 
Buyers Initial Comments at 5; Consumer Protection Coalition Reply 
Comments at 2; CREA and NewSun Initial Comments at 92; EDF 
Renewables Initial Comments at 14; ENGIE Initial Comments at 12; 
EPRI Initial Comments at 20-21; Fervo Energy Reply Comments at 8-9; 
Illinois Commission Initial Comments at 14; Invenergy Initial 
Comments at 52; NARUC Initial Comments at 38-39; OSPA Reply Comments 
at 14; Ohio Commission Consumer Advocate Initial Comments at 15; OMS 
Initial Comments at 19; [Oslash]rsted Initial Comments at 3; 
[Oslash]rsted Reply Comments at 8; R Street Initial Comments at 9; 
SEIA Initial Comments at 41; Tesla Initial Comments at 8; WATT 
Coalition Initial Comments at 2; WATT Coalition Reply Comments at 1; 
Joint Fed.-State Task Force on Elec. Transmission, Technical 
Conference, Docket No. AD21-15-000, recording at 1:16:18-1:24:02 
(approx.) (Commissioner Darcie Houck) (July 16, 2023).
    \2886\ Cyprus Creek Initial Comments at 26; SEIA Initial 
Comments at 40; Shell Initial Comments, app. A at v-vi.
    \2887\ SEIA Initial Comments at 40; see also AEE Initial 
Comments at 42; EDF Renewables Initial Comments at 14; ENGIE Initial 
Comments at 12; [Oslash]rsted Initial Comments at 37; OMS Initial 
Comments at 19.
    \2888\ SEIA Initial Comments at 40-41.
    \2889\ Clean Energy Associations Reply Comments at 9-10; 
Environmental Defense Fund Initial Comments at 7; Fervo Energy Reply 
Comments at 9; NARUC Initial Comments at 38.
---------------------------------------------------------------------------

    1540. With respect to reducing interconnection delays, Illinois 
Commission asserts, for example, that alternative transmission 
technologies allow resources to come online more quickly and allow for 
better use of the existing transmission system, requiring fewer 
transmission buildouts.\2890\ OMS contends that failing to consider 
alternative transmission technologies risks requiring longer lead-time 
network upgrades.\2891\ WATT Coalition argues that use of the 
appropriate technologies will result in fewer withdrawals from

[[Page 61227]]

the interconnection queue and a reduction in restudies and 
delays.\2892\ WATT Coalition points out that, when interconnection 
customers withdraw, grid enhancing technologies offer additional value 
because they are scalable and modular to address evolving needs and can 
be redeployed as those needs continue to change.\2893\
---------------------------------------------------------------------------

    \2890\ Illinois Commission Initial Comments at 14.
    \2891\ OMS Initial Comments at 19.
    \2892\ WATT Coalition Initial Comments at 2.
    \2893\ Id. at 2-3; WATT Coalition Reply Comments at 5-6.
---------------------------------------------------------------------------

    1541. With respect to reliability, Ohio Commission Consumer 
Advocate contends that some alternative transmission technologies could 
provide substantial benefits by resolving thermal overloads and 
avoiding voltage collapse.\2894\
---------------------------------------------------------------------------

    \2894\ Ohio Commission Consumer Advocate Initial Comments at 15.
---------------------------------------------------------------------------

    1542. Some commenters argue that a requirement to study alternative 
transmission technologies would not slow down interconnection studies 
overall.\2895\ For example, AEE states that, if a technology is not 
proven or commercially viable, it will be quickly ruled out of further 
evaluation under prevailing study approaches.\2896\ ACORE claims that 
an evaluation of alternative transmission technologies would not be a 
burden but rather an integral part of interconnection studies because 
such an evaluation will likely reduce the number of withdrawals and 
restudies.\2897\ WATT Coalition argues that, because transmission 
providers currently use an iterative process when conducting 
interconnection studies, adding the proposed list of alternative 
transmission technologies to an iterative solution set should not 
significantly change the time frame or complexity of studies.\2898\
---------------------------------------------------------------------------

    \2895\ ACORE Reply Comments at 3-4; AEE Initial Comments at 44; 
ENGIE Initial Comments at 13; Fervo Energy Initial Comments at 7.
    \2896\ AEE Initial Comments at 44.
    \2897\ ACORE Reply Comments at 3-4.
    \2898\ WATT Coalition Reply Comments at 2.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1543. Some commenters argue that the proposal is unnecessary 
because transmission providers already consider alternative 
transmission technologies in interconnection studies.\2899\ For 
example, Southern states that transmission providers already include 
the assessment of alternative transmission technologies such as static 
VAR compensators as needed in interconnection studies.\2900\ AEE 
responds that, if alternative transmission technologies are already 
being evaluated, then the proposal will not place an additional burden 
on interconnection queues.\2901\
---------------------------------------------------------------------------

    \2899\ Bonneville Initial Comments at 23-24; MISO Initial 
Comments at 120; MISO Reply Comments at 12; Southern Initial 
Comments at 29.
    \2900\ Southern Initial Comments at 29.
    \2901\ AEE Reply Comments at 42-43.
---------------------------------------------------------------------------

    1544. Several commenters oppose the proposal because they believe 
it conflates the use of alternative transmission technologies in 
operations with their use in planning.\2902\ For instance, MISO argues 
that alternative transmission technologies are not necessarily the 
solution needed for any particular interconnection because these are 
often operational solutions that are inappropriate for wide-scale 
deployment in a planning process, which reviews an entire cycle of 
proposed interconnections and identifies solutions to support those 
interconnections for the expected lifetime of their 
interconnection.\2903\ MISO claims that using alternative transmission 
technologies in planning for interconnection rather than in operations 
may be inconsistent with ``good utility practice'' and ``applicable 
regulatory standards'', and MISO expresses concerns about the impact or 
effectiveness of using alternative transmission technologies in place 
of network upgrades.\2904\ NYTOs assert that alternative transmission 
technologies should generally not be used in interconnection studies 
unless they are effective in the planning context.\2905\ PJM argues 
that alternative transmission technologies should not be incorporated 
into the generator interconnection process because they do not 
represent long-term solutions that can serve as blanket substitutes for 
the need for transmission expansion.\2906\ In response, AEE and WATT 
Coalition argue that the primary purpose of alternative transmission 
technologies is to serve as a complementary bridge technology while 
more robust transmission is built.\2907\
---------------------------------------------------------------------------

    \2902\ MISO Initial Comments at 120; NRECA Initial Comments at 
45-46; NYTOs Initial Comments at 32: PJM Initial Comments at 68.
    \2903\ MISO Initial Comments at 120; see also NRECA Initial 
Comments at 45-46.
    \2904\ MISO Initial Comments at 122-123.
    \2905\ NYTOs Initial Comments at 32; see also Puget Sound 
Initial Comments at 13-14.
    \2906\ PJM Initial Comments at 68.
    \2907\ AEE Reply Comments at 43-44; WATT Coalition Reply 
Comments at 3-4.
---------------------------------------------------------------------------

    1545. Some commenters express concern that alternative transmission 
technologies are not always appropriate for addressing long-term, 
interconnection-related reliability issues.\2908\ Southern adds that, 
because transmission providers already consider these technologies and 
are subject to mandatory reliability standards, interconnection 
customers should not be able to request certain reliability fixes 
because their overall focus may be to minimize cost instead of 
maximizing reliability.\2909\ EEI asserts that building firm 
transmission capacity or replacing or upgrading limiting equipment 
provides a more reliable long-term solution than the use of alternative 
transmission technologies because they are not dependable for reducing 
congestion or providing more capacity in the long-term or during 
extreme system conditions.\2910\
---------------------------------------------------------------------------

    \2908\ AECI Initial Comments at 9; AEP Initial Comments at 51; 
Avangrid Initial Comments at 36; Southern Initial Comments at 29; 
U.S. Chamber of Commerce Initial Comments at 12.
    \2909\ Southern Initial Comments at 29.
    \2910\ EEI Initial Comments at 20.
---------------------------------------------------------------------------

    1546. Ameren and EEI oppose the proposal because they assert it 
overlaps with pending proposals in other proceedings.\2911\ EEI argues 
the Commission should not promulgate requirements related to 
alternative transmission technologies in this proceeding while other 
Commission proceedings meant to address the use of these same 
technologies are pending.\2912\ ACORE responds that, given the benefits 
of incorporating alternative transmission technologies in 
interconnection studies, there is no justification for delaying this 
requirement pending action in the other Commission proceedings.\2913\
---------------------------------------------------------------------------

    \2911\ Ameren Initial Comments at 30; EEI Initial Comments at 
20.
    \2912\ EEI Initial Comments at 21 (citing Electric Transmission 
Incentives Policy Under Section 219 of the Federal Power Act, Notice 
of Proposed Rulemaking, Docket No. RM20-10-000; Grid-Enhancing 
Technologies, Notice of Workshop, Docket No. AD19-19-000; 
Implementation of Dynamic Line Ratings, Notice of Inquiry, Docket 
No. AD22-5-000; Building for the Future Through Electric Regional 
Transmission Planning and Cost Allocation and Generator 
Interconnection, Notice of Proposed Rulemaking, Docket No. RM21-17-
000).
    \2913\ ACORE Reply Comments at 4.
---------------------------------------------------------------------------

    1547. Other commenters argue that requiring interconnection studies 
to consider alternative transmission technologies will increase 
interconnection study timelines and therefore slow interconnection 
request processing speeds, contrary to the NOPR's objective.\2914\ 
Puget Sound asserts that ``the time is not ripe'' to enforce new 
standards concerning alternative transmission technologies, given the 
sweeping changes proposed in the NOPR, adding that advanced 
transmission technologies requirements

[[Page 61228]]

may not be possible in the short term and could negate the Commission's 
goals to streamline the interconnection process.\2915\
---------------------------------------------------------------------------

    \2914\ AECI Initial Comments at 9; AEP Initial Comments at 53; 
Avangrid Initial Comments at 35; Dominion Initial Comments at 41; 
EEI Initial Comments at 21; Eversource Initial Comments at 36-37; 
Indicated PJM TOs Initial Comments at 55; Indicated PJM TOs Reply 
Comments at 18; ISO-NE Initial Comments at 41; MISO Initial Comments 
at 11, 123; National Grid Initial Comments at 42-43; Puget Sound 
Initial Comments at 13.
    \2915\ Puget Sound Initial Comments at 13.
---------------------------------------------------------------------------

    1548. MISO contends that some alternative transmission 
technologies, e.g., technologies that can control line impedances, may 
shift the burden of system impacts to other parties by causing 
additional new constraints.\2916\ Indicated PJM TOs are concerned that, 
if one interconnection customer request changes power flows, such as 
through the use of phase angle regulators, it will impact other 
interconnection customers and effectively require a whole additional 
set of studies for large areas of the transmission system.\2917\ AECI 
argues that the appropriate balance of the burden to justify the use of 
a particular technology should rest with the interconnection customer 
so that ``capricious study requests'' are avoided.\2918\
---------------------------------------------------------------------------

    \2916\ MISO Initial Comments at 122, 124.
    \2917\ Indicated PJM TOs Initial Comments at 55.
    \2918\ AECI Initial Comments at 9.
---------------------------------------------------------------------------

    1549. Several commenters argue that the NOPR proposal is overly 
burdensome for transmission providers.\2919\ For instance, MISO TOs 
note the competing interests (i.e., accelerating the interconnection 
process and layering numerous additional requirements and significantly 
increasing the number of studies an RTO/ISO and its transmission owners 
must perform).\2920\ MISO argues that the Commission's proposal would 
require MISO to conduct 4,780 evaluations in the first phase of its 
interconnection study process.\2921\ MISO contends that, when 
evaluating how these technologies can be incorporated, the effects on 
the rest of the interconnection queue and system can generate debate 
that could slow down the interconnection process. Similarly, National 
Grid claims that new alternative transmission technologies can present 
modeling uncertainties (e.g., operating parameters and cost 
uncertainties) and potential software limitations that transmission 
owners would need an unforeseeable amount of time to evaluate and could 
lead to possible penalties if study deadlines are not met.\2922\
---------------------------------------------------------------------------

    \2919\ Dominion Initial Comments at 41; EEI Initial Comments at 
21; Eversource Initial Comments at 36-37; MISO TOs Initial Comments 
at 30; NextEra Initial Comments at 6.
    \2920\ MISO TOs Initial Comments at 30.
    \2921\ MISO Initial Comments at 11.
    \2922\ National Grid Initial Comments at 42-43.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) List of Alternative Transmission Technologies
    1550. Some commenters broadly support the list of proposed 
alternative transmission technologies,\2923\ with others supporting 
particular technologies (e.g., dynamic line ratings \2924\ and advanced 
power flow control \2925\).
---------------------------------------------------------------------------

    \2923\ NARUC Initial Comments at 39; OMS Initial Comments at 19; 
[Oslash]rsted Initial Comments at 16; WATT Coalition Initial 
Comments at 3; Xcel Initial Comments at 47.
    \2924\ Illinois Commission Initial Comments at 14; OMS Initial 
Comments at 19; WATT Coalition Initial Comments at 2; Joint Fed.-
State Task Force on Elec. Transmission, Technical Conference, Docket 
No. AD21-15-000, recording at 1:16:18-1:24:02 (approx.) 
(Commissioner Darcie Houck) (July 16, 2023).
    \2925\ WATT Coalition Initial Comments at 2; Joint Fed.-State 
Task Force on Elec. Transmission, Technical Conference, Docket No. 
AD21-15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner 
Darcie Houck) (July 16, 2023).
---------------------------------------------------------------------------

    1551. MISO and SoCal Edison oppose the proposed list of 
technologies because they contend that it includes technologies that 
are not appropriate for interconnection.\2926\ MISO asserts that, 
although the deployment of devices such as static series synchronous 
compensators could solve some problems, they could create other issues 
(e.g., a change to the impedance of any one transmission facility could 
cause problems or impact operations elsewhere), requiring the holistic 
management of their operation and deployment.\2927\ SoCal Edison claims 
that certain technologies that the interconnection customer may request 
to be evaluated, such as dynamic line ratings, have not been fully 
tested by certain RTOs/ISOs and thus should be excluded from the 
permissible list of options requested by an interconnection 
customer.\2928\
---------------------------------------------------------------------------

    \2926\ MISO Initial Comments at 122; SoCal Edison Initial 
Comments at 20.
    \2927\ MISO Initial Comments at 122.
    \2928\ SoCal Edison Initial Comments at 20.
---------------------------------------------------------------------------

    1552. Some commenters assert that, although dynamic line ratings 
may be beneficial during operations, they may not be appropriate for 
interconnection or transmission planning.\2929\ Others note several 
operational challenges of using dynamic line ratings in 
interconnection, such as: (1) there is currently no Commission or NERC 
guidance on how to use dynamic line ratings absent thorough data on 
wind conditions, temperature, and other future system conditions; 
\2930\ and (2) interconnection study software is not capable of 
incorporating dynamic line ratings, and it is not clear what 
assumptions should be used on affected systems.\2931\ ISO-NE argues 
that the Commission should continue to consider the use and 
implementation of this technology in Docket No. AD22-5, rather than 
here.\2932\ In response, WATT Coalition argues that there is 
significant value in considering dynamic line ratings in planning, 
adding that dynamic line ratings and other grid enhancing technologies 
are not more difficult to study than legacy devices and traditional 
solutions.\2933\
---------------------------------------------------------------------------

    \2929\ Indicated PJM TOs Initial Comments at 56; ISO-NE Initial 
Comments at 41; NYTOs Initial Comments at 32-33; PacifiCorp Initial 
Comments at 44; Tri-State Initial Comments at 23; U.S. Chamber of 
Commerce Initial Comments at 12-13.
    \2930\ PacifiCorp Initial Comments at 44.
    \2931\ Tri-State Initial Comments at 23.
    \2932\ ISO-NE Initial Comments at 41.
    \2933\ WATT Coalition Reply Comments at 4-6.
---------------------------------------------------------------------------

    1553. While acknowledging the benefits that advanced power flow 
control devices provide for real-time operations, Indicated PJM TOs 
contend that they are inappropriate in the context of implementing 
solutions to facilitate interconnection.\2934\ Tri-State claims that 
advanced power flow control devices may push power onto other affected 
systems, which is a more significant challenge in non-RTO/ISO 
scenarios.\2935\ MISO asserts that the widespread use of advanced flow 
control devices can have widespread impacts due to sizeable adjustments 
to line impedances and that using these devices could result in a 
cascade of issues across the system, pushing the problem and the costs 
of remedying it to other customers.\2936\ WATT Coalition asserts that 
automatic power factor controllers are just as effective at mitigating 
overloads as reconductoring but that automatic power factor controllers 
are the only flexible AC transmission system devices that suffer from 
the ``perverse incentive'' identified by stakeholders because 
installation costs are much lower than the upgrades they compete 
with.\2937\ PacifiCorp states that in the course of the interconnection 
study process it often considers the use of advanced power flow control 
devices as potential alternatives to standard system 
infrastructure.\2938\
---------------------------------------------------------------------------

    \2934\ Indicated PJM TOs Initial Comments at 56.
    \2935\ Tri-State Initial Comments at 23.
    \2936\ MISO Initial Comments at 122.
    \2937\ WATT Coalition Initial Comments at 3.
    \2938\ PacifiCorp Initial Comments at 43.
---------------------------------------------------------------------------

    1554. Some commenters raise concerns about using transmission 
switching for interconnection. For instance, Tri-State questions 
whether transmission switching is meant to be a remedial action scheme 
or to create permanent open points on the system, which it argues may 
be problematic in non-RTOs/ISOs and may result in

[[Page 61229]]

reduced reliability on the transmission system.\2939\ MISO argues that 
applying automatic topology changes would be remedial action schemes, 
noting that MISO and its transmission owners have attempted to reduce 
the number of remedial action schemes employed on the system as a 
matter of good utility practice.\2940\ PacifiCorp contends that 
transmission switching is a complex process that can be implemented 
only under particular factual scenarios and system conditions, adding 
that it is unlikely that system congestion could be reliably reduced by 
requiring the analysis of transmission switching in the study 
process.\2941\
---------------------------------------------------------------------------

    \2939\ Tri-State Initial Comments at 23.
    \2940\ MISO Initial Comments at 122.
    \2941\ PacifiCorp Initial Comments at 44.
---------------------------------------------------------------------------

    1555. Other commenters argue that the Commission should not limit 
the alternative transmission technologies to a pre-approved list.\2942\ 
Some commenters contend that the Commission's proposal could limit 
future grid enhancing technologies that might be the best solution 
because the list includes only five technologies and would not require 
transmission providers to consider new grid enhancing technologies 
until the list is expanded.\2943\ AEE and ENGIE ask the Commission to 
provide a non-exhaustive list of alternative transmission technologies 
and allow any alternative transmission technologies or grid enhancing 
technologies that are proven and commercially viable to qualify for 
evaluation, consistent with the Commission's statutory obligation to 
``encourage, as appropriate, the deployment of advanced transmission 
technologies'' and the list of alternative transmission technologies 
included in that statute.\2944\
---------------------------------------------------------------------------

    \2942\ Amazon Initial Comments at 6-7; CTC Global Initial 
Comments at 17; ENGIE Initial Comments at 13; Environmental Defense 
Fund Initial Comments at 7; Invenergy Initial Comments at 52; 
Microgrid Resources Initial Comments at 8; NRECA Initial Comments at 
46; Public Interest Organizations Initial Comments at 53-55; Xcel 
Initial Comments at 47.
    \2943\ Ameren Initial Comments at 31-32; MISO Reply Comments at 
13-14; Shell Initial Comments, app. A at v.
    \2944\ AEE Initial Comments at 44-45 (citing 42 U.S.C. 16422); 
ENGIE Initial Comments at 13.
---------------------------------------------------------------------------

    1556. Commenters suggest adding the following technologies to the 
list: (1) synchronous condensers and voltage source converters; \2945\ 
(2) IBR technology solutions for advanced control capabilities and 
control parameter tuning; \2946\ (3) microgrid control technologies; 
\2947\ and (4) remedial action schemes, which they contend are an 
effective and inexpensive way to mitigate local transmission 
constraints the use of which is not allowed in many transmission 
providers' policies.\2948\
---------------------------------------------------------------------------

    \2945\ NARUC Initial Comments at 39; Xcel Initial Comments at 
47.
    \2946\ EPRI Initial Comments at 21.
    \2947\ Microgrid Resources Initial Comments at 8.
    \2948\ Enel Initial Comments at 80.
---------------------------------------------------------------------------

    1557. Several commenters also suggest adding advanced conductors to 
the required list of alternative transmission technologies.\2949\ VEIR 
and ACORE argue that advanced conductors may be a beneficial 
alternative to network upgrades because: (1) advanced conductors meet 
the same criteria of quick deployment and low cost and have advantages 
over other network upgrades, especially the elimination of additional 
siting and permitting requirements; \2950\ and (2) a recent Grid 
Strategies LLC report finds ``short lead time to reconductor existing 
lines can help manage risk and uncertainties and significantly increase 
system capacity to mitigate overloads identified in interconnection 
studies.'' \2951\ NARUC asks the Commission to consider requiring an 
evaluation of the accuracy of transmission line ratings on surrounding 
or impacted transmission facilities if requested by an interconnection 
customer.\2952\ Additionally, Ampjack proposes tower lifting to 
increase transmission line ratings due to the time savings, lack of 
outages, and use of existing structures.\2953\
---------------------------------------------------------------------------

    \2949\ ACORE Initial Comments at 6-7; CTC Global Initial 
Comments at 6-9; VEIR Initial Comments at 5-7.
    \2950\ VEIR Initial Comments at 5-7.
    \2951\ ACORE Initial Comments at 7 (citing Jay Caspary and Jesse 
Schneider, Grid Strategies, LLC, Opportunities to Use Advanced 
Conductors to Accelerate Grid Decarbonization, at 9 (Feb. 2022), 
https://acore.org/wp-content/uploads/2022/03/Advanced_Conductors_to_Accelerate_Grid_Decarbonization.pdf).
    \2952\ NARUC Initial Comments at 39-40.
    \2953\ Ampjack Initial Comments at 1-4.
---------------------------------------------------------------------------

    1558. Many commenters recommend that the Commission add storage 
that performs a transmission function to the list.\2954\ Illinois 
Commission contends that storage that performs a transmission function 
can relieve congestion, maintain reliability, and be placed on the 
transmission system more quickly and cheaply than building new 
transmission lines.\2955\ Tesla suggests expanding the list to include 
batteries as virtual transmission, arguing that it provides several 
benefits (e.g., providing emergency capacity for congested transmission 
lines and surplus generation and surplus load capacity to allow 
operation of transmission lines closer to thermal capacity without risk 
of outage and averting the need for load shed by providing grid 
stability service).\2956\ Clean Energy Associations note that the 
Commission has approved tariffs for storage that performs a 
transmission function. Clean Energy Associations assert that it would 
be inconsistent to prohibit an interconnection customer from adding 
electric storage to an interconnection request specifically to address 
transmission reliability impacts in lieu of conventional upgrades, 
while at the same time allowing an interconnection customer to add such 
storage to an interconnection request for purposes unrelated to 
transmission reliability or allowing an interconnection customer to 
limit electric storage operations as a means to avoid network 
upgrades.\2957\
---------------------------------------------------------------------------

    \2954\ AES Initial Comments at 25; Clean Energy Associations 
Initial Comments at 62; Clean Energy Associations Reply Comments at 
9; ENGIE Initial Comments at 13; Illinois Commission Initial 
Comments at 14-15; Illinois CUB Reply Comments at 1; NARUC Initial 
Comments at 39; NESCOE Reply Comments at 19; NY Commission and 
NYSERDA Initial Comments at 10; Ohio Commission Consumer Advocate 
Initial Comments at 17; OMS Initial Comments at 19; [Oslash]rsted 
Initial Comments at 16; Tesla Initial Comments at 8-9; Union of 
Concerned Scientists Reply Comments at 14-15; Xcel Initial Comments 
at 47; Joint Fed.-State Task Force on Elec. Transmission, Technical 
Conference, Docket No. AD21-15-000, recording at 1:16:18-1:24:02 
(approx.) (Commissioner Darcie Houck) (July 16, 2023).
    \2955\ Illinois Commission Initial Comments at 14-15.
    \2956\ Tesla Initial Comments at 8-9.
    \2957\ Clean Energy Associations Initial Comments at 62-63.
---------------------------------------------------------------------------

    1559. Other commenters do not agree with adding storage that 
performs a transmission function to the list.\2958\ MISO notes that, 
although it already evaluates storage that performs a transmission 
function in its generator interconnection process, it was a subject of 
considerable debate.\2959\ Shell states that, while storage that 
performs a transmission function may provide system benefits, it has 
concerns regarding the ability of storage that performs a transmission 
function to ``queue jump'' interconnection customers, thus putting 
those customers at a competitive disadvantage.\2960\
---------------------------------------------------------------------------

    \2958\ Ameren Initial Comments at 31; MISO Initial Comments at 
121; Shell Initial Comments, app. A at v.
    \2959\ MISO Initial Comments at 121.
    \2960\ Shell Initial Comments, app. A at v.
---------------------------------------------------------------------------

(2) Whether To Mandate the Consideration of Alternative Transmission 
Technologies
    1560. Several commenters argue that these technologies should be 
studied by default, rather than at the request of the interconnection 
customer, with some suggesting an ``opt-out'' that the

[[Page 61230]]

interconnection customer could elect.\2961\ Fervo Energy argues that 
mandating the consideration of grid enhancing technologies could be 
more efficient and facilitate more and faster interconnection, although 
there may be delays initially as transmission providers adjust.\2962\ 
Clean Energy Associations ask that transmission providers automatically 
evaluate grid enhancing technologies, unless all interconnection 
customers in a cluster opt out.\2963\ [Oslash]rsted recommends that the 
Commission consider requiring that advanced transmission technologies 
be studied and implemented when network upgrades are needed but cannot 
be completed within three years of being identified.\2964\
---------------------------------------------------------------------------

    \2961\ ACORE Initial Comments at 6; AEE Initial Comments at 42, 
44; AEE Reply Comments at 41-42; Amazon Initial Comments at 6; Clean 
Energy Associations Initial Comments at 63-64; Environmental Defense 
Fund Initial Comments at 7; ELCON Initial Comments at 11; ENGIE 
Initial Comments at 13; Fervo Energy Reply Comments at 9; Hannon 
Armstrong Initial Comments at 2; Invenergy Initial Comments at 52-
53; R Street Initial Comments at 16; WATT Coalition Initial Comments 
at 2; WATT Coalition Reply Comments at 1; Joint Fed.-State Task 
Force on Elec. Transmission, Technical Conference, Docket No. AD21-
15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner Darcie 
Houck) (July 16, 2023).
    \2962\ Fervo Energy Reply Comments at 9.
    \2963\ Clean Energy Associations Initial Comments at 63.
    \2964\ [Oslash]rsted Reply Comments at 8.
---------------------------------------------------------------------------

    1561. CAISO contends that the Commission should simply require 
transmission providers to include a statement in their tariffs that 
they will consider alternative transmission technologies for every 
interconnection and incorporate them when they are the cost-effective 
solution.\2965\ CAISO states that this would allow the interconnection 
customer to request an unexecuted interconnection agreement and to 
raise with the Commission any transmission provider refusal to consider 
a technology.\2966\ Ohio Commission Consumer Advocate suggests that 
transmission providers and interconnection customers mutually determine 
an appropriate number of evaluations for grid enhancing 
technologies.\2967\
---------------------------------------------------------------------------

    \2965\ CAISO Initial Comments at 38.
    \2966\ Id.; see also MISO Reply Comments at 13.
    \2967\ Ohio Commission Consumer Advocate Initial Comments at 16.
---------------------------------------------------------------------------

(3) Alternative Transmission Technologies in Provisional 
Interconnection Service
    1562. Some commenters argue that alternative transmission 
technologies could assist with provisional interconnection service. For 
instance, R Street and Hannon Armstrong assert that these technologies 
can be used as a temporary measure until other network upgrades are 
completed, thus reducing the cost and delays of generator 
interconnection, even if they only serve as a bridge to a permanent 
solution set, such as cluster network upgrades.\2968\ NextEra contends 
that, when an alternative transmission technology may serve as a 
temporary solution, the transmission provider should reasonably 
cooperate with requests from an interconnection customer willing to 
fund installation of that technology as an interim solution.\2969\ 
Fervo Energy asks the Commission to require transmission providers to 
consider alternative transmission technologies when responding to a 
provisional interconnection request if these technologies allow for 
earlier in-service dates.\2970\
---------------------------------------------------------------------------

    \2968\ R Street Initial Comments at 16; Hannon Armstrong Initial 
Comments at 2.
    \2969\ NextEra Initial Comments at 38-39.
    \2970\ Fervo Energy Reply Comments at 10.
---------------------------------------------------------------------------

    1563. Others oppose requiring evaluation of alternative 
transmission technologies for provisional interconnection 
service.\2971\ For instance, MISO argues that the consideration of 
advanced transmission technologies for provisional interconnection 
service should not be mandatory because it may result in delays that 
are contrary to the goals of this proceeding.\2972\
---------------------------------------------------------------------------

    \2971\ Ameren Initial Comments at 32; MISO Initial Comments at 
124.
    \2972\ MISO Initial Comments at 124.
---------------------------------------------------------------------------

(4) Alternative Transmission Technologies for NRIS or ERIS
    1564. Some commenters responded to whether the use of alternative 
transmission technologies can support an interconnection customer's 
request for NRIS, or whether the use of such technologies can only be 
used if the interconnection customer requested ERIS. Hannon Armstrong 
asserts that one or more of these alternative transmission technologies 
may be able to delay or eliminate the needed network upgrades 
identified in interconnection studies under both ERIS and NRIS.\2973\ 
MISO argues that technologies that merely curtail generation would not 
be suitable for interconnection requests seeking NRIS as they could not 
pass the deliverability test, while technologies that can control 
transmission line impedances, such as phase shifters, are acceptable 
for NRIS.\2974\ Invenergy contends that a given alternative 
transmission technology may only facilitate ERIS service in certain 
circumstances but that there is no reason to limit the scope of 
alternative transmission technologies at the outset without having 
performed any relevant analysis.\2975\ Clean Energy Associations ask 
the Commission to require transmission providers to publicly post any 
service differences (e.g., if use of a given technology would enable 
ERIS but not necessarily NRIS).\2976\
---------------------------------------------------------------------------

    \2973\ Hannon Armstrong Initial Comments at 2.
    \2974\ MISO Initial Comments at 124.
    \2975\ Invenergy Initial Comments at 53.
    \2976\ Clean Energy Associations Initial Comments at 62.
---------------------------------------------------------------------------

(5) Study and Network Upgrade Cost Allocation for Alternative 
Transmission Technologies
    1565. Commenters address the Commission's question about how costs 
incurred for evaluating alternative transmission technology study 
requests would be allocated among interconnection customers in the 
cluster. WATT Coalition argues that any marginal increase of study 
costs to accommodate the evaluation of grid enhancing technologies 
should be allocated evenly across interconnection customer cluster 
study participants.\2977\ However, NARUC and Indicated PJM TOs 
disagree, asserting that additional costs incurred for evaluating 
alternative transmission technologies should be allocated to the 
requesting interconnection customer(s) to maintain cost certainty and 
equity.\2978\ Fervo Energy proposes that, if the requested alternative 
transmission technology would benefit more than one interconnection 
customer in the cluster, a pro rata allocation of study cost among 
those interconnection customers would be appropriate; however, if the 
requested technology only serves one interconnection customer, Fervo 
Energy argues that direct cost allocation for that study cost is 
appropriate.\2979\ Fervo Energy adds that it would support pro rata 
allocation of costs even if the Commission mandates consideration of 
alternative transmission technologies.\2980\
---------------------------------------------------------------------------

    \2977\ WATT Coalition Initial Comments at 4.
    \2978\ NARUC Initial Comments at 40; Indicated PJM TOs Reply 
Comments at 17-18.
    \2979\ Fervo Energy Initial Comments at 7.
    \2980\ Fervo Energy Reply Comments at 10.
---------------------------------------------------------------------------

    1566. NextEra argues that, under the ``but for'' principle of cost 
allocation, the interconnection customer's cost responsibility should 
be limited to the cost of the alternative transmission technology that 
would have sufficed as a long-term solution for a given network 
upgrade, especially when transmission providers choose instead to 
construct more costly upgrades beyond what is

[[Page 61231]]

required for the interconnection customer's proposed generating 
facility.\2981\ Tri-State instead argues that the Commission's proposal 
does not consider the likely outcome of an interconnection request 
advancing with a new technology, which will force the subsequent 
interconnection customer to fund costly network upgrades when it would 
be more equitable for the interconnection customers to share the cost 
of a single network upgrade.\2982\
---------------------------------------------------------------------------

    \2981\ NextEra Initial Comments at 38.
    \2982\ Tri-State Initial Comments at 23.
---------------------------------------------------------------------------

(6) Timing of Alternative Transmission Technology Evaluation Requests
    1567. Some commenters discuss limiting the request to include 
alternative transmission technologies to the initial stages of the 
interconnection process. ISO-NE and NESCOE argue that any alternatives 
that are proposed should be included in the initial interconnection 
request with specific assumptions that can be studied.\2983\
---------------------------------------------------------------------------

    \2983\ ISO-NE Initial Comments at 41; NESCOE Reply Comments at 
21.
---------------------------------------------------------------------------

    1568. Other commenters argue that interconnection customers should 
be able to request the study of alternative transmission technologies 
later in the interconnection process or when more information is 
available.\2984\ Clean Energy Associations contend that transmission 
providers should be required to post the costs of requested 
technologies and give interconnection customers the flexibility to 
adopt appropriate solutions, subject to system conditions and any 
limitations in the area.\2985\ [Oslash]rsted suggests that once cluster 
studies are done, and if the required upgrades are outside of the 
cluster area, then alternate transmission technologies, with the 
addition of energy storage, should be evaluated by the transmission 
provider during its system impact study phase.\2986\
---------------------------------------------------------------------------

    \2984\ EDF Renewables Initial Comments at 14-15; Enel Initial 
Comments at 79; Fervo Energy Reply Comments at 9; Invenergy Initial 
Comments at 55; [Oslash]rsted Initial Comments at 9.
    \2985\ Clean Energy Associations Initial Comments at 62.
    \2986\ [Oslash]rsted Initial Comments at 9 (referencing 
definition of ``alternative transmission technologies,'' NOPR, 179 
FERC ] 61,194 at P 294 n.406).
---------------------------------------------------------------------------

    1569. NARUC asks the Commission to ensure that there is an 
opportunity for information exchange between the transmission provider 
and interconnection customer to design alternative transmission 
technology solutions and supports implementation of a time frame to 
facilitate that information exchange.\2987\ Ohio Commission Consumer 
Advocate contends that some changes would be required to address unique 
attributes of grid enhancing technologies that may be overlooked by 
existing frameworks and that the cost and duration of modeling and 
evaluations would be best addressed by transmission providers in 
concert with interconnection customers.\2988\
---------------------------------------------------------------------------

    \2987\ NARUC Initial Comments at 40-41.
    \2988\ Ohio Commission Consumer Advocate Initial Comments at 16.
---------------------------------------------------------------------------

(d) Requests for Clarification and Flexibility
    1570. Ameren asks how software or operational barriers (such as 
whether the MISO software can model the technology) will be 
addressed.\2989\ Ameren asks for clarification as to who pays for the 
software necessary to model the alternative transmission technology and 
whether that gets assigned to the interconnection customer requesting 
the use of the advanced transmission technology or to the cluster of 
interconnection customers, some of which may prefer a different 
solution that does not involve use of an advanced transmission 
technology. Ameren claims that it is unclear what happens if 
interconnection customers within the same cluster disagree about using 
an alternative transmission technology in place of a network upgrade 
and whether consensus is required.
---------------------------------------------------------------------------

    \2989\ Ameren Initial Comments at 32.
---------------------------------------------------------------------------

    1571. NARUC suggests that the Commission clarify that transmission 
providers need not perform a separate study for each requested 
alternative transmission technology.\2990\ NARUC also asks the 
Commission to clarify that interconnection customers bear the burden of 
designing the alternative transmission technology solutions, preparing 
necessary technical data, and determining whether it is temporary or 
permanent.
---------------------------------------------------------------------------

    \2990\ NARUC Initial Comments at 40.
---------------------------------------------------------------------------

    1572. NEPOOL urges the Commission to receive input from each RTO/
ISO to consider how much flexibility to provide with respect to the 
list of alternative transmission technologies because they are the most 
informed with respect to which alternative transmission technologies 
are feasible.\2991\ Similarly, NYTOs ask the Commission to allow 
regions to determine which alternative transmission technologies would 
be appropriate and beneficial in performing interconnection studies 
instead of mandating their use.\2992\
---------------------------------------------------------------------------

    \2991\ NEPOOL Initial Comments at 17.
    \2992\ NYTOs Initial Comments at 32-33.
---------------------------------------------------------------------------

    1573. Some commenters underscore the importance of transmission 
providers retaining the discretion to decline to adopt an alternative 
transmission technology in the place of a network upgrade.\2993\ 
National Grid argues that, to the extent an interconnection customer 
requests evaluation of a new alternative transmission technology beyond 
the list proposed in the NOPR and provides studies in support of its 
proposed use, the transmission owner should be permitted to determine 
whether the evaluation of such a new technology will be 
beneficial.\2994\ Indicated PJM TOs request that, if the final rule 
requires transmission providers to consider alternative transmission 
technologies, the transmission provider and transmission owners have 
the ability to reject the request without a study when they have 
knowledge or experience that the request will not work.\2995\
---------------------------------------------------------------------------

    \2993\ Ameren Initial Comments at 31; APS Initial Comments at 
23; Indicated PJM TOs Initial Comments at 57; National Grid Initial 
Comments at 42; PacifiCorp Initial Comments at 43; Xcel Initial 
Comments at 47.
    \2994\ National Grid Initial Comments at 42.
    \2995\ Indicated PJM TOs Reply Comments at 17.
---------------------------------------------------------------------------

(e) Miscellaneous
    1574. Invenergy argues that, if an alternative transmission 
technology is not selected, the transmission providers should provide 
detailed reports, including a cost-benefit analysis, behind the 
decision and there should be a process to resolve disagreements over 
the decision with the interconnection customer.\2996\ R Street requests 
that the Commission require transmission providers to describe the 
benefits, or lack thereof, of the set of technologies listed in the 
NOPR.\2997\ WATT Coalition and California Public Utilities Commissioner 
Darcie Houck request that transmission providers abide by strict 
standards when studying grid enhancing technologies.\2998\
---------------------------------------------------------------------------

    \2996\ Invenergy Initial Comments at 54.
    \2997\ R Street Initial Comments at 16.
    \2998\ WATT Coalition Initial Comments at 3-4; Joint Fed.-State 
Task Force on Elec. Transmission, Technical Conference, Docket No. 
AD21-15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner 
Darcie Houck) (July 16, 2023).
---------------------------------------------------------------------------

    1575. In addition to the study of alternative transmission 
technologies that the Commission envisions, [Oslash]rsted recommends 
requiring the deployment of these alternative transmission technologies 
as a medium-term or long-term alternative to transmission build 
out.\2999\
---------------------------------------------------------------------------

    \2999\ [Oslash]rsted Initial Comments at 16.
---------------------------------------------------------------------------

    1576. EDF Renewables suggests that the Commission require the 
consideration of alternative transmission technologies not only in

[[Page 61232]]

interconnection and transmission planning but also in market operations 
upon an interconnection customer's request.\3000\
---------------------------------------------------------------------------

    \3000\ EDF Renewables Initial Comments at 14-15.
---------------------------------------------------------------------------

    1577. Enel claims that interconnection customer interconnection 
facilities are underutilized and could be networked into the 
transmission system to mitigate transmission constraints and to 
increase system reliability.\3001\ Enel suggests that the Commission 
add language to the pro forma LGIA that allows interconnection 
facilities to convert to distribution facilities or regional 
transmission facilities.
---------------------------------------------------------------------------

    \3001\ Enel Initial Comments at 80-81.
---------------------------------------------------------------------------

iii. Commission Determination
    1578. We adopt, with modifications, the proposed revisions to 
section 7.3 of the pro forma LGIP, and sections 3.3.6 and 3.4.10 of the 
pro forma SGIP. We modify the NOPR proposal to require transmission 
providers to evaluate the following enumerated list of alternative 
transmission technologies: static synchronous compensators, static VAR 
compensators, advanced power flow control devices, transmission 
switching, synchronous condensers, voltage source converters, advanced 
conductors, and tower lifting. We modify proposed pro forma LGIP 
section 7.3 to require transmission providers to evaluate the list of 
alternative transmission technologies enumerated in this final rule 
during the cluster study, including any restudies, of the generator 
interconnection process in all instances (i.e., for all interconnection 
customers in a cluster), without the need for a request from an 
interconnection customer. We require transmission providers to evaluate 
each alternative transmission technology listed in pro forma LGIP 
section 7.3 and to determine, in the transmission provider's sole 
discretion, whether it should be used, consistent with good utility 
practice, applicable reliability standards, and other applicable 
regulatory requirements. Finally, we require transmission providers to 
include, in the pro forma LGIP cluster study report, an explanation of 
the results of the evaluation of the enumerated alternative 
transmission technologies for feasibility, cost, and time savings as an 
alternative to a traditional network upgrade.
    1579. We modify the enumerated list of alternative transmission 
technologies from the NOPR proposal to: (1) retain synchronous, static 
VAR compensators, advanced power flower control, and transmission 
switching in the list; (2) add synchronous condensers, voltage source 
converters, advanced conductors, and tower lifting to the list; and (3) 
remove dynamic line ratings from the list. Generally, we find that 
these enumerated alternative transmission technologies are those with 
the most potential to be useful to reduce interconnection costs by 
providing lower cost network upgrades to interconnect new generating 
facilities and, thus, we require transmission providers to evaluate 
these technologies in the interconnection process for their 
feasibility, cost, and time savings potential.
    1580. We also adopt, with modifications, the proposed revisions to 
sections 3.3.6 and 3.4.10 of the pro forma SGIP. Consistent with the 
pro forma LGIP requirement, we require transmission providers to 
evaluate the enumerated alternative transmission technologies in all 
instances, without the need for a request from an interconnection 
customer. We modify the proposal to require such evaluations to occur 
during the pro forma SGIP feasibility study and system impact study of 
the generator interconnection process, as opposed to in the pro forma 
SGIP system impact study and facilities study. We find that it is 
appropriate to modify the proposal so that these evaluations occur 
during the relevant pro forma SGIP studies where network upgrades are 
identified, consistent with the pro forma LGIP requirement. We require 
transmission providers to evaluate each alternative transmission 
technology listed in pro forma SGIP sections 3.3.6 and 3.4.10 and 
determine, in the transmission provider's sole discretion, whether it 
should be used, consistent with good utility practice, applicable 
reliability standards, and other applicable regulatory requirements.
    1581. Finally, we require transmission providers to include, in the 
feasibility study report and system impact study report, an explanation 
of the results of the evaluation of the enumerated alternative 
transmission technologies for feasibility, cost, and time savings as an 
alternative to a traditional network upgrade. We note that this reform 
is one of the few reforms in this final rule that applies to small 
generating facilities, in addition to large generating facilities. As 
described below, we find that the enumerated alternative transmission 
technologies that we are requiring transmission providers to evaluate 
in their interconnection studies are appropriate for evaluation in the 
pro forma SGIP context because they are scalable, and we find that the 
enumerated alternative transmission technologies have the potential to 
provide similar benefits in the context of both small and large 
generating facilities, including cost and time savings. As such, we 
adopt, with modifications, the proposed revisions to require 
transmission providers to evaluate the enumerated alternative 
transmission technologies in all instances in both the pro forma LGIP 
and pro forma SGIP.
    1582. This final rule does not create a presumption in favor of 
substituting alternative transmission technologies for necessary 
traditional network upgrades, either categorically or in specific 
cases.\3002\ This final rule is agnostic as to whether, in a specific 
case, an alternative transmission technology is an acceptable 
alternative to a traditional network upgrade,\3003\ ``that would allow 
the interconnection customer to flow the output of its generating 
facility onto the transmission provider's transmission system in a safe 
and reliable manner.'' \3004\ The determination in each specific case 
whether to require a traditional network upgrade or an alternative 
transmission

[[Page 61233]]

technology is to be made by the transmission provider, and the 
determination should be consistent with good utility practice, 
applicable reliability standards, and other applicable regulatory 
requirements.\3005\ This rule mandates a process of evaluation of 
alternatives to traditional network upgrades, not outcomes in specific 
cases.
---------------------------------------------------------------------------

    \3002\ See PJM Initial Comments at 68 (``PJM therefore cautions 
the Commission not to conflate the operational benefits of 
alternative transmission technologies . . . with the need to address 
significant capacity enhancement needs (short and long-term) or 
long-range transmission needs under rapid growth or changing 
resource mix scenarios.''); MISO Initial Comments at 120 (``However, 
the Commission fails to recognize that these technologies may be 
evaluated in the generator interconnection process already but may 
nonetheless not be adopted as they are not the appropriate solution 
to a Transmission Issue related to an interconnection.'').
    \3003\ See MISO Initial Comments at 121-22 (``Further, although 
these technologies may be evaluated, the technologies identified by 
the Commission still may not provide the appropriate solution from a 
planning perspective.[ ] Many of the technologies identified are 
appropriately considered as operational tools or short-term 
solutions but are not necessarily appropriate for planning to 
support a particular generator interconnection.'').
    \3004\ See Order No. 2003, 104 FERC ] 61,103 at P 767 (``Both 
Energy Resource Interconnection Service and Network Resource 
Interconnection Service provide for the construction of Network 
Upgrades that would allow the Interconnection Customer to flow the 
output of its Generating Facility onto the Transmission Provider's 
Transmission System in a safe and reliable manner''); Order No. 
2003-A, 106 FERC ] 61,220 at P 404; pro forma LGIA art. 9.3 
(``Transmission Provider shall cause the Transmission System and the 
Transmission Provider's Interconnection Facilities to be operated, 
maintained and controlled in a safe and reliable manner and in 
accordance with this LGIA''); Midwest Indep. Transmission Sys. 
Operator, Inc., 138 FERC ] 61,233, at P 190 (2012), reh'g denied, 
139 FERC ] 61,253 (2012), partial reh'g granted on other grounds, 
150 FERC ] 61,035 (2015). See also pro forma LGIA art. 9.4 
(``Interconnection Customer shall at its own expense operate, 
maintain and control the Large Generating Facility and 
Interconnection Customer's Interconnection Facilities in a safe and 
reliable manner and in accordance with this LGIA'').
    \3005\ See MISO Initial Comments at 123 (``Additionally, as 
noted by the Commission in the proposed reform, although alternative 
transmission technologies may be useful tools for operations, 
relying on these tools for planning for interconnection may not be 
consistent with `good utility practice' and `applicable regulatory 
standards.' '').
---------------------------------------------------------------------------

    1583. Based on the record, we affirm the Commission's preliminary 
finding in the NOPR that alternative transmission technologies have the 
potential to provide benefits to optimize the transmission system in 
specific scenarios.\3006\ Specifically, a number of commenters argue 
that selecting alternative transmission technologies as network 
upgrades may reduce interconnection costs by providing lower cost 
transmission solutions to interconnecting new generating facilities 
\3007\ and may allow for a faster interconnection by providing 
solutions that can be implemented more quickly.\3008\ Commenters also 
point out that alternative transmission technologies allow for better 
use of the existing transmission system,\3009\ can enhance 
reliability,\3010\ and may reduce withdrawals, restudies, and overall 
interconnection delays.\3011\ In addition, several commenters argue 
that decreasing the costs of network upgrades will reduce the number of 
withdrawals from interconnection queues, which will ultimately create a 
more efficient interconnection process by reducing the number of 
restudies triggered by withdrawals.\3012\ Furthermore, commenters argue 
that alternative transmission technologies offer additional value 
because they are scalable and modular to address evolving needs and can 
be redeployed as those needs continue to change.\3013\ We find that 
failing to evaluate the enumerated alternative transmission 
technologies renders Commission-jurisdictional rates unjust and 
unreasonable and fails to ensure that interconnection customers are 
able to interconnect in a reliable, efficient, transparent, and timely 
manner.\3014\
---------------------------------------------------------------------------

    \3006\ NOPR, 179 FERC ] 61,194 at PP 294-295.
    \3007\ AEE Initial Comments at 42; EDF Renewables Initial 
Comments at 14; ENGIE Initial Comments at 12; OMS Initial Comments 
at 19; [Oslash]rsted Initial Comments at 3; SEIA Initial Comments at 
40.
    \3008\ AEE Initial Comments at 42; OMS Initial Comments at 19; 
[Oslash]rsted Initial Comments at 3; SEIA Initial Comments at 40.
    \3009\ Illinois Commission Initial Comments at 14; Joint Fed.-
State Task Force on Elec. Transmission, Technical Conference, Docket 
No. AD21-15-000, recording at 1:16:18-1:24:02 (approx.) 
(Commissioner Darcie Houck) (July 16, 2023).
    \3010\ AEE Initial Comments at 42; Ohio Commission Consumer 
Advocate Initial Comments at 15; Joint Fed.-State Task Force on 
Elec. Transmission, Technical Conference, Docket No. AD21-15-000, 
recording at 1:16:18-1:24:02 (approx.) (Commissioner Darcie Houck) 
(July 16, 2023).
    \3011\ [Oslash]rsted Initial Comments at 3, 15-16; R Street 
Initial Comments at 16; SEIA Initial Comments at 40; WATT Coalition 
Initial Comments at 2.
    \3012\ SEIA Initial Comments at 41; WATT Coalition Initial 
Comments at 2.
    \3013\ WATT Coalition Initial Comments at 2-3; WATT Coalition 
Reply Comments at 5-6.
    \3014\ NOPR, 179 FERC ] 61,194 at P 296; see Clean Energy 
Associations Reply Comments at 9-10; Environmental Defense Fund 
Initial Comments at 7; Fervo Reply Comments at 9; NARUC Initial 
Comments at 38.
---------------------------------------------------------------------------

    1584. However, as stated above,\3015\ this final rule mandates a 
process of evaluation of alternative transmission technologies, not 
outcomes in specific cases, and does not create a presumption in favor 
of using an alternative transmission technology as a substitute for a 
traditional network upgrade deemed necessary in a specific case. 
Rather, under the approach adopted here, in all cases, the transmission 
provider is required only to evaluate the use of alternative 
transmission technologies as network upgrades consistent with good 
utility practice, applicable reliability standards, and other 
applicable regulatory requirements.\3016\ We recognize that, after the 
transmission provider evaluates the enumerated alternative transmission 
technologies, the transmission provider, in its sole discretion, may 
still decide to remedy an identified reliability problem with a 
traditional network upgrade.
---------------------------------------------------------------------------

    \3015\ See supra P 1582.
    \3016\ See MISO Initial Comments at 122-123.
---------------------------------------------------------------------------

    1585. We modify the proposed requirement that transmission 
providers evaluate the enumerated alternative transmission technologies 
only at the request of the interconnection customer. Instead, we 
require transmission providers to evaluate the enumerated alternative 
transmission technologies in all instances, without a request from an 
interconnection customer. We find that this approach both ensures that 
the enumerated alternative transmission technologies are considered in 
the interconnection process and avoids introducing additional 
procedural complexity to the interconnection process. This approach, 
which was suggested by many commenters,\3017\ will provide the benefits 
of an evaluation of the enumerated alternative transmission 
technologies more broadly and consistently and in a more efficient 
manner. We believe that modifying the proposal addresses concerns 
raised by commenters about the NOPR proposal.\3018\ More specifically, 
evaluating alternative transmission technologies only by request, as 
proposed in the NOPR, would create an overly complicated and time-
consuming process under which transmission providers evaluate each 
alternative transmission technology for each interconnection request 
individually. Commenters also raise concerns about the impact on costs 
and timing for the entire cluster if only a portion of the cluster 
requests evaluation of alternative transmission technologies or if 
interconnection customers within the same cluster disagree about using 
an alternative transmission technology.\3019\ Given these concerns, and 
the potential for benefits to be gained by the evaluation and use, at 
the transmission provider's sole discretion, of the enumerated 
alternative transmission technologies, we find that it would be overly 
burdensome and complex to require transmission providers to track and 
process interconnection customer-specific study requests and to resolve 
conflicts between interconnection customers' different study requests, 
at the expense of those benefits.
---------------------------------------------------------------------------

    \3017\ ACORE Initial Comments at 6; AEE Initial Comments at 42; 
CAISO Initial Comments at 38; Amazon Initial Comments at 6; ELCON 
Initial Comments at 11; Fervo Energy Reply Comments at 9; Hannon 
Armstrong Initial Comments at 2; Invenergy Initial Comments at 52-
53; R Street Initial Comments at 16; Joint Fed.-State Task Force on 
Elec. Transmission, Technical Conference, Docket No. AD21-15-000, 
recording at 1:16:18-1:24:02 (approx.) (Commissioner Darcie Houck) 
(July 16, 2023).
    \3018\ Indicated PJM TOs Initial Comments at 55; MISO Initial 
Comments at 11, 121; MISO TOs Initial Comments at 30; National Grid 
Initial Comments at 42-43.
    \3019\ CAISO Initial Comments at 38; Puget Sound Initial 
Comments at 13; Ameren Initial Comments at 32.
---------------------------------------------------------------------------

    1586. The record before us demonstrates that the requirements we 
adopt today will not overly burden transmission providers.\3020\ We 
find that requiring transmission providers to evaluate the enumerated 
alternative transmission technologies in each interconnection study 
will not be a significant additional burden on interconnection queues 
for those transmission providers that already consider alternative 
transmission technologies in their interconnection process. 
Furthermore, we find that the benefits of evaluating and implementing 
the enumerated alternative transmission technologies outweigh the 
potential

[[Page 61234]]

burden or the potential of increased study times. As recognized by 
commenters and explained above, the evaluation and use, at the 
transmission provider's sole discretion, of the enumerated alternative 
transmission technologies could decrease network upgrade costs, 
withdrawals, and restudies, thereby increasing the efficiency of the 
interconnection process overall. For these reasons, we disagree with 
commenters that argue that requiring transmission providers to evaluate 
the enumerated alternative transmission technologies is contrary to the 
NOPR's goal of increasing the speed of interconnection queue 
processing.
---------------------------------------------------------------------------

    \3020\ AEE Initial Comments at 44; ENGIE Initial Comments at 13; 
ACORE Reply Comments at 3-4.
---------------------------------------------------------------------------

    1587. We find that, in conducting an evaluation of the enumerated 
alternative transmission technologies, it is appropriate for 
transmission providers to continue to retain discretion regarding 
whether to use each enumerated alternative transmission technology, 
consistent with the NOPR.\3021\ The requirement is to evaluate the 
enumerated alternative transmission technologies in the interconnection 
process for feasibility, cost, and time savings and to determine 
whether, in the transmission provider's sole discretion, an alternative 
transmission technology should be used as a solution--consistent with 
good utility practice, applicable reliability standards, and other 
applicable regulatory requirements.\3022\ The transmission provider 
must determine whether using any of the enumerated alternative 
transmission technologies is an appropriate and reliable network 
upgrade ``that would allow the interconnection customer to flow the 
output of its generating facility onto the transmission provider's 
transmission system in a safe and reliable manner.'' \3023\ The 
requirement to make such a determination before allowing for the use of 
the enumerated alternative transmission technologies addresses concerns 
that their use may impinge on reliability, delay network upgrades 
instead of reducing the need for them or obviating the need for them 
altogether, or fail to address all transmission system issues that a 
traditional network upgrade would address. We recognize the need to 
avoid time-consuming delays and costly disputes or litigation over 
interconnection costs that could arise as a result of this 
reform.\3024\ Therefore, we find that, if a transmission provider 
evaluates the enumerated alternative transmission technologies as 
required herein and, in its sole discretion, determines not to use any 
enumerated alternative transmission technologies as an alternative to a 
traditional network upgrade, the transmission provider has complied 
with this final rule, including tariffs filed pursuant to this final 
rule.
---------------------------------------------------------------------------

    \3021\ NOPR, 179 FERC ] 61,194 at P 299.
    \3022\ See MISO Initial Comments at 122-123 (``Additionally, as 
noted by the Commission in the proposed reform, although alternative 
transmission technologies may be useful tools for operations, 
relying on these tools for planning for interconnection may not be 
consistent with `good utility practice' and `applicable regulatory 
standards.' '').
    \3023\ See Order No. 2003, 104 FERC ] 61,103 at P 767 (``Both 
Energy Resource Interconnection Service and Network Resource 
Interconnection Service provide for the construction of Network 
Upgrades that would allow the Interconnection Customer to flow the 
output of its Generating Facility onto the Transmission Provider's 
Transmission System in a safe and reliable manner''); Order No. 
2003-A, 106 FERC ] 61,220 at P 404; pro forma LGIA art. 9.3 
(``Transmission Provider shall cause the Transmission System and the 
Transmission Provider's Interconnection Facilities to be operated, 
maintained and controlled in a safe and reliable manner and in 
accordance with this LGIA''); Midwest Indep. Transmission Sys. 
Operator, Inc., 138 FERC ] 61,233, at P 190 (2012), reh'g denied, 
139 FERC ] 61,253 (2012), partial reh'g granted on other grounds, 
150 FERC ] 61,035 (2015). See also pro forma LGIA art. 9.4 
(``Interconnection Customer shall at its own expense operate, 
maintain and control the Large Generating Facility and 
Interconnection Customer's Interconnection Facilities in a safe and 
reliable manner and in accordance with this LGIA'').
    \3024\ See SPP Initial Comments at 26 (``Even though the 
Commission has stated that transmission providers retain the 
discretion regarding whether to use such technologies, the very fact 
that the transmission provider is required to evaluate them will 
lead to disputes if the transmission provider then exercises that 
discretion.'').
---------------------------------------------------------------------------

    1588. Because we modify the NOPR proposal and require transmission 
providers to evaluate the enumerated alternative transmission 
technologies in all instances, we find that the final rule will not 
``effectively require a whole additional set of studies for large areas 
of the transmission system'' or exponentially increase the number of 
studies needed to consider the various combinations, as Indicated PJM 
TOs argue could occur under the NOPR proposal.\3025\ This is because 
transmission providers will not be evaluating the enumerated 
alternative transmission technologies for a subset of interconnection 
customers within a cluster--but rather for the entire cluster.
---------------------------------------------------------------------------

    \3025\ Indicated PJM TOs Initial Comments at 55.
---------------------------------------------------------------------------

    1589. Regarding WATT Coalition and California Public Utility 
Commissioner Darcie Houck's request that transmission providers abide 
by strict standards when studying alternative transmission 
technologies,\3026\ we decline to adopt any such standards in the pro 
forma LGIP and pro forma SGIP governing the evaluation of alternative 
transmission technologies. We find that it is appropriate to continue 
to rely on transmission providers to use good utility practice, 
applicable reliability standards, and other applicable regulatory 
requirements, in their evaluations of alternative transmission 
technologies, including the enumerated list, because the specific 
evaluation may depend on the transmission provider's individual 
transmission system, cluster makeup, and other factors. Similarly, 
regarding National Grid's concern that studying every potential 
alternative transmission technology for every interconnection request 
could cause transmission providers to be penalized for not meeting 
study deadlines,\3027\ the final rule does not require the study of all 
technologies considered alternative transmission technologies but 
rather the evaluation of the enumerated alternative transmission 
technologies. Further, we find that the transmission provider-- 
consistent with good utility practice, applicable reliability 
standards, and other applicable regulatory requirements--retains the 
sole discretion to determine whether a particular technology in the 
enumerated list of alternative transmission technologies is appropriate 
and reliable as a network upgrade, or not, for a given cluster.
---------------------------------------------------------------------------

    \3026\ WATT Coalition Initial Comments at 3-4; Joint Fed.-State 
Task Force on Elec. Transmission, Technical Conference, Docket No. 
AD21-15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner 
Darcie Houck) (July 16, 2023).
    \3027\ National Grid Initial Comments at 42-43.
---------------------------------------------------------------------------

    1590. We also believe that the requirement that transmission 
providers evaluate the enumerated alternative transmission technologies 
for an entire cluster--rather than on an individual interconnection 
customer-request basis--and the modifications to the enumerated list of 
alternative transmission technologies (as discussed below) will ease 
the burden on transmission providers, thereby lessening the risk that 
they are unable to complete studies by the required deadlines. We note 
that we are not dictating how a transmission provider must evaluate 
each enumerated alternative transmission technology on the list in each 
instance; we recognize that in some cases transmission providers may be 
able to rapidly determine if a certain enumerated alternative 
transmission technology is inappropriate for further study. In response 
to Invenergy's request that transmission providers should provide 
detailed evaluation reports on why an alternative transmission 
technology was not selected, transmission providers are required to 
include an explanation of the results of the evaluation of the required 
alternative transmission

[[Page 61235]]

technologies for feasibility, cost, and time savings as an alternative 
to a traditional network upgrade in the applicable study report. 
However, we do not direct any additional detailed requirements related 
to this reporting requirement because we find they are not needed or 
appropriate. We find the required explanation of the results of the 
transmission provider's evaluation included in the applicable study 
report provides sufficient transparency without placing a further 
burden on transmission providers that would delay the processing of 
interconnection requests.
    1591. Because we modify the NOPR proposal to require transmission 
providers to evaluate all the enumerated alternative transmission 
technologies in all instances, i.e., regardless of an interconnection 
customer requesting such an evaluation, we decline to adopt commenters' 
request to require transmission providers to evaluate the required 
alternative transmission technologies by default with an ``opt-out'' 
option for interconnection customers. We are not persuaded that there 
are benefits to including an ``opt-out'' option in the requirement, and 
we find it would be overly burdensome and complex to require 
transmission providers to track and process interconnection customers' 
requests to ``opt-out'' of the evaluation of certain alternative 
transmission technologies. Further, an ``opt-out'' would run contrary 
to our goal to have transmission providers evaluate the enumerated 
technologies in order to achieve beneficial outcomes like decreasing 
network upgrade costs, withdrawals, and restudies, thereby increasing 
the efficiency of the interconnection process overall.
    1592. As discussed above, the enumerated alternative transmission 
technologies that transmission providers must evaluate in 
interconnection studies are: static synchronous compensators, static 
VAR compensators, synchronous condensers, advanced power flow control, 
transmission switching, voltage source converters, advanced conductors, 
and tower lifting. We discuss each technology in turn.
    1593. Regarding synchronous and static VAR compensators, we find 
that, in providing reactive power to the transmission system, such 
devices could reduce interconnection costs by providing the voltage 
support where needed for the new generation facility being 
interconnected to operate reliably, rather than building a traditional 
network upgrade to resolve the voltage support issues. This potentially 
results in lower cost network upgrades to interconnect new generating 
facilities. ISO-NE states that it already evaluates static synchronous 
compensators when evaluating interconnection requests.\3028\ Similarly, 
as Indicated PJM TOs attest, PJM already considers static synchronous 
compensators in its interconnection and transmission planning 
processes.\3029\ Accordingly, we find that synchronous and static VAR 
compensators are appropriately included in the list of alternative 
transmission technologies enumerated in this final rule that 
transmission providers must evaluate in the interconnection process.
---------------------------------------------------------------------------

    \3028\ ISO-NE Initial Comments at 41.
    \3029\ Indicated PJM TOs Initial Comments at 57.
---------------------------------------------------------------------------

    1594. Regarding advanced power flow controls, we find that these 
devices allow power to be pushed and pulled to alternate lines with 
spare capacity leading to maximum utilization of transmission capacity 
and mitigation of overloads. Advanced power flow control devices can be 
scaled back as needed, providing an advantage over new lines or 
reconductors.\3030\ PacifiCorp attests that it often considers the use 
of advanced power flow control devices as potential alternatives to 
standard system infrastructure, and Indicated PJM TOs note that PJM and 
PJM transmission owners already consider the appropriateness of power 
flow control devices when conducting interconnection studies.\3031\ As 
discussed above, our decision to modify the NOPR proposal and require 
transmission providers to evaluate the enumerated alternative 
transmission technologies in all instances addresses Indicated PJM TOs' 
statement that evaluation of advanced power flow control devices in the 
interconnection process would significantly increase the complexity of 
interconnection studies and thus could cause delays in their 
completion.\3032\ We acknowledge the possibility that use of advanced 
power flow control devices can have impacts on line impedance which may 
result in issues in other parts of the system, as suggested by MISO. 
However, the requirement of this Final rule is merely that the 
transmission provider evaluate each alternative transmission 
technology, not that they deploy them in all circumstances. We 
appreciate, and expect, that if a transmission provider's evaluation 
demonstrates that deployment of advanced power flow control devices 
would create issues on the transmission provider's system as described 
by MISO, it will not select that advanced power flow control as the 
network upgrade.\3033\
---------------------------------------------------------------------------

    \3030\ AEE Initial Comments at 42.
    \3031\ PacifiCorp Initial Comments at 43; Indicated PJM TOs at 
57.
    \3032\ Supra P 1585.
    \3033\ See also infra P 1602.
---------------------------------------------------------------------------

    1595. We also retain transmission switching on the enumerated list 
of alternative technologies in this final rule. Transmission switching 
can be used to route energy around areas with high congestion and 
improve the overall transfer capability of the system, potentially 
resulting in lower network upgrade costs. In regard to PacifiCorp's 
argument that transmission switching is a complex process that can be 
implemented only under very particular factual scenarios and system 
conditions, transmission providers are already required to evaluate the 
impact of the proposed interconnection on the reliability of the 
transmission system \3034\ and thus should understand whether the 
factual scenarios and system conditions exist that would make a 
transmission switching solution appropriate. In response to Tri-State's 
question about whether transmission switching is meant to be a remedial 
action scheme or to create permanent normally open points on the 
system, this final rule does not prescribe how transmission providers 
deploy any of the enumerated alternative transmission technologies on 
their systems if they determine to use them. To Tri-State's concern 
that transmission switching solutions may be ``problematic in highly 
interconnected systems not operating in an RTO/ISO,'' we reiterate that 
transmission providers retain the discretion to determine whether to 
deploy any of the enumerated alternative transmission technologies, 
including transmission switching solutions.
---------------------------------------------------------------------------

    \3034\ See pro forma LGIP section 7.3; pro forma SGIP sections 
3.3.1, 3.4.1.
---------------------------------------------------------------------------

    1596. We find that the record supports including synchronous 
condensers and voltage source converters to the list because these 
technologies similarly may reduce interconnection costs in situations 
where voltage support is a constraint and where a new or modified 
transmission line with these technologies may provide a lower cost 
network upgrade option to interconnect new generating facilities. 
Specifically, ISO-NE states that it already evaluates synchronous 
condensers when evaluating interconnection requests,\3035\ and NARUC 
and Xcel urge the Commission to include evaluation of synchronous 
condensers and voltage

[[Page 61236]]

source converters in the interconnection process.\3036\
---------------------------------------------------------------------------

    \3035\ ISO-NE Initial Comments at 41.
    \3036\ NARUC Initial Comments at 39; Xcel Initial Comments at 
47.
---------------------------------------------------------------------------

    1597. We also add advanced conductors and tower lifting to the list 
of alternative transmission technologies enumerated in this final rule. 
We note the comments arguing that advanced conductors may be beneficial 
as network upgrades.\3037\ ACORE explains that deploying advanced 
conductors can significantly increase transmission capacity and allow 
for the interconnection of new generating facilities without the 
construction of new network upgrades.\3038\ Similarly, we find that 
tower lifting has the potential to increase transmission line ratings 
by providing additional clearance from the ground.\3039\ By increasing 
transmission line ratings, there will be more ``headroom'' on the 
system to address normal and contingency conditions identified in 
interconnection studies, and likely a reduced need for network 
upgrades.\3040\ Given these potential benefits to interconnection 
customers, we require transmission providers to evaluate advanced 
conductors and tower lifting in the interconnection process.
---------------------------------------------------------------------------

    \3037\ ACORE Initial Comments at 6-7; CTC Global Initial 
Comments at 6-9; VEIR Initial Comments at 5-6.
    \3038\ ACORE Initial Comments at 7 (citing Jay Caspary and Jesse 
Schneider, Grid Strategies, LLC, Opportunities to Use Advanced 
Conductors to Accelerate Grid Decarbonization, at 2 (Feb. 2022), 
https://acore.org/wp-content/uploads/2022/03/AdvancedConductorstoAccelerateGridDecarbonization.pdf).
    \3039\ See Ampjack Initial Comments at 4. As with other network 
upgrades, we note that tower lifting may require a modification to a 
certificate of public convenience and necessity (CPCN) or similar 
permit issued by a state utility regulator, which may include tower 
height limits or other physical restrictions. To the extent the 
transmission provider considers potential delays or the possibility 
of not receiving such a state CPCN modification when evaluating 
potential network upgrades, it should include a similar 
consideration in its evaluation of alternative transmission 
technologies.
    \3040\ See id. at 1, 4.
---------------------------------------------------------------------------

    1598. We remove dynamic line ratings from the list of enumerated 
alternative transmission technologies proposed in the NOPR. We agree 
with commenters that the technology may be less beneficial in the 
interconnection context than in the transmission operations and 
planning context because, for example, dynamic line ratings' ability to 
increase the available interconnection service depends on favorable 
weather and congestion parameters.\3041\ That is, while dynamic line 
ratings may relieve congestion to increase available interconnection 
service temporarily or in the short-term, they may not be an adequate 
substitute for building interconnection facilities and/or traditional 
network upgrades identified through the interconnection study process 
that are needed to reliably interconnect a generating facility to the 
transmission system during all hours.
---------------------------------------------------------------------------

    \3041\ Indicated PJM TOs Initial Comments at 56; ISO-NE Initial 
Comments at 41; NYTOs Initial Comments at 32-33; PacifiCorp Initial 
Comments at 44; Tri-State Initial Comments at 23; U.S. Chamber of 
Commerce Initial Comments at 12-13.
---------------------------------------------------------------------------

    1599. We decline to add storage that performs a transmission 
function to the list of alternative transmission technologies 
enumerated in this final rule. The Commission has determined that the 
evaluation of whether a storage resource performs a transmission 
function requires a case-by-case analysis of either how a particular 
storage resource would be operated or the requirements set forth in a 
tariff governing selection of such storage resources. For example, in 
approving SPP's proposal to establish a framework under which an 
electric storage resource may be considered a transmission asset 
(thereby making the selected storage resources eligible for cost-based 
rate recovery through transmission rates), the Commission identified 
five considerations that, together, ensure that a selected storage 
resource will serve a transmission function.\3042\
---------------------------------------------------------------------------

    \3042\ Sw. Power Pool, Inc., 183 FERC ] 61,153, at P 29 (2023).
---------------------------------------------------------------------------

    1600. We clarify that transmission providers are not precluded from 
studying a technology that is not included in the enumerated list of 
alternative transmission technologies. Under the modified requirement, 
transmission providers must evaluate the enumerated alternative 
transmission technologies in all instances, but we are not precluding a 
transmission provider from studying or evaluating any other technology, 
including those such as dynamic line ratings that we have determined 
not to add to the list of technologies enumerated in this final rule. 
We acknowledge that certain transmission providers already evaluate in 
certain studies transmission technologies not included in the final 
rule list.\3043\ In addition, we clarify that, with respect to this 
final rule determination, transmission providers are not required to 
propose and justify on compliance any technology it studies in the 
interconnection process beyond those required in this final rule.
---------------------------------------------------------------------------

    \3043\ For example, PacifiCorp notes that it already considers 
advanced power flow technologies as potential alternatives to 
standard system infrastructure. PacifiCorp Initial Comments at 43.
---------------------------------------------------------------------------

    1601. In the NOPR, the Commission generally proposed a method to 
allocate the costs of cluster studies and the costs of network upgrades 
within a cluster through the interconnection study process.\3044\ With 
respect to study costs, the Commission sought comment on how costs 
incurred for evaluating alternative transmission technology study 
requests would be allocated among interconnection customers in the 
cluster under a NOPR proposal in which interconnection customers would 
identify and request particular technologies to be studied.\3045\ Given 
our modification to the NOPR proposal to require transmission providers 
to evaluate the enumerated alternative transmission technologies in the 
pro forma LGIP cluster study on behalf of the whole cluster, rather 
than upon an individual customer's request, we find that it is not 
necessary to consider alternative cost allocation methods for cluster 
study costs and network upgrade costs associated with the enumerated 
alternative transmission technologies. Specifically, we clarify that 
the allocation of cluster study costs for, and substation and system 
network upgrades associated with, the enumerated alternative 
transmission technologies must be consistent with the allocation of 
costs for cluster studies and associated substation and system network 
upgrades for any other network upgrades because the enumerated 
alternative transmission technologies located on the high-side of the 
point of interconnection would fall within the definition of substation 
and system network upgrades,\3046\ and they would be adopted only if 
they resolve system reliability issues triggered by an interconnection 
request. In other words, the enumerated alternative transmission 
technologies must be included among the set of options transmission 
providers consider when studying a cluster and any implemented 
enumerated alternative transmission technologies must receive the same 
cost treatment as any other option.
---------------------------------------------------------------------------

    \3044\ See NOPR, 179 FERC ] 61,194 at PP 82-83, 88-89.
    \3045\ Id. P 301.
    \3046\ Network Upgrades are ``the additions, modifications, and 
upgrades to the Transmission Provider's Transmission System required 
at or beyond the point at which the Interconnection Facilities 
connect to the Transmission Provider's Transmission System to 
accommodate the interconnection of the Large Generating Facility to 
the Transmission Provider's Transmission System.'' Pro forma LGIP 
section 1 (Definitions).
---------------------------------------------------------------------------

    1602. Accordingly, the cost allocation concerns raised by several 
commenters in response to the NOPR proposal are now unfounded.\3047\ 
Regarding MISO's concern that some alternative transmission 
technologies may shift the burden of system impacts to other

[[Page 61237]]

parties,\3048\ we find that the possibility of this burden shifting is 
minimal because the revised pro forma LGIP, as adopted in this final 
rule, requires transmission providers to evaluate the enumerated 
alternative transmission technologies on a cluster-wide basis for 
feasibility, cost, and time savings. We recognize that, after the 
transmission provider evaluates the enumerated alternative transmission 
technologies, the transmission provider, in its sole discretion, may 
still decide to remedy an identified reliability problem with a 
traditional network upgrade.
---------------------------------------------------------------------------

    \3047\ AEP Initial Comments at 52-53; Ameren Initial Comments at 
32; NextEra Initial Comments at 38; and Tri-State Initial Comments 
at 23.
    \3048\ MISO Initial Comments at 122.
---------------------------------------------------------------------------

    1603. Regarding cost treatment for the enumerated alternative 
transmission technologies in the pro forma SGIP, the Commission did not 
propose to require, and this final rule does not adopt, cluster studies 
for small generator interconnection requests. Accordingly, the study 
process for small generating facilities in the pro forma SGIP remains a 
serial process and costs for evaluating the enumerated alternative 
transmission technologies must be allocated to the small generator 
interconnection request being studied. Likewise, the costs for any 
implemented enumerated alternative transmission technologies must be 
allocated to a small generator interconnection customer consistent with 
the allocation of any other network upgrade costs in the small 
generator interconnection process.
    1604. As explained in section III.A.3 of this final rule, we are 
not requiring transmission providers to allocate study costs on a pro 
rata basis, as Fervo Energy requests. Because this final rule does not 
adopt the NOPR proposal for interconnection customers to request the 
study of particular technologies, we need not address the arguments 
raised by NARUC and Indicated PJM TOs related to the study costs 
associated with that unadopted proposal.
    1605. The Commission sought comment on whether transmission 
providers should be required to evaluate whether alternative 
transmission technologies can be deployed on a temporary basis to 
provide provisional interconnection service. We are not persuaded by 
arguments in favor of such a requirement. While we acknowledge 
commenters' arguments that alternative transmission technologies could 
serve as a temporary solution to reduce the overall costs and delays of 
generator interconnection, we agree with MISO that mandatory evaluation 
of alternative transmission technologies for provisional 
interconnection service could hinder ensuring that interconnection 
customers are able to interconnect in a reliable, efficient, 
transparent, and timely manner by adding burden and delay.\3049\
---------------------------------------------------------------------------

    \3049\ MISO Initial Comments at 124.
---------------------------------------------------------------------------

    1606. The Commission also sought comment on whether alternative 
transmission technologies as supplements for, or in the place of, 
traditional network upgrades was sufficient to guarantee a level of 
service to accommodate an interconnection customer seeking NRIS, or 
whether such a network upgrade could only relate to ERIS.\3050\ We 
agree with commenters that the enumerated alternative transmission 
technologies may enable NRIS, but such a determination will be 
dependent on the analysis by the particular transmission provider and 
the particular technology under evaluation. We decline to adopt Clean 
Energy Association's proposal that transmission providers be required 
to post additional information beyond the explanation of the results of 
the evaluation of each alternative transmission technology. As 
discussed above, transmission providers must include, in the applicable 
study report, an explanation of the results of the evaluation of the 
enumerated alternative transmission technologies for feasibility, cost, 
and time savings.
---------------------------------------------------------------------------

    \3050\ NOPR, 179 FERC ] 61,194 at P 301.
---------------------------------------------------------------------------

    1607. We find that the following commenters' proposals are outside 
the scope of this proceeding and, therefore, we do not address the 
substance: (1) requiring transmission providers to consider alternative 
transmission technologies in market operations at the request of the 
interconnection customer; \3051\ (2) adding language to the pro forma 
LGIA that would allow interconnection facilities to convert to 
distribution or regional transmission facilities; \3052\ and (3) 
requiring transmission providers to study and implement advanced 
transmission technologies when network upgrades are needed but cannot 
be completed within three years of being identified.\3053\
---------------------------------------------------------------------------

    \3051\ EDF Renewables Initial Comments at 14-15.
    \3052\ Enel Initial Comments at 80-81.
    \3053\ [Oslash]rsted Reply Comments at 8.
---------------------------------------------------------------------------

    1608. Because we adopt a requirement for transmission providers to 
evaluate the enumerated alternative transmission technologies, rather 
than at the request of the interconnection customer, we do not address 
comments regarding the following issues, which become moot by this 
modification to the NOPR proposal: the timing of submission of the 
alternative transmission technology evaluation request; \3054\ the 
burden of proof for a submission of an alternative transmission 
technology evaluation request; \3055\ whether there should be a limit 
on alternative transmission technology evaluation requests; \3056\ 
whether transmission providers and transmission owners should be able 
to reject alternative transmission technology evaluation requests; 
\3057\ whether an interconnection customer can request evaluation of an 
alternative transmission technology not on the required list; \3058\ 
and whether transmission providers need to perform a separate study for 
each requested alternative transmission technology.\3059\
---------------------------------------------------------------------------

    \3054\ Enel Initial Comments at 79; Invenergy Initial Comments 
at 55; see also EDF Renewables Initial Comments at 14-15; Fervo 
Energy Reply Comments at 9.
    \3055\ AECI Initial Comments at 9; NARUC Initial Comments at 40; 
ISO-NE Initial Comments at 41; NESCOE Reply Comments at 21.
    \3056\ EEI Initial Comments at 21.
    \3057\ Indicated PJM TOs Reply Comments at 17.
    \3058\ National Grid Initial Comments at 42.
    \3059\ NARUC Initial Comments at 40.
---------------------------------------------------------------------------

    1609. We do not find compelling commenters' request that the 
Commission not require the evaluation of alternative transmission 
technologies while other proceedings concerning grid enhancing 
technologies are pending.\3060\ The Commission proposed and received 
extensive comment on evaluation of alternative transmission 
technologies in the interconnection process. Based on the record, we 
find that it is appropriate for the Commission to adopt a modified NOPR 
proposal to require transmission providers to evaluate the required 
list of enumerated alternative transmission technologies.
---------------------------------------------------------------------------

    \3060\ EEI Initial Comments at 20; see also Ameren Initial 
Comments at 30.
---------------------------------------------------------------------------

b. Annual Informational Report
i. NOPR Proposal
    1610. In the NOPR, in order to add transparency to the evaluation 
process and deployment of alternative transmission technologies in 
generator interconnection processes, the Commission proposed to revise 
the pro forma LGIP and pro forma SGIP to require transmission providers 
to submit an annual informational report to the Commission that details 
whether, and if so how, advanced power flow control, transmission 
switching, dynamic line ratings, static synchronous compensators, and 
static VAR compensators were considered in interconnection requests 
over the last year.\3061\ The Commission proposed to create a new 
docket to collect all annual informational report filings, and proposed 
that any informational reports that transmission providers file at the 
Commission would be for informational

[[Page 61238]]

purposes and would neither be formally noticed nor require additional 
action by the Commission. The Commission sought comment on: (1) whether 
to require transmission providers to explain why an alternative 
transmission technology that was considered was not deployed; and (2) 
the scope of the annual informational report, and whether additional 
information should be included.
---------------------------------------------------------------------------

    \3061\ NOPR, 179 FERC ] 61,194 at P 302.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1611. A broad group of commenters support the NOPR proposal.\3062\ 
Many commenters agree that the reports would be beneficial to 
interconnection customers because they would provide insight as to why 
alternative transmission technologies were or were not deployed.\3063\ 
Some commenters contend that the annual informational report will allow 
interconnection customers to better tailor their requests to consider 
alternative transmission technologies, such that those requests are 
most likely to be successful.\3064\ Similarly, commenters argue that 
the annual informational reports would allow sharing of best practices 
in the industry on the use of these technologies and their evaluation, 
and would lessen concerns over the potential risks of new technologies 
by socializing examples of their consideration and 
implementation.\3065\ ELCON and Fervo Energy assert that the annual 
informational reports will provide interconnection customers with 
additional information to ascertain the feasibility of certain 
configurations and interconnection points.\3066\
---------------------------------------------------------------------------

    \3062\ APPA-LPPC Initial Comments at 32; Clean Energy Buyers 
Initial Comments at 5; ELCON Initial Comments at 8; Enel Initial 
Comments at 81; Eversource Initial Comments at 37-38; CTC Global 
Initial Comments at 13; NARUC Initial Comments at 41; Pine Gate 
Initial Comments at 59; Public Interest Organizations Initial 
Comments at 55; SEIA Initial Comments at 41; WATT Coalition Initial 
Comments at 3.
    \3063\ NARUC Initial Comments at 41; Pine Gate Initial Comments 
at 59.
    \3064\ Pine Gate Initial Comments at 59.
    \3065\ CTC Global Initial Comments at 13; Eversource Initial 
Comments at 37-38.
    \3066\ ELCON Initial Comments at 8; Fervo Energy Reply Comments 
at 9-10.
---------------------------------------------------------------------------

    1612. Additionally, Enel states that transmission providers can be 
resistant to using advanced transmission technologies, and the annual 
informational report will allow the Commission to evaluate whether a 
transmission provider is artificially restricting the use of advanced 
transmission technologies, similar to the study completion metrics 
required by the Commission in Order No. 845.\3067\ Some commenters 
argue that if the Commission observes that transmission providers are 
routinely citing certain technical or other reasons for not deploying 
certain technologies, the annual informational report will provide a 
record from which it can initiate action in a separate proceeding to 
remedy the issue.\3068\
---------------------------------------------------------------------------

    \3067\ Enel Initial Comments at 81.
    \3068\ CTC Global Initial Comments at 13; Pine Gate Initial 
Comments at 59.
---------------------------------------------------------------------------

    1613. Several commenters argue in support of the annual 
informational report to promote transparency between market 
participants, interconnection customers, and regulators.\3069\ Lastly, 
commenters argue that the additional work and obligation for the annual 
informational report would be an effective use of limited resources to 
benefit the efficiency, transparency, and modernization of the 
interconnection process.\3070\
---------------------------------------------------------------------------

    \3069\ Eversource Initial Comments at 37-38; NARUC Initial 
Comments at 41.
    \3070\ Enel Initial Comments at 81; Eversource Initial Comments 
at 37-38.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1614. Some commenters oppose the proposal on the basis that it 
would be too burdensome.\3071\ Xcel Energy does not believe annual 
informational reports are necessary and requests that any informational 
reporting requirements be limited to decrease the burden on the 
engineers that need to focus on performing the interconnection 
studies.\3072\ PacifiCorp states that imposing an additional reporting 
obligation on transmission providers would not only be duplicative, but 
it would add to an already significant list of administrative tasks 
that transmission providers must undertake to comply with existing, and 
proposed, interconnection obligations, without clear benefit.\3073\ 
NYTOs believe that preparing and submitting an annual informational 
report with detailed analysis of the consideration of alternative 
transmission technologies would require dedicated resources on the part 
of the transmission provider.\3074\ MISO asserts that the annual 
informational report at this time may not be useful, especially in the 
already transparent RTO/ISO context, and could divert scarce staff 
resources from the work of moving forward in the study and agreements 
process for implementing much-needed new generation.\3075\ Similarly, 
Indicated PJM TOs state that PJM currently maintains a publicly 
available website that details all the types of network upgrades 
necessary to support interconnections, including the types of devices 
identified here by the Commission.\3076\ CAISO also opposes the 
proposal because CAISO believes that it is contrary to the goal of 
reducing interconnection queue backlogs by adding more studies and 
reporting requirements onto transmission provider staff.\3077\
---------------------------------------------------------------------------

    \3071\ Ameren Initial Comments at 33; CAISO Initial Comments at 
39; MISO Initial Comments at 125; NYTOs Initial Comments at 33; 
PacifiCorp Initial Comments at 44; Xcel Initial Comments at 48.
    \3072\ Xcel Initial Comments at 48.
    \3073\ PacifiCorp Initial Comments at 44.
    \3074\ NYTOs Initial Comments at 33.
    \3075\ MISO Initial Comments at 125; MISO Reply Comments at 18.
    \3076\ Indicated PJM TOs Initial Comments at 57-58.
    \3077\ CAISO Initial Comments at 38.
---------------------------------------------------------------------------

    1615. Idaho Power believes that the report may simply result in 
more disputes over why one entity allows a particular technology, while 
another one does not.\3078\
---------------------------------------------------------------------------

    \3078\ Idaho Power Initial Comments at 16.
---------------------------------------------------------------------------

    1616. CAISO and MISO also argue that there is limited value to 
interconnection reports.\3079\ CAISO argues that in this NOPR, the 
Commission recognizes that imposing reporting requirements in Order No. 
845 failed to incentivize transmission providers to meet their study 
obligations, and thus the Commission should not repeat that mistake 
here by burdening transmission provider staff with yet another 
reporting requirement.\3080\ Similarly, MISO points out that neither 
the Commission nor any commenter used the interconnection queue reports 
required by Order No. 845 to discuss the topic of study delays.\3081\
---------------------------------------------------------------------------

    \3079\ CAISO Initial Comments at 39; MISO Reply Comments at 18-
19.
    \3080\ CAISO Initial Comments at 39.
    \3081\ MISO Reply Comments at 18-19.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
    1617. Several commenters emphasize the importance of transparency 
when an alternative transmission technology is not selected.\3082\ 
ENGIE asks the Commission to require transmission providers to provide 
publicly available information addressing why or why not an alternative 
transmission technology was adopted or rejected in a specific 
case.\3083\ CTC Global believes that transmission providers should be 
required to include explanations regarding the alternative transmission 
technologies considered, deployed, or rejected in the annual 
reports.\3084\ CTC

[[Page 61239]]

Global requests that the Commission also mandate reporting on the 
energy efficiency of the components used in various network upgrades 
and through the interconnection process.\3085\ Eversource suggests 
that, in addition to the five technologies listed in the NOPR, 
transmission providers be allowed to provide reporting on any other 
grid enhancing technology or alternative transmission technology that 
was considered during the prior year.\3086\
---------------------------------------------------------------------------

    \3082\ CTC Global Initial Comments at 14, 17-18; ENGIE Initial 
Comments at 13; Eversource Initial Comments at 37-38; Fervo Energy 
Initial Comments at 7.
    \3083\ ENGIE Initial Comments at 13.
    \3084\ CTC Global Initial Comments at 17-18.
    \3085\ Id. at 14.
    \3086\ Eversource Initial Comments at 37-38.
---------------------------------------------------------------------------

    1618. In contrast, Ameren argues that, if the Commission imposes 
this reporting burden on transmission providers, it should not further 
exacerbate the burden by requiring the transmission provider to also 
report explanations of common obstacles to the use of these alternative 
transmission technologies.\3087\ Instead, Ameren states that the 
Commission should encourage interconnection customers and transmission 
providers to share with Commission staff through a technical conference 
or other forum the types of technologies being considered and whether 
adopted. Ameren suggests that this type of information gathering should 
be undertaken before the Commission imposes specific reforms or 
reporting requirements.
---------------------------------------------------------------------------

    \3087\ Ameren Initial Comments at 33.
---------------------------------------------------------------------------

iii. Commission Determination
    1619. We decline to adopt the NOPR proposal to require transmission 
providers to submit an annual informational report to the Commission 
that details whether, and if so how, the list of alternative 
transmission technologies were considered in interconnection studies 
over the last year. We are persuaded by commenters' arguments that the 
time and resources required to produce the annual informational report 
may hinder the ability to increase the speed of interconnection queue 
processing.\3088\ We find that these challenges outweigh the 
incremental increased transparency to the evaluation process and 
deployment of alternative transmission technologies in generator 
interconnection processes, particularly in light of additional 
reporting requirements in other parts of this final rule.
---------------------------------------------------------------------------

    \3088\ MISO Initial Comments at 125; MISO Reply Comments at 18; 
NYTOs Initial Comments at 33; PacifiCorp Initial Comments at 44; 
Xcel Initial Comments at 48.
---------------------------------------------------------------------------

    1620. Specifically, the annual informational report would be 
duplicative of the requirement in section 7.3 of the pro forma LGIP and 
sections 3.3.6 and 3.4.10 of the pro forma SGIP that we adopt in this 
final rule. Under these provisions, transmission providers must explain 
how the required alternative transmission technologies were evaluated 
for feasibility, cost, and time savings in each pro forma LGIP cluster 
study report or pro forma SGIP feasibility study and system impact 
study reports. The description of the results of the evaluation 
required in these reports should provide transparency into the 
evaluation process and deployment of alternative transmission 
technologies in generator interconnection processes. In response to 
Enel's argument that an annual informational report will allow the 
Commission to evaluate if a transmission provider is artificially 
restricting the use of alternative transmission technologies, we find 
that this concern is adequately addressed through the modified 
requirement that transmission providers evaluate all required 
alternative transmission technologies by default in all studies and 
restudies.
3. Modeling and Ride-Through Requirements for Non-Synchronous 
Generating Facilities
a. Modeling Requirements
i. Need for Reform and NOPR Proposal
    1621. In the NOPR, the Commission preliminarily found that the pro 
forma LGIP and pro forma SGIP may be unduly discriminatory or 
preferential to the extent that they do not require non-synchronous 
generating facilities to provide accurate and validated models to 
transmission providers during the generator interconnection 
process.\3089\ Specifically, the Commission noted that, while 
Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2 of 
the pro forma SGIP require all generating facilities to submit certain 
types of information, the information required is only sufficient to 
accurately model the behavior of synchronous generating facilities. The 
Commission stated its concern that, without a reform to require 
interconnection customers developing non-synchronous generating 
facilities \3090\ to provide sufficiently accurate and validated 
models, interconnection studies may not identify the appropriate 
interconnection facilities and network upgrades, which could lead to 
unjust and unreasonable rates for interconnection service.\3091\
---------------------------------------------------------------------------

    \3089\ NOPR, 179 FERC ] 61,194 at P 318.
    \3090\ Non-synchronous generating facilities are ``connected to 
the bulk power system through power electronics, but do not produce 
power at system frequency (60 Hz).'' They ``do not operate in the 
same way as traditional generators and respond differently to 
network disturbances.'' Reactive Power Requirements for Non-
Synchronous Generation, Order No. 827, 81 FR 40793 (June 23, 2016), 
155 FERC ] 61,277, at P 10 n.24 (2016).
    \3091\ NOPR, 179 FERC ] 61,194 at P 319.
---------------------------------------------------------------------------

    1622. The Commission proposed to revise Attachment A to Appendix 1 
of the pro forma LGIP and Attachment 2 of the pro forma SGIP to ensure 
that all interconnection customers requesting to interconnect a non-
synchronous generating facility must provide the transmission provider 
with the models needed for accurate interconnection studies.\3092\ 
Pursuant to this proposal, interconnection customers requesting to 
interconnect a non-synchronous generating facility would be required to 
provide models that contain the details necessary to accurately model 
the performance of the generating facility in response to system 
disturbances in accordance with the control system settings that would 
be used by the interconnection customer during the commissioning and 
operation of the generating facility.
---------------------------------------------------------------------------

    \3092\ Id. P 328.
---------------------------------------------------------------------------

    1623. Specifically, the Commission proposed to require each 
interconnection customer requesting to interconnect a non-synchronous 
generating facility to submit to the transmission provider: (1) a 
validated, user-defined root mean square (RMS) positive sequence 
dynamic model; (2) an appropriately parameterized, generic library RMS 
positive sequence dynamic model, including a model block diagram of the 
inverter control system and plant control system, that corresponds to a 
model listed in a new table of acceptable models or a model otherwise 
approved by WECC; and (3) a validated EMT model, if the transmission 
provider performs an EMT study as part of the interconnection study 
process.\3093\
---------------------------------------------------------------------------

    \3093\ Id. P 329.
---------------------------------------------------------------------------

    1624. With regard to the validated, user-defined RMS positive 
sequence dynamic model, the Commission proposed to define a user-
defined model as any set of programming code created by equipment 
manufacturers or developers that captures the latest features of 
controllers that are mainly software-based and represents the entities' 
control strategies but does not necessarily correspond to any 
particular generic library model.\3094\ The Commission explained that 
in order for this model to be ``validated,'' it must be confirmed that 
the equipment behavior is consistent with the model behavior, and 
described how the interconnection customer may make such confirmation.
---------------------------------------------------------------------------

    \3094\ Id. P 330.

---------------------------------------------------------------------------

[[Page 61240]]

    1625. With regard to the appropriately parameterized, generic 
library RMS positive sequence dynamic model, the Commission proposed a 
table of acceptable generic library models based on the current WECC 
list of approved dynamic models for renewable energy generating 
facilities.\3095\ The Commission noted that WECC's list of approved 
dynamic models has also been integrated into NERC reliability 
guidelines and that these models represent the current state of the art 
with regard to dynamic modeling requirements for non-synchronous 
generating facilities.
---------------------------------------------------------------------------

    \3095\ Id. P 331.
---------------------------------------------------------------------------

    1626. The Commission stated that it believed that these models 
represent the full spectrum of modeling data that transmission 
providers need to perform accurate interconnection studies for non-
synchronous generating facilities.\3096\ The Commission also recognized 
that the modeling data proposed to be required from non-synchronous 
generating facilities may be more voluminous than that required of 
synchronous generating facilities; however, the Commission noted that 
this data submission requirement is intended to result in a comparable 
level of modeling accuracy among all generating facilities.
---------------------------------------------------------------------------

    \3096\ Id. P 332.
---------------------------------------------------------------------------

    1627. The Commission stated that an interconnection customer's 
failure to provide the above information within the deadlines 
established in the pro forma LGIP and pro forma SGIP would make the 
interconnection request incomplete and would be considered invalid in 
accordance with section 3.4.3 of the pro forma LGIP and section 1.3 of 
the pro forma SGIP.\3097\ Pursuant to those provisions, if the 
interconnection customer does not cure the deficiency within the 10-
business day cure period, the interconnection request will be 
considered withdrawn pursuant to section 3.7 of the pro forma LGIP and 
section 1.3 of the pro forma SGIP. The Commission also proposed to 
require that any proposed modification of the interconnection request 
be accompanied by updated models of the proposed generating 
facility.\3098\
---------------------------------------------------------------------------

    \3097\ Id. P 333.
    \3098\ Id. P 334.
---------------------------------------------------------------------------

    1628. The Commission sought comment on: (1) whether the proposed 
reforms are necessary and/or sufficient to ensure that interconnection 
customers proposing non-synchronous generating facilities would submit 
models during the generator interconnection process that accurately 
reflect the behavior of their proposed generating facility; (2) whether 
the inclusion of the table based on NERC guidelines that cite WECC-
approved models is appropriate; and (3) if not, how the Commission 
could require interconnection customers to submit models that are 
widely known in industry to be accurate without listing specific 
models.\3099\
---------------------------------------------------------------------------

    \3099\ Id. P 335.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1629. Many commenters support the NOPR proposal.\3100\ SPP states 
that it has the highest penetration of IBRs \3101\ of any RTO/ISO, so 
it is particularly sensitive to potential harm that could occur if 
those resources fail to perform as expected.\3102\ ISO-NE argues that 
data issues are one of the largest causes of study delays in its 
region, and requiring data accuracy will improve study processing time 
and support first-ready, first-served reforms.\3103\ NERC contends that 
the existing interconnection process does not provide sufficiently 
accurate and validated models for IBRs.\3104\
---------------------------------------------------------------------------

    \3100\ AEP Initial Comments at 54; APPA-LPPC Initial Comments at 
33; APS Initial Comments at 24; CAISO Initial Comments at 39; Clean 
Energy Associations Initial Comments at 65; EEI Initial Comments at 
23; NERC Initial Comments at 9-10; EPRI Initial Comments at 19; 
Eversource Initial Comment at 38; ISO-NE Initial Comments at 42; 
MISO Initial Comments at 125; MISO TOs Initial Comments at 33; NARUC 
Initial Comments at 42; National Grid Initial Comments at 44; North 
Carolina Commission and Staff Initial Comments at 27; NRECA Initial 
Comments at 48; NYTOs Initial Comments at 33; Ohio Commission 
Initial Comments at 17; OMS Initial Comments at 20; PacifiCorp 
Initial Comments at 45; PPL Initial Comments at 25; R Street Initial 
Comments at 17; SPP Initial Comments at 27; U.S. Chamber of Commerce 
Initial Comments at 13.
    \3101\ ``Inverter-based resource'' (IBR) refers to a resource 
that is asynchronously connected to the transmission system and is 
either completely or partially interfaced with the bulk power system 
through power electronics. See Reliability Guideline: BPS-Connected 
Inverter-Based Resource Performance, at vii, https://www.nerc.com/comm/RSTC_Reliability_Guidelines/Inverter-Based_Resource_Performance_Guideline.pdf. The term ``non-synchronous 
generating facilities'' refers to the same resources.
    \3102\ SPP Initial Comments at 27.
    \3103\ ISO-NE Initial Comments at 42.
    \3104\ NERC Initial Comments at 18.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1630. Several commenters oppose the NOPR proposal in its 
entirety,\3105\ while additional commenters express concerns about 
specific aspects. Pine Gate asserts that the Commission should not 
incorporate requirements into the pro forma LGIP and pro forma SGIP 
that are already being addressed by NERC through the standards 
development process.\3106\ Pine Gate states that the pro forma LGIA and 
pro forma SGIA require interconnection customers to remain compliant 
with the applicable reliability standards, and recommends that the 
Commission address these modeling and performance reforms under the 
generic statement regarding compliance with applicable NERC Reliability 
Standards or by adding a similar statement in each applicable section 
of article 9 in the pro forma LGIA.\3107\
---------------------------------------------------------------------------

    \3105\ ENGIE Initial Comment at 13-14; NYISO Initial Comments at 
53-54; Pine Gate Initial Comments at 60-61; SEIA Initial Comments at 
41.
    \3106\ Pine Gate Initial Comments at 60.
    \3107\ Id. at 60-61 (citing pro forma LGIA art. 9.1).
---------------------------------------------------------------------------

    1631. NYISO argues that the final rule should not include a 
modeling requirement because it would be inefficient and necessitate a 
rebuild of NYISO's study base case.\3108\ NYISO explains that, if the 
NOPR proposal is adopted, its interconnection study analysis would take 
much longer to ensure accurate results, significantly slowing the 
interconnection process.
---------------------------------------------------------------------------

    \3108\ NYISO Initial Comments at 53-54.
---------------------------------------------------------------------------

    1632. ENGIE argues that the required models in the NOPR proposal 
are very detailed, there are few consultants that perform this 
modeling, and the value obtained is low because the study likely will 
become outdated as project components are substituted for more advanced 
technologies. ENGIE recommends requiring a power flow and dynamic 
model, which it contends provides sufficient information on reliability 
impacts.\3109\
---------------------------------------------------------------------------

    \3109\ ENGIE Initial Comments at 13-14.
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) Cure Period for Modeling Information
    1633. AES asserts that a 10-day cure period for interconnection 
customers to correct or provide additional information on models for 
non-synchronous generating facilities is not adequate and that no less 
than a 20 business-day cure period is needed.\3110\
---------------------------------------------------------------------------

    \3110\ AES Initial Comments at 25-26.
---------------------------------------------------------------------------

(2) Transmission Provider Requirements
    1634. SEIA requests that the Commission modify the NOPR proposal to 
require transmission providers to make available to interconnection 
customers the necessary system data needed to create accurate models, 
provide clear modeling requirements and validation guidelines and 
procedures,\3111\ and engage stakeholders before making any modeling 
changes.
---------------------------------------------------------------------------

    \3111\ SEIA Initial Comments at 42-43 (citing, e.g., CAISO, 
Electromagnetic Transient Modeling Requirements (Apr. 14, 2021), 
http://www.caiso.com/Documents/CaliforniaISOElectromagneticTransientModelingRequirements.pdf.).

---------------------------------------------------------------------------

[[Page 61241]]

(3) Models Not Available Early in Interconnection Study Process
    1635. Multiple commenters argue that accurate models for non-
synchronous generating facilities may not be available early in the 
interconnection study process and may need to be updated during the 
process.\3112\ Pine Gate and Public Interest Organizations assert that 
the Commission should revise the NOPR proposal to allow for later 
submission of such models to reduce the administrative burden on 
transmission providers and interconnection customers.\3113\
---------------------------------------------------------------------------

    \3112\ Alliant Energy Initial Comments at 10-11; Clean Energy 
Associations Initial Comments at 66; EPRI Initial Comments at 17-18; 
NextEra Initial Comments at 40; [Oslash]rsted Initial Comments at 
17; Pine Gate Initial Comments at 61; PPL Initial Comments at 25; 
Public Interest Organizations Reply Comments at 13; SEIA Initial 
Comments at 42.
    \3113\ Pine Gate Initial Comments at 61; Public Interest 
Organizations Reply Comments at 13.
---------------------------------------------------------------------------

    1636. SEIA requests that the Commission modify the NOPR proposal to 
require interconnection customers to provide all operating models 
within one year before the commercial operation date of the generating 
facility, so that the models reflect the most accurate operating 
information.\3114\ Clean Energy Associations assert that models 
requested very early in the interconnection study process, before 
product feature details have been finalized, may need to be updated 
prior to commercial operation, and argue that minor model changes 
should not result in excessive triggering of material modification 
rules.\3115\
---------------------------------------------------------------------------

    \3114\ SEIA Initial Comments at 42.
    \3115\ Clean Energy Associations Initial Comments at 66.
---------------------------------------------------------------------------

    1637. Alliant Energy and PPL state that technical information 
provided at the time an interconnection request is submitted can become 
outdated during the interconnection study process,\3116\ and Alliant 
Energy asserts that the Commission should therefore provide for 
flexibility as to when and how required information for modeling 
requirements is provided.\3117\ [Oslash]rsted argues that offshore wind 
interconnection customers may not be able to provide a validated model 
at the time of the interconnection request due to long lead times in 
generating facility development and equipment that is still being 
developed.\3118\
---------------------------------------------------------------------------

    \3116\ Alliant Energy Initial Comments at 10-11; PPL Initial 
Comments at 25.
    \3117\ Alliant Energy Initial Comments at 10-11.
    \3118\ [Oslash]rsted Initial Comments at 17.
---------------------------------------------------------------------------

    1638. EPRI suggests that an alternative approach to the NOPR 
proposal is to require the use of models that generally conform to the 
capability and performance standards Institute of Electrical and 
Electronics Engineers (IEEE) Standard 2800-022 and IEEE Standard 1547-
2018 during the interconnection study process, and notes that such 
studies are subject to further assessment once a detailed, site-
specific model is available.\3119\
---------------------------------------------------------------------------

    \3119\ EPRI Initial Comments at 18.
---------------------------------------------------------------------------

(4) RMS Models
    1639. Several commenters request modifications to the proposed 
requirements for RMS models.\3120\ Tesla and SEIA argue that the 
Commission should require transmission providers to accept user-defined 
library RMS positive sequence dynamics models, as these models better 
reflect the actual technology intended to be used by the resource, 
results in a much greater degree of modeling accuracy, and can help 
support greater penetration of renewable resources.\3121\ In addition, 
Tesla suggests that the Commission seek informational submissions from 
transmission providers regarding software tools and resources needed to 
integrate more accurate user-defined RMS modeling. Clean Energy 
Associations argue that the transmission provider should have 
discretion to require a user-defined RMS model, a generic library RMS 
model (with site-specific parameterization), or both, instead of always 
being required to collect both.\3122\ MISO encourages the Commission to 
require that the user-defined model be compatible with the transmission 
provider's software.\3123\ Further, MISO requests that the Commission 
confirm that the user-defined model meets the transmission provider's 
MOD-032-1 requirements. Longroad Energy recommends that the Commission 
require NERC to improve the degree to which power flow software vendors 
allow accurate modeling of IBR technology before the Commission 
establishes modeling standards that might stifle technological 
improvements.\3124\
---------------------------------------------------------------------------

    \3120\ Clean Energy Associations Initial Comments at 65-66; 
Eversource Initial Comments at 39; ISO-NE Initial Comments at 42-43; 
MISO Initial Comments at 125; SEIA Initial Comments at 43; Tesla 
Initial Comments at 11.
    \3121\ SEIA Initial Comments at 43; Tesla Initial Comments at 
11.
    \3122\ Clean Energy Associations Initial Comments at 65-66.
    \3123\ MISO Initial Comments at 125.
    \3124\ Longroad Energy Reply Comments at 20.
---------------------------------------------------------------------------

    1640. Other commenters express concern with the difficulties of 
user-defined models.\3125\ Eversource requests that the Commission 
specify that all positive sequence models provided must be non-
proprietary and accessible to neighboring utilities, system operators, 
and other entities that need to access them.\3126\ ISO-NE asserts that 
it does not accept user-defined models under its interconnection study 
procedures and requests that the final rule allow for a process where 
accurate, working, non-proprietary models are provided and screened in 
advance of the study process.\3127\
---------------------------------------------------------------------------

    \3125\ Eversource Initial Comments at 39; ISO-NE Initial 
Comments at 42.
    \3126\ Eversource Initial Comments at 39.
    \3127\ ISO-NE Initial Comments at 43.
---------------------------------------------------------------------------

(5) Model Validation
    1641. Some commenters argue that the Commission should provide 
further direction regarding model validation requirements for non-
synchronous generating facilities.\3128\ NERC and SDG&E argue that 
reliability assessments indicate that model validation with actual 
installed equipment and a ``true-up'' of generator interconnection 
modeling would help ensure proper analysis and studies prior to 
commissioning.\3129\ NERC recommends that the Commission enhance the 
interconnection process by ensuring more rigorous plant commissioning, 
with both the interconnection customer and the transmission provider 
signing off on models used in studies as compared with actual installed 
equipment.\3130\ In addition, NERC asks the Commission to require 
transmission providers to conduct quality review of models before study 
and require interconnection customers to satisfy quality review 
milestones.\3131\
---------------------------------------------------------------------------

    \3128\ Clean Energy Associations Initial Comments at 66-67; NERC 
Initial Comments at 18-20; EPRI Initial Comments at 14-15; 
[Oslash]rsted Initial Comments at 16, 18; SDG&E Reply Comments at 3; 
Tesla Initial Comments at 10.
    \3129\ NERC Initial Comments at 18; SDG&E Reply Comments at 3.
    \3130\ NERC Initial Comments at 18.
    \3131\ Id. at 20.
---------------------------------------------------------------------------

    1642. Tesla argues that, in lieu of multiple attestations or test 
data, the Commission should develop an approach to validation that 
requires interconnection customers to submit ``model-to-model'' and 
``product-to-model'' benchmarking data for non-synchronous generating 
facilities.\3132\
---------------------------------------------------------------------------

    \3132\ Tesla Initial Comments at 10.
---------------------------------------------------------------------------

    1643. Clean Energy Associations assert that the Commission should 
add language that provides that the attestation required for model 
validation be the best available by the original equipment manufacturer 
at the time of model delivery.\3133\ In addition, Clean Energy 
Associations and [Oslash]rsted argue that the Commission should define 
the

[[Page 61242]]

phrase ``accurate and validated models.'' \3134\ Clean Energy 
Associations explain that it is common practice to submit an 
interconnection request with advanced, next-generation equipment that 
the manufacturer may still be developing, in which case the product and 
validated models may not be available at the time of the 
interconnection request, and request that the Commission allow 
transmission providers flexibility to accommodate such new equipment in 
their interconnection studies.\3135\
---------------------------------------------------------------------------

    \3133\ Clean Energy Associations Initial Comments at 66.
    \3134\ Id.; [Oslash]rsted Initial Comments at 16, 18.
    \3135\ Clean Energy Associations Initial Comments at 67.
---------------------------------------------------------------------------

    1644. Clean Energy Associations and [Oslash]rsted assert that, if 
accurate and validated models require a comparison with unit level 
factory tests, then this may not be feasible for offshore wind farms, 
especially if they are connecting with HVDC transmission 
technology.\3136\ They explain that these types of configurations are 
often project-specific and do not have a definition of a ``validated 
model.'' [Oslash]rsted also requests that the Commission explain why a 
``model block diagram of the inverter control system and plant control 
system'' is necessary given the availability of WECC model block 
diagrams in simulation tools.\3137\
---------------------------------------------------------------------------

    \3136\ Id. at 66-67; [Oslash]rsted Initial Comments at 16-17.
    \3137\ [Oslash]rsted Initial Comments at 18.
---------------------------------------------------------------------------

    1645. EPRI argues that the Commission should modify the language in 
the pro forma LGIA and pro forma SGIA to ensure that all models are 
validated and appropriately parameterized.\3138\ EPRI contends that the 
NOPR proposal fails to provide adequate directions and requirements 
with respect to model validation, testing, verification, and conformity 
assessment, as required during various stages of the interconnection 
process. EPRI asserts that a ``validated'' plant model would not be 
available during the interconnection study stage because validation of 
the plant model is not possible--within reasonable efforts--until after 
the commissioning and commercial operation of the generating facility. 
EPRI states that alternatives to this would be requiring generic models 
that are appropriately parametrized and conform to IEEE Standard 2800-
2022 requirements.
---------------------------------------------------------------------------

    \3138\ EPRI Initial Comments at 14-15.
---------------------------------------------------------------------------

(6) Table of Acceptable RMS Models
    1646. Several commenters agree that a table of acceptable RMS 
models based on NERC guidelines that cite WECC-approved models is 
appropriate.\3139\ Ameren asserts that the Commission should provide a 
table based on NERC guidelines that cite WECC-approved models as one 
but not the only example.\3140\ Shell agrees that a table based on NERC 
guidelines is appropriate as long as the functionality and proprietary 
controls are adequately reflected (e.g., mimic the actual inverter 
performance of manufacturers' models).\3141\ Shell explains that a 
generic model may not be able to support the operational 
characteristics of inverters. SPP states that, in its experience, some 
manufacturers do not support WECC-approved generic dynamics models and 
that having Commission support for more specific, detailed, and vetted 
modeling information requirements will be helpful to improve data 
quality and access.\3142\
---------------------------------------------------------------------------

    \3139\ Ameren Initial Comments at 34; Bonneville Initial 
Comments at 24; Shell Initial Comments, app. A, at vi; Tri-State 
Initial Comments at 24.
    \3140\ Ameren Initial Comments at 34.
    \3141\ Shell Initial Comments, app. A, at vi.
    \3142\ SPP Initial Comments at 28.
---------------------------------------------------------------------------

    1647. R Street and EPRI offer alternatives to a table based on NERC 
guidelines that cite WECC-approved models.\3143\ R Street argues that 
providing a list of models in the final rule is not prudent given the 
dynamic nature of the table, and that the list should instead be posted 
on relevant public industry websites, including those of NERC.\3144\ 
EPRI states that one alternative could be to include a reference and 
hyperlink to the NERC and WECC-approved models lists.\3145\ EPRI also 
suggests that if the Commission retains the table, it should consider 
revising the description of the DER_A model to add the word 
``aggregated'' to the description and also consider adding columns with 
the model names from other applicable software tools.
---------------------------------------------------------------------------

    \3143\ EPRI Initial Comments at 20; R Street Initial Comments at 
17.
    \3144\ R Street Initial Comments at 17.
    \3145\ EPRI Initial Comments at 20.
---------------------------------------------------------------------------

(7) EMT Modeling
    1648. NERC and EPRI support the EMT modeling proposal in the 
NOPR.\3146\ NERC recommends that all non-synchronous generating 
facilities perform EMT models prior to interconnection for 
consideration by transmission operators and planners.\3147\ NERC 
contends that event analysis underscores the value of EMT studies in 
helping manage reliability risks of the modern transmission system.
---------------------------------------------------------------------------

    \3146\ Id. at 15, 19; NERC Initial Comments at 21.
    \3147\ NERC Initial Comments at 21.
---------------------------------------------------------------------------

    1649. EPRI agrees that performing EMT studies should be at the 
discretion of the transmission provider.\3148\ However, EPRI recommends 
collecting validated and appropriately parametrized EMT models during 
the interconnection process regardless of whether the transmission 
provider performs an EMT study because an EMT study may become 
necessary in the future, and the interconnection stage is the best time 
to obtain models due to the close coordination between interconnection 
customers, consultants, equipment manufacturers, and generating 
facility designers. EPRI also suggests that an industry-accepted 
generic EMT model could be required in lieu of a validated EMT 
model.\3149\
---------------------------------------------------------------------------

    \3148\ EPRI Initial Comments at 19.
    \3149\ Id. at 15.
---------------------------------------------------------------------------

    1650. Clean Energy Associations argue that the Commission should 
require submission of an EMT model one year before the scheduled 
commercial operation date of the non-synchronous generating facility if 
the transmission provider performs an EMT study as part of the 
interconnection study process.\3150\ Clean Energy Associations assert 
that, if the Commission moves forward with a requirement for 
interconnection customers to provide EMT models, it should require the 
transmission provider and its consultants to protect these models with 
the highest degree of confidentiality because these models contain 
proprietary and highly commercially sensitive material that could pose 
a reliability risk if obtained by malicious actors.
---------------------------------------------------------------------------

    \3150\ Clean Energy Associations Initial Comments at 68-70.
---------------------------------------------------------------------------

    1651. Several commenters oppose the EMT modeling proposal.\3151\ 
AES contends that EMT modeling is not yet used widely in the industry 
and thus should not be adopted as a minimum standard.\3152\
---------------------------------------------------------------------------

    \3151\ AES Initial Comments at 26; Bonneville Initial Comments 
at 24; Invenergy Initial Comments at 57-58; Longroad Energy Reply 
Comments at 21; SEIA Initial Comments at 41-42.
    \3152\ AES Initial Comments at 26.
---------------------------------------------------------------------------

    1652. Longroad Energy argues that EMT studies are more expensive 
than transient stability studies, require highly specialized 
engineering experience to perform, and are limited to modeling a 
fraction of a transmission provider's transmission system.\3153\ 
Longroad Energy asserts that the Commission should continue to allow 
transmission providers the discretion to determine where such studies 
will meaningfully

[[Page 61243]]

impact the interconnection requirements for an interconnection request. 
Further, Longroad Energy asserts that the Commission should require 
transmission providers to publish studies demonstrating the need for 
EMT studies to prevent unnecessarily imposing a costly, time-consuming 
step in the interconnection study process.
---------------------------------------------------------------------------

    \3153\ Longroad Energy Reply Comments at 21.
---------------------------------------------------------------------------

    1653. SEIA asserts that EMT models are not yet industry standard 
models, require significant processing power compared to RMS models, 
and are not necessarily more accurate than RMS models.\3154\ Bonneville 
asserts that it has found that EMT modeling studies are rarely 
necessary, and therefore any requirement to provide EMT models or 
studies should be left to the transmission provider's discretion.\3155\
---------------------------------------------------------------------------

    \3154\ SEIA Initial Comments at 41-42 (citing Summary of the 
Joint Generator Interconnection Workshop, at 28 (Aug. 9-11, 2022), 
https://www.esig.energy/wp-content/uploads/2022/10/Joint-Generator-Workshop-Summary-1.pdf (Generator Interconnection Workshop 
Summary)).
    \3155\ Bonneville Initial Comments at 24.
---------------------------------------------------------------------------

(d) Requests for Clarification
    1654. Invenergy requests that the Commission clarify that, if a 
validated EMT model is unavailable at the time of submission of an 
interconnection request: (1) whether the interconnection request may 
proceed and provide a generic EMT model, if available; and (2) if a 
validated EMT model is determined to be necessary, whether the 
interconnection customer may submit this information by the time of 
cluster restudy, or as soon thereafter as it becomes available from the 
manufacturer.\3156\
---------------------------------------------------------------------------

    \3156\ Invenergy Initial Comments at 58.
---------------------------------------------------------------------------

    1655. APS requests clarity from the Commission on the process for 
curing deficiencies with respect to information provided by the 
interconnection customer, such as the number of times an 
interconnection customer is allowed to provide inaccurate data and cure 
deficiencies, before an interconnection request is deemed 
withdrawn.\3157\
---------------------------------------------------------------------------

    \3157\ APS Initial Comments at 24.
---------------------------------------------------------------------------

(e) Miscellaneous
    1656. ClearPath asserts that the Commission should consider how the 
NOPR proposal will align with technological advancements and supply 
chain challenges.\3158\ ClearPath explains that the average 
interconnection queue wait time is 3.7 years, which may present 
opportunities for interconnection customers to adopt newer, more 
advanced equipment after they enter the interconnection queue. 
ClearPath further explains that supply chain challenges may force an 
interconnection customer to change equipment procurement unexpectedly 
while in the interconnection queue, and requests that the Commission 
explain whether a change in equipment that necessitates submitting new 
models and data is considered a material modification.
---------------------------------------------------------------------------

    \3158\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------

    1657. Consumers Energy notes that NERC is currently in the 
interconnection data gathering process, potentially making inclusion of 
additional requirements within the rulemaking duplicative and 
recommends consistency between NERC and Commission interconnection 
improvement efforts.\3159\
---------------------------------------------------------------------------

    \3159\ Consumers Energy Initial Comments at 9.
---------------------------------------------------------------------------

    1658. EPRI states that the NOPR proposal does not specify 
information and data that the transmission providers may need to 
provide to the interconnection customer during the design stage (e.g., 
acceptable voltage ranges, protection details, short circuit levels, 
etc.).\3160\ EPRI asserts that the final rule could consider the list 
of data from Annex H of IEEE 2800-2022, which includes definitions that 
could help define the combined generating and storage service level MW 
of a generating facility referred to in the NOPR proposal, including 
the continuous rating, continuous absorption rating, and short-term 
rating for IBRs.
---------------------------------------------------------------------------

    \3160\ EPRI Initial Comments at 22.
---------------------------------------------------------------------------

iii. Commission Determination
    1659. We adopt the NOPR proposal to revise Attachment A to Appendix 
1 of the pro forma LGIP and Attachment 2 of the pro forma SGIP to 
require each interconnection customer requesting to interconnect a non-
synchronous generating facility to submit to the transmission provider: 
(1) a validated user-defined RMS positive sequence dynamic model; (2) 
an appropriately parameterized generic library RMS positive sequence 
dynamic model, including a model block diagram of the inverter control 
system and plant control system, that corresponds to a model listed in 
a new table of acceptable models or a model otherwise approved by WECC; 
and (3) a validated EMT model, if the transmission provider performs an 
EMT study as part of the interconnection study process.
    1660. We also adopt the NOPR proposals to: (1) define a user-
defined model as any set of programming code created by equipment 
manufacturers or developers that captures the latest features of 
controllers that are mainly software-based and represent the entities' 
control strategies but does not necessarily correspond to any 
particular generic library model, as contained in Attachment A to 
Appendix 1 of the pro forma LGIP and Attachment 2 of the pro forma 
SGIP; (2) revise Attachment A to Appendix 1 of the pro forma LGIP and 
Attachment 2 of the pro forma SGIP to add a table of acceptable generic 
library models, based on the current WECC list of approved dynamic 
models for renewable energy generating facilities; and (3) revise 
section 4.4.4 of the pro forma LGIP and section 1.4 of the pro forma 
SGIP to require that any proposed modification of the interconnection 
request be accompanied by updated models of the proposed generating 
facility.
    1661. Based on the record before us, we affirm the Commission's 
preliminary finding in the NOPR that the pro forma LGIP and pro forma 
SGIP are unduly discriminatory or preferential because they do not 
require non-synchronous generating facilities to provide accurate and 
validated models to transmission providers during the generator 
interconnection process that provide a comparable degree of accuracy as 
the models required of a synchronous generator. The current pro forma 
LGIP and pro forma SGIP provisions ensure that synchronous generating 
facilities are required to provide accurate, validated models to 
transmission providers during the generator interconnection process. 
However, the current pro forma LGIP and pro forma SGIP provisions are 
insufficient to ensure that non-synchronous generating facilities 
submit models with a comparable level of accuracy.
    1662. Additionally, we find that the lack of a requirement for non-
synchronous generating facilities to provide accurate and validated 
models to transmission providers in the pro forma LGIP and pro forma 
SGIP results in unjust and unreasonable rates. Accurate and validated 
models are necessary to minimize study delays and to ensure that 
transmission providers conduct accurate interconnection studies that 
identify the necessary interconnection facilities and network upgrades 
to accommodate the interconnection request. Data issues are commonly 
cited as a major source of study delays, which contributes to 
interconnection queue backlogs.\3161\ As described above, 
interconnection queue backlogs create uncertainty in the timing and 
cost of interconnecting to the transmission system and hinders the 
timely development of new generation.

[[Page 61244]]

Moreover, without accurate models, transmission providers cannot 
conduct accurate interconnection studies that identify the appropriate 
interconnection facilities and network upgrades, leading to the 
inaccurate assignment of interconnection costs and resulting in 
Commission-jurisdictional rates that are unjust and unreasonable.\3162\
---------------------------------------------------------------------------

    \3161\ See, e.g., ISO-NE Initial Comments at 42.
    \3162\ NARUC Initial Comments at 42; see also EEI Initial 
Comments at 23 (explaining that this requirement will improve 
transmission provider's ability to identify appropriate 
interconnection facilities and network upgrades for non-synchronous 
generating facilities); MISO TOs Initial Comments at 33 (stating 
that the current lack of accurate modeling means that transmission 
providers are unable to fully assess their ability to respond to 
system disturbances).
---------------------------------------------------------------------------

    1663. Furthermore, many commenters agree that this reform will help 
prevent potential reliability concerns if non-synchronous generating 
facilities do not perform when in service as modeled during the 
interconnection process.\3163\ For example, additional modeling 
requirements will significantly improve the accuracy of both 
interconnection and reliability studies as well as address concerns 
regarding non-synchronous generation disturbance events.\3164\
---------------------------------------------------------------------------

    \3163\ APS Initial Comments at 24; CAISO Initial Comments at 39-
40; Clean Energy Associations Initial Comments at 65; NERC Initial 
Comments at 9-10; Eversource Initial Comment at 38.
    \3164\ Eversource Initial Comment at 38.
---------------------------------------------------------------------------

    1664. NYISO argues that the final rule would be inefficient and 
necessitate a rebuild of NYISO's study base case, take longer to ensure 
accurate results, and significantly slow the interconnection 
process.\3165\ While we will not opine here on the NYISO-specific 
compliance with the final rule, we disagree that requiring accurate 
dynamic models of generating facilities will make the interconnection 
process take longer to ensure accurate results. To the contrary, we 
find here that a lack of accurate models is a major cause of study 
delays and contributes to interconnection study backlogs.
---------------------------------------------------------------------------

    \3165\ NYISO Initial Comments at 53-54.
---------------------------------------------------------------------------

    1665. The majority of commenters support the NOPR proposal.\3166\ 
We affirm that, consistent with this final rule, all interconnection 
customers requesting to interconnect a non-synchronous generating 
facility must provide the transmission provider with the required 
models needed for accurate interconnection studies. We find that the 
models required herein contain the details necessary to accurately 
model the performance of the non-synchronous generating facility in 
response to system disturbances, and we decline to adopt alternative 
model proposals put forth by commenters. This reform promotes a 
consistent approach among all generating facilities with respect to 
modeling, such that all interconnection customers are required to 
submit information sufficient to accurately model the behavior of their 
proposed generating facilities.
---------------------------------------------------------------------------

    \3166\ AEP Initial Comments at 54; APPA-LPPC Initial Comments at 
33; APS Initial Comments at 24; CAISO Initial Comments at 39; Clean 
Energy Associations Initial Comments at 65; EEI Initial Comments at 
23; NERC Initial Comments at 9-10; EPRI Initial Comments at 19; 
Eversource Initial Comments at 38; ISO-NE Initial Comments at 42; 
MISO Initial Comments at 125; MISO TOs Initial Comments at 33; NARUC 
Initial Comments at 42; National Grid Initial Comments at 44; North 
Carolina Commission and Staff Initial Comments at 27; NRECA Initial 
Comments at 48; NYTOs Initial Comments at 33; Ohio Commission 
Initial Comments at 17; OMS Initial Comments at 20; PacifiCorp 
Initial Comments at 45; PPL Initial Comments at 25; R Street Initial 
Comments at 17; SPP Initial Comments at 27; U.S. Chamber of Commerce 
Initial Comments at 13.
---------------------------------------------------------------------------

    1666. We decline to adopt AES's request for a 20-day cure period 
for model deficiencies.\3167\ Under the proposed provisions, if an 
interconnection customer fails to provide the required models above 
within the deadlines established in the pro forma LGIP and pro forma 
SGIP, its interconnection request will be incomplete and considered 
invalid in accordance with section 3.4.4 of the pro forma LGIP and 
section 1.3 of the pro forma SGIP. Pursuant to those provisions, if the 
interconnection customer does not cure such a deficiency within the 10-
business day cure period, the interconnection request will be 
considered withdrawn pursuant to section 3.7 of the pro forma LGIP and 
section 1.3 of the pro forma SGIP. In it its request, AES provides no 
explanation for why the 10-business day cure period is insufficient. 
Moreover, we believe that the existing 10-business day cure period 
should be consistently applied to all interconnection request 
deficiencies and that having an extended cure period for model 
deficiencies would potentially introduce delays in the interconnection 
process. We note that interconnection customers may submit their 
interconnection requests early in the customer request window, which 
will allow for more time to ensure their models are valid.
---------------------------------------------------------------------------

    \3167\ AES Initial Comments at 25-26.
---------------------------------------------------------------------------

    1667. We disagree with Pine Gate that the revisions to the pro 
forma LGIP and pro forma SGIP, as adopted, incorporate requirements 
into the pro forma LGIP and pro forma SGIP that are already being 
addressed by NERC through the standards development process.\3168\ We 
note that NERC supports the NOPR proposal and argues that the existing 
interconnection process does not provide sufficiently accurate and 
validated models for non-synchronous generating facilities to 
transmission providers.\3169\ We find that these modeling requirements 
are appropriately addressed in the interconnection context, where 
interconnection customers must provide information to a transmission 
provider for use in interconnection studies, and thus adopt the 
revisions in the pro forma LGIP and pro forma SGIP. In addition, the 
pro forma LGIA and pro forma SGIA revisions apply to a wide spectrum of 
generating facilities, including newly interconnecting generating 
facilities that are currently outside the bounds of NERC's 
jurisdiction.\3170\ As such, we find that this reform can holistically 
address the identified issues alongside the NERC standards; even if 
NERC is taking action, that need not prevent us from taking action 
here.
---------------------------------------------------------------------------

    \3168\ Pine Gate Initial Comments at 60.
    \3169\ NERC Initial Comments at 18.
    \3170\ But see Registration of Inverter-based Resources, 181 
FERC ] 61,124, at P 31, (2022) (``[W]e find it necessary to ensure 
that NERC register the owners and operators of those unregistered 
IBRs that, in the aggregate, have a material impact on Bulk-Power 
System reliability, to ensure those entities are subject to a 
relevant set of mandatory and enforceable Reliability Standard 
requirements.'').
---------------------------------------------------------------------------

    1668. We disagree with ENGIE that the value obtained from the 
models in the NOPR proposal is low because of the likelihood that the 
study will be outdated as project components are substituted with more 
advanced technology.\3171\ We recognize that the project components for 
non-synchronous generating facilities may change during the 
interconnection process. We find, however, that this does not diminish 
the value of a transmission provider receiving the identified 
information from interconnection customers requesting to interconnect a 
non-synchronous generating facility and receiving models that represent 
the best information interconnection customers have available about 
their proposed generating facilities because these models will ensure 
that the transmission provider can accurately model the impact of the 
proposed generating facility throughout the interconnection process. In 
addition, proposed section 4.4.4 of the pro forma LGIP and section 1.4 
of the pro forma SGIP require that any modification of the 
interconnection request be accompanied by updates to the models. 
Pursuant to these provisions, the models are required to be updated as 
project components are changed. Ensuring that the model of the proposed 
generating

[[Page 61245]]

facility is accurate throughout the interconnection study process will 
allow the interconnection customer to understand the actual, potential 
impact on their interconnection request of changing these project 
components as they are considering such technological advancements.
---------------------------------------------------------------------------

    \3171\ ENGIE Initial Comments at 13-14.
---------------------------------------------------------------------------

    1669. Similarly, we disagree with commenters that argue that 
accurate models for non-synchronous generating facilities may not be 
available early in the interconnection study process and may need to be 
updated during that process.\3172\ We find that the reforms we adopt 
herein are consistent with the principles behind other requirements in 
the pro forma LGIP and pro forma SGIP, namely those that set forth 
requirements for an interconnection request, including requirements 
that requests be viable and well-defined.\3173\ The requirement to 
submit accurate models also reduces the chance that a transmission 
provider would need to perform additional studies, in this case if an 
interconnection customer submits models that are inaccurate and those 
inaccuracies are not discovered until late in the interconnection 
process. In that instance, i.e., if model validation occurs at a point 
further into the interconnection process, inaccurate models that are 
used in interconnection studies could create errors in the studies, 
potentially leading to restudies and subsequent delays which would 
frustrate the efficiency gained by moving to a first-ready, first-
served cluster study process. Further, we find that the definition of a 
validated model (i.e., confirmation that the equipment behavior is 
consistent with the modeled behavior) is sufficiently flexible to 
enable interconnection customers to provide such a model with their 
interconnection requests.\3174\ Moreover, the option for the 
interconnection customer to submit an attestation that the models 
accurately reflect the expected behavior of a proposed generating 
facility would be based in the interconnection customer's best 
understanding at the time of the interconnection request, providing 
further flexibility if the interconnection customer chooses to change 
the equipment or control systems of the proposed generating facility, 
which is permitted as part of the interconnection process.
---------------------------------------------------------------------------

    \3172\ Alliant Energy Initial Comments at 10-11; Clean Energy 
Associations Initial Comments at 66; EPRI Initial Comments at 17-18; 
NextEra Initial Comments at 40; [Oslash]rsted Initial Comments at 
17; Pine Gate Initial Comments at 61; PPL Initial Comments at 25; 
Public Interest Organizations Reply Comments at 13; SEIA Initial 
Comments at 42.
    \3173\ Pro forma LGIP section 3.4.1; pro forma SGIP section 1.3.
    \3174\ Pro forma LGIP Attachment A to Appendix 1.
---------------------------------------------------------------------------

    1670. In addition, we do not believe, as suggested by 
commenters,\3175\ that there is a need to require transmission 
providers to make available additional information and system data in 
order for an interconnection customer to develop an RMS model. Although 
measured transmission system information is an input into the RMS 
model, the purpose of the model is to represent the behavior of the 
facility itself, and the interconnection customer should be able to use 
likely transmission system configurations to parameterize and validate 
the RMS model. To the extent that the interconnection customer believes 
that actual transmission data is required to tune the model block 
diagram, the scoping meeting provides a venue for such discussions. The 
provisions set forth in new pro forma LGIP section 3.4.6 further detail 
scoping meetings, which occur during the customer engagement window.
---------------------------------------------------------------------------

    \3175\ SEIA Initial Comments at 42; Tesla Initial Comments at 
11.
---------------------------------------------------------------------------

    1671. We decline to adopt requirements that constrain the 
discretion of transmission providers to use either user-defined RMS 
models or generic library RMS models, as suggested by commenters.\3176\ 
We find that the transmission provider is in the best position to 
determine the power flow modeling method that is best suited to 
ensuring the reliability of its system.
---------------------------------------------------------------------------

    \3176\ Clean Energy Associations Initial Comments at 65-66; 
Eversource Initial Comments at 39; ISO-NE Initial Comments at 42-43; 
MISO Initial Comments at 125; SEIA Initial Comments at 43; Tesla 
Initial Comments at 11.
---------------------------------------------------------------------------

    1672. We decline to modify the NOPR proposal to allow the 
transmission provider to require either a user-defined RMS model or a 
generic library RMS model, as suggested by Clean Energy Associations, 
rather than requiring the interconnection customer to submit both, as 
adopted in this final rule.\3177\ We believe that requiring the 
interconnection customer to submit both models is of value in providing 
the transmission provider discretion to choose which model most 
accurately represents a given generating facility's behavior. Providing 
these models does not represent an unreasonable burden on the 
interconnection customer, as the process of developing and 
parameterizing an RMS model is significantly simpler than doing so for 
an EMT model.
---------------------------------------------------------------------------

    \3177\ Clean Energy Associations Initial Comments at 65-66.
---------------------------------------------------------------------------

    1673. We decline to require the user-defined RMS model to be 
compatible with the transmission provider's software and meet the 
transmission provider's MOD-032-1 requirements at the time the 
interconnection request is submitted, as requested by MISO.\3178\ While 
the user-defined RMS model will have to meet these requirements prior 
to the cluster study for generating facilities seeking to interconnect 
pursuant to the pro forma LGIP and optional feasibility study or system 
impact study for generating facilities seeking to interconnect pursuant 
to the pro forma SGIP, the scoping meeting is the appropriate time to 
provide and discuss this information in order to correct the model if 
it is incompatible with the transmission provider's software or 
otherwise causes the transmission system model to be unable to 
solve.\3179\
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    \3178\ MISO Initial Comments at 125.
    \3179\ The scoping meeting is a meeting between representatives 
of the interconnection customer and transmission provider ``to 
exchange information including any transmission data and earlier 
study evaluations that would be reasonably expected to affect such 
interconnection options,'' and ``to analyze such information.'' 
Appendix C, pro forma LGIP section 1.
---------------------------------------------------------------------------

    1674. We decline to require NERC to improve the degree to which 
power flow software vendors allow accurate modeling of IBR technology, 
as requested by Longroad Energy.\3180\ While we agree that improved 
accuracy of IBR modeling is beneficial, this rulemaking is focused on 
entities that execute, or request the unexecuted filing of, LGIAs and 
SGIAs, and placing obligations on NERC or vendors is outside the scope 
of this proceeding. Equipment providers can develop and submit 
validated generic models to the software vendors' model libraries or 
the WECC model validation process to be included in the WECC table of 
approved models, if they desire to do so.
---------------------------------------------------------------------------

    \3180\ Longroad Energy Reply Comments at 20.
---------------------------------------------------------------------------

    1675. In response to commenters that argue that the Commission 
should provide further direction regarding model validation 
requirements for non-synchronous generating facilities,\3181\ we note 
that Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2 
of the pro forma SGIP, as adopted in this final rule, provide that, for 
a model to be ``validated,'' the interconnection customer must provide 
evidence that the equipment behavior is consistent with the model 
behavior. In addition, Attachment A to Appendix 1 of the pro forma LGIP 
and Attachment 2 of the pro

[[Page 61246]]

forma SGIP provide that this can involve, for example, an attestation 
from the interconnection customer that the model accurately represents 
the entire generating facility, attestations from each equipment 
manufacturer that the user-defined model accurately represents the 
relevant component of the generating facility, or test data. We find 
that this definition of a ``validated'' model and examples of an 
attestation in the proposal are sufficient and provide flexibility to 
allow interconnection customers to provide such a model with their 
interconnection requests. Therefore, we decline to adopt alternative 
proposals for model validation put forth by commenters.
---------------------------------------------------------------------------

    \3181\ EPRI Initial Comments at 14-15; Clean Energy Associations 
Initial Comments at 66-67; NERC Initial Comments at 18-20; 
[Oslash]rsted Initial Comments at 16, 18; SDG&E Reply Comments at 3; 
Tesla Initial Comments at 10.
---------------------------------------------------------------------------

    1676. We decline to adopt alternatives and revisions to the table 
of acceptable generic library models based on the current WECC list of 
approved dynamic models for renewable energy generating facilities, as 
suggested by R Street and EPRI.\3182\ We find that the table, as 
adopted, is appropriate because it represents the full spectrum of 
modeling data that transmission providers need to perform accurate 
interconnection studies for non-synchronous generating facilities. 
Nevertheless, we recognize that the list of models approved by WECC is 
subject to change and note that the table provides that ``a model 
otherwise approved by [WECC],'' \3183\ and not reflected in the table, 
would also meet the model requirements.
---------------------------------------------------------------------------

    \3182\ EPRI Initial Comments at 20; R Street Initial Comments at 
17.
    \3183\ Pro forma LGIP, app. 1, attach. A; Pro forma SGIP, 
attach. 2.
---------------------------------------------------------------------------

    1677. In response to commenters that oppose a requirement for a 
validated EMT model,\3184\ we note that these concerns mischaracterize 
the NOPR proposal as mandating EMT models on a national basis. Rather, 
Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2 of 
the pro forma SGIP, as adopted, requires that, in circumstances where 
the transmission provider performs an EMT study as part of its 
interconnection study process, the interconnection customer must 
provide an EMT model. We find that the transmission provider is in the 
best position to determine whether an EMT study is necessary to ensure 
system reliability because the transmission provider has the in-depth 
knowledge of its transmission system required to recognize where and 
when regular dynamic modeling is inadequate to capture the true 
behavior of generating facilities.
---------------------------------------------------------------------------

    \3184\ AES Initial Comments at 26; Bonneville Initial Comments 
at 24; Invenergy Initial Comments at 57-58; Longroad Energy Reply 
Comments at 21; SEIA Initial Comments at 41-42.
---------------------------------------------------------------------------

    1678. Similarly, we decline to adopt EPRI's request to require EMT 
models regardless of whether the transmission provider performs an EMT 
study.\3185\ Developing an EMT model may place an unreasonable 
administrative burden on an interconnection customer in situations 
where such a model is not used by the transmission provider. We also 
decline to adopt EPRI's request to allow use of an industry-accepted, 
generic EMT model instead of a validated EMT model, as the record does 
not indicate that any such industry-accepted, generic models currently 
exist.\3186\
---------------------------------------------------------------------------

    \3185\ EPRI Initial Comments at 19.
    \3186\ Id. at 15.
---------------------------------------------------------------------------

    1679. We decline Clean Energy Associations' request that the 
Commission require submission of an EMT model one year before the 
scheduled commercial operation date of the non-synchronous generating 
facility if the transmission provider performs an EMT study as part of 
the interconnection study process.\3187\ As noted above, we find that 
the proposal for models to be submitted with the interconnection 
request is consistent with the principles behind other requirements in 
the pro forma LGIP and pro forma SGIP and that transmission providers 
need these models to perform interconnection studies and ensure that 
prospective generating facilities do not create reliability risks to 
the transmission system. In response to Clean Energy Associations' 
request that the Commission require the transmission provider and its 
consultants to protect the EMT models and other information with the 
highest degree of confidentiality,\3188\ we note that the pro forma 
generator interconnection procedures and agreements include provisions 
for the treatment of confidential information.\3189\
---------------------------------------------------------------------------

    \3187\ Clean Energy Associations Initial Comments at 68-69.
    \3188\ Id. at 70.
    \3189\ See pro forma LGIP section 13.1; pro forma SGIP section 
4.5; pro forma LGIA art. 22; pro forma SGIA art. 9.
---------------------------------------------------------------------------

    1680. In response to Invenergy's request for clarification 
regarding whether a generic EMT model may be provided if a validated 
EMT model is unavailable at the time of submission of an 
interconnection request,\3190\ we note that there is currently no 
industry-accepted generic EMT model; therefore, a validated EMT model 
is required. In response to Invenergy's request for clarification 
regarding whether the interconnection customer may submit this 
information by the time of a cluster restudy if a validated EMT model 
is determined to be necessary, we clarify that a validated EMT model, 
if required by the transmission provider, must be submitted with the 
interconnection request to proceed in the interconnection study 
process. As validation can consist of, for example an attestation from 
the interconnection customer that the model accurately represents the 
entire generating facility, based on the interconnection customer's 
understanding at the time of submission, we believe an interconnection 
customer should be able to provide a validated EMT model at the time of 
the interconnection request.
---------------------------------------------------------------------------

    \3190\ Invenergy Initial Comments at 58.
---------------------------------------------------------------------------

    1681. In response to APS' request for clarification on the number 
of times an interconnection customer is allowed to provide inaccurate 
data and cure deficiencies before an interconnection request is deemed 
withdrawn,\3191\ we note that section 3.4.4 of the pro forma LGIP and 
section 1.3 of the pro forma SGIP provide the timeline for when a 
transmission provider must notify an interconnection customer that its 
interconnection request is deficient, and at that point, the 
interconnection customer has 10 business days to provide the additional 
requested information. We clarify that an interconnection customer has 
until the end of the 10 business-day period to cure deficiencies in its 
interconnection request. In the case of the pro forma LGIP, the 
interconnection customer may submit this information early in the 
cluster request window to ensure that there is sufficient time to 
address any issues with the interconnection request and the required 
models.
---------------------------------------------------------------------------

    \3191\ APS Initial Comments at 24.
---------------------------------------------------------------------------

    1682. In response to ClearPath's question regarding whether a 
change in equipment that necessitates submitting updated models is 
considered a material modification,\3192\ we highlight that section 4.4 
of the pro forma LGIP and section 1.4 of the pro forma SGIP set forth 
procedures for modifications to an interconnection request, including 
the evaluation of technical changes to a request. Further, we note that 
section 4.6 of the pro forma LGIP contains the transmission provider's 
technological change procedure, which was designed to allow 
transmission providers to evaluate whether equipment changes to an 
interconnection request should trigger the material modification 
provisions. A change in equipment may also qualify under the 
transmission

[[Page 61247]]

provider's definition of permissible technological advancements in 
section 1 of the pro forma LGIP. This definition includes advancements 
that the interconnection process can accommodate without triggering the 
material modification provision of the pro forma LGIP.
---------------------------------------------------------------------------

    \3192\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------

    1683. In response to Consumers Energy's recommendation that there 
should be consistency between NERC Reliability Standards and data 
collection efforts and the Commission's rulemaking,\3193\ we are not 
persuaded that there is a conflict or duplication between this final 
rule and NERC's Reliability Standards and interconnection data 
collection efforts. NERC Reliability Standards apply only to entities 
that are registered with NERC. Many smaller non-synchronous generating 
facilities are currently excluded from NERC registration but 
interconnect under the pro forma SGIP and pro forma LGIP and execute, 
or request the unexecuted filing of, the pro forma SGIA or pro forma 
LGIA.\3194\ The revisions to the pro forma interconnection procedures 
and pro forma interconnection agreements require all new 
interconnection customers that interconnect under the pro forma 
interconnection procedures and pro forma interconnection agreements to 
adhere to the new modeling requirements, regardless of whether the new 
interconnection customers must abide by the NERC Reliability Standards. 
We also note that NERC supports the proposed reforms.\3195\
---------------------------------------------------------------------------

    \3193\ Consumers Energy Initial Comments at 9.
    \3194\ NERC Initial Comments at 13-14.
    \3195\ Id. at 8-9, 18-20.
---------------------------------------------------------------------------

b. Ride Through Requirements
i. Need for Reform and NOPR Proposal
    1684. In the NOPR, the Commission preliminarily found that the pro 
forma LGIA and pro forma SGIA ride through provisions could result in 
undue discrimination and preferential treatment.\3196\ The Commission 
stated that, although synchronous and non-synchronous generating 
facilities are able to ``ride through'' system events and remain online 
and continue to provide real and reactive power following a 
disturbance, the existing pro forma LGIA and pro forma SGIA impose 
differing ride through requirements because they fail to account for a 
non-synchronous generating facility's ability to engage in momentary 
cessation.\3197\ The Commission expressed concern that, given advances 
in inverter technology, the lack of performance requirements regarding 
the use of momentary cessation by non-synchronous generating facilities 
may not be supportable on either a technical or cost basis.\3198\
---------------------------------------------------------------------------

    \3196\ NOPR, 179 FERC ] 61,194 at P 320.
    \3197\ Id. PP 320-321.
    \3198\ Id. P 325.
---------------------------------------------------------------------------

    1685. The Commission proposed to require newly interconnecting non-
synchronous generating facilities to continue current injection inside 
the ``no trip zone'' of the frequency and voltage ride through curves 
of NERC Reliability Standard PRC-024-3 or its successor 
standards.\3199\ The Commission explained that the pro forma LGIA 
defined the term ``ride through'' as the ability of the large 
generating facility to stay connected to and synchronized with the 
transmission system during system disturbances within a range of under-
frequency and over-frequency conditions. The Commission proposed to 
expand this definition to include the ability of the large generating 
facility to stay connected to and synchronized with the transmission 
system during system disturbances within under-voltage and over-voltage 
conditions.
---------------------------------------------------------------------------

    \3199\ Id. P 336. The ``no trip zone'' is defined as a set of 
voltage and frequency no trip boundaries within which applicable 
protection and controls may not be set to cause the generating 
facility to trip or cease current injection. See PRC-024-3--
Frequency and Voltage Protection Settings for Generating Resources, 
https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-024-3.pdf.
---------------------------------------------------------------------------

    1686. In addition, the Commission proposed to require any newly 
interconnecting non-synchronous generating facility to have the 
ability, during abnormal frequency conditions and voltage conditions 
within the ``no trip zone'' defined by NERC Reliability Standard PRC-
024-3 or its successor standards, to maintain power production at pre-
disturbance levels unless providing primary frequency response or fast 
frequency response, and to have the ability to provide dynamic reactive 
power to maintain system voltage in accordance with the generating 
facility's voltage schedule.\3200\ The Commission sought comment on 
whether adherence to these proposed requirements would be readily 
achievable through changes to control settings and whether such changes 
to control settings could be made at a relatively minor cost.\3201\
---------------------------------------------------------------------------

    \3200\ NOPR, 179 FERC ] 61,194 at P 337.
    \3201\ Id. P 338.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1687. Many commenters generally support the goal of the NOPR 
proposal.\3202\ CAISO asserts that the proposed reforms are essential 
for transmission providers to maintain reliability as non-synchronous 
generating facilities proliferate, and it urges the Commission to 
impose the proposed requirements on all interconnection customers that 
have not yet executed LGIAs as well as all prospective interconnection 
customers.\3203\ CAISO argues that interconnection customers that have 
already procured certain inverters that cannot meet the requirements 
can request non-conforming LGIAs, or request that their LGIAs be filed 
unexecuted, but it notes that it recently implemented similar 
requirements, and interconnection customers have been able to procure 
the inverters and technology necessary to meet the requirements.
---------------------------------------------------------------------------

    \3202\ AEP Initial Comments at 54; AES Initial Comments at 27; 
Ameren Initial Comments at 34; APPA-LPPC Initial Comments at 33; 
CAISO Initial Comments at 39-40; Consumers Energy Initial Comments 
at 9; NERC Initial Comments at 4, 23; Eversource Initial Comments at 
38; Illinois Commission Initial Comments at 16; MISO TOs Initial 
Comments at 32-33; NARUC Initial Comments at 42; National Grid 
Initial Comments at 43-44; North Carolina Commission and Staff 
Initial Comments at 26-27; NRECA Initial Comments at 48; NYISO 
Initial Comments at 54; Ohio Commission Consumer Advocate Initial 
Comments at 17; PacifiCorp Initial Comments at 45; Pine Gate Initial 
Comments at 59; SPP Initial Comments at 28; U.S. Chamber of Commerce 
Initial Comments at 13.
    \3203\ CAISO Initial Comments at 39-40.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1688. Pine Gate asserts that the Commission should not incorporate 
requirements into the pro forma LGIP and pro forma SGIP that are 
already being addressed by NERC through the standards development 
process, which will add new requirements related to the vast majority 
of the modeling and performance issues identified in the NOPR.\3204\ In 
addition, Pine Gate notes that the pro forma LGIA and pro forma SGIA 
already require interconnection customers to remain compliant with the 
applicable reliability standards.\3205\
---------------------------------------------------------------------------

    \3204\ Pine Gate Initial Comments at 60.
    \3205\ Id. (citing pro forma LGIA art. 9.1).
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) IEEE Standards 2800 and 1547
    1689. NERC and MISO support modifying the pro forma LGIP to 
incorporate elements of NERC Reliability Standards, NERC guidelines, 
and IEEE standards.\3206\ Specifically, MISO supports adopting IEEE 
Standard 2800-2022 by reference in the pro forma LGIA.\3207\ MISO 
asserts that

[[Page 61248]]

implementing IEEE Standard 2800-2022 will ensure resource capabilities 
protect against the types of events described in several recent NERC 
disturbance reports. NERC notes that the IEEE standards are inherently 
not mandatory unless a governing authority with jurisdiction adopts and 
enforces them and include many recommended practices that could be 
deemed informational.\3208\ Accordingly, NERC asserts that IEEE 
Standard 2800-2022 operates similar to NERC reliability guidelines, 
although IEEE Standard 2800-2022 is only available upon purchase.
---------------------------------------------------------------------------

    \3206\ NERC Initial Comments at 9; MISO Reply Comments at 26.
    \3207\ MISO Reply Comments at 25.
    \3208\ NERC Initial Comments at 3.
---------------------------------------------------------------------------

    1690. NERC recommends that the Commission explicitly integrate the 
requirements and recommendations from IEEE Standard 2800-2022 into the 
pro forma interconnection agreements.\3209\ Specifically, NERC contends 
that the Commission should prioritize the disturbance ride through, 
active power-frequency control, reactive power-voltage control, data 
sharing, and modeling provisions of IEEE Standard 2800-2022. However, 
NERC states that some transmission system conditions may require 
inverter control modes, settings, or protections that will not conform 
to IEEE Standard 2800-2022 region-wide expectations. NERC also argues 
that transmission providers should be permitted to establish additional 
performance requirements for specific locations and instances beyond 
region-wide requirements established under pro forma provisions, 
subject to transparency and public notice.
---------------------------------------------------------------------------

    \3209\ Id. at 6.
---------------------------------------------------------------------------

    1691. Some commenters request that the Commission amend its 
proposal to reference IEEE Standard 2800 or successor standards for 
large generating facilities and IEEE Standard 1547 for small generating 
facilities.\3210\ EPRI asserts that these standards have been developed 
through a rigorous process and provide for IBR performance that 
supports system reliability while providing sufficient flexibility for 
RTOs/ISOs and interconnection customers.\3211\ EPRI also notes that 
inverter manufacturers have publicly stated that state-of-the-art 
equipment already has the majority of the capabilities required by IEEE 
Standard 2800.
---------------------------------------------------------------------------

    \3210\ Clean Energy Associations Initial Comments at 73; EPRI 
Initial Comments at 5; SEIA Initial Comments at 43 (citing Generator 
Interconnection Workshop Summary at 20).
    \3211\ EPRI Initial Comments at 5.
---------------------------------------------------------------------------

    1692. EPRI argues that the Commission should consider narrowly 
specifying ride through requirements by reference to IEEE Standards 
2800 and 1547; aligning all applicable definitions proposed in the NOPR 
with those standards; and evaluating the alignment of additional 
definitions or performance specifications with potential future 
revisions of those standards.\3212\ EPRI asserts that failing to do so 
could create undue technical barriers to IBRs, and that paraphrasing of 
IEEE standards, rather than directly referencing the standards' 
requirements, could lead to an inconsistent implementation of the final 
rule in different regions with insufficient reliability benefits.\3213\
---------------------------------------------------------------------------

    \3212\ Id.
    \3213\ Id. at 5-6.
---------------------------------------------------------------------------

    1693. EPRI asserts that, if the Commission specifies its own ride 
through performance requirements, an alternative but less preferred 
approach would be to use the precise language and definitions as 
published in IEEE Standards 2800 and 1547.\3214\
---------------------------------------------------------------------------

    \3214\ Id. at 6.
---------------------------------------------------------------------------

    1694. EPRI argues that the NOPR proposal does not seem entirely 
aligned with the NERC IBR guidelines and is not as clear as the 
applicable industry standards like IEEE Standard 2800-2022.\3215\ EPRI 
also asserts that the Commission should consider what it characterizes 
as significant improvements in IEEE Standard 2800 over the NERC 
reliability guidelines. EPRI contends that the NERC IBR reliability 
guidelines cited in the NOPR did not fully consider all technical and 
stakeholder concerns considered by IEEE Standard 2800 and are therefore 
in contravention of the IEEE Standard 2800-2022 consensus 
requirements.\3216\
---------------------------------------------------------------------------

    \3215\ Id. at 9.
    \3216\ Id. at 3.
---------------------------------------------------------------------------

    1695. SEIA states that IBRs are currently capable of riding through 
disturbances and that many developers have implemented controls to 
ensure they do so following the release of the consensus-based IEEE 
standards.\3217\ SEIA argues that incorporating IEEE Standard 2800 into 
the pro forma LGIA would bring some certainty in generating facility 
design because the reliability requirements for each generating 
facility would be known at the time of the interconnection 
request.\3218\
---------------------------------------------------------------------------

    \3217\ SEIA Initial Comments at 43.
    \3218\ Id. at 44.
---------------------------------------------------------------------------

(2) Feasibility of NOPR Proposal
    1696. Some commenters argue that the proposed requirement in the 
NOPR ``to maintain power production at pre-disturbance levels unless 
providing primary frequency response or fast frequency response'' is 
not feasible.\3219\ Invenergy asserts that, in order to increase 
reactive power output to maintain system voltage, a generator would 
necessarily have to reduce real power output: therefore, Invenergy 
requests that the NOPR proposal be revised to clarify this potential 
inconsistency.\3220\ Clean Energy Associations and Public Interest 
Organizations contend that a requirement to maintain active power 
injection at pre-disturbance levels would lead to an undesirable 
response from generating facilities during a grid disturbance that 
could lead to voltage collapse, and the more helpful response would be 
to shift some power output to prioritize reactive power.\3221\
---------------------------------------------------------------------------

    \3219\ CAISO Initial Comments at 40; Clean Energy Associations 
Initial Comments at 71-72; NERC at 4; EPRI Initial Comments at 10; 
Invenergy Initial Comments at 58; [Oslash]rsted Initial Comments at 
19-20; Public Interest Organizations Reply Comments at 14; Southern 
Initial Comments at 34.
    \3220\ Invenergy Initial Comments at 58.
    \3221\ Clean Energy Associations Initial Comments at 71-72; 
Public Interest Organizations Reply Comments at 14.
---------------------------------------------------------------------------

    1697. Southern suggests adding a sentence to article 9.7.3 in the 
pro forma LGIA to address circumstances under which the generating 
facility is unable to maintain active power while delivering reactive 
power.\3222\ Clean Energy Associations suggest that the Commission 
replace the requirement to maintain active power production with 
language from NERC Reliability Standard PRC-024-3, which requires 
current injection and not active power injection to continue at pre-
disturbance levels.\3223\ Alternatively, Clean Energy Associations and 
Invenergy suggest the proposed language could be made more workable by 
only requiring a return to the pre-disturbance level of power 
production following voltage recovery, subject to the energy 
availability of the resource, which Clean Energy Associations explains 
would allow a generator to correctly shift from active power to 
reactive power during the voltage disturbance.\3224\
---------------------------------------------------------------------------

    \3222\ Southern Initial Comments at 34 (suggesting the addition 
of the following sentence: ``If the plant cannot maintain active 
power while delivering reactive power due to its current or apparent 
power limitation, then the preference should be given to either 
active or reactive power as specified by the Transmission 
Provider.'').
    \3223\ Clean Energy Associations Initial Comments at 76.
    \3224\ Id. at 76-77; Invenergy Initial Comments at 58.
---------------------------------------------------------------------------

    1698. CAISO requests that the Commission not require that inverters 
be able to provide real power during a transitory disturbance.\3225\ 
CAISO states that, unlike synchronous generating facilities, IBRs are 
current limited and generally operate at their maximum output. CAISO 
argues that maintaining

[[Page 61249]]

real power output at pre-disturbance levels would likely inhibit a non-
synchronous generating facility's ability to provide reactive power 
during a disturbance, and to help ensure reliability CAISO recommends 
removing the real power requirements and requiring non-synchronous 
generating facilities to provide reactive power at pre-disturbance 
levels. EPRI agrees that maintaining active power at the pre-
disturbance levels during and after the abnormal voltage period may not 
be practical, given that voltage disturbances tend to be limited to a 
region relatively close to the fault location, and is not aligned with 
IEEE Standard 2800-2022 or other international requirements.\3226\ EPRI 
and NERC recommend that IBR plant performance requirements should 
address active and/or reactive current during an abnormal voltage 
condition and requirements for the restoration of active power output 
in the post-fault period.\3227\
---------------------------------------------------------------------------

    \3225\ CAISO Initial Comments at 40.
    \3226\ EPRI Initial Comments at 10.
    \3227\ Id. at 9-10; NERC Reply Comments at 4.
---------------------------------------------------------------------------

    1699. EPRI argues that the implementation of frequency and voltage 
protection relay settings should not be exactly aligned with the NERC 
Reliability Standard PRC-024 curves but rather be based on the actual 
limits of equipment capability, with the objective to avoid potential 
damages.\3228\
---------------------------------------------------------------------------

    \3228\ EPRI Initial Comments at 12.
---------------------------------------------------------------------------

    1700. [Oslash]rsted argues that it is not possible to maintain real 
power production with depressed voltage that is still within the no 
trip zone of NERC Reliability Standard PRC-024-3, and explains that 
prioritizing reactive current during fault ride through mode (even 
within the no trip zone) is instrumental to maintain reliability.\3229\ 
[Oslash]rsted recommends replacing the reference to good utility 
practice in proposed article 9.7.3 of the pro forma LGIA and instead 
rely on Order No. 842 and its definition of ``Bulk-Power System--
Primary Frequency Response.'' \3230\
---------------------------------------------------------------------------

    \3229\ [Oslash]rsted Initial Comments at 19-20.
    \3230\ Id. at 20 (referring to Essential Reliability Servs. & 
the Evolving Bulk-Power Sys. Primary Frequency Response, Order No. 
842, 83 FR 9639 (Mar. 6, 2018), 162 FERC ] 61,128, order on 
clarification and reh'g, 164 FERC ] 61,135 (2018)).
---------------------------------------------------------------------------

    1701. NERC notes that conventional grid-following IBRs are current-
limited devices, and their active power output is voltage-dependent, 
making maintaining 100% of pre-disturbance active power while providing 
reactive power to support the bulk-power system during the fault period 
not always feasible.\3231\ NERC recommends referring to ``controls that 
maintain pre-disturbance active current (Ip)'' in addition to the 
provision of reactive current (Iq) (i.e., reactive power support) 
rather than referring to ``power.'' \3232\
---------------------------------------------------------------------------

    \3231\ NERC Reply Comments at 4.
    \3232\ Id.
---------------------------------------------------------------------------

(3) Applicability to All Types of Generating Facilities
    1702. Invenergy asserts that the NOPR proposal should go beyond the 
pro forma LGIA's current requirements and apply evenly to all 
generating facilities, not just non-synchronous generating 
facilities.\3233\ Similarly, Clean Energy Associations assert that the 
Commission currently only requires that relay settings not trip a 
generating facility during a voltage or frequency excursion and that 
there is no actual performance standard to ride through a disturbance 
for synchronous generating facilities.\3234\ Clean Energy Associations 
assert that, to prevent undue discrimination, the Commission should 
either proceed with a similar effort to require ride through 
performance from synchronous generating facilities; or allow ride 
through performance exceptions for non-synchronous generating facility 
trips caused by auxiliary equipment performance, which are a primary 
cause of ride through failure for both synchronous and non-synchronous 
generating facilities.
---------------------------------------------------------------------------

    \3233\ Invenergy Initial Comments at 58.
    \3234\ Clean Energy Associations Initial Comments at 77.
---------------------------------------------------------------------------

    1703. EPRI states that article 9.7.3 of the pro forma LGIA could 
benefit from additional modifications that differentiate between the 
ride through requirements for synchronous and non-synchronous large 
generating facilities because the two technologies have inherently 
different technical capabilities and operating principles.\3235\
---------------------------------------------------------------------------

    \3235\ EPRI Initial Comments at 11.
---------------------------------------------------------------------------

    1704. [Oslash]rsted urges the Commission to take note of the 
differences between technologies regarding their ability to ride 
through transmission system faults.\3236\ For example, [Oslash]rsted 
states that it uses a plant controller for wind turbines that is frozen 
in fault ride through mode and that controls aiding voltage recovery 
are performed by individual turbines until voltage profile is back 
within a normal operating band of 90-110% of rated voltage.
---------------------------------------------------------------------------

    \3236\ [Oslash]rsted Initial Comments at 16.
---------------------------------------------------------------------------

    [Oslash]rsted concludes that not all non-synchronous generating 
facilities are subject to the types of operating and power production 
concerns highlighted by the Commission in the NOPR.
(4) Proposed Revisions to the Pro Forma LGIA
    1705. [Oslash]rsted asserts that interconnection customers can only 
``ensure'' ride through capability of the generating and 
interconnection facilities per the definition in article 1 in the pro 
forma LGIA. [Oslash]rsted contends that the Commission's use of the 
term ``transmission system'' in article 9.7.3 of the pro forma LGIA is 
unclear in this context, and thus [Oslash]rsted alleges that it will be 
difficult to demonstrate compliance. Accordingly, [Oslash]rsted urges 
the Commission to use the term ``generation and interconnection 
facilities'' instead of ``transmission system'' in article 9.7.3 of the 
pro forma LGIA.\3237\
---------------------------------------------------------------------------

    \3237\ Id. at 18-19.
---------------------------------------------------------------------------

    1706. [Oslash]rsted states that, in case of severe voltage dip, 
IBRs may freeze in phase locked loop, essentially holding the 
calculated angle of the external voltage at a certain value.\3238\ 
[Oslash]rsted argues that this makes IBR units not strictly 
synchronized with the transmission system during this period.\3239\ 
Accordingly, [Oslash]rsted asks the Commission to remove the phrase 
``stay synchronized'' from article 9.7.3 of the pro forma LGIA.
---------------------------------------------------------------------------

    \3238\ A ``phase locked loop'' is a circuit that synchronizes an 
output signal with a reference or input signal in frequency as well 
as phase. Roland E. Best, Phase-Locked Loops: Design, Simulation and 
Applications, at 1 (6th ed. McGraw-Hill 2007).
    \3239\ [Oslash]rsted Initial Comments at 19.
---------------------------------------------------------------------------

(d) Requests for Clarification and Miscellaneous
    1707. NV Energy questions the ramifications of non-synchronous 
generating facilities failing to maintain a composite power delivery at 
continuous rated power output at the high side of the generator 
substation at a power factor within the range of 0.95 leading to 0.95 
lagging.\3240\ NV Energy suggests in this circumstance the non-
synchronous generating facilities make a payment for failing to 
maintain the tariff-required composite power delivery. NV Energy notes 
that there is a pending reactive power rulemaking and inquires whether 
the industry should assume that payments for reactive power will be 
addressed in that rulemaking.
---------------------------------------------------------------------------

    \3240\ NV Energy Initial Comments at 8.
---------------------------------------------------------------------------

    1708. Eversource requests that the Commission clarify that 
transmission providers may include additional performance requirements 
in the LGIA appendices for non-synchronous generating facilities that 
are necessary to

[[Page 61250]]

ensure reliable interconnection in a given area, such as harmonics or 
radio frequency interference.\3241\
---------------------------------------------------------------------------

    \3241\ Eversource Initial Comments at 38-39.
---------------------------------------------------------------------------

    1709. Invenergy asserts that the Commission should not rely 
entirely on ride through and other burdens on interconnection customers 
to address larger transmission system issues that should be addressed 
through regional transmission planning processes.\3242\
---------------------------------------------------------------------------

    \3242\ Invenergy Initial Comments at 59.
---------------------------------------------------------------------------

    1710. EPRI states that addressing how to apply grandfathering to 
existing facilities is an important consideration that should be 
addressed through Commission/NERC requirements. EPRI suggests that the 
Commission could add a procedure and criteria for a transmission 
provider to waive the grandfathering rule and require retrofits of 
existing facilities at the time of plant changes, or upgrades to meet 
the specified performance and modelling requirements, or to meet 
specific capability and performance standards such as IEEE Standard 
2800-2022.\3243\
---------------------------------------------------------------------------

    \3243\ EPRI Initial Comments at 21-22.
---------------------------------------------------------------------------

iii. Commission Determination
    1711. We adopt, with modifications, the NOPR proposal to revise 
article 9.7.3 of the pro forma LGIA and article 1.5.7 of the pro forma 
SGIA to establish ride through requirements during abnormal frequency 
conditions and voltage conditions within the ``no trip zone'' defined 
by NERC Reliability Standard PRC-024-3 or successor mandatory ride 
through reliability standards, as set forth in the modified pro forma 
LGIA language discussed below. We modify the proposed requirements to 
acknowledge the physical limitations of newly interconnecting non-
synchronous generating facilities. In the NOPR, the Commission stated 
that compliance with the NOPR proposal would be largely a control 
settings issue and may not be costly. We are persuaded by comments that 
contend that compliance with the NOPR proposal would be infeasible for 
certain types of inverters and non-synchronous generating facilities, 
and thus make modifications to address these concerns.
    1712. Based on the record, we affirm the Commission's preliminary 
finding in the NOPR that the pro forma LGIA and pro forma SGIA fail to 
account for a non-synchronous generating facility's ability to engage 
in momentary cessation. We note that the physical characteristics of 
synchronous generating facilities result in such facilities continuing 
to inject electric current during transmission system disturbances, 
consistent with the existing requirements to remain ``connected to and 
synchronized with the [t]ransmission [s]ystem'' as required by the pro 
forma LGIA and pro forma SGIA. As a result of these requirements, 
synchronous generating facilities continue to inject current during 
such disturbances, such that services provided supporting transmission 
system reliability are not disrupted during such events. However, the 
existing pro forma LGIA and pro forma SGIA do not currently require 
non-synchronous generating facilities to be capable of continuing to 
inject current in a manner comparable to synchronous generating 
facilities during system disturbances. As a result, non-synchronous 
generating facilities often cease injecting current during transmission 
system disturbances through ``momentary cessation.'' We agree with 
commenters that such behavior by non-synchronous generating facilities 
can pose significant risk to the reliability of the bulk-power system, 
as documented in several reports and NERC-issued alerts.\3244\
---------------------------------------------------------------------------

    \3244\ NERC Initial Comments at 9, 11 (citing NOPR, 179 FERC ] 
61,194 at P 313 n.433 (citing San Fernando Disturbance, at vi (Nov. 
2020), https://www.nerc.com/pa/rrm/ea/Documents/San_Fernando_Disturbance_Report.pdf; NERC and CAISO, Multiple Solar 
PV Disturbances in CAISO (Apr. 2022), https://www.nerc.com/pa/rrm/ea/Documents/NERC_2021_California_Solar_PV_Disturbances_Report.pdf; 
NERC, Odessa Disturbance (Sept. 2021) https://www.nerc.com/pa/rrm/ea/Documents/Odessa_Disturbance_Report.pdf)).
---------------------------------------------------------------------------

    1713. Moreover, without requirements for non-synchronous generating 
facilities to remain connected to and synchronized with the 
transmission system, and not to engage in momentary cessation, 
interconnection studies may not be able to accurately model expected 
behavior and identify the appropriate interconnection facilities and 
network upgrades to accommodate the interconnection request, resulting 
in an inaccurate assignment of interconnection costs. As a result, we 
find that the lack of comparable requirements for non-synchronous 
generating facilities to have the capability to remain ``connected to 
and synchronized with the [t]ransmission [s]ystem'' in the pro forma 
LGIA and pro forma SGIA results in rates that are unjust, unreasonable, 
and unduly discriminatory or preferential.
    1714. While a number of commenters object to the specific 
provisions proposed in the NOPR to resolve this issue, addressed 
further below, no commenter disagrees that there is a lack of 
requirements in the pro forma LGIA and pro forma SGIA regarding the use 
of momentary cessation by non-synchronous generating facilities. 
Moreover, no commenter disputes the technical ability of non-
synchronous generating facilities to continue to inject current during 
transmission system disturbances.
    1715. Specifically, we require that during abnormal frequency 
conditions and voltage conditions within the ``no trip zone'' defined 
by NERC Reliability Standard PRC-024-3 or successor mandatory ride 
through reliability standards, the non-synchronous generating facility 
must ensure that, within any physical limitations of the generating 
facility, its control and protection settings are configured or set to: 
(1) continue active power production during disturbance and post 
disturbance periods at pre-disturbance levels unless providing primary 
frequency response or fast frequency response; \3245\ (2) minimize 
reductions in active power and remain within dynamic voltage and 
current limits, if reactive power priority mode is enabled, unless 
providing primary frequency response or fast frequency response; (3) 
not artificially limit dynamic reactive power capability during 
disturbances; and (4) return to pre-disturbance active power levels 
without artificial ramp rate limits if active power is reduced, unless 
providing primary frequency response or fast frequency response.
---------------------------------------------------------------------------

    \3245\ Fast frequency response is defined as power injected to 
(or absorbed from) the grid in response to changes in measured or 
observed frequency during the arresting phase of a frequency 
excursion event to improve the frequency nadir or initial rate-of-
change of frequency. See Fast Frequency Response Concepts and Bulk 
Power System Reliability Needs, https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts_and_BPS_Reliability_Needs_White_Paper.pdf at 7.
---------------------------------------------------------------------------

    1716. In comparison to the NOPR proposal, this language, as 
adopted, provides non-synchronous generating facilities, within any 
physical limitations of the generating facility, the ability to reduce 
active power production in order to prioritize reactive power output in 
support of transmission system voltage.\3246\ This language also 
recognizes that such facilities may not be able to ride through 
disturbances with the same performance as synchronous generating 
facilities without costly equipment modification. However, this 
language requires non-synchronous generating facilities, within any 
physical limitations of the generating facility, to configure or set 
their facilities to ride through disturbances and continue to support

[[Page 61251]]

system reliability. This language is consistent with suggestions by a 
number of commenters that the final rule recognize that non-synchronous 
generating facilities cannot provide both real and reactive power at 
pre-disturbance levels during a disturbance,\3247\ allow for the 
prioritization of reactive power,\3248\ and address restoration of 
active power output in the post-fault period.\3249\
---------------------------------------------------------------------------

    \3246\ ``Active power'' as used here and ``real power'' as used 
in the NOPR proposal refer to the same concept: power than can be 
used by load in order to perform work.
    \3247\ CAISO Initial Comments at 40; Clean Energy Associations 
Initial Comments at 71-72; NERC at 4; EPRI Initial Comments at 10; 
Invenergy Initial Comments at 58; [Oslash]rsted Initial Comments at 
19-20; Public Interest Organizations Reply Comments at 14; Southern 
Initial Comments at 34.
    \3248\ Clean Energy Associations Initial Comments at 71-72; 
Public Interest Organizations Reply Comments at 14; [Oslash]rsted 
Initial Comments at 19-20.
    \3249\ EPRI Initial Comments at 9-10; NERC Reply Comments at 4; 
Clean Energy Associations Initial Comments at 76-77; Invenergy 
Initial Comments at 58.
---------------------------------------------------------------------------

    1717. The adopted language requires non-synchronous generating 
facilities, within any physical limitations of the generating facility, 
to configure or set their facilities to be able to ride through 
disturbances and continuing to support system reliability. 
Specifically, while grid-forming inverters are available, they are not 
widely commercially deployed due to lack of experience, cost, or other 
factors.\3250\ Given the existing technical capabilities of non-
synchronous generating facilities, we agree with commenters that the 
NOPR proposal requiring active power to be maintained at pre-
disturbance levels during a system disturbance in all instances may not 
be feasible, or preferrable from a reliability perspective. For 
example, we agree there may be instances where the injection of 
reactive power should be prioritized to maintain reliability during a 
system disturbance, which may require non-synchronous generating 
facilities to temporarily reduce their injection of active power.\3251\ 
As a result, we adopt a modified NOPR proposal to accommodate existing 
technical capabilities and physical limitations of non-synchronous 
generating facilities, by providing for reductions in active power to 
prioritize reactive power while prohibiting non-synchronous generating 
facilities from configuring or setting their control and protection 
settings to effectively artificially limit such resources below their 
actual capability.
---------------------------------------------------------------------------

    \3250\ A grid-forming inverter is an inverter that is capable of 
synthesizing voltage and frequency without an external reference. 
See, e.g., Abraham Ellis, Grid Forming Inverters: Requirements and 
Practical Applications, at 4 (May 1, 2019) https://www.osti.gov/servlets/purl/1639991.
    \3251\ NERC Initial Comments at 23; CAISO Initial Comments at 
40.
---------------------------------------------------------------------------

    1718. We also adopt the NOPR proposal to revise article 9.7.3 of 
the pro forma LGIA to include in the definition of ``ride through'' the 
ability of the large generating facility to stay connected to and 
synchronized with the transmission system during system disturbances 
within under-voltage and over-voltage conditions. This revision ensures 
that large generating facilities are capable of remaining connected to 
and synchronized with the transmission system, consistent with the 
other ride through requirements adopted here and similar requirements 
in the pro forma SGIA.
    1719. Some commenters request that the Commission either 
incorporate IEEE Standard 2800-2022 by reference, or explicitly 
incorporate this standard's performance requirements into the pro forma 
LGIA. Although we acknowledge the value of IEEE 2800-2022, we decline 
to incorporate it by reference. IEEE 2800-2022 was developed for a 
different purpose; it is a voluntary guideline that uses discretionary 
terms (e.g., ``may,'' ``should,'' ``can,'' or ``upon agreement''). It 
is unclear whether IEEE 2800-2022 would adequately address the problem 
identified by the Commission because the Commission would have limited 
authority to enforce these discretionary provisions.
    1720. Invenergy and Clean Energy Associations assert that the 
Commission should impose similar ride through requirements on 
synchronous generating facilities. Alternatively, Clean Energy 
Associations assert that, to prevent undue discrimination, the 
Commission should allow ride through performance exceptions for non-
synchronous generating facility trips caused by auxiliary equipment 
performance, which are a primary cause of ride through failure for both 
synchronous and non-synchronous generating facilities. We do not 
believe that imposing similar ride through requirements on synchronous 
generating facilities is necessary because the physical characteristics 
of synchronous generating facilities result in such facilities 
continuing to inject electric current during transmission system 
disturbances, i.e., do not allow for momentary cessation.
    1721. We also decline to grant Clean Energy Associations' 
alternative request because we find that a ride through exception for 
non-synchronous generating facility trips caused by auxiliary equipment 
performance is not needed. As NERC has noted, protection on auxiliary 
equipment for non-synchronous resources, other than the generator-
connected unit auxiliary transformer, is already exempted from the 
requirements of NERC Reliability Standard PRC-024-3 specifically 
because protection for such auxiliary equipment does not cause a 
resource to trip or cease injecting current.\3252\ We do not believe 
that auxiliary equipment performance is considered a physical 
limitation of a non-synchronous generating facility such that control 
and protection settings can be configured or set to reduce active power 
production during disturbances, and therefore no exception is needed.
---------------------------------------------------------------------------

    \3252\ Petition of the North American Reliability Corporation 
for Approval of Proposed Reliability Standard PRC-024-3, Docket No. 
RD20-7, at 12 (filed Mar. 20, 2020).
---------------------------------------------------------------------------

    1722. Pine Gate asserts that the Commission should not adopt 
requirements to the pro forma LGIP and pro forma SGIP that are already 
being addressed by NERC through the standards development process. We 
disagree because adding such provisions to the pro forma LGIA and pro 
forma SGIA will require all newly interconnecting generating facilities 
to abide by such provisions regardless of whether such newly 
interconnecting generating facilities are outside the bounds of NERC's 
jurisdiction. As such, we find that this modified reform can 
holistically address the identified issues alongside the NERC 
standards.
    1723. NV Energy raises questions about the ramifications of non-
synchronous generating facilities failing to maintain reactive power 
and whether the Commission is proposing any changes to reactive power 
compensation. We clarify that the Commission is not proposing changes 
to reactive power compensation in this proceeding.
    1724. Invenergy argues that the Commission should not rely entirely 
on ride through requirements and other burdens on interconnection 
customers to address larger transmission system issues that should be 
addressed through regional transmission planning processes. The need to 
establish interconnection requirements for generating facilities to 
``remain connected to and synchronized with the [t]ransmission 
[s]ystem'' during system disturbances is properly addressed in this 
proceeding that deals with reforming the interconnection processes for 
newly interconnecting generating facilities. Regarding Invenergy's 
arguments that larger transmission system issues need to be addressed 
in the regional transmission planning processes, we note that while 
reforms to regional transmission planning are

[[Page 61252]]

outside the scope of this proceeding, the Commission is considering 
addressing regional transmission planning and cost allocation in 
another pending proceeding.\3253\
---------------------------------------------------------------------------

    \3253\ See Transmission Planning and Cost Allocation NOPR, 179 
FERC ] 61,028 (2022).
---------------------------------------------------------------------------

    1725. EPRI argues that the grandfathering of existing non-
synchronous generating facilities is an important consideration that 
should be addressed through Commission and NERC requirements and 
suggests that the Commission could add a procedure and criteria for a 
transmission provider to waive the grandfathering rule and require 
retrofits of existing non-synchronous generating facilities at the time 
of plant changes or require upgrades to meet the specified performance 
and modeling requirements. We decline to add the requested procedure. 
The final rule changes to the pro forma LGIA and pro forma SGIA adopted 
herein apply prospectively to interconnection customers that execute, 
or request the unexecuted filing of, an LGIA after the Commission-
approved effective date of the transmission provider's filing in 
compliance with this final rule. Both the NOPR proposal and the adopted 
language were intended to be achieved through changes to control 
settings at minimal cost for current inverter technology; it did not 
contemplate imposing potentially significant retrofit or equipment 
costs on existing non-synchronous generating facilities.\3254\
---------------------------------------------------------------------------

    \3254\ NOPR, 179 FERC ] 61,194 at P 325.
---------------------------------------------------------------------------

    1726. [Oslash]rsted requests clarification on how the NOPR proposal 
will affect a plant controller for wind turbines that is frozen in 
fault ride through mode and control actions aiding voltage recovery are 
performed by individual turbines until the voltage profile returns to 
the normal operating band of 90-110% of rated voltage. We note that the 
reforms, as adopted, apply to a non-synchronous generating facility as 
a whole, rather than to any individual component within the facility. 
As long as the non-synchronous generating facility as a whole meets the 
ride through requirements, it does not matter which part of the 
facility is controlling the generating facility's output.
    1727. [Oslash]rsted also notes that non-synchronous generating 
facilities may freeze in phase locked loop during disturbances, making 
them not strictly synchronized with the transmission system. 
[Oslash]rsted asks the Commission to remove the phrase ``stay 
synchronized'' from article 9.7.3 of the pro forma LGIA. We decline to 
do so because the NOPR did not propose to revise this phrase and this 
final rule establishes the specific ride through requirements for newly 
interconnecting non-synchronous generating facilities.
    1728. [Oslash]rsted recommends that instead of references in this 
clause to ``good utility practice,'' the Commission should instead rely 
on Order No. 842 and its definition of ``Bulk-Power System--Primary 
Frequency Response.'' This comment refers to language not subject to 
the Commission's proposed revisions and is therefore outside the scope 
of this rulemaking proceeding. We also note that ``Bulk-Power System--
Primary Frequency Response'' refers to the title of Order No. 842, and 
not any definition within.
c. Applicability of Ride Through Requirements
i. Need for Reform and NOPR Proposal
    1729. In the NOPR, the Commission noted that generating facilities 
interconnecting under the pro forma LGIA that are subject to 
reliability standards are required to ride through frequency and 
voltage disturbance events, while generating facilities that are not 
already subject to reliability standards are not, despite the fact that 
all generating facilities newly interconnecting under the pro forma 
LGIA are technically capable of riding through disturbances.\3255\ The 
Commission explained that there is an existing gap in the applicability 
of ride through requirements for large generating facilities with a 
capacity above 20 MW and with a gross plant/facility aggregate 
nameplate rating of 75 MVA or less.\3256\ The Commission preliminarily 
found that the pro forma LGIA requirements could result in unduly 
discriminatory or preferential treatment due to this gap in the 
applicability of ride through performance requirements to similarly 
situated generating facilities.
---------------------------------------------------------------------------

    \3255\ NOPR, 179 FERC ] 61,194 at P 326.
    \3256\ Id. P 340.
---------------------------------------------------------------------------

    1730. The Commission proposed to revise the pro forma LGIA to 
require that all newly interconnecting large generating facilities 
provide ride through capability consistent with any standards and 
guidelines that are applied to other generating facilities in the 
balancing authority area on a comparable basis.\3257\ The Commission 
noted that the proposed reform is consistent with existing language in 
article 1.5.7 of the pro forma SGIA that requires newly interconnecting 
small generating facilities to ride through abnormal frequency and 
voltage events and not disconnect during such events.
---------------------------------------------------------------------------

    \3257\ Id.
---------------------------------------------------------------------------

    1731. In addition to the substantive changes, the Commission 
proposed to replace the term ``applicable reliability council'' with 
``electric reliability organization,'' and replace the term ``control 
area'' with ``balancing authority area'' throughout the pro forma LGIP 
and pro forma LGIA. The Commission explained that these proposed 
replacements reflect updated terminology.\3258\
---------------------------------------------------------------------------

    \3258\ Id. P 341.
---------------------------------------------------------------------------

ii. Comments
    1732. Several commenters support the NOPR proposal.\3259\ Enel 
notes that the Commission's proposed definition of ``electric 
reliability organization'' includes NERC, but it does not include the 
applicable regional entity, which Enel asserts should be included 
because the regional entity may have approved the regional reliability 
standards.\3260\
---------------------------------------------------------------------------

    \3259\ Ameren Initial Comments at 34; APPA-LPPC Initial Comments 
at 33; CAISO Initial Comments at 39-40.
    \3260\ Enel Initial Comments at 81.
---------------------------------------------------------------------------

iii. Commission Determination
    1733. We adopt the NOPR proposal to revise the pro forma LGIA to 
require that all newly interconnecting large generating facilities 
provide frequency and voltage ride through capability consistent with 
any standards and guidelines that are applied to other generating 
facilities in the balancing authority area on a comparable basis. 
Adopting this reform enables the Commission to address an existing gap 
in the applicability of ride through requirements for large generating 
facilities with a capacity above 20 MW and with a gross plant/facility 
aggregate nameplate rating 75 MVA or less.
    1734. Based on the record before us, we confirm the Commission's 
preliminary finding in the NOPR that the pro forma LGIP is unduly 
discriminatory or preferential insofar as generating facilities that 
are not already subject to reliability standards are not required to 
ride through frequency and voltage disturbance events, despite being 
technically capable of doing so. We note that no commenter opposes this 
reform.
    1735. We also adopt the NOPR proposal to replace the term 
``applicable reliability council'' with ``electric reliability 
organization,'' and the term ``control area'' with ``balancing 
authority area,'' throughout the pro forma LGIP and pro forma LGIA. In 
response to Enel's concerns, we note that, while regional reliability 
standards may be developed by the applicable

[[Page 61253]]

regional entity, the Commission has found that regional reliability 
standards are considered part of the electric reliability 
organization's set of reliability standards and are therefore covered 
under the proposed definition.\3261\
---------------------------------------------------------------------------

    \3261\ Order No. 672, 114 FERC ] 61,104, at P 296, order on 
reh'g, Order No. 672-A, 114 FERC ] 61,328.
---------------------------------------------------------------------------

D. Issues Beyond the Scope of This Rulemaking

1. Comments
    1736. Multiple commenters ask the Commission to consider additional 
information or interconnection reforms not specifically raised in the 
NOPR. For example, some commenters address foundational issues such as 
generator retirement and/or replacement processes; \3262\ the 
application of generator interconnection standards to merchant 
transmission and HVDC projects; \3263\ conducting a root-cause 
investigation of interconnection queue delays to identify and address 
key barriers to bringing new generating facilities online; \3264\ 
initiating a technical conference to identify additional reforms to 
meet present and future challenges; \3265\ establishing a process to 
provide access to transmission data to third-party businesses; \3266\ 
introduction of competition into the interconnection process or 
construction of network upgrades; \3267\ the introduction of project 
prioritization to allocate scarce interconnection access; \3268\ 
changes to operational practices to reduce network upgrade 
requirements; \3269\ and issues particular to different regions or 
transmission providers.\3270\
---------------------------------------------------------------------------

    \3262\ AEP Initial Comments at 43-44; Elevate Initial Comments 
at 3-7, 8-11; Illinois Commission Initial Comments at 11; New York 
State Department Reply Comments at 4.
    \3263\ Invenergy Initial Comments at 64-65.
    \3264\ Equinor Wind Reply Comments at 7.
    \3265\ Pine Gate Reply Comments at 5.
    \3266\ Tesla Initial Comments at 6, 8.
    \3267\ Enel Initial Comments at 5, 52-56; Shell Reply Comments 
at 5-18.
    \3268\ Arizona Commission Initial Comments at 1; Colorado 
Commission Initial Comments at 9.
    \3269\ Clean Energy Associations Initial Comments at 64.
    \3270\ Avangrid Initial Comments at 24-25; New York State 
Department Initial Comments at 10; PJM Part 1 Reply Comments at 1; 
Roy J Shanker Initial Comments at 2-7; Roy J Shanker Reply Comments 
at 3-9; Southern Reply Comments at 8-9.
---------------------------------------------------------------------------

    1737. Other commenters seek changes to tariff language such as 
additional reforms specific to small generating facilities and the 
small generator interconnection process; \3271\ explicitly stating that 
interconnection terms may be subject to remedial waiver upon 
appropriate Commission action; \3272\ requiring detailed information be 
made available concerning either transmission congestion on 
transmission providers' systems or technical information associated 
with a particular point of interconnection; \3273\ clarifications to 
the interconnection service types (i.e., energy-only or network 
resource); \3274\ replacing power flow studies with security 
constrained economic dispatch analysis for energy-only service studies; 
\3275\ the three-year suspension option in the pro forma LGIA; \3276\ 
and additional pro forma LGIA language on termination and breach.\3277\
---------------------------------------------------------------------------

    \3271\ Bonneville Initial Comments at 25; EPRI Initial Comments 
at 24-38; Hydropower Commenters Initial Comments at 10-11; IREC 
Initial Comments at 2-3; R Street Initial Comments at 9; and Xcel 
Initial Comments at 19.
    \3272\ OSPA Reply Comments at 14.
    \3273\ CREA and NewSun Initial Comments at 21-22; [Oslash]rsted 
Initial Comments at 5-6.
    \3274\ Enel Initial Comments at 27-28; North Dakota Commission 
Initial Comments at 7; R Street Initial Comments at 7; Tri-State 
Initial Comments at 26; Xcel Initial Comments at 16.
    \3275\ Enel Initial Comments at 73-75.
    \3276\ El Paso Electric Initial Comments at 4-5.
    \3277\ Tri-State Initial Comments at 34-35.
---------------------------------------------------------------------------

    1738. Several commenters focus on process-specific reforms, such as 
automation of the interconnection queue process to ease delays; \3278\ 
aligning the interconnection queue and the project development 
processes; \3279\ interconnection study issues such as staffing to 
conduct studies and study criteria and scope; \3280\ additional 
transparency from transmission providers on the interconnection study 
process, such as online interconnection queue tracking and performance 
metrics; \3281\ and whether to implement an independent transmission 
monitor or allow third parties to conduct interconnection studies to 
reduce interconnection queue backlogs.\3282\
---------------------------------------------------------------------------

    \3278\ CESA Initial Comments at 5; NextEra Initial Comments at 
2.
    \3279\ Enel Initial Comments at 2-4.
    \3280\ Affected Interconnection Customers Initial Comments at 
14-15; Clean Energy Associations Initial Comments at 27; CREA and 
NewSun Initial Comments at 21-22; Cypress Creek Initial Comments at 
3-8; New York State Department Initial Comments at 3.
    \3281\ Public Interest Organizations Initial Comments at 23-25.
    \3282\ Dominion Reply Comments at 22-24; EPSA Initial Comments 
at 13-14; SDG&E Reply Comments at 2; Southern Reply Comments at 6-7; 
ACORE Initial Comments at 5.
---------------------------------------------------------------------------

    1739. Some commenters focus on network upgrade cost issues, in 
particular the participant funding model currently in place in certain 
RTOs/ISOs; \3283\ minimum thresholds for identifying network upgrades; 
\3284\ a self-build option for stand-alone facilities; \3285\ and the 
``good faith'' standard applied to cost and timeline estimates for 
network upgrades and related transmission facilities.\3286\
---------------------------------------------------------------------------

    \3283\ ACORE Initial Comments at 8; CREA and NewSun Initial 
Comments at 93-104; NextEra Reply Comments at 3, 16; North Carolina 
Commission and Staff Initial Comments at 2-16; OSPA Reply Comments 
at 4-7; Public Interest Organizations Reply Comments at 13-14; 
Senators Hickenlooper and King Initial Comments at 1-2.
    \3284\ Enel Initial Comments at 2-4.
    \3285\ CESA Initial Comments at 16-17; EEI Reply Comments at 14-
15; Interwest Initial Comments at 5.
    \3286\ Pattern Energy Initial Comments at 14-15.
---------------------------------------------------------------------------

    1740. Commenters raising resource-specific concerns address the 
interconnection of qualifying facilities; \3287\ challenges specific to 
the hydropower industry, including modifications to the readiness 
standard and site control requirements; \3288\ steps to promote new 
pumped storage projects; \3289\ using regional planning to develop 
operating assumptions applied to the study of electric storage 
resources; \3290\ and greater clarity on interconnection of battery 
storage additions to existing and proposed generating facilities.\3291\
---------------------------------------------------------------------------

    \3287\ CREA and NewSun Initial Comments at 104-106; Uda Law Firm 
Initial Comments at 1-9.
    \3288\ Hydropower Commenters Initial Comments at 7.
    \3289\ Id. at 27-28.
    \3290\ Interwest Reply comments at 15.
    \3291\ SEIA Reply Comments at 21-22.
---------------------------------------------------------------------------

    1741. Several commenters argue in favor of greater coordination 
between generator interconnection and transmission planning \3292\ or 
identify interconnection as a matter requiring interregional 
planning.\3293\
---------------------------------------------------------------------------

    \3292\ ACORE Initial Comments at 2-4; ACEG Initial Comments at 
1-4; CESA Initial Comments at 13-14; Clean Energy Associations 
Initial Comments at 10-11; Consumer Protection Coalition Reply 
Comments at 1-2; Cypress Creek Initial Comments at 10-11; EDF 
Renewables Initial Comments at 12-13; ELCON Initial Comments at 11-
13; Enel Reply Comments at 2; ENGIE Reply Comments at 4; Google 
Initial Comments at 6-7, 22; Invenergy Initial Comments at 62-63; 
Interwest Reply Comments at 15; National Grid Initial Comments at 
45-46; New York State Department Reply Comments at 2-4; NYTOs 
Initial Comments at 23-24; OSPA Reply Comments at 15; Pattern Energy 
Initial Comments at 6-7; Public Interest Organizations Reply 
Comments at 16; R Street Initial Comments at 6-7; Union of Concerned 
Scientists Reply Comments at 8.
    \3293\ North Carolina Commission and Staff Initial Comments at 
2-3; Pattern Energy Initial Comments at 8-11.
---------------------------------------------------------------------------

    1742. Some comments request that the Commission provide distinct 
treatment for Native American energy projects by adopting rules and 
policies that meet the unique needs of Tribes and that allow 
alternative means for fulfilling interconnection requirements, such as 
by providing additional time for the posting of deposits or eliminating 
commercial readiness requirements.\3294\

[[Page 61254]]

Other comments request that the Commission incorporate environmental 
justice considerations into the interconnection process by quantifying 
in the proportional impact analysis the remediation of past economic 
injustice and benefits of renewable development in impoverished areas 
\3295\ or by prioritizing the provision of low-cost, clean energy to 
low income and people of color communities under the FPA's public 
interest standard.\3296\
---------------------------------------------------------------------------

    \3294\ OSPA Reply Comments at 15-16.
    \3295\ OSPA Initial Comments at 15-16; OSPA Reply Comments at 3.
    \3296\ Energy Keepers Initial Comments at 3; Navajo Utility 
Initial Comments at 13. Public Interest Organizations Reply Comments 
at 11.
---------------------------------------------------------------------------

2. Commission Determination
    1743. We consider the comments referenced in the section above to 
be beyond the scope of this proceeding. The Commission proposed 
specific reforms in the NOPR, to which commenters have responded and 
for which a record has been established. Even for those issues 
tangentially connected to NOPR proposals, the record here is inadequate 
to support their full consideration. Further, we consider issues 
regarding the coordination of transmission planning with generator 
interconnection to be beyond the scope of this rulemaking. We note that 
the Commission proposed reforms related to coordination between 
regional transmission planning and cost allocation and generator 
interconnection in Docket No. RM21-17-000.\3297\
---------------------------------------------------------------------------

    \3297\ ANOPR, 176 FERC ] 61,024.
---------------------------------------------------------------------------

IV. Compliance Procedures

A. NOPR Proposal

    1744. In the NOPR, the Commission proposed to require each 
transmission provider to submit a compliance filing within 180 days of 
the effective date of the final rule revising its LGIP, LGIA, SGIP, and 
SGIA, as necessary, to demonstrate that it meets the requirements set 
forth in the final rule.\3298\ The Commission also proposed to permit 
appropriate entities to seek an ``independent entity variation'' or a 
``regional reliability variation'' from the proposed 
requirements.\3299\ The Commission further noted that some transmission 
providers may have provisions in their existing LGIPs, LGIAs, SGIPs, 
and SGIAs subject to the Commission's jurisdiction that the Commission 
has previously deemed to be consistent with or superior to the pro 
forma LGIP, pro forma LGIA, pro forma SGIP, and/or pro forma SGIA or 
permissible under the independent entity variation standard or regional 
reliability variation standard. Where these provisions would be 
modified by the final rule, the Commission proposed to require 
transmission providers to either comply with the final rule or 
demonstrate that these previously approved variations continue to meet 
the ``consistent with or superior to'' and ``regional reliability 
variation'' standard for non-RTO/ISO transmission providers and the 
independent entity variation standard for RTOs/ISOs.
---------------------------------------------------------------------------

    \3298\ NOPR, 179 FERC ] 61,194 at P 342.
    \3299\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 822-
827; Order No. 2006, 111 FERC ] 61,220 at PP 546-550).
---------------------------------------------------------------------------

    1745. The Commission explained that it would assess whether each 
compliance filing satisfies the proposed requirements and issue 
additional orders as necessary to ensure that each transmission 
provider meets the requirements of the final rule.\3300\
---------------------------------------------------------------------------

    \3300\ Id. P 343.
---------------------------------------------------------------------------

    1746. The Commission also proposed that non-public utility 
transmission providers would have to adopt the proposed requirements as 
a condition of maintaining the status of their safe harbor tariff or 
otherwise satisfying the reciprocity requirement of Order No. 
888.\3301\
---------------------------------------------------------------------------

    \3301\ Id. P 344.
---------------------------------------------------------------------------

B. Comments

1. Compliance Filing Deadline
    1747. Consumers Energy and NRECA support the proposed requirement 
for transmission providers to submit compliance filings within 180 days 
of the effective date of a final rule in this proceeding.\3302\ NRECA 
states that 180 days is a reasonable amount of time for transmission 
providers to assess their generation portfolios and for interconnection 
customers to gauge project viability and withdraw those interconnection 
requests that are not commercially ready.\3303\ Consumers Energy 
suggests that the Commission require RTOs/ISOs to justify any 
individual extensions for compliance filings.\3304\ NRECA asks the 
Commission to waive any existing withdrawal penalties during the period 
between a final rule and compliance filings to encourage the rapid 
withdrawal of speculative interconnection requests and the pursuit of 
ready interconnection requests.\3305\
---------------------------------------------------------------------------

    \3302\ Consumers Energy Initial Comments at 10; NRECA Initial 
Comments at 7, 49.
    \3303\ NRECA Initial Comments at 7, 49.
    \3304\ Consumers Energy Initial Comments at 10.
    \3305\ NRECA Initial Comments at 49.
---------------------------------------------------------------------------

    1748. Some commenters argue that the Commission should provide a 
longer time period for compliance filings because the scope and 
complexity of the reforms will require substantial time and resources 
and will involve lengthy stakeholder processes.\3306\ Some commenters 
also note that transmission providers will need to balance other 
priorities while developing compliance filings, such as administering 
the interconnection queue and pursuing transmission planning 
reforms.\3307\ Some commenters state that the 180-day period will be 
difficult for large, multi-state RTOs/ISOs that must develop large-
scale tariff revisions in conjunction with large stakeholder 
communities.\3308\ EEI suggests a 240-day deadline for compliance 
filings,\3309\ while other commenters state that one year would be more 
appropriate.\3310\
---------------------------------------------------------------------------

    \3306\ Dominion Initial Comments at 6; EEI Initial Comments at 
22; MISO Initial Comments at 126; NEPOOL Initial Comments at 12.
    \3307\ EEI Initial Comments at 22; MISO Initial Comments at 126.
    \3308\ Avangrid Initial Comments at 36-37; Dominion Initial 
Comments at 41-42; MISO Initial Comments at 126.
    \3309\ EEI Initial Comments at 22.
    \3310\ Dominion Initial Comments at 6; MISO Initial Comments at 
126.
---------------------------------------------------------------------------

    1749. PJM asks the Commission to hold its compliance filing 
obligation in abeyance until PJM completes the transition mechanism 
from its recent interconnection queue reform in Docket No. ER22-2110-
000, which was the result of an 18-month stakeholder process.\3311\ PJM 
states that, if it is required to submit a compliance filing during the 
transition process, that will cast a cloud over the transition process 
while the request for an independent entity variation works through a 
prolonged regulatory process, bringing into doubt interconnection 
agreements finalized as part of the transition and further aggravating 
backlogs.\3312\ PJM explains that, when it completes this transition 
process, it can evaluate whether to adopt the final rule's reforms or 
demonstrate that its reforms are superior.\3313\ PJM asserts that such 
a ``staged'' compliance process aligns with past Commission decisions 
and would bring more certainty to interconnection customers.\3314\
---------------------------------------------------------------------------

    \3311\ PJM Initial Comments at 2-5, 11; see also OPSI Initial 
Comments at 2-3 (explaining that it will be crucial that this 
proceeding does not disrupt PJM's ongoing interconnection queue 
reform); see also PJM Interconnection, L.L.C., 181 FERC ] 61,162.
    \3312\ PJM Initial Comments at 2, 5, 11.
    \3313\ Id. at 12.
    \3314\ Id. at 3 (citing, e.g., Order No. 890, 118 FERC ] 61,119 
at P 135 (adopting a two-tiered implementation process of the final 
rule)).
---------------------------------------------------------------------------

2. Regional Flexibility
    1750. A number of commenters call for the final rule to provide 
regional flexibility to account for differences in geography, state 
policies and regulatory

[[Page 61255]]

frameworks, different network electrical characteristics, market 
structures, resource mixes, and other factors.\3315\ Many commenters 
explain that many transmission providers have already adopted or are in 
the process of adopting some of the NOPR proposals or similar processes 
targeting the challenges cited in the NOPR.\3316\ Many commenters ask 
the Commission to ensure the final rule acknowledges and accommodates 
existing interconnection queue reform efforts and does not undo or 
disrupt progress.\3317\ Some commenters specifically ask the Commission 
to allow transmission providers like PJM and Dominion to implement 
recent interconnection queue reform proposals, even though they differ 
in some aspects from the NOPR.\3318\ Some commenters ask the Commission 
to continue applying its current standards for variations from the pro 
forma LGIP (i.e., independent entity variations for RTOs/ISOs and 
consistent with or superior to variations for non-RTOs/ISOs).\3319\ For 
example, ISO-NE contends that the Commission should respect its 
existing independent entity variations and allow it to continue 
building upon those variations.\3320\
---------------------------------------------------------------------------

    \3315\ APPA-LPPC Initial Comments at 2-3; Avangrid Initial 
Comments at 36; Avangrid Reply Comments at 4; Dominion Reply 
Comments at 4; EEI Initial Comments at 3-4; EEI Reply Comments at 
13; Idaho Power Initial Comments at 1; Illinois Commission Comments 
at 3; Indicated PJM TOs Initial Comments at 1-2; Indicated PJM TOs 
Reply Comments at 43; ISO-NE Initial Comments at 3, 13, 15-16, 38; 
MISO TOs Initial Comments at 13; NARUC Initial Comments at 6-7; 
National Grid Initial Comments at 4-5; NEPOOL Initial Comments at 3-
4, 12, 17; NESCOE Reply Comments at 4; NRECA Initial Comments at 7; 
NYTOs Initial Comments at 6; North Dakota Commission Initial 
Comments at 2; Southern Initial Comments at 14-15; U.S. Chamber of 
Commerce Initial Comments at 2-3.
    \3316\ ACORE Reply Comments at 6; Alliant Initial Comments at 1; 
Ameren Initial Comments at 35; APPA-LPPC Initial Comments at 2-3; 
ClearPath Initial Comments at 6; Early Adopters Coalition Initial 
Comments at 2, 13; EEI Initial Comments at 3-4; MISO Initial 
Comments at 2-3, 18; MISO Reply Comments at 2; NARUC Initial 
Comments at 10-11; National Grid Initial Comments at 4-5; NYISO 
Reply Comments at 2; NYTOs Initial Comments at 6; Omaha Public Power 
Initial Comments at 13; U.S. Chamber of Commerce Initial Comments at 
2-3.
    \3317\ ACORE Reply Comments at 6; Alliant Initial Comments at 1; 
APPA-LPPC Initial Comments at 2-3; Ameren Initial Comments at 35; 
Early Adopters Coalition Initial Comments at 2-3, 13, 19, 21; 
Dominion Initial Comments at 42; Dominion Reply Comments at 4; Duke 
Southeast Utilities Initial Comments at 3-4; Illinois Commission 
Comments at 3; Indicated PJM TOs Initial Comments at 1-2; Indicated 
PJM TOs Reply Comments at 9; MISO Initial Comments at 4-5, 18-19, 
128; MISO TOs Initial Comments at 7-9; NARUC Initial Comments at 7, 
11; National Grid Initial Comments at 4-5; NRECA Initial Comments at 
8; NYTOs Initial Comments at 6; Omaha Public Power Initial Comments 
at 13; OMS Initial Comments at 3-4; PacifiCorp Initial Comments at 
2; U.S. Chamber of Commerce Initial Comments at 2-3.
    \3318\ ClearPath Initial Comments at 6; Dominion Initial 
Comments at 5-6; Indicated PJM TOs Initial Comments at 1-2; MISO 
Reply Comments at 2; PJM Initial Comments at 2.
    \3319\ Ameren Initial Comments at 35; Consumer Protection 
Coalition Reply Comments at 2; EEI Initial Comments at 3; Google 
Reply Comments at 7-8; Indicated PJM TOs Initial Comments at 9; 
Indicated PJM TOs Reply Comments at 44; ISO-NE Initial Comments at 
13-15; National Grid Initial Comments at 4-5; NEPOOL Initial 
Comments at 3; NYTOs Initial Comments at 6; PG&E Initial Comments at 
2; PG&E Reply Comments at 2; PJM Initial Comments at 3, 12.
    \3320\ ISO-NE Initial Comments at 8-15 (providing a detailed 
overview of ISO-NE's existing independent entity variations, which 
align the interconnection process with the forward capacity market, 
provide for targeted clustering, and allow interconnection customers 
to pursue elective transmission upgrades to support queued 
interconnection requests).
---------------------------------------------------------------------------

    1751. In contrast, other commenters request that the Commission 
apply a new standard when evaluating variations from the pro forma 
requirements.\3321\ OMS asks the Commission to allow transmission 
providers initiating their own stakeholder-supported interconnection 
reforms to continue developing regionally appropriate solutions upon a 
compliance showing of ``substantial conformity'' with the final rule 
requirements.\3322\ MISO argues that the Commission should create an 
``independent entity presumption of reasonableness,'' under which the 
Commission would rebuttably presume that any previous, proactive RTO/
ISO reform that addresses the objectives of a final rule requirement 
(but does not conform to every detail) is eligible for an independent 
entity variation, unless an intervenor demonstrates that the previous 
reform does not provide the benefit that technical compliance with the 
final rule would.\3323\ NextEra also states that requiring transmission 
providers and stakeholders to have to justify whether their past reform 
initiatives match the Commission's new rule would likely waste time and 
resources.\3324\
---------------------------------------------------------------------------

    \3321\ MISO Initial Comments at 18-19.
    \3322\ OMS Initial Comments at 4.
    \3323\ MISO Initial Comments at 18-19.
    \3324\ NextEra Reply Comments at 7.
---------------------------------------------------------------------------

    1752. Similarly, the Early Adopters Coalition ask the Commission to 
rebuttably presume that first-ready, first-served interconnection queue 
reforms already in place continue to be just and reasonable and not 
unduly discriminatory and consistent with or superior to the pro forma 
requirements.\3325\ Further, the Early Adopters Coalition and Indicated 
PJM TOs argue that there is an insufficient legal foundation under FPA 
section 206 to conclude that the Early Adopters Coalition's tariffs are 
unjust, unreasonable, and unduly discriminatory or preferential because 
the Commission's FPA section 206 finding only speaks to the generic pro 
forma requirements, while many transmission providers' tariffs have 
already departed from those requirements.\3326\ Indicated PJM TOs state 
that the Commission lacks the authority under FPA section 206 to 
require modification of a tariff that does not include the elements 
determined in the final rule to be unjust and unreasonable or unduly 
discriminatory.\3327\
---------------------------------------------------------------------------

    \3325\ Early Adopters Coalition Initial Comments at 18.
    \3326\ Id. at 2, 15 (citing Emera Maine v. FERC, 854 F.3d 9, 25 
(D.C. Cir. 2017)); Indicated PJM TOs Reply Comments at 8; PacifiCorp 
Initial Comments at 6-7.
    \3327\ Indicated PJM TOs Reply Comments at 7-9.
---------------------------------------------------------------------------

    1753. The Early Adopters Coalition also express concern that the 
proposed reforms would result in a higher burden of proof to justify 
departures from the pro forma requirements in future filings and signal 
that the Commission may not accept further incremental improvements; 
therefore, they ask the Commission to clarify that the final rule will 
not stifle their ability to improve their existing tariffs.\3328\
---------------------------------------------------------------------------

    \3328\ Early Adopters Coalition Initial Comments at 21.
---------------------------------------------------------------------------

    1754. PacifiCorp expresses concern that the NOPR proposal could 
disrupt some of PacifiCorp's unique processes, including its inclusion 
of small generating facilities in the cluster study process with large 
generating facilities and its incorporation of the Commission-
jurisdictional interconnection process into its state-level 
interconnection procedures.\3329\
---------------------------------------------------------------------------

    \3329\ PacifiCorp Initial Comments at 7-9.
---------------------------------------------------------------------------

    1755. CREA and NewSun contest PacifiCorp's and the other Early 
Adopters Coalition's argument that the Commission's approval of their 
LGIPs under FPA section 205 exempts them from any reforms adopted in a 
final rule in this proceeding because the Commission has an obligation 
under FPA section 206 to remedy unjust, unreasonable, and unduly 
discriminatory or preferential practices.\3330\ CREA and NewSun also 
note that neither utility- nor region-specific findings are necessary 
in a generic rulemaking; rather, the Commission can rely on basic 
economic theory and generic factual predictions.\3331\ CREA and NewSun 
also

[[Page 61256]]

assert that the sole authority cited by the Early Adopters Coalition, 
Emera Maine v. FERC, is inapposite, because it involved a challenge to 
a specific transmission owners' base return on equity, not a nationwide 
rulemaking.\3332\
---------------------------------------------------------------------------

    \3330\ CREA and NewSun Reply Comments at 15-16.
    \3331\ Id. at 17-18 (citing Transmission Access Policy Study 
Grp. v. FERC, 225 F.3d 667, 687 (D.C. Cir. 2000), aff'd sub nom. New 
York v. FERC, 535 U.S. 1, 14 (2002); Xcel Energy Servs. v. FERC, 41 
F.4th 548, 560-61 (D.C. Cir. 2022)).
    \3332\ Id. at 19.
---------------------------------------------------------------------------

    1756. In response to requests for additional flexibility, Public 
Interest Organizations and Clean Energy Associations assert that 
transmission providers should be required to demonstrate in compliance 
filings that their approach to a given requirement complies with the 
Commission's final rule.\3333\
---------------------------------------------------------------------------

    \3333\ Clean Energy Associations Reply Comments at 11; Public 
Interest Organizations Reply Comments at 14.
---------------------------------------------------------------------------

    1757. Xcel asks the Commission to state in the final rule that 
there is not just one just and reasonable approach to interconnection 
reform.\3334\ Xcel requests that the Commission confirm that 
alternative approaches used by RTOs/ISOs that achieve the policy goals 
of prioritizing ready interconnection requests and increasing the speed 
of interconnection queue processing are consistent with and superior to 
the pro forma LGIP, instead of using the independent entity variation 
standard when approving those RTOs/ISOs' compliance filings. Xcel 
explains that its preferred approach would allow non-RTOs/ISOs to 
replicate processes that are working efficiently in RTOs/ISOs.
---------------------------------------------------------------------------

    \3334\ Xcel Initial Comments at 17.
---------------------------------------------------------------------------

    1758. ACORE expresses concern that too much flexibility would 
detract from the benefits of a final rule.\3335\ ACORE explains that a 
consistent minimum set of requirements and common interconnection study 
methods and best practices is essential across all transmission 
providers.
---------------------------------------------------------------------------

    \3335\ ACORE Reply Comments at 6.
---------------------------------------------------------------------------

3. Reciprocity Tariffs
    1759. APPA-LPPC and NRECA seek clarification on the NOPR's 
statements regarding reciprocity tariffs.\3336\ They point out that 
Commission precedent allows non-public utilities to satisfy the 
reciprocity requirement of Order No. 888 through one of three means: 
(1) providing service to a public utility transmission provider under a 
safe harbor tariff; (2) providing service under a bilateral agreement; 
or (3) seeking waiver.\3337\ APPA-LPPC and NRECA explain that the 
NOPR's statement that non-public utility transmission providers ``will 
have to adopt the requirements of this Proposed Rule as a condition of 
maintaining the status of their safe harbor tariff or otherwise 
satisfying the reciprocity requirement of Order No. 888'' could be read 
to suggest that the other ways of satisfying the reciprocity 
requirement no longer exist.\3338\ APPA-LPPC and NRECA ask the 
Commission to clarify that non-public utilities will still be able to 
satisfy reciprocity requirements through bilateral arrangements or 
waiver.
---------------------------------------------------------------------------

    \3336\ APPA-LPPC Initial Comments at 34-36; NRECA Initial 
Comments at 10, 50.
    \3337\ APPA-LPPC Initial Comments at 34; NRECA Initial Comments 
at 50.
    \3338\ APPA-LPPC Initial Comments at 36; NRECA Initial Comments 
at 51.
---------------------------------------------------------------------------

4. Effective Date
    1760. MISO asks the Commission to make the reforms effective when 
orders on compliance are issued, rather than on the final rule's 
effective date, to avoid retroactive implementation of the proposed 
reforms and disruption in administering interconnection queues.\3339\ 
MISO explains that an effective date prior to the date of accepted 
compliance provisions would require a transmission provider to file new 
agreements with pending language, which means that transmission 
providers will need to file interconnection agreements and service 
agreements instead of using the electronic quarterly report (EQR) 
process.
---------------------------------------------------------------------------

    \3339\ MISO Initial Comments at 127; MISO Reply Comments at 27.
---------------------------------------------------------------------------

5. Miscellaneous
    1761. SoCal Edison states that the final rule should not 
automatically apply to a wholesale distribution access tariff without 
further consideration in a separate rulemaking.\3340\ SoCal Edison 
argues that the Commission should allow entities to align distribution-
level tariffs with corresponding transmission-level tariffs to avoid 
gaming of interconnection locations and contends that the changes 
proposed in this NOPR are too extensive to apply to the unique 
characteristics of the distribution system.\3341\ SoCal Edison states 
that the Commission has previously confirmed that reforms to the LGIP 
and LGIA are not required for the interconnection agreements under the 
wholesale distribution access tariff, and different processes, 
interconnection costs, and penalties could introduce new challenges for 
wholesale distribution providers and interconnection efficiencies that 
have not been addressed in the NOPR.
---------------------------------------------------------------------------

    \3340\ SoCal Edison Initial Comments at 10; SoCal Edison Reply 
Comments at 2.
    \3341\ SoCal Edison Initial Comments at 10-11.
---------------------------------------------------------------------------

C. Commission Determination

    1762. We modify the deadline for transmission providers to submit a 
compliance filing to adopt the requirements of this final rule as 
revisions to the LGIP, LGIA, SGIP, and SGIA in their tariffs. We 
require the submission of such compliance filings within 90 calendar 
days of the publication date of this final rule in the Federal Register 
rather than the proposed 180 days from the effective date of the final 
rule. We believe that it is important to implement this final rule in a 
timely manner, given the pressing need to reform the interconnection 
processes, as discussed in this final rule. On the Commission-approved 
effective date of the transmission provider's compliance filing with 
this final rule, the transmission provider will commence the transition 
study process.\3342\ After the conclusion of the transition study 
process, the transmission provider will begin the first standard 
cluster study process,\3343\ and in its compliance filing, the 
transmission provider will indicate the number of calendar days after 
the conclusion of the transition study process when it will begin this 
first standard cluster study process (e.g., 30 calendar days after the 
conclusion of the transition study process).\3344\ By setting a 90-
calendar day compliance filing deadline, the Commission may be in a 
position to act on the filings sooner, which will allow transmission 
providers to commence the transition process and progress to the first 
standard cluster study process earlier, and thereby implement the 
reforms contemplated by this final rule earlier rather than later.
---------------------------------------------------------------------------

    \3342\ Pro forma LGIP section 5.1.1.1 (Transitional Serial 
Study); Pro forma LGIP section 5.1.1.2 (Transitional Cluster Study).
    \3343\ We note that this standard cluster study process is 
distinct from the transitional cluster study process described 
above. See supra section III.A.7.c.
    \3344\ Pro forma LGIP section 3.4.1 (Cluster Request Window).
---------------------------------------------------------------------------

    1763. We note that 90 days is longer than the 60 days provided for 
compliance with Order No. 2003. In their compliance filings for Order 
No. 2003, transmission providers were required to adopt the pro forma 
LGIP and pro forma LGIA. Under this final rule, transmission providers 
are required to revise the LGIP, LGIA, SGIP, and SGIA in their tariffs, 
but are not provided significant discretion as to the terms of those 
documents, except for those who request deviations, as discussed below. 
While we recognize that the compliance filings for some transmission 
providers will entail more complexity, we believe that 90 calendar

[[Page 61257]]

days should be sufficient time to prepare and submit even the more 
complex compliance filings. Further, the need to implement the reforms 
set forth in this final rule earlier rather than later outweighs the 
concerns raised about the timing of the compliance filing deadline.
    1764. Consistent with Order Nos. 888, 890, 2003, 2006, and 845, we 
adopt the NOPR proposal to continue to apply the ``consistent with or 
superior to'' standard when considering proposals from non-RTO/ISO 
transmission providers to deviate from the requirements of this final 
rule.\3345\ Consistent with Order Nos. 2003, 2006, and 845, we adopt 
the NOPR proposal to continue to use the ``independent entity 
variation'' standard when considering such proposals from RTOs/
ISOs.\3346\ Consistent with Order Nos. 888, 890, 2003, 2006, and 845, 
we adopt the NOPR proposal to continue to allow non-RTO/ISO 
transmission providers to use the regional differences rationale to 
seek variations made in response to established reliability 
requirements.\3347\ In this final rule, we make no changes to the 
standards used to judge requested variations, as described in Order 
Nos. 888, 890, 2003, 2006, and 845.
---------------------------------------------------------------------------

    \3345\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,769-
770; Order No. 890, 118 FERC ] 61,119 at P 109 (``[W]e reiterate 
that any departures from the pro forma [open access transmission 
tariff] proposed by an ISO or an RTO must be `consistent with or 
superior to' the pro forma [open access transmission tariff] in this 
Final Rule.''); Order No. 2003, 104 FERC ] 61,103 at P 825; Order 
No. 2006, 111 FERC ] 61,220 at PP 546-547; Order No. 845, 163 FERC ] 
61,043 at P 43 (explaining that a transmission provider that is not 
an RTO/ISO that seeks a variation from the requirements of the final 
rule must present its justification for the variation as consistent 
with or superior to the pro forma LGIA or pro forma LGIP).
    \3346\ Order No. 2003, 104 FERC ] 61,103 at P 826 (``[w]ith 
respect to an RTO or ISO . . . we will allow it to seek `independent 
entity variations' from the Final Rule . . . This is a balanced 
approach that recognizes that an RTO or ISO has different operating 
characteristics depending on its size and location and is less 
likely to act in an unduly discriminatory manner than a Transmission 
Provider that is a market participant.''); Order No. 2006, 111 FERC 
] 61,220 at PP 447, 549; Order No. 845, 163 FERC ] 61,043 at P 556.
    \3347\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,770; 
Order No. 890, 118 FERC ] 61,119 at P 109; Order No. 2003, 104 FERC 
] 61,103 at P 826 (``if on compliance a non-RTO or ISO Transmission 
Provider offers a variation from the Final Rule LGIP and Final Rule 
LGIA, and the variation is in response to established (i.e., 
approved by the Applicable Reliability Council) reliability 
requirements, then it may seek to justify its variation using the 
regional difference rationale.''); Order No. 2006, 111 FERC ] 61,220 
at PP 546-547; Order No. 845, 163 FERC ] 61,043 at P 43.
---------------------------------------------------------------------------

    1765. We reject requests to presume that any transmission 
provider's tariff meets the requirements of this final rule. We 
recognize that many transmission providers have adopted or are in the 
process of adopting similar reforms to those adopted in this final 
rule. We do not intend to disrupt these ongoing transition processes or 
stifle further innovation. On compliance, transmission providers can 
propose deviations from the requirements adopted in this final rule--
including deviations seeking to minimize interference with ongoing 
transition plans--and demonstrate how those deviations satisfy the 
standards discussed above, which the Commission will consider on a 
case-by-case basis.
    1766. We disagree with commenters that suggest that FPA section 206 
requires the Commission to make findings specific to each transmission 
provider's tariff in this final rule to require transmission providers 
to comply with the requirements of this final rule. As some commenters 
recognize, neither utility- nor region-specific findings are necessary 
in a generic rulemaking.\3348\
---------------------------------------------------------------------------

    \3348\ See Transmission Access Policy Study Grp., 225 F.3d at 
687-88.
---------------------------------------------------------------------------

    1767. In response to commenters that prefer regional reform over 
generic one-size-fits-all reform, we note that transmission providers 
may seek the appropriate variation on compliance provided the reason 
for the variation is sufficiently justified and may continue to propose 
solutions to interconnection issues under FPA section 205. However, 
given the nation-wide need for reforms to ensure that interconnection 
customers are able to interconnect to the transmission system in a 
reliable, efficient, transparent, and timely manner, as well as prevent 
undue discrimination, we believe that a generic rulemaking is 
appropriate, as explained above in section II and throughout this final 
rule.
    1768. In the NOPR, the Commission stated that non-public utility 
transmission providers ``will have to adopt the requirements of this 
Proposed Rule as a condition of maintaining the status of their safe 
harbor tariff or otherwise satisfying the reciprocity requirement of 
Order No. 888.'' \3349\ As requested by NRECA and APPA-LPPC,\3350\ we 
clarify that this final rule does not modify the Commission's 
reciprocity requirement in Order Nos. 888 and 2003.\3351\ Thus, while a 
non-public utility's adoption of the proposed LGIP/LGIA and SGIP/SGIA 
changes is a condition of maintaining a safe harbor tariff,\3352\ non-
public utilities may still use a request for waiver or bilateral 
agreements to satisfy the reciprocity requirement of Order No. 888-
A.\3353\
---------------------------------------------------------------------------

    \3349\ NOPR, 179 FERC ] 61,194 at P 344.
    \3350\ APPA-LLC Initial Comments at 34-36; NRECA Initial 
Comments at 50-51.
    \3351\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,760-
761; Order No. 2003, 104 FERC ] 61,103 at PP 840-842.
    \3352\ Order No. 2003, 104 FERC ] 61,103 at P 842 (``A non-
public utility that has a `safe harbor' Tariff may add to its Tariff 
an interconnection agreement and interconnection procedures that 
substantially conform or are superior to the Final Rule LGIP and 
Final Rule LGIA if it wishes to continue to qualify for safe harbor 
treatment.'')
    \3353\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,285-
86; see also Order No. 2003, 104 FERC ] 61,103 at P 841; Order No. 
2003-A, 106 FERC ] 61,220 at P 760 (clarifying that reciprocity 
applies to interconnection service in a manner consistent with the 
reciprocity provision in the pro forma open access transmission 
tariff); Order No. 2006, 111 FERC ] 61,220 at P 534.
---------------------------------------------------------------------------

    1769. With respect to MISO's comments, as explained below, this 
final rule is effective November 6, 2023. This final rule will be 
effective as described above; however, the pro forma LGIP, pro forma 
LGIA, pro forma SGIP, and pro forma SGIP requirements in transmission 
providers' tariffs will not be effective until the Commission-approved 
effective date of the transmission provider's filing in compliance with 
this final rule. In other words, interconnection customers seeking to 
interconnect to MISO's transmission system will not be subject to the 
requirements of this final rule until the Commission issues an order on 
MISO's compliance filing with a Commission-approved effective date for 
MISO's tariff revisions.
    1770. In response to SoCal Edison's request for the Commission to 
clarify that the reforms described herein will not automatically apply 
to wholesale distribution access tariffs, we note that in Order No. 
2003, the Commission stated that the pro forma LGIA and pro forma LGIP 
adopted in that final rule apply to a request to interconnect to a 
public utility's ``distribution'' facilities used to transmit electric 
energy in interstate commerce on behalf of a wholesale purchaser 
pursuant to a Commission-filed open access transmission tariff.\3354\ 
To the extent that SoCal Edison has concerns about its specific 
wholesale distribution access

[[Page 61258]]

tariff, this is a matter better suited to SoCal Edison's compliance 
filing.\3355\
---------------------------------------------------------------------------

    \3354\ See Order No. 2003, 104 FERC ] 61,103 at P 804; id. P 803 
(some lower-voltage facilities are ``local distribution'' facilities 
not under our jurisdiction, but some are used for jurisdictional 
service such as carrying power to a wholesale power customer for 
resale and are included in a public utility's open access 
transmission tariff (although in some instances, there is a separate 
open access transmission tariff rate for using them, sometimes 
called a wholesale distribution rate.)); Order No. 2003-A, 106 FERC 
] 61,220 at P 733 (``We clarify that Order No. 2003 applies to all 
facilities subject to a Commission-approved [open access 
transmission tariff], regardless of how the facilities may be 
labeled by the Transmission Provider) (citing N. Y. v. FERC, 535 
U.S. at 12; Puget Sound Energy, Inc., 104 FERC ] 61,272, at PP 16-18 
(2003)).
    \3355\ See Order No. 2003-A, 106 FERC ] 61,220 at P 734. We 
note, however, that the Commission has previously accepted SoCal 
Edison's filing, made in compliance with Order No. 2003, to 
implement provisions from the Commission's pro forma LGIA and pro 
forma LGIP into its wholesale distribution access tariff. See S. 
Cal. Edison Co., 110 FERC ] 61,176 (2005).
---------------------------------------------------------------------------

    1771. We also note that, in addition to the modifications described 
above, the pro forma LGIP, pro forma LGIA, pro forma SGIP, pro forma 
SGIP language below includes several corrections of clerical errors and 
other minor, clarifying edits: see, e.g., pro forma LGIA article 8.4, 
pro forma LGIP appendix G.

V. Information Collection Statement

    1772. The information collection requirements contained in this 
final rule are subject to review by the Office of Management and Budget 
(OMB) under section 3507(d) of the Paperwork Reduction Act of 
1995.\3356\ OMB's regulations require approval of certain information 
collection requirements imposed by agency rules.\3357\ Respondents 
subject to the filing requirements of this final rule will not be 
penalized for failing to respond to the collection of information 
unless the collection of information displays a valid OMB control 
number.
---------------------------------------------------------------------------

    \3356\ 44 U.S.C. 3507(d).
    \3357\ 5 CFR 1320.11 (2022).
---------------------------------------------------------------------------

    1773. The reforms adopted in this final rule revise the 
Commission's standard large generator interconnection procedures and 
agreements (i.e., the pro forma LGIP and pro forma LGIA) and the 
Commission's standard small generator interconnection procedures and 
agreement (i.e., the pro forma SGIP and pro forma SGIA) that every 
public utility transmission provider is required to include in their 
tariff under Sec.  35.28 of the Commission's regulations.\3358\ This 
final rule requires each transmission provider to amend the standard 
large generator interconnection procedures and agreement and the 
standard small generator interconnection procedures and agreement in 
its tariff to implement the reforms adopted in this final rule, which 
are intended to ensure that the generator interconnection process is 
just, reasonable, and not unduly discriminatory or preferential. These 
provisions affect the following collections of information: FERC-516, 
Electric Rate Schedules and Tariff Filings (Control No. 1902-0096); and 
FERC-516A, Standardization of Small Generator Interconnection 
Agreements and Procedures (Control No. 1902-0203).
---------------------------------------------------------------------------

    \3358\ 18 CFR 35.28(f)(1) (2022).
---------------------------------------------------------------------------

    1774. In the NOPR, the Commission solicited comments on: the 
Commission's need for this information; whether the information will 
have practical utility; the accuracy of the burden estimates; ways to 
enhance the quality, utility, and clarity of the information to be 
collected or retained; and any suggested methods for minimizing 
respondents' burden. In response to comments on the NOPR,\3359\ we note 
that this information collection statement estimates only those burdens 
\3360\ to generate, maintain, retain, or disclose or provide 
information to or for a Federal agency, and does not intend to estimate 
overall compliance or implementation costs for transmission providers.
---------------------------------------------------------------------------

    \3359\ Indicated PJM TOs state that the NOPR did not attempt to 
quantify the administrative burden for the transmission provider's 
staff to perform the tasks required by the proposed reforms, and SPP 
offered an estimated range of its potential costs of administering 
the proposed procedures. See Indicated PJM TOs Initial Comments at 
7; SPP Initial Comments at 28; see also NOPR, 179 FERC ] 61,194 at P 
358 & n.480.
    \3360\ ``Burden'' is the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, or 
disclose or provide information to or for a Federal agency. For 
further explanation of what is included in the information 
collection burden, refer to 5 CFR 1320.3 (2022).
---------------------------------------------------------------------------

    1775. Summary of the Revisions to the Collection of Information due 
to the final rule in Docket No. RM22-14-000:
     FERC-516: This final rule revises the Commission's pro 
forma LGIP and pro forma LGIA (and thus requires each public utility to 
amend its LGIP and LGIA) to ensure that interconnection customers are 
able to interconnect to the transmission system in a reliable, 
efficient, transparent, and timely manner, and prevent undue 
discrimination. As illustrated in the table below, most reforms affect 
the pro forma LGIP and pro forma LGIA.
     FERC-516A: Among other requirements, this final rule 
amends the Commission's standard small generator interconnection 
procedures and agreement (i.e., the pro forma SGIP and pro forma SGIA) 
regarding evaluation of alternative transmission technologies, modeling 
required for accurate interconnection studies, and maintenance of power 
production during abnormal frequency conditions and certain voltage 
conditions.
     Title: Electric Rate Schedules and Tariff Filings (FERC-
516) and Standardization of Small Generator Interconnection Agreements 
and Procedures (FERC-516A).
     Action: Revision of collections of information in 
accordance with Docket No. RM22-14-000.
     OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0203 
(FERC-516A).
     Respondents: Public utility transmission providers, 
including RTOs/ISOs.
     Frequency of Information Collection: One time during Year 
1. Multiple times during subsequent years.
     Necessity of Information: The reforms in this final rule 
ensure that interconnection customers are able to interconnect to the 
transmission system in a reliable, efficient, transparent, and timely 
manner, and prevent undue discrimination. The reforms are intended to 
ensure that the generator interconnection process is just, reasonable, 
and not unduly discriminatory or preferential.
     Internal Review: We have reviewed the reforms that impose 
information collection burdens and have determined that such reforms 
are necessary. These requirements conform to the Commission's need for 
efficient information collection, communication, and management within 
the energy industry. We have specific, objective support for the burden 
estimates associated with the information collection requirements.
     Public Reporting Burden: Our estimate of the number of 
reporting entities is based on the number of transmission providers 
that submitted compliance filings to the Commission in response to 
Order No. 845, which is the Commission's most recent rulemaking that 
required transmission providers to revise their generator 
interconnection procedures and agreements, and Order No. 881, which is 
the Commission's most recent major rulemaking adopting reforms to the 
pro forma tariff. As such, we estimate that 44 transmission providers, 
including RTOs/ISOs, will be subject to this rulemaking. The burden and 
cost estimates below are based on (1) the initial need for transmission 
providers to file revised versions of the standard interconnection 
procedures and agreements in Year 1 and (2) ongoing information 
collection activities in connection with reporting and disclosure 
requirements in subsequent years. For many reforms, we estimate no 
ongoing information collection burden because there is either no 
information collection aspect of the reform or the requirements would 
merely supplant existing ones.
    1776. The Commission estimates that the final rule in Docket No. 
RM22-14-000 will adjust the burden and cost of FERC-516 and FERC-516A 
as follows:

[[Page 61259]]

                                                      Table 1--Information Collection Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                   Changes due to Final Rule in Docket No. RM22-14-000
---------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Annual number of                             Average burden (hr.) &    Total annual burden
               Reforms                    Number of           responses per           Total number of      cost ($) per response   hours & total annual
                                         respondents            respondent          responses (rounded)           \3361\            cost ($) (rounded)
                                                    (1)  (2)....................  (1) * (2) = (3).......  (4)...................  (3) * (4) = (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        FERC-516
--------------------------------------------------------------------------------------------------------------------------------------------------------
Interconnection Information Access..           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 2.............  Ongoing: 88...........  Ongoing: 4 hr; $364...   $16,016
                                                                                                                                  Ongoing: 352 hr;
                                                                                                                                   $32,032
First Ready, First Served Cluster              44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Study Process.                                          Ongoing: 4.............  Ongoing: 176..........  Ongoing: 4 hr; $364...   $320,320
                                                                                                                                  Ongoing: 704 hr;
                                                                                                                                   $64,064
Allocation of Cluster Study Costs...           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Allocation of Cluster Network                  44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
 Upgrade Costs.                                          Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Study Deposits and LGIA Deposit.....           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Demonstration of Site Control.......           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $320,320
                                                                                                                                  Ongoing: 0
Commercial Readiness................           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Withdrawal Penalties................           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Transition Process..................           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............  $320,320
                                                                                                                                  Ongoing: 0
Elimination of Reasonable Efforts              44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Standard.\3362\.                                        Ongoing: 4.............  Ongoing: 176..........  Ongoing: 4 hr; $364...  $320,320
                                                                                                                                  Ongoing: 704 hr;
                                                                                                                                   $64,064
Affected System Study Process.......           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
                                                         Ongoing: 0.............  Ongoing: 44...........  Ongoing: 0............   $320,320
                                                                                                                                  Ongoing: 0
Affected System Pro Forma Agreements           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Affected System Modeling and Study             44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
 Assumptions.                                            Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Co-Located Generating Facilities               44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
 Behind One Point of Interconnection                     Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
 with Shared Interconnection                                                                                                      Ongoing: 0
 Requests.
Revisions to Modification to Require           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Consideration of Generating                             Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $320,320
 Facility Additions.                                                                                                              Ongoing: 0
Availability of Surplus                        44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
 Interconnection Service.                                Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Operating Assumptions for                      44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Interconnection Studies.                                Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $320,320
                                                                                                                                  Ongoing: 0
Incorporating Enumerated Alternative           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Transmission Technologies into the                      Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $320,320
 Generator Interconnection Process.                                                                                               Ongoing: 0
Modeling Requirements...............           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Ride-Through Requirements...........           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Applicability of Ride-Through                  44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
 Requirements.                                           Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
                                     -------------------------------------------------------------------------------------------------------------------
    Total New Burden for FERC-516     .................      Year 1: 924 Ongoing: 1,760 hr; $160,160
     (due to Docket No. RM22-14-000).
                                      Year 1: 30,448 hr; $2,770,768 Ongoing: 484
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 61260]]

 
                                                                        FERC-516A
--------------------------------------------------------------------------------------------------------------------------------------------------------
Incorporating Enumerated Alternative           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Transmission Technologies into the                      Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $320,320
 Generator Interconnection Process.                                                                                               Ongoing: 0
Modeling Requirements...............           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
Ride-Through Requirements...........           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                                                                  Ongoing: 0
                                     -------------------------------------------------------------------------------------------------------------------
    Total New Burden for FERC-516A    .................          Year 1: 132 responses Ongoing: 0
     (due to Docket No. RM22-14-000).
                                         Year 1: 3,872 hr; $352,352 Ongoing: 0
                                     -------------------------------------------------------------------------------------------------------------------
        Grand Total (FERC-516 plus    .................             Year 1: 1,056 Ongoing: 484
         FERC-516A, including all
         respondents).
                                        Year 1: 34,320 hr; $3,123,120 Ongoing:
                                                  1,760 hr; $160,160
                                     -------------------------------------------------------------------------------------------------------------------
        Grand Total Average Per       .................  .......................  ......................          Year 1: $70,980 Ongoing: $3,640
         Entity Cost (44 TPs).
--------------------------------------------------------------------------------------------------------------------------------------------------------

    1777. In this final rule, after accounting for the adjustments and 
inputs noted above, updated labor costs, and reforms not being adopted, 
the Commission used the numbers provided in the NOPR for all reforms 
being adopted.
---------------------------------------------------------------------------

    \3361\ Commission staff estimate that respondents' hourly wages 
plus benefits are comparable to those of FERC employees. Therefore, 
the hourly cost used in this analysis is $91 per hour ($188,922 per 
year).
    \3362\ Commission staff only estimates the information 
collection burden associated with the requirements outlined in the 
final rule and does not estimate the potential appeal process 
burden, which an applicant can pursue voluntarily.
---------------------------------------------------------------------------

    1778. Interested persons may obtain information on the reporting 
requirements by contacting Ellen Brown, Office of the Executive 
Director, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426 via email ([email protected]) or telephone 
((202) 502-8663).

VI. Environmental Analysis

    1779. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\3363\ We 
conclude that neither an Environmental Assessment nor an Environmental 
Impact Statement is required for this final rule under Sec.  
380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale of electric energy subject to 
the Commission's jurisdiction, plus the classification, practices, 
contracts, and regulations that affect rates, charges, classification, 
and services.\3364\
---------------------------------------------------------------------------

    \3363\ Regulations Implementing the National Environmental 
Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. 
& Regs. Preambles 1986-1990 ] 30,783 (1987) (cross-referenced at 41 
FERC ] 61,284).
    \3364\ 18 CFR 380.4(a)(15) (2022).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    1780. The Regulatory Flexibility Act of 1980 \3365\ requires a 
description and analysis of proposed and final rules that will have 
significant economic impact on a substantial number of small entities. 
The Small Business Administration (SBA) sets the threshold for what 
constitutes a small business. Under SBA's size standards,\3366\ 
transmission providers and RTOs/ISOs fall under the category of 
Electric Bulk Power Transmission and Control (North American Industry 
Classification System (NAICS) code 221121), that has a size threshold 
of under 950 employees (including the entity and its associates).\3367\
---------------------------------------------------------------------------

    \3365\ 5 U.S.C. 601-612.
    \3366\ 13 CFR 121.201 (2022).
    \3367\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administration's regulations define the threshold for 
a small Electric Bulk Power Transmission and Control entity (NAICS 
code 221121) to be 950 employees (``the maximum allowed for a 
concern and its affiliates to be considered small''). See 13 CFR 
121.201 (2022); see also 5 U.S.C. 601(3) (citing to section 3 of the 
Small Business Act, 15 U.S.C. 632).
---------------------------------------------------------------------------

    1781. We estimate that there are 44 transmission providers affected 
by the reforms proposed in this final rule. Furthermore, we estimate 
that 6 of the 44 total transmission providers, approximately 14% 
(rounded), are small entities.
    1782. We estimate that one-time costs (in Year 1) associated with 
the reforms required by this final rule for one transmission provider 
(as shown in the table above) would be $70,980. Following Year 1, we 
estimate that the annual ongoing costs for one transmission provider 
would be $3,640. According to SBA guidance, the determination of 
significance of impact ``should be seen as relative to the size of the 
business, the size of the competitor's business, and the impact the 
regulation has on larger competitors.'' \3368\ We do not consider the 
estimated cost to be a significant economic impact. As a result, we 
certify that the reforms proposed in this final rule would not have a 
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \3368\ U.S. Small Business Administration, A Guide for 
Government Agencies How to Comply with the Regulatory Flexibility 
Act, at 18 (Aug. 2017), https://cdn.advocacy.sba.gov/wp-content/uploads/2019/06/21110349/How-to-Comply-with-the-RFA.pdf.
---------------------------------------------------------------------------

VIII. Document Availability

    1783. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the

[[Page 61261]]

Commission's Home Page (https://www.ferc.gov).
    1784. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number in the docket number field. User assistance is 
available for eLibrary and the Commission's website during normal 
business hours from the Commission's Online Support at (202) 502-6652 
(toll free at 1-866-208-3676) or email at [email protected], 
or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. 
Email the Public Reference Room at [email protected].

IX. Effective Date and Congressional Notification

    1785. The final rule is effective November 6, 2023. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission. Commissioner Danly is concurring with a separate 
statement attached.
    Commissioner Clements is concurring with a separate statement 
attached.
    Commissioner Christie is concurring with a separate statement 
attached.

    Issued: July 28, 2023.
Kimberly D. Bose,
Secretary.

    In consideration of the foregoing, the Commission amends part 35, 
chapter I, title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.28 by adding paragraph (f)(1)(ii) to read as follows:

Sec.  35.28   Non-discriminatory open access transmission tariff.

* * * * *
    (f) * * *
    (1) * * *
    (ii) Any public utility that conducts interconnection studies shall 
be liable for and eligible to appeal certain penalties under the 
interconnection procedures and agreements adopted by the Commission-
approved independent system operator or regional transmission 
organization under paragraph (f)(1) of this section following that 
public utility's failure to complete an interconnection study by the 
appropriate deadline.
* * * * *

    NOTE:  The following appendices will not appear in the Code of 
Federal Regulations.

Appendix A: Abbreviated Names of Commenters

------------------------------------------------------------------------
 
------------------------------------------------------------------------
Americans for a Clean Energy Grid...............  ACEG.
Alliance for Clean Energy-New York..............  ACE-NY.
American Council on Renewable Energy............  ACORE.
Associated Electric Cooperative, Inc............  AECI.
Advanced Energy Economy.........................  AEE.
American Electric Power Service Corporation.....  AEP.
AES Clean Energy Development, LLC...............  AES.
Acciona Energy USA Global LLC; Copenhagen         Affected
 Infrastructure IV K/S; Hecate Energy LLC;         Interconnection
 Leeward Renewable Energy Development, LLC; and    Customers.
 Tri Global Energy, LLC.
Allen Meyer.....................................  Allen Meyer.
Alliant Energy Corporate Services, Inc..........  Alliant Energy.
Amazon Energy LLC...............................  Amazon.
Ameren Services Company.........................  Ameren.
Ampjack Industries Ltd..........................  Ampjack.
Anbaric Development Partners, LLC...............  Anbaric.
American Public Power Association and Large       APPA-LPPC.
 Public Power Council.
Apple Inc.......................................  Apple.
Arizona Public Service Company..................  APS.
Arizona Corporation Commission..................  Arizona Commission.
Avangrid, Inc...................................  Avangrid.
Bonneville Power Administration.................  Bonneville.
Bretton C Little................................  Bretton C Little.
California Independent System Operator            CAISO.
 Corporation.
California Energy Storage Alliance..............  CESA.
The American Clean Power Association and RENEW    Clean Energy
 Northeast.                                        Associations.
Clean Energy Buyers Association.................  Clean Energy Buyers.
Clean Energy States Alliance....................  Clean Energy States.
ClearPath, Inc..................................  ClearPath.
Colorado Public Utilities Commission............  Colorado Commission.
Interconnection Cost Consumer Protection          Consumer Protection
 Coalition.                                        Coalition.
Consumers Energy Company........................  Consumers Energy.
Community Renewable Energy Association and        CREA and NewSun.
 NewSun Energy LLC.
CTC Global Corporation..........................  CTC Global.
Cypress Creek Renewables, LLC...................  Cypress Creek.
Dominion Energy Services, Inc...................  Dominion.
Duke Energy Carolinas, LLC; Duke Energy           Duke Southeast
 Progress, LLC; and Duke Energy Florida, LLC.      Utilities.
Duke Energy Carolinas, LLC; Duke Energy           Early Adopters
 Progress, LLC; Dominion Energy South Carolina     Coalition.
 Inc.; PacifiCorp; Public Service Company of
 Colorado; and Tri-State Generation and
 Transmission Association, Inc.
Environmental Defense Fund......................  Environmental Defense
                                                   Fund.
EDF Renewables LLC..............................  EDF Renewables.
Edison Electric Institute.......................  EEI.
El Paso Electric Company........................  El Paso Electric.
Electricity Consumers Resource Council..........  ELCON.
Elevate Renewable Energy F7, LLC................  Elevate.
North American Electric Reliability Corporation;  NERC.
 Midwest Reliability Organization; Northeast
 Power Coordinating Council, Inc.;
 ReliabilityFirst Corporation; SERC Reliability
 Corporation; Texas Reliability Entity, Inc.;
 and Western Electricity Coordinating Council.
Enel North America, Inc.........................  Enel.

[[Page 61262]]

 
Energy Keepers, Inc.............................  Energy Keepers.
ENGIE North America, Inc........................  ENGIE.
Electric Power Research Institute...............  EPRI.
Electric Power Supply Association...............  EPSA.
Equinor Wind US LLC.............................  Equinor Wind.
Evergreen Action................................  Evergreen Action.
Eversource Energy Service Company...............  Eversource.
Fervo Energy Company............................  Fervo Energy.
Golden State Clean Energy.......................  GCSE.
Google LLC......................................  Google.
Guzman Energy LLC...............................  Guzman Energy.
Hannon Armstrong Sustainable Infrastructure       Hannon Armstrong.
 Capital, Inc.
Rye Development, LLC; rPlus Hydro, LLP; Nelson    Hydropower Commenters.
 Energy LLC; Advanced Hydro Solutions LLC; Hydro
 Green Energy, LLC; Natel Energy, Inc.; and
 Sorenson Engineering, Inc. and its affiliates,
 Cat Creek Energy, LLC and National Hydropower
 Association.
Idaho Power Company.............................  Idaho Power.
Illinois Commerce Commission....................  Illinois Commission.
Citizens Utility Board of Illinois..............  Illinois CUB.
Indicated PJM Transmission Owners...............  Indicated PJM TOs.
4,293 people collected Evergreen Action.........  Individual
                                                   Signatories.
Interwest Energy Alliance.......................  Interwest.
Invenergy Solar Development North America LLC;    Invenergy.
 Invenergy Thermal Development LLC; Invenergy
 Wind Development North America LLC; and
 Invenergy Transmission LLC.
Iowa Utilities Board............................  Iowa Commission.
Interstate Renewable Energy Council.............  IREC.
ISO New England Inc.............................  ISO-NE.
ISO/RTO Council.................................  ISO/RTO Council.
Los Angeles Department of Water and Power.......  LADWP.
Longroad Energy Holdings, LLC...................  Longroad Energy.
Lori Ecker......................................  Lori Ecker.
Microgrid Resources Coalition...................  Microgrid Resources.
Midcontinent Independent System Operator, Inc...  MISO.
MISO Transmission Owners........................  MISO TOs.
National Association of Regulatory Utility        NARUC.
 Commissioners.
National Grid Plc...............................  National Grid.
New England Power Pool Participants Committee...  NEPOOL.
New England States Committee on Electricity.....  NESCOE.
New Jersey Board of Public Utilities............  New Jersey Commission.
New York State Department of State Utility        New York State
 Intervention Unit.                                Department.
NextEra Energy, Inc.............................  NextEra.
North Carolina Utilities Commission and North     North Carolina
 Carolina Utilities Commission Public Staff.       Commission and Staff.
North Dakota Public Service Commission..........  North Dakota
                                                   Commission.
Northwest & Intermountain Power Producers         Northwest and
 Coalition.                                        Intermountain.
National Rural Electric Cooperative Association.  NRECA.
Navajo Tribal Utility Authority.................  Navajo Utility.
Nevada Power Company and Sierra Pacific Power     NV Energy.
 Company.
New York Public Service Commission and New York   NY Commission and
 State Energy Research and Development Authority.  NYSERDA.
New York Transmission Owners....................  NYTOs.
New York Independent System Operator, Inc.......  NYISO.
Public Commission of Ohio's Office of the         Ohio Commission
 Federal Energy Advocate.                          Consumer Advocate.
Omaha Public Power District.....................  Omaha Public Power.
Organization of MISO States, Inc................  OMS.
[Oslash]rsted North America, Inc................  [Oslash]rsted.
OCETI Sakowin Power Authority...................  OSPA.
Renewable Northwest and NW Energy Coalition.....  Pacific Northwest
                                                   Organizations.
Avista Corporation; Idaho Power Company;          Pacific Northwest
 Portland General Electric Company; and Puget      Utilities.
 Sound Energy, Inc.
PacifiCorp......................................  PacifiCorp.
Pattern Energy Group LP.........................  Pattern Energy.
Payton Alaama...................................  Payton Alaama.
Pennsylvania Public Utility Commission..........  Pennsylvania
                                                   Commission.
Pacific Gas and Electric Company................  PG&E.
Pine Gate Renewables, LLC.......................  Pine Gate.
PJM Interconnection, L.L.C......................  PJM.
PJM Cities and Communities Coalition............  PJM Coalition.
Organization of PJM States, Inc.................  OPSI.
PPL Electric Utilities Corporation..............  PPL.
Puget Sound Energy, Inc.........................  Puget Sound.
Sustainable FERC Project, Sierra Club, Natural    Public Interest
 Resources Defense Council, Earthjustice, Acadia   Organizations.
 Center, Environmental Defense Fund, National
 Audubon Society, Southern Environmental Law
 Center, and Southface.
R Street Institute..............................  R Street.
Rick K. Lathrop.................................  Rick K Lathrop.
Roy J Shanker Ph.D..............................  Roy J Shanker.
rPlus Hydro, LLLP...............................  rPlus.
RWE Renewables Americas, LLC....................  RWE Renewables.
San Diego Gas & Electric Company................  SDG&E.
Solar Energy Industries Association.............  SEIA.
U.S. Senators John D. Hickenlooper and Angus      Senators Hickenlooper
 King.                                             and King.
Shell Energy North America......................  Shell.
Southern California Edison Company..............  SoCal Edison.
Southern Company Services, Inc..................  Southern.
Southwest Power Pool, Inc.......................  SPP.
Connecticut Department of Energy and              State Agencies.
 Environmental Protection, Connecticut Attorney
 General, Connecticut Office of Consumer
 Counsel, Delaware Attorney General, Delaware
 Division of the Public Advocate, Attorney
 General for the District of Columbia, District
 of Columbia Office of People's Counsel,
 Attorney General of Maryland, Maryland Office
 of People's Counsel, Massachusetts Attorney
 General, Pennsylvania Office of Consumer
 Advocate, and the Rhode Island Attorney General.

[[Page 61263]]

 
Sue Hilton......................................  Sue Hilton.
Transmission Access Policy Study Group..........  TAPS.
Tesla, Inc......................................  Tesla.
Tri-State Generation and Transmission             Tri-State.
 Association, Inc.
Uda Law Firm, P.C...............................  Uda Law Firm.
Utah Municipal Power Agency.....................  UMPA.
Union of Concerned Scientists...................  Union of Concerned
                                                   Scientists.
U.S. Chamber of Commerce........................  U.S. Chamber of
                                                   Commerce.
United States Department of Energy..............  U.S. DOE.
VEIR Inc........................................  VEIR.
Vermont Electric Power Company, Inc.............  Vermont Electric and
                                                   Vermont Transco.
Vistra Corp.....................................  Vistra.
Western Area Power Administration...............  WAPA.
WATT Coalition..................................  WATT Coalition.
Colorado Public Utilities Commission Chair Megan  Western Regulators.
 Decker, Oregon Public Utility Commission Chair
 Cynthia Hall, New Mexico Public Regulation
 Commission Chair Cynthia Hall and Vice-Chair
 Joe Maestas, Arizona Corporation Commission
 Chair Lea Marquez Peterson, Nevada Public
 Utilities Commission Chair Hayley Williamson,
 California Public Utilities Commission
 Commissioner Cliff Rechtschaffen, and
 Washington Utilities and Transportation
 Commission Commissioner Ann Rendahl.
WIRES...........................................  WIRES.
Xcel Energy Services Inc........................  Xcel.
------------------------------------------------------------------------

Appendix B: Interconnection Study Metrics

                            Table 2--RTOS/ISOS Interconnection Study Metrics 2022 \1\
----------------------------------------------------------------------------------------------------------------
                                                      Studies         Delayed
      Transmission provider          Completed    completed past  studies at end    Withdrawals   Withdrawn pre-
                                      studies        deadline         of year                          study
----------------------------------------------------------------------------------------------------------------
CAISO...........................             340             340  ..............             108               1
ISO-NE..........................              51              46              23              24               8
MISO............................             609             597             285              49               0
NYISO...........................              84              72              25              34              28
PJM \2\.........................             153             152           2,211             240             137
----------------------------------------------------------------------------------------------------------------
\1\ We do not include data from SPP in this table. SPP is transitioning to a new interconnection study process
  and thus its data is not clearly comparable to the other RTOs/ISOs.
\2\ Data drawn from the following sources, respectively: http://www.caiso.com/Documents/FERC845_InterconnectionStudyStatistics.pdf (CAISO); https://cdn.misoenergy.org/MISO%20Generator%20Interconnection%20Study%20Metrics%20Q1%202023444684.pdf (MISO); https://www.oasis.oati.com/isne/ isne/ (ISO-NE) https://www.nyiso.com/interconnections (NYISO); and https://www.pjm.com/-/media/planning/services-requests/interconnection-study-statistics.ashx (PJM).

                          Table 3--Non-RTOS/ISOS Interconnection Study Metrics 2022 \3\
----------------------------------------------------------------------------------------------------------------
                                                                      Delayed
      Transmission provider          Completed    Completed past  studies at end    Withdrawals   Withdrawn pre-
                                      studies        deadline         of year                          study
----------------------------------------------------------------------------------------------------------------
Alabama Power Company (Southern              148               0               0              45               5
 Company).......................
Arizona Public Service..........              40              40             106              12               5
Avista Corp.....................              14               5               1              11               3
Black Hills Colorado............               4               0               5               0               0
Black Hills Power...............               7               1               4               1               0
Cheyenne Light, Fuel, and Power                4               0               2               0               0
 Co.............................
Deseret Generation and                         4               0               0               0               0
 Transmission Coop..............
Dominion Energy South Carolina..               2               2               0              23              21
Duke Energy Carolinas...........               1               1               0               4               0
El Paso Electric Co.............               6               2               0               7               1
Florida Power & Light...........              60              43              78               0               0
GridLiance......................               1               0               0               0               0
Idaho Power.....................              98              20               7              15               5
Louisville Gas and Electric.....              18              16              15               2               1
Nevada Power....................             103               0               0              15               4
Northwestern Corp (Montana).....              33              14               4              10               2
PacifiCorp......................             202               0               0              41               7
Portland General Electric                     10               9               9               0               0
 Company........................
Public Service Company of                     41              39              28              12               1
 Colorado.......................
Public Service Company of New                 21              21              29               8               0
 Mexico.........................
Puget Sound Energy..............              50              37               6               6               2
Tampa Electric Company..........              25              13               1               4               2
Tri-State Generation and                      30               0               0              11              10
 Transmission...................
Tucson Electric Power Co.\4\....              20              20               0               3               2
----------------------------------------------------------------------------------------------------------------
\3\ This table excludes the following non-RTO/ISO transmission providers that did not report any completed or
  ongoing interconnection studies for 2022: Basin Electric Power Coop.; Cube Yadkin Transmission, LLC; Golden
  Spread Coop; Gulf Power Company; MATL LLP; UNS Electric, Inc.; and Versant Power.

[[Page 61264]]

 
\4\ Data drawn from the following sources, respectively: https://www.oasis.oati.com/SOCO/index.html (Alabama
  Power Company (Southern Company)); https://www.oasis.oati.com/azps/ (Arizona Public Service); https://www.oasis.oati.com/avat/ (Avista Corp.); https://www.blackhillscorp.com/utilities-businesses/transmission/electric-transmission-services (Black Hills Colorado); https://www.blackhillscorp.com/utilities-businesses/transmission/electric-transmission-services (Black Hills Power); http://www.oatioasis.com/CLPT/index.html
  (Cheyenne Light, Fuel, and Power Co.); https://www.oasis.oati.com/dgt/index.html (Deseret Generation and
  Transmission Coop.); https://www.oasis.oati.com/SCEG/(DominionEnergySouthCarolina); http://www.oasis.oati.com/duk/index.html (Duke Energy Carolinas); https://www.oasis.oati.com/epe/index.html (El Paso Electric Co.);
  https://www.oasis.oati.com/FPL/index.html (Florida Power & Light); https://www.oasis.oati.com/SMCN/index.html
  (GridLiance); https://www.oasis.oati.com/ipco/ (Idaho Power); https://www.oasis.oati.com/LGEE/index.html
  (Louisville Gas and Electric); http://www.oasis.oati.com/NEVP/ (Nevada Power); http://www.oatioasis.com/NWMT/
  (Northwestern Corp (Montana); https://www.oasis.oati.com/PPW/ (PacifiCorp); https://www.oasis.oati.com/PGE/
  (Portland General Electric Company); https://www.oasis.oati.com/psco/index.html (Public Service Company of
  Colorado); https://www.oasis.oati.com/PNM/ (Public Service Company of New Mexico); https://www.oasis.oati.com/psei/index.html (Puget Sound Energy); https://www.oasis.oati.com/TEC/ (Tampa Electric Company); https://www.oasis.oati.com/tsgt/index.html (Tri-State Generation and Transmission); and https://www.oasis.oati.com/tepc/_ (Tucson Electric Power Co.).

                        Table 4--RTO/ISO End Of Year Delayed Interconnection Studies \5\
----------------------------------------------------------------------------------------------------------------
                                                                      Delayed         Delayed         Delayed
                      Transmission provider                       studies at end  studies at end  studies at end
                                                                      of 2020         of 2021         of 2022
----------------------------------------------------------------------------------------------------------------
CAISO...........................................................  ..............  ..............  ..............
ISO-NE..........................................................              12              19              23
MISO............................................................             479             385             285
NYISO...........................................................              26              48              25
PJM.............................................................             272           1,281           2,211
----------------------------------------------------------------------------------------------------------------
\5\ We do not include data from SPP in this table. SPP is transitioning to a new interconnection study process
  and thus its data is not clearly comparable to the other RTOs/ISOs.

                        Table 5--Non-RTO/ISO End Of Year Delayed Interconnection Studies
----------------------------------------------------------------------------------------------------------------
                                                                      Delayed         Delayed         Delayed
                      Transmission provider                       studies at end  studies at end  studies at end
                                                                      of 2020         of 2021         of 2022
----------------------------------------------------------------------------------------------------------------
Alabama Power Company (Southern Company)........................               0               0               0
Arizona Public Service..........................................              29              55             106
Avista Corp.....................................................               2               7               1
Black Hills Colorado............................................               0               0               5
Black Hills Power...............................................               0               0               4
Cheyenne Light, Fuel, and Power Co..............................               0               0               2
Deseret Generation and Transmission Coop........................               0               0               0
Dominion Energy South Carolina..................................              16              19               0
Duke Energy Carolinas...........................................               6               1               0
El Paso Electric Co.............................................               1               0               0
Florida Power & Light...........................................              48              21              78
GridLiance......................................................               0               0               0
Gulf Power Co...................................................              13              12  ..............
Idaho Power.....................................................               0               0               7
Louisville Gas and Electric.....................................               3              12              15
Nevada Power....................................................               0               0               0
Northwestern Corp (Montana).....................................               2               1               4
PacifiCorp......................................................               0               0               0
Portland General Electric Company...............................               2               0               9
Public Service Company of Colorado..............................               0               0              28
Public Service Company of New Mexico............................              20              17              29
Puget Sound Energy..............................................               0               2               6
Tampa Electric Company..........................................              16               5               1
Tri-State Generation and Transmission...........................              28               0               0
Tucson Electric Power Co........................................               2               1               0
----------------------------------------------------------------------------------------------------------------

Appendix C: Pro forma LGIP

    Note: Deletions are in brackets and additions are in italics.

Section 1. Definitions

    Adverse System Impact shall mean the negative effects due to 
technical or operational limits on conductors or equipment being 
exceeded that may compromise the safety and reliability of the 
electric system.
    Affected System shall mean an electric system other than 
[the]Transmission Provider's Transmission System that may be 
affected by the proposed interconnection.
    Affected System Facilities Construction Agreement shall mean the 
agreement contained in Appendix 11 to this LGIP that is made between 
Transmission Provider and Affected System Interconnection Customer 
to facilitate the construction of and to set forth cost 
responsibility for necessary Affected System Network Upgrades on 
Transmission Provider's Transmission System.
    Affected System Interconnection Customer shall mean any entity 
that submits an interconnection request for a generating facility to 
a transmission system other than Transmission Provider's 
Transmission System that may cause the need for Affected System 
Network Upgrades on the Transmission Provider's Transmission System.
    Affected System Network Upgrades shall mean the additions, 
modifications, and upgrades to Transmission Provider's Transmission 
System required to accommodate Affected System Interconnection 
Customer's proposed interconnection to a transmission system other 
than Transmission Provider's Transmission System.

[[Page 61265]]

    Affected System Operator shall mean the entity that operates an 
Affected System.
    Affected System Queue Position shall mean the queue position of 
an Affected System Interconnection Customer in Transmission 
Provider's interconnection queue relative to Transmission Provider's 
Interconnection Customers' Queue Positions.
    Affected System Study shall mean the evaluation of Affected 
System Interconnection Customers' proposed interconnection(s) to a 
transmission system other than Transmission Provider's Transmission 
System that have an impact on Transmission Provider's Transmission 
System, as described in Section 9 of this LGIP.
    Affected System Study Agreement shall mean the agreement 
contained in Appendix 9 to this LGIP that is made between 
Transmission Provider and Affected System Interconnection Customer 
to conduct an Affected System Study pursuant to Section 9 of this 
LGIP.
    Affected System Study Report shall mean the report issued 
following completion of an Affected System Study pursuant to Section 
9.6 of this LGIP.
    Affiliate shall mean, with respect to a corporation, partnership 
or other entity, each such other corporation, partnership or other 
entity that directly or indirectly, through one or more 
intermediaries, controls, is controlled by, or is under common 
control with, such corporation, partnership or other entity.
    Ancillary Services shall mean those services that are necessary 
to support the transmission of capacity and energy from resources to 
loads while maintaining reliable operation of the Transmission 
Provider's Transmission System in accordance with Good Utility 
Practice.
    Applicable Laws and Regulations shall mean all duly promulgated 
applicable federal, state and local laws, regulations, rules, 
ordinances, codes, decrees, judgments, directives, or judicial or 
administrative orders, permits and other duly authorized actions of 
any Governmental Authority.
    [Applicable Reliability Council shall mean the reliability 
council applicable to the Transmission System to which the 
Generating Facility is directly interconnected.]
    Applicable Reliability Standards shall mean the requirements and 
guidelines of [NERC,] the [Applicable Reliability Council] Electric 
Reliability Organization and the [Control Area] Balancing Authority 
Area of the Transmission System to which the Generating Facility is 
directly interconnected.
    Balancing Authority shall mean an entity that integrates 
resource plans ahead of time, maintains demand and resource balance 
within a Balancing Authority Area, and supports interconnection 
frequency in real time.
    Balancing Authority Area shall mean the collection of 
generation, transmission, and loads within the metered boundaries of 
the Balancing Authority. The Balancing Authority maintains load-
resource balance within this area.
    Base Case shall mean the base case power flow, short circuit, 
and stability data bases used for the Interconnection Studies by 
[the] Transmission Provider or Interconnection Customer.
    Breach shall mean the failure of a Party to perform or observe 
any material term or condition of the Standard Large Generator 
Interconnection Agreement.
    Breaching Party shall mean a Party that is in Breach of the 
Standard Large Generator Interconnection Agreement.
    Business Day shall mean Monday through Friday, excluding Federal 
Holidays.
    Calendar Day shall mean any day including Saturday, Sunday or a 
Federal Holiday.
    Cluster shall mean a group of one or more Interconnection 
Requests that are studied together for the purpose of conducting a 
Cluster Study.
    Cluster Request Window shall mean the time period set forth in 
Section 3.4.1 of this LGIP.
    Cluster Restudy shall mean a restudy of a Cluster Study 
conducted pursuant to Section 7.5 of this LGIP.
    Cluster Restudy Report Meeting shall mean the meeting held to 
discuss the results of a Cluster Restudy pursuant to Section 7.5 of 
this LGIP.
    Cluster Restudy Report shall mean the report issued following 
completion of a Cluster Restudy pursuant to Section 7.5 of this 
LGIP.
    Cluster Study shall mean the evaluation of one or more 
Interconnection Requests within a Cluster as described in Section 7 
of this LGIP.
    Cluster Study Agreement shall mean the agreement contained in 
Appendix 2 to this LGIP for conducting the Cluster Study.
    Cluster Study Process shall mean the following processes, 
conducted in sequence: the Cluster Request Window; the Customer 
Engagement Window and Scoping Meetings therein; the Cluster Study; 
any needed Cluster Restudies; and the Interconnection Facilities 
Study.
    Cluster Study Report shall mean the report issued following 
completion of a Cluster Study pursuant to Section 7 of this LGIP.
    Cluster Study Report Meeting shall mean the meeting held to 
discuss the results of a Cluster Study pursuant to Section 7 of this 
LGIP.
    Clustering shall mean the process whereby one or more [a group 
of] Interconnection Requests [is] are studied together, instead of 
serially, [for the purpose of conducting the Interconnection System 
Impact Study] as described in Section 7 of this LGIP.
    Commercial Operation shall mean the status of a Generating 
Facility that has commenced generating electricity for sale, 
excluding electricity generated during Trial Operation.
    Commercial Operation Date of a unit shall mean the date on which 
the Generating Facility commences Commercial Operation as agreed to 
by the Parties pursuant to Appendix E to the Standard Large 
Generator Interconnection Agreement.
    Commercial Readiness Deposit shall mean a deposit paid as set 
forth in Sections 3.4.2, 7.5, and 8.1 of this LGIP.
    Confidential Information shall mean any confidential, 
proprietary or trade secret information of a plan, specification, 
pattern, procedure, design, device, list, concept, policy or 
compilation relating to the present or planned business of a Party, 
which is designated as confidential by the Party supplying the 
information, whether conveyed orally, electronically, in writing, 
through inspection, or otherwise.
    Contingent Facilities shall mean those unbuilt Interconnection 
Facilities and Network Upgrades upon which the Interconnection 
Request's costs, timing, and study findings are dependent, and if 
delayed or not built, could cause a need for [Re-Studies] restudies 
of the Interconnection Request or a reassessment of the 
Interconnection Facilities and/or Network Upgrades and/or costs and 
timing.
    [Control Area shall mean an electrical system or systems bounded 
by interconnection metering and telemetry, capable of controlling 
generation to maintain its interchange schedule with other Control 
Areas and contributing to frequency regulation of the 
interconnection. A Control Area must be certified by an Applicable 
Reliability Council.]
    Customer Engagement Window shall mean the time period set forth 
in Section 3.4.5 of this LGIP.
    Default shall mean the failure of a Breaching Party to cure its 
Breach in accordance with Article 17 of the Standard Large Generator 
Interconnection Agreement.
    Dispute Resolution shall mean the procedure for resolution of a 
dispute between the Parties in which they will first attempt to 
resolve the dispute on an informal basis.
    Distribution System shall mean the Transmission Provider's 
facilities and equipment used to transmit electricity to ultimate 
usage points such as homes and industries directly from nearby 
generators or from interchanges with higher voltage transmission 
networks which transport bulk power over longer distances. The 
voltage levels at which distribution systems operate differ among 
areas.
    Distribution Upgrades shall mean the additions, modifications, 
and upgrades to the Transmission Provider's Distribution System at 
or beyond the Point of Interconnection to facilitate interconnection 
of the Generating Facility and render the transmission service 
necessary to effect Interconnection Customer's wholesale sale of 
electricity in interstate commerce. Distribution Upgrades do not 
include Interconnection Facilities.
    Effective Date shall mean the date on which the Standard Large 
Generator Interconnection Agreement becomes effective upon execution 
by the Parties subject to acceptance by FERC, or if filed 
unexecuted, upon the date specified by FERC.
    Electric Reliability Organization shall mean the North American 
Electric Reliability Corporation or its successor organization.
    Emergency Condition shall mean a condition or situation: (1) 
that in the judgment of the Party making the claim is imminently 
likely to endanger life or property; or (2) that, in the case of a 
Transmission Provider, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the 
security of, or damage to Transmission

[[Page 61266]]

Provider's Transmission System, Transmission Provider's 
Interconnection Facilities or the electric systems of others to 
which the Transmission Provider's Transmission System is directly 
connected; or (3) that, in the case of Interconnection Customer, is 
imminently likely (as determined in a non-discriminatory manner) to 
cause a material adverse effect on the security of, or damage to, 
the Generating Facility or Interconnection Customer's 
Interconnection Facilities. System restoration and black start shall 
be considered Emergency Conditions; provided that Interconnection 
Customer is not obligated by the Standard Large Generator 
Interconnection Agreement to possess black start capability.
    Energy Resource Interconnection Service shall mean an 
Interconnection Service that allows the Interconnection Customer to 
connect its Generating Facility to the Transmission Provider's 
Transmission System to be eligible to deliver the Generating 
Facility's electric output using the existing firm or nonfirm 
capacity of the Transmission Provider's Transmission System on an as 
available basis. Energy Resource Interconnection Service in and of 
itself does not convey transmission service.
    Engineering & Procurement (E&P) Agreement shall mean an 
agreement that authorizes the Transmission Provider to begin 
engineering and procurement of long lead-time items necessary for 
the establishment of the interconnection in order to advance the 
implementation of the Interconnection Request.
    Environmental Law shall mean Applicable Laws or Regulations 
relating to pollution or protection of the environment or natural 
resources.
    Federal Power Act shall mean the Federal Power Act, as amended, 
16 U.S.C. Sec. Sec. 791a et seq.
    FERC shall mean the Federal Energy Regulatory Commission 
(Commission) or its successor.
    Force Majeure shall mean any act of God, labor disturbance, act 
of the public enemy, war, insurrection, riot, fire, storm or flood, 
explosion, breakage or accident to machinery or equipment, any 
order, regulation or restriction imposed by governmental, military 
or lawfully established civilian authorities, or any other cause 
beyond a Party's control. A Force Majeure event does not include 
acts of negligence or intentional wrongdoing by the Party claiming 
Force Majeure.
    Generating Facility shall mean Interconnection Customer's 
[device]device(s) for the production and/or storage for later 
injection of electricity identified in the Interconnection Request, 
but shall not include [the]Interconnection Customer's 
Interconnection Facilities.
    Generating Facility Capacity shall mean the net capacity of the 
Generating Facility [and] or the aggregate net capacity of the 
Generating Facility where it includes [multiple energy production 
devices] more than one device for the production and/or storage for 
later injection of electricity.
    Good Utility Practice shall mean any of the practices, methods 
and acts engaged in or approved by a significant portion of the 
electric industry during the relevant time period, or any of the 
practices, methods and acts which, in the exercise of reasonable 
judgment in light of the facts known at the time the decision was 
made, could have been expected to accomplish the desired result at a 
reasonable cost consistent with good business practices, 
reliability, safety and expedition. Good Utility Practice is not 
intended to be limited to the optimum practice, method, or act to 
the exclusion of all others, but rather to be acceptable practices, 
methods, or acts generally accepted in the region.
    Governmental Authority shall mean any federal, state, local or 
other governmental regulatory or administrative agency, court, 
commission, department, board, or other governmental subdivision, 
legislature, rulemaking board, tribunal, or other governmental 
authority having jurisdiction over the Parties, their respective 
facilities, or the respective services they provide, and exercising 
or entitled to exercise any administrative, executive, police, or 
taxing authority or power; provided, however, that such term does 
not include Interconnection Customer, Transmission Provider, or any 
Affiliate thereof.
    Hazardous Substances shall mean any chemicals, materials or 
substances defined as or included in the definition of ``hazardous 
substances,'' ``hazardous wastes,'' ``hazardous materials,'' 
``hazardous constituents,'' ``restricted hazardous materials,'' 
``extremely hazardous substances,'' ``toxic substances,'' 
``radioactive substances,'' ``contaminants,'' ``pollutants,'' 
``toxic pollutants'' or words of similar meaning and regulatory 
effect under any applicable Environmental Law, or any other 
chemical, material or substance, exposure to which is prohibited, 
limited or regulated by any applicable Environmental Law.
    Initial Synchronization Date shall mean the date upon which the 
Generating Facility is initially synchronized and upon which Trial 
Operation begins.
    In-Service Date shall mean the date upon which the 
Interconnection Customer reasonably expects it will be ready to 
begin use of the Transmission Provider's Interconnection Facilities 
to obtain back feed power.
    Interconnection Customer shall mean any entity, including the 
Transmission Provider, Transmission Owner or any of the Affiliates 
or subsidiaries of either, that proposes to interconnect its 
Generating Facility with the Transmission Provider's Transmission 
System.
    Interconnection Customer's Interconnection Facilities shall mean 
all facilities and equipment, as identified in Appendix A of the 
Standard Large Generator Interconnection Agreement, that are located 
between the Generating Facility and the Point of Change of 
Ownership, including any modification, addition, or upgrades to such 
facilities and equipment necessary to physically and electrically 
interconnect the Generating Facility to [the] Transmission 
Provider's Transmission System. Interconnection Customer's 
Interconnection Facilities are sole use facilities.
    Interconnection Facilities shall mean [the]Transmission 
Provider's Interconnection Facilities and [the]Interconnection 
Customer's Interconnection Facilities. Collectively, Interconnection 
Facilities include all facilities and equipment between the 
Generating Facility and the Point of Interconnection, including any 
modification, additions or upgrades that are necessary to physically 
and electrically interconnect the Generating Facility to 
[the]Transmission Provider's Transmission System. Interconnection 
Facilities are sole use facilities and shall not include 
Distribution Upgrades, Stand Alone Network Upgrades or Network 
Upgrades.
    Interconnection Facilities Study shall mean a study conducted by 
[the]Transmission Provider or a third party consultant for 
[the]Interconnection Customer to determine a list of facilities 
(including Transmission Provider's Interconnection Facilities and 
Network Upgrades as identified in the [Interconnection System 
Impact]Cluster Study), the cost of those facilities, and the time 
required to interconnect the Generating Facility with[the] 
Transmission Provider's Transmission System. The scope of the study 
is defined in Section 8 of this LGIP[the Standard Large Generator 
Interconnection Procedures].
    Interconnection Facilities Study Agreement shall mean the form 
of agreement contained in Appendix 3[4] of this LGIP [the Standard 
Large Generator Interconnection Procedures] for conducting the 
Interconnection Facilities Study.
    Interconnection Facilities Study Report shall mean the report 
issued following completion of an Interconnection Facilities Study 
pursuant to Section 8 of this LGIP.
    [Interconnection Feasibility Study shall mean a preliminary 
evaluation of the system impact and cost of interconnecting the 
Generating Facility to Transmission Provider's Transmission System, 
the scope of which is described in Section 6 of the Standard Large 
Generator Interconnection Procedures.]
    [Interconnection Feasibility Study Agreement shall mean the form 
of agreement contained in Appendix 2 of the Standard Large Generator 
Interconnection Procedures for conducting the Interconnection 
Feasibility Study.]
    Interconnection Request shall mean an Interconnection Customer's 
request, in the form of Appendix 1 to this LGIP [the Standard Large 
Generator Interconnection Procedures], in accordance with the 
Tariff, to interconnect a new Generating Facility, or to increase 
the capacity of, or make a Material Modification to the operating 
characteristics of, an existing Generating Facility that is 
interconnected with the Transmission Provider's Transmission System.
    Interconnection Service shall mean the service provided by the 
Transmission Provider associated with interconnecting the 
Interconnection Customer's Generating Facility to the Transmission 
Provider's Transmission System and enabling it to receive electric 
energy and capacity from the Generating Facility at the Point of 
Interconnection, pursuant to the terms of the Standard Large 
Generator Interconnection Agreement and, if applicable, the 
Transmission Provider's Tariff.

[[Page 61267]]

    Interconnection Study shall mean any of the following studies: 
[the Interconnection Feasibility Study, the Interconnection System 
Impact Study,] the Cluster Study, the Cluster Restudy, the Surplus 
Interconnection Service System Impact Study, and the Interconnection 
Facilities Study, described in this LGIP [the Standard Large 
Generator Interconnection Procedures].
    [Interconnection System Impact Study shall mean an engineering 
study that evaluates the impact of the proposed interconnection on 
the safety and reliability of Transmission Provider's Transmission 
System and, if applicable, an Affected System. The study shall 
identify and detail the system impacts that would result if the 
Generating Facility were interconnected without project 
modifications or system modifications, focusing on the Adverse 
System Impacts identified in the Interconnection Feasibility Study, 
or to study potential impacts, including but not limited to those 
identified in the Scoping Meeting as described in the Standard Large 
Generator Interconnection Procedures.]
    [Interconnection System Impact Study Agreement shall mean the 
form of agreement contained in Appendix 3 of the Standard Large 
Generator Interconnection Procedures for conducting the 
Interconnection System Impact Study.]
    IRS shall mean the Internal Revenue Service.
    Joint Operating Committee shall be a group made up of 
representatives from Interconnection Customers and the Transmission 
Provider to coordinate operating and technical considerations of 
Interconnection Service.
    Large Generating Facility shall mean a Generating Facility 
having a Generating Facility Capacity of more than 20 MW.
    LGIA Deposit shall mean the deposit Interconnection Customer 
submits when returning the executed LGIA, or within 10 Business Days 
of requesting that the LGIA be filed unexecuted at the Commission, 
in accordance with Section 11.3 of this LGIP.
    Loss shall mean any and all losses relating to injury to or 
death of any person or damage to property, demand, suits, 
recoveries, costs and expenses, court costs, attorney fees, and all 
other obligations by or to third parties, arising out of or 
resulting from the other Party's performance, or non-performance of 
its obligations under the Standard Large Generator Interconnection 
Agreement on behalf of the [indemnifying] Indemnifying Party, except 
in cases of gross negligence or intentional wrongdoing by the 
[indemnifying]Indemnifying Party.
    Material Modification shall mean those modifications that have a 
material impact on the cost or timing of any Interconnection Request 
with an equal or later Queue Position [queue priority date].
    Metering Equipment shall mean all metering equipment installed 
or to be installed at the Generating Facility pursuant to the 
Standard Large Generator Interconnection Agreement at the metering 
points, including but not limited to instrument transformers, MWh-
meters, data acquisition equipment, transducers, remote terminal 
unit, communications equipment, phone lines, and fiber optics.
    Multiparty Affected System Facilities Construction Agreement 
shall mean the agreement contained in Appendix 12 to this LGIP that 
is made among Transmission Provider and multiple Affected System 
Interconnection Customers to facilitate the construction of and to 
set forth cost responsibility for necessary Affected System Network 
Upgrades on Transmission Provider's Transmission System.
    Multiparty Affected System Study Agreement shall mean the 
agreement contained in Appendix 10 to this LGIP that is made among 
Transmission Provider and multiple Affected System Interconnection 
Customers to conduct an Affected System Study pursuant to Section 9 
of this LGIP.
    [NERC shall mean the North American Electric Reliability Council 
or its successor organization.]
    Network Resource shall mean any designated generating resource 
owned, purchased, or leased by a Network Customer under the Network 
Integration Transmission Service Tariff. Network Resources do not 
include any resource, or any portion thereof, that is committed for 
sale to third parties or otherwise cannot be called upon to meet the 
Network Customer's Network Load on a non-interruptible basis.
    Network Resource Interconnection Service shall mean an 
Interconnection Service that allows the Interconnection Customer to 
integrate its Large Generating Facility with the Transmission 
Provider's Transmission System (1) in a manner comparable to that in 
which the Transmission Provider integrates its generating facilities 
to serve native load customers; or (2) in an RTO or ISO with market 
based congestion management, in the same manner as Network 
Resources. Network Resource Interconnection Service in and of itself 
does not convey transmission service.
    Network Upgrades shall mean the additions, modifications, and 
upgrades to the Transmission Provider's Transmission System required 
at or beyond the point at which the Interconnection Facilities 
connect to the Transmission Provider's Transmission System to 
accommodate the interconnection of the Large Generating Facility to 
the Transmission Provider's Transmission System.
    Notice of Dispute shall mean a written notice of a dispute or 
claim that arises out of or in connection with the Standard Large 
Generator Interconnection Agreement or its performance.
    Optional Interconnection Study shall mean a sensitivity analysis 
based on assumptions specified by the Interconnection Customer in 
the Optional Interconnection Study Agreement.
    Optional Interconnection Study Agreement shall mean the form of 
agreement contained in Appendix 4[5] of this LGIP [the Standard 
Large Generator Interconnection Procedures] for conducting the 
Optional Interconnection Study.
    Party or Parties shall mean Transmission Provider, Transmission 
Owner, Interconnection Customer or any combination of the above.
    Permissible Technological Advancement {Transmission Provider 
inserts definition here.{time} 
    Point of Change of Ownership shall mean the point, as set forth 
in Appendix A to the Standard Large Generator Interconnection 
Agreement, where the Interconnection Customer's Interconnection 
Facilities connect to the Transmission Provider's Interconnection 
Facilities.
    Point of Interconnection shall mean the point, as set forth in 
Appendix A to the Standard Large Generator Interconnection 
Agreement, where the Interconnection Facilities connect to the 
Transmission Provider's Transmission System.
    Proportional Impact Method shall mean a technical analysis 
conducted by Transmission Provider to determine the degree to which 
each Generating Facility in the Cluster Study contributes to the 
need for a specific System Network Upgrade.
    Provisional Interconnection Service shall mean Interconnection 
Service provided by Transmission Provider associated with 
interconnecting the Interconnection Customer's Generating Facility 
to Transmission Provider's Transmission System and enabling that 
Transmission System to receive electric energy and capacity from the 
Generating Facility at the Point of Interconnection, pursuant to the 
terms of the Provisional Large Generator Interconnection Agreement 
and, if applicable, the Tariff.
    Provisional Large Generator Interconnection Agreement shall mean 
the interconnection agreement for Provisional Interconnection 
Service established between Transmission Provider and/or the 
Transmission Owner and the Interconnection Customer. This agreement 
shall take the form of the Large Generator Interconnection 
Agreement, modified for provisional purposes.
    Queue Position shall mean the order of a valid Interconnection 
Request, relative to all other pending valid Interconnection 
Requests, [that is] established pursuant to Section 4.1 of this 
LGIP. [based upon the date and time of receipt of the valid 
Interconnection Request by the Transmission Provider.]
    Reasonable Efforts shall mean, with respect to an action 
required to be attempted or taken by a Party under the Standard 
Large Generator Interconnection Agreement, efforts that are timely 
and consistent with Good Utility Practice and are otherwise 
substantially equivalent to those a Party would use to protect its 
own interests.
    Scoping Meeting shall mean the meeting between representatives 
of [the]Interconnection Customer(s) and Transmission Provider 
conducted for the purpose of discussing the proposed Interconnection 
Request and any alternative interconnection options, 
[to]exchang[e]ing information including any transmission data and 
earlier study evaluations that would be reasonably expected to 
impact such interconnection options, refining information and models 
provided by Interconnection Customer(s), discussing the Cluster 
Study materials posted to OASIS pursuant to Section 3.5 of this 
LGIP, and [to]analyz[e]ing such information[, and to determine the 
potential feasible Points of Interconnection].
    Site Control shall mean [documentation reasonably 
demonstrating]the exclusive land

[[Page 61268]]

right to develop, construct, operate, and maintain the Generating 
Facility over the term of expected operation of the Generating 
Facility. Site Control may be demonstrated by documentation 
establishing: (1) ownership of, a leasehold interest in, or a right 
to develop a site [for the purpose of constructing]of sufficient 
size to construct and operate the Generating Facility; (2) an option 
to purchase or acquire a leasehold site of sufficient size to 
construct and operate the Generating Facility[for such purpose]; or 
(3) [an exclusivity or other business relationship between]any other 
documentation that clearly demonstrates the right of Interconnection 
Customer[and the entity having the right to sell, lease or grant 
Interconnection Customer the right to possess or]to exclusively 
occupy a site [for such purpose.]of sufficient size to construct and 
operate the Generating Facility. Transmission Provider will maintain 
acreage requirements for each Generating Facility type on its OASIS 
or public website.
    Small Generating Facility shall mean a Generating Facility that 
has a Generating Facility Capacity of no more than 20 MW.
    Stand Alone Network Upgrades shall mean Network Upgrades that 
are not part of an Affected System that an Interconnection Customer 
may construct without affecting day-to-day operations of the 
Transmission System during their construction and the following 
conditions are met: (1) a Substation Network Upgrade must only be 
required for a single Interconnection Customer in the Cluster and no 
other Interconnection Customer in that Cluster is required to 
interconnect to the same Substation Network Upgrades, and (2) a 
System Network Upgrade must only be required for a single 
Interconnection Customer in the Cluster, as indicated under the 
Transmission Provider's Proportional Impact Method. Both 
[the]Transmission Provider and [the]Interconnection Customer must 
agree as to what constitutes Stand Alone Network Upgrades and 
identify them in Appendix A to the Standard Large Generator 
Interconnection Agreement. If [the]Transmission Provider and 
Interconnection Customer disagree about whether a particular Network 
Upgrade is a Stand Alone Network Upgrade, [the]Transmission Provider 
must provide [the]Interconnection Customer a written technical 
explanation outlining why [the]Transmission Provider does not 
consider the Network Upgrade to be a Stand Alone Network Upgrade 
within 15 days of its determination.
    Standard Large Generator Interconnection Agreement (LGIA) shall 
mean the form of interconnection agreement applicable to an 
Interconnection Request pertaining to a Large Generating Facility 
that is included in the Transmission Provider's Tariff.
    Standard Large Generator Interconnection Procedures (LGIP) shall 
mean the interconnection procedures applicable to an Interconnection 
Request pertaining to a Large Generating Facility that are included 
in the Transmission Provider's Tariff.
    Substation Network Upgrades shall mean Network Upgrades that are 
required at the substation located at the Point of Interconnection.
    Surplus Interconnection Service shall mean any unneeded portion 
of Interconnection Service established in a Large Generator 
Interconnection Agreement, such that if Surplus Interconnection 
Service is utilized, the total amount of Interconnection Service at 
the Point of Interconnection would remain the same.
    System Network Upgrades shall mean Network Upgrades that are 
required beyond the substation located at the Point of 
Interconnection.
    System Protection Facilities shall mean the equipment, including 
necessary protection signal communications equipment, required to 
protect (1) the Transmission Provider's Transmission System from 
faults or other electrical disturbances occurring at the Generating 
Facility and (2) the Generating Facility from faults or other 
electrical system disturbances occurring on the Transmission 
Provider's Transmission System or on other delivery systems or other 
generating systems to which the Transmission Provider's Transmission 
System is directly connected.
    Tariff shall mean the Transmission Provider's Tariff through 
which open access transmission service and Interconnection Service 
are offered, as filed with FERC, and as amended or supplemented from 
time to time, or any successor tariff.
    Transitional Cluster Study shall mean an Interconnection Study 
evaluating a Cluster of Interconnection Requests during the 
transition to the Cluster Study Process, as set forth in Section 
5.1.1.2 of this LGIP.
    Transitional Cluster Study Report shall mean the report issued 
following completion of a Transitional Cluster Study pursuant to 
Section 5.1.1.2 of this LGIP.
    Transitional Serial Interconnection Facilities Study shall mean 
an Interconnection Facilities Study evaluating an Interconnection 
Request on a serial basis during the transition to the Cluster Study 
Process, as set forth in Section 5.1.1.1 of this LGIP.
    Transitional Serial Interconnection Facilities Study Report 
shall mean the report issued following completion of a Transitional 
Interconnection Facilities Study pursuant to Section 5.1.1.1 of this 
LGIP.
    Transmission Owner shall mean an entity that owns, leases or 
otherwise possesses an interest in the portion of the Transmission 
System at the Point of Interconnection and may be a Party to the 
Standard Large Generator Interconnection Agreement to the extent 
necessary.
    Transmission Provider shall mean the public utility (or its 
designated agent) that owns, controls, or operates transmission or 
distribution facilities used for the transmission of electricity in 
interstate commerce and provides transmission service under the 
Tariff. The term Transmission Provider should be read to include the 
Transmission Owner when the Transmission Owner is separate from the 
Transmission Provider.
    Transmission Provider's Interconnection Facilities shall mean 
all facilities and equipment owned, controlled, or operated by 
[the]Transmission Provider from the Point of Change of Ownership to 
the Point of Interconnection as identified in Appendix A to the 
Standard Large Generator Interconnection Agreement, including any 
modifications, additions or upgrades to such facilities and 
equipment. Transmission Provider's Interconnection Facilities are 
sole use facilities and shall not include Distribution Upgrades, 
Stand Alone Network Upgrades or Network Upgrades.
    Transmission System shall mean the facilities owned, controlled 
or operated by the Transmission Provider or Transmission Owner that 
are used to provide transmission service under the Tariff.
    Trial Operation shall mean the period during which 
Interconnection Customer is engaged in on-site test operations and 
commissioning of the Generating Facility prior to Commercial 
Operation.
    Withdrawal Penalty shall mean the penalty assessed by 
Transmission Provider to an Interconnection Customer that chooses to 
withdraw or is deemed withdrawn from Transmission Provider's 
interconnection queue or whose Generating Facility does not 
otherwise reach Commercial Operation. The calculation of the 
Withdrawal Penalty is set forth in Section 3.7.1 of this LGIP.

Section 2. Scope and Application

2.1 Application of Standard Large Generator Interconnection Procedures

    Sections 2 through 13 apply to processing an Interconnection 
Request pertaining to a Large Generating Facility.

2.2 Comparability

    Transmission Provider shall receive, process and analyze all 
Interconnection Requests in a timely manner as set forth in this 
LGIP. Transmission Provider [will use the same Reasonable 
Efforts]shall process[ing] and analyze[ing] Interconnection Requests 
from all Interconnection Customers comparably, regardless of whether 
the Generating Facilities are owned by Transmission Provider, its 
subsidiaries or Affiliates or others.

2.3 Base Case Data

    Transmission Provider shall maintain base power flow, short 
circuit and stability databases, including all underlying 
assumptions, and contingency list on either its OASIS site or a 
password-protected website, subject to confidentiality provisions in 
LGIP Section 13.1. In addition, Transmission Provider shall maintain 
network models and underlying assumptions on either its OASIS site 
or a password-protected website. Such network models and underlying 
assumptions should reasonably represent those used during the most 
recent interconnection study and be representative of current system 
conditions. If Transmission Provider posts this information on a 
password-protected website, a link to the information must be 
provided on Transmission Provider's OASIS site. Transmission 
Provider is permitted to require that Interconnection Customers, 
OASIS site users and password-protected website users sign a 
confidentiality agreement before the release of commercially 
sensitive information or Critical Energy Infrastructure Information 
in the Base Case data. Such databases and lists, hereinafter 
referred to as Base Cases, shall include all (1) generation projects 
and

[[Page 61269]]

(2) transmission projects, including merchant transmission projects 
that are proposed for the Transmission System for which a 
transmission expansion plan has been submitted and approved by the 
applicable authority.

2.4 No Applicability to Transmission Service

    Nothing in this LGIP shall constitute a request for transmission 
service or confer upon an Interconnection Customer any right to 
receive transmission service.

Section 3. Interconnection Requests

3.1 [General.] Interconnection Requests

3.1.1 Study Deposits

3.1.1.1 Study Deposit

    [An ]Interconnection Customer shall submit to Transmission 
Provider, during a Cluster Request Window, an Interconnection 
Request in the form of Appendix 1 to this LGIP, an application fee 
of $5,000, and a refundable study deposit of[$10,000]:
    a. $35,000 plus $1,000 per MW for Interconnection Requests 
=20 MW <80 MW, or;
    b. $150,000 for Interconnection Requests =80 MW <200 
MW; or
    c. $250,000 for Interconnection Requests >=200 MW.
    Transmission Provider shall apply the study deposit toward the 
cost of the Cluster [an Interconnection Feasibility]Study Process.

3.1.2 Submission

    Interconnection Customer shall submit a separate Interconnection 
Request for each site [and may submit multiple Interconnection 
Requests for a single site. Interconnection Customer must submit a 
deposit with each Interconnection Request even when more than one 
request is submitted for a single site]. Where multiple Generating 
Facilities share a site, Interconnection Customer(s) may submit 
separate Interconnection Requests or a single Interconnection 
Request. An Interconnection Request to evaluate one site at two 
different voltage levels shall be treated as two Interconnection 
Requests.
    At Interconnection Customer's option, Transmission Provider and 
Interconnection Customer will identify alternative Point(s) of 
Interconnection and configurations at [the]a Scoping Meeting within 
the Customer Engagement Window to evaluate in this process and 
attempt to eliminate alternatives in a reasonable fashion given 
resources and information available. Interconnection Customer will 
select the definitive Point[(s)] of Interconnection to be studied no 
later than the execution of the [Interconnection Feasibility Study 
Agreement.]Cluster Study Agreement. For purposes of clustering 
Interconnection Requests, Transmission Provider may propose changes 
to the requested Point of Interconnection to facilitate efficient 
interconnection of Interconnection Customers at common Point(s) of 
Interconnection. Transmission Provider shall notify Interconnection 
Customers in writing of any intended changes to the requested Point 
of Interconnection within the Customer Engagement Window, and the 
Point of Interconnection shall only change upon mutual agreement.
    Transmission Provider shall have a process in place to consider 
requests for Interconnection Service below the Generating Facility 
Capacity. These requests for Interconnection Service shall be 
studied at the level of Interconnection Service requested for 
purposes of Interconnection Facilities, Network Upgrades, and 
associated costs, but may be subject to other studies at the full 
Generating Facility Capacity to ensure safety and reliability of the 
system, with the study costs borne by [the]Interconnection Customer. 
If after the additional studies are complete, Transmission Provider 
determines that additional Network Upgrades are necessary, then 
Transmission Provider must: (1) specify which additional Network 
Upgrade costs are based on which studies; and (2) provide a detailed 
explanation of why the additional Network Upgrades are necessary. 
Any Interconnection Facility and/or Network Upgrade costs required 
for safety and reliability also would be borne by 
[the]Interconnection Customer. Interconnection Customers may be 
subject to additional control technologies as well as testing and 
validation of those technologies consistent with Article 6 of the 
LGIA. The necessary control technologies and protection systems 
shall be established in Appendix C of that executed, or requested to 
be filed unexecuted, LGIA.
    Transmission Provider shall have a process in place to study 
Generating Facilities that include at least one electric storage 
resource using operating assumptions (i.e., whether the 
interconnecting Generating Facility will or will not charge at peak 
load) that reflect the proposed charging behavior of the Generating 
Facility as requested by Interconnection Customer, unless 
Transmission Provider determines that Good Utility Practice, 
including Applicable Reliability Standards, otherwise requires the 
use of different operating assumptions. If Transmission Provider 
finds Interconnection Customer's requested operating assumptions 
conflict with Good Utility Practice, Transmission Provider must 
provide Interconnection Customer an explanation in writing of why 
the submitted operating assumptions are insufficient or 
inappropriate by no later than thirty (30) Calendar Days before the 
end of the Customer Engagement Window and allow Interconnection 
Customer to revise and resubmit requested operating assumptions one 
time at least ten (10) Calendar Days prior to the end of the 
Customer Engagement Window. Transmission Provider shall study these 
requests for Interconnection Service, with the study costs borne by 
Interconnection Customer, using the submitted operating assumptions 
for purposes of Interconnection Facilities, Network Upgrades, and 
associated costs. These requests for Interconnection Service also 
may be subject to other studies at the full Generating Facility 
Capacity to ensure safety and reliability of the system, with the 
study costs borne by Interconnection Customer. Interconnection 
Customer's Generating Facility may be subject to additional control 
technologies as well as testing and validation of such additional 
control technologies consistent with Article 6 of the LGIA. The 
necessary control technologies and protection systems shall be set 
forth in Appendix C of the Interconnection Customer's LGIA.

3.2 Identification of Types of Interconnection Services

    At the time the Interconnection Request is submitted, 
Interconnection Customer must request either Energy Resource 
Interconnection Service or Network Resource Interconnection Service, 
as described; provided, however, any Interconnection Customer 
requesting Network Resource Interconnection Service may also request 
that it be concurrently studied for Energy Resource Interconnection 
Service, up to the point when an Interconnection Facilit[y]ies Study 
Agreement is executed. Interconnection Customer may then elect to 
proceed with Network Resource Interconnection Service or to proceed 
under a lower level of interconnection service to the extent that 
only certain upgrades will be completed.

3.2.1 Energy Resource Interconnection Service

3.2.1.1 The Product

    Energy Resource Interconnection Service allows Interconnection 
Customer to connect the Large Generating Facility to the 
Transmission System and be eligible to deliver the Large Generating 
Facility's output using the existing firm or non-firm capacity of 
the Transmission System on an ``as available'' basis. Energy 
Resource Interconnection Service does not in and of itself convey 
any right to deliver electricity to any specific customer or Point 
of Delivery.

3.2.1.2 The Study

    The study consists of short circuit/fault duty, steady state 
(thermal and voltage) and stability analyses. The short circuit/
fault duty analysis would identify direct Interconnection Facilities 
required and the Network Upgrades necessary to address short circuit 
issues associated with the Interconnection Facilities. The stability 
and steady state studies would identify necessary upgrades to allow 
full output of the proposed Large Generating Facility, except for 
Generating Facilities that include at least one electric storage 
resource that request to use operating assumptions pursuant to 
Section 3.1.2, unless the Transmission Provider determines that Good 
Utility Practice, including Applicable Reliability Standards, 
otherwise requires the use of different operating assumptions, and 
would also identify the maximum allowed output, at the time the 
study is performed, of the interconnecting Large Generating Facility 
without requiring additional Network Upgrades.

3.2.2 Network Resource Interconnection Service

3.2.2.1 The Product

    Transmission Provider must conduct the necessary studies and 
construct the Network

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Upgrades needed to integrate the Large Generating Facility (1) in a 
manner comparable to that in which Transmission Provider integrates 
its generating facilities to serve native load customers; or (2) in 
an ISO or RTO with market based congestion management, in the same 
manner as Network Resources. Network Resource Interconnection 
Service Allows Interconnection Customer's Large Generating Facility 
to be designated as a Network Resource, up to the Large Generating 
Facility's full output, on the same basis as existing Network 
Resources interconnected to Transmission Provider's Transmission 
System, and to be studied as a Network Resource on the assumption 
that such a designation will occur.

3.2.2.2 The Study

    The Interconnection Study for Network Resource Interconnection 
Service shall assure that Interconnection Customer's Large 
Generating Facility meets the requirements for Network Resource 
Interconnection Service and as a general matter, that such Large 
Generating Facility's interconnection is also studied with 
Transmission Provider's Transmission System at peak load, under a 
variety of severely stressed conditions, to determine whether, with 
the Large Generating Facility at full output, except for Generating 
Facilities that include at least one electric storage resource that 
request to use, and for which Transmission Provider approves, 
operating assumptions pursuant to Section 3.1.2, the aggregate of 
generation in the local area can be delivered to the aggregate of 
load on Transmission Provider's Transmission System, consistent with 
Transmission Provider's reliability criteria and procedures. This 
approach assumes that some portion of existing Network Resources are 
displaced by the output of Interconnection Customer's Large 
Generating Facility. Network Resource Interconnection Service in and 
of itself does not convey any right to deliver electricity to any 
specific customer or Point of Delivery. The Transmission Provider 
may also study the Transmission System under non-peak load 
conditions. However, upon request by the Interconnection Customer, 
the Transmission Provider must explain in writing to the 
Interconnection Customer why the study of non-peak load conditions 
is required for reliability purposes.

3.3 Utilization of Surplus Interconnection Service

    Transmission Provider must provide a process that allows an 
Interconnection Customer to utilize or transfer Surplus 
Interconnection Service at an existing Point of Interconnection. The 
original Interconnection Customer or one of its affiliates shall 
have priority to utilize Surplus Interconnection Service. If the 
existing Interconnection Customer or one of its affiliates does not 
exercise its priority, then that service may be made available to 
other potential Interconnection Customers.

3.3.1 Surplus Interconnection Service Request

    Surplus Interconnection Service requests may be made by the 
existing Interconnection Customer [whose Generating Facility is 
already interconnected]or one of its affiliates or may be submitted 
once Interconnection Customer has executed the LGIA or requested 
that the LGIA be filed unexecuted. Surplus Interconnection Service 
requests also may be made by another Interconnection Customer. 
Transmission Provider shall provide a process for evaluating 
Interconnection Requests for Surplus Interconnection Service. 
Studies for Surplus Interconnection Service shall consist of 
reactive power, short circuit/fault duty, stability analyses, and 
any other appropriate studies. Steady-state (thermal/voltage) 
analyses may be performed as necessary to ensure that all required 
reliability conditions are studied. If the Surplus Interconnection 
Service was not studied under off-peak conditions, off-peak steady 
state analyses shall be performed to the required level necessary to 
demonstrate reliable operation of the Surplus Interconnection 
Service. If the original system impact study report or Cluster Study 
Report is not available for the Surplus Interconnection Service, 
both off-peak and peak analysis may need to be performed for the 
existing Generating Facility associated with the request for Surplus 
Interconnection Service. The reactive power, short circuit/fault 
duty, stability, and steady-state analyses for Surplus 
Interconnection Service will identify any additional Interconnection 
Facilities and/or Network Upgrades necessary.
    Transmission Provider shall study Surplus Interconnection 
Service requests for a Generating Facility that includes at least 
one electric storage resource using operating assumptions (i.e., 
whether the interconnecting Generating Facility will or will not 
charge at peak load) that reflect the proposed charging behavior of 
the Generating Facility as requested by Interconnection Customer, 
unless Transmission Provider determines that Good Utility Practice, 
including Applicable Reliability Standards, otherwise requires the 
use of different operating assumptions.

3.4 Valid Interconnection Request

3.4.1 Cluster Request Window

    Transmission Provider shall accept Interconnection Requests 
during a forty-five (45) Calendar Day period (the Cluster Request 
Window). The initial Cluster Request Window shall open for 
Interconnection Requests beginning {Transmission Provider to provide 
number of Calendar Days{time}  after the conclusion of the 
transition process set out in Section 5.1 of this LGIP and 
successive Cluster Request Windows shall open annually every 
{Transmission Provider to provide Month and Day (e.g., January 
1){time}  thereafter.

3.4.[1]2 Initiating an Interconnection Request

    An Interconnection Customer seeking to join a Cluster shall 
submit its Interconnection Request to Transmission Provider within, 
and no later than the close of, the Cluster Request Window. 
Interconnection Requests submitted outside of the Cluster Request 
Window will not be considered. To initiate an Interconnection 
Request, Interconnection Customer must submit all of the following:
    (i) [a $10,000 deposit,]applicable study deposit amount, 
pursuant to Section 3.1.1.1 of this LGIP,
    (ii) a completed application in the form of Appendix 1, [and]
    (iii) demonstration of no less than ninety percent (90%) Site 
Control or [a posting of an additional deposit of $10,000. Such 
deposits shall be applied toward any Interconnection Studies, 
pursuant to the Interconnection Request. If Interconnection Customer 
demonstrates Site Control within the cure period specified in 
Section 3.4.3 after submitting its Interconnection Request, the 
additional deposit shall be refundable; otherwise, all such 
deposit(s), additional and initial, become non-refundable.] (1) a 
signed affidavit from an officer of the company indicating that Site 
Control is unobtainable due to regulatory limitations as such term 
is defined by the Transmission Provider; and (2) documentation 
sufficiently describing and explaining the source and effects of 
such regulatory limitations, including a description of any 
conditions that must be met to satisfy the regulatory limitations 
and the anticipated time by which Interconnection Customer expects 
to satisfy the regulatory requirements and (3) a deposit in lieu of 
Site Control of $10,000 per MW, subject to a minimum of $500,000 and 
a maximum of $2,000,000. Interconnection Requests from multiple 
Interconnection Customers for multiple Generating Facilities that 
share a site must include a contract or other agreement that allows 
for shared land use.
    (iv) Generating Facility Capacity (MW) (and requested 
Interconnection Service level if the requested Interconnection 
Service is less than the Generating Facility Capacity),
    (v) If applicable, (1) the requested operating assumptions 
(i.e., whether the interconnecting Generating Facility will or will 
not charge at peak load) to be used by Transmission Provider that 
reflect the proposed charging behavior of the Generating Facility 
that includes at least one electric storage resource, and (2) a 
description of any control technologies (software and/or hardware) 
that will limit the operation of the Generating Facility to the 
operating assumptions submitted by Interconnection Customer.
    (vi) A Commercial Readiness Deposit equal to two times the study 
deposit described in Section 3.1.1.1 of this LGIP in the form of an 
irrevocable letter of credit or cash. This Commercial Readiness 
Deposit is refunded to Interconnection Customer according to Section 
3.7 of this LGIP,
    (vii) A Point of Interconnection, and
    (viii) Whether the Interconnection Request shall be studied for 
Network Resource Interconnection Service or for Energy Resource 
Interconnection Service, consistent with Section 3.2 of this LGIP.
    An Interconnection Customer that submits a deposit in lieu of 
Site Control due to demonstrated regulatory limitations must 
demonstrate that it is taking identifiable steps to secure the 
necessary regulatory approvals from the applicable federal, state, 
and/or tribal entities before execution of the Cluster Study 
Agreement. Such deposit will be held by Transmission Provider until

[[Page 61271]]

Interconnection Customer provides the required Site Control 
demonstration for its point in the Cluster Study Process. 
Interconnection Customers facing qualifying regulatory limitations 
must demonstrate one-hundred percent (100%) Site Control within one-
hundred eighty (180) Calendar Days of the effective date of the 
LGIA.
    Interconnection Customer shall promptly inform Transmission 
Provider of any material change to Interconnection Customer's 
demonstration of Site Control under Section 3.4.2(iii) of this LGIP. 
If Transmission Provider determines, based on Interconnection 
Customer's information, that Interconnection Customer no longer 
satisfies the Site Control requirement, Transmission Provider shall 
give Interconnection Customer ten (10) Business Days to demonstrate 
satisfaction with the applicable requirement subject to Transmission 
Provider's approval. Absent such, Transmission Provider shall deem 
the Interconnection Request withdrawn pursuant to Section 3.7 of 
this LGIP.
    The expected In-Service Date of the new Large Generating 
Facility or increase in capacity of the existing Generating Facility 
shall be no more than the process window for the regional expansion 
planning period (or in the absence of a regional planning process, 
the process window for Transmission Provider's expansion planning 
period) not to exceed seven years from the date the Interconnection 
Request is received by Transmission Provider, unless Interconnection 
Customer demonstrates that engineering, permitting and construction 
of the new Large Generating Facility or increase in capacity of the 
existing Generating Facility will take longer than the regional 
expansion planning period. The In-Service Date may succeed the date 
the Interconnection Request is received by Transmission Provider by 
a period up to ten years, or longer where Interconnection Customer 
and Transmission Provider agree, such agreement not to be 
unreasonably withheld.

3.4.[2]3 Acknowledgment of Interconnection Request

    Transmission Provider shall acknowledge receipt of the 
Interconnection Request within five (5) Business Days of receipt of 
the request and attach a copy of the received Interconnection 
Request to the acknowledgement.

3.4.[3]4 Deficiencies in Interconnection Request

    An Interconnection Request will not be considered to be a valid 
request until all items in Section [3.4.1]3.4.2 of this LGIP have 
been received by Transmission Provider. If an Interconnection 
Request fails to meet the requirements set forth in Section 
[3.4.1]3.4.2 of this LGIP, Transmission Provider shall notify 
Interconnection Customer within five (5) Business Days of receipt of 
the initial Interconnection Request of the reasons for such failure 
and that the Interconnection Request does not constitute a valid 
request. Interconnection Customer shall provide Transmission 
Provider the additional requested information needed to constitute a 
valid request within ten (10) Business Days after receipt of such 
notice but no later than the close of the Cluster Request Window. At 
any time, if Transmission Provider finds that the technical data 
provided by Interconnection Customer is incomplete or contains 
errors, Interconnection Customer and Transmission Provider shall 
work expeditiously and in good faith to remedy such issues. In the 
event that [Failure by] Interconnection Customer fails to comply 
with this Section 3.4.[3]4 of this LGIP, Transmission Providers 
shall deem the Interconnection Request withdrawn (without the cure 
period provided under Section 3.7 of this LGIP), the application fee 
is forfeited to the Transmission Provider, and the study deposit and 
Commercial Readiness Deposit shall be returned to Interconnection 
Customer [shall be treated in accordance with Section 3.7].

3.4.5 Customer Engagement Window

    Upon the close of each Cluster Request Window, Transmission 
Provider shall open a sixty (60) Calendar Day period (Customer 
Engagement Window). During the Customer Engagement Window, 
Transmission Provider shall hold a Scoping Meeting with all 
interested Interconnection Customers. Notwithstanding the preceding 
requirements and upon written consent of all Interconnection 
Customers within the Cluster, Transmission Provider may shorten the 
Customer Engagement Window and begin the Cluster Study. Within ten 
(10) Business Days of the opening of the Customer Engagement Window, 
Transmission Provider shall post on its OASIS a list of 
Interconnection Requests for that Cluster. The list shall identify, 
for each anonymized Interconnection Request: (1) the requested 
amount of Interconnection Service; (2) the location by county and 
state; (3) the station or transmission line or lines where the 
interconnection will be made; (4) the projected In-Service Date; (5) 
the type of Interconnection Service requested; and (6) the type of 
Generating Facility or Facilities to be constructed, including fuel 
types, such as coal, natural gas, solar, or wind. The Transmission 
Provider must ensure that project information is anonymized and does 
not reveal the identity or commercial information of interconnection 
customers with submitted requests. During the Customer Engagement 
Window, Transmission Provider shall provide to Interconnection 
Customer a non-binding updated good faith estimate of the cost and 
timeframe for completing the Cluster Study and a Cluster Study 
Agreement to be executed prior to the close of the Customer 
Engagement Window.
    At the end of the Customer Engagement Window, all 
Interconnection Requests deemed valid that have executed a Cluster 
Study Agreement in the form of Appendix 2 to this LGIP shall be 
included in the Cluster Study. Any Interconnection Requests not 
deemed valid at the close of the Customer Engagement Window shall be 
deemed withdrawn (without the cure period provided under Section 3.7 
of this LGIP) by Transmission Provider, the application fee shall be 
forfeited to the Transmission Provider, and the Transmission 
Provider shall return the study deposit and Commercial Readiness 
Deposit to Interconnection Customer. Immediately following the 
Customer Engagement Window, Transmission Provider shall initiate the 
Cluster Study described in Section 7 of this LGIP.

3.4.[4]6 Cluster Study Scoping Meetings

    [Within ten (10) Business Days after receipt of a valid 
Interconnection Request]During the Customer Engagement Window, 
Transmission Provider shall [establish a date agreeable to]hold a 
Scoping Meeting with all Interconnection Customers whose valid 
Interconnection Requests were received in that Cluster Request 
Window.
    The purpose of the Cluster Study Scoping Meeting shall be to 
discuss alternative interconnection options, to exchange information 
including any transmission data and earlier study evaluations that 
would reasonably be expected to impact such interconnection options, 
to discuss the Cluster Study materials posted to OASIS pursuant to 
Section 3.5 of this LGIP, if applicable, and to analyze such 
information [and to determine the potential feasible Points of 
Interconnection]. Transmission Provider and Interconnection 
Customer(s) will bring to the meeting such technical data, 
including, but not limited to: (i) general facility loadings, (ii) 
general instability issues, (iii) general short circuit issues, (iv) 
general voltage issues, and (v) general reliability issues as may be 
reasonably required to accomplish the purpose of the meeting. 
Transmission Provider and Interconnection Customer(s) will also 
bring to the meeting personnel and other resources as may be 
reasonably required to accomplish the purpose of the meeting in the 
time allocated for the meeting. On the basis of the meeting, 
Interconnection Customer(s) shall designate its Point of 
Interconnection.[, pursuant to Section 6.1,] and one or more 
available alternative Point(s) of Interconnection. The duration of 
the meeting shall be sufficient to accomplish its purpose. If the 
Cluster Study Scoping Meeting consists of more than one 
Interconnection Customer, Transmission Provider shall issue, no 
later than fifteen (15) Business Days after the commencement of the 
Customer Engagement Window, and Interconnection Customer shall 
execute a non-disclosure agreement prior to a group Cluster Study 
Scoping Meeting, which will provide for confidentiality of 
identifying commercially sensitive information pertaining to any 
other Interconnection Customers.

3.5 OASIS Posting

3.5.1 OASIS Posting

    Transmission Provider will maintain on its OASIS a list of all 
Interconnection Requests. The list will identify, for each 
Interconnection Request: (i) the maximum summer and winter megawatt 
electrical output; (ii) the location by county and state; (iii) the 
station or transmission line or lines where the interconnection will 
be made; (iv) the projected In-Service Date; (v) the status of the 
Interconnection Request, including Queue Position; (vi) the type of 
Interconnection Service being requested; and (vii) the availability 
of any studies related to the Interconnection Request; (viii) the 
date of the Interconnection Request; (ix) the type of

[[Page 61272]]

Generating Facility to be constructed [(combined cycle, base load or 
combustion turbine and fuel type)]; and (x) for Interconnection 
Requests that have not resulted in a completed interconnection, an 
explanation as to why it was not completed. Except in the case of an 
Affiliate, the list will not disclose the identity of 
Interconnection Customer until Interconnection Customer executes an 
LGIA or requests that Transmission Provider file an unexecuted LGIA 
with FERC. Before holding a Scoping Meeting with its Affiliate, 
Transmission Provider shall post on OASIS an advance notice of its 
intent to do so. Transmission Provider shall post to its OASIS site 
any deviations from the study timelines set forth herein. 
Interconnection Study reports and Optional Interconnection Study 
reports shall be posted to Transmission Provider's OASIS site 
subsequent to the meeting between Interconnection Customer and 
Transmission Provider to discuss the applicable study results. 
Transmission Provider shall also post any known deviations in the 
Large Generating Facility's In-Service Date.

3.5.2 Requirement To Post Interconnection Study Metrics

    Transmission Provider will maintain on its OASIS or its website 
summary statistics related to processing Interconnection Studies 
pursuant to Interconnection Requests, updated quarterly. If 
Transmission Provider posts this information on its website, a link 
to the information must be provided on Transmission Provider's OASIS 
site. For each calendar quarter, Transmission Providers must 
calculate and post the information detailed in [sections]Sections 
3.5.2.1 through 3.5.2.4 of this LGIP.

3.5.2.1 Interconnection [Feasibility Studies]Cluster Study Processing 
Time

    (A) Number of Interconnection Requests that had [Interconnection 
Feasibility]Cluster Studies completed within Transmission Provider's 
coordinated region during the reporting quarter,
    (B) Number of Interconnection Requests that had [Interconnection 
Feasibility]Cluster Studies completed within Transmission Provider's 
coordinated region during the reporting quarter that were completed 
more than [[timeline as listed in Transmission Provider's LGIP]]one 
hundred fifty (150) Calendar Days after [receipt by Transmission 
Provider of the Interconnection Customer's executed Interconnection 
Feasibility Study Agreement]the close of the Customer Engagement 
Window,
    (C) At the end of the reporting quarter, the number of active 
valid Interconnection Requests with ongoing incomplete 
[Interconnection Feasibility] Cluster Studies where such 
Interconnection Requests had executed [Interconnection Feasibility]a 
Cluster Study Agreement[s] received by Transmission Provider more 
than [[timeline as listed in Transmission Provider's LGIP]]one 
hundred fifty (150) Calendar Days before the reporting quarter end,
    (D) Mean time (in days), [Interconnection Feasibility]Cluster 
Studies completed within Transmission Provider's coordinated region 
during the reporting quarter, from the [date when Transmission 
Provider received the executed Interconnection Feasibility Study 
Agreement]commencement of the Cluster Study to the date when 
Transmission Provider provided the completed [Interconnection 
Feasibility]Cluster Study Report to [the] Interconnection Customer,
    (E) Mean time (in days), Cluster Studies were completed within 
Transmission Provider's coordinated region during the reporting 
quarter, from the close of the Cluster Request Window to the date 
when Transmission Provider provided the completed Cluster Study 
Report to Interconnection Customer.
    [(E)](F) Percentage of [Interconnection Feasibility]Cluster 
Studies exceeding [[timeline as listed in Transmission Provider's 
LGIP]]one hundred fifty (150) Calendar Days to complete this 
reporting quarter, calculated as the sum of 3.5.2.1(B) plus 
3.5.2.1(C) divided by the sum of 3.5.2.1(A) plus 3.5.2.1(C)[)].

3.5.2.2 [Interconnection System Impact Studies]Cluster Restudies 
Processing Time

    (A) Number of Interconnection Requests that had [Interconnection 
System Impact Studies]Cluster Restudies completed within 
Transmission Provider's coordinated region during the reporting 
quarter,
    (B) Number of Interconnection Requests that had [Interconnection 
System Impact Studies]Cluster Restudies completed within 
Transmission Provider's coordinated region during the reporting 
quarter that were completed more than [[timeline as listed in 
Transmission Provider's LGIP]]one hundred fifty (150) Calendar Days 
after [receipt by] Transmission Provider notifies Interconnection 
Customers in the Cluster that a Cluster Restudy is required pursuant 
to Section 7.5(4) of this LGIP [of the Interconnection Customer's 
executed Interconnection System Impact Study Agreement],
    (C) At the end of the reporting quarter, the number of active 
valid Interconnection Requests with ongoing incomplete [System 
Impact Studies]Cluster Restudies where Transmission Provider 
notified Interconnection Customers in the Cluster that a Cluster 
Restudy is required pursuant to Section 7.5(4) of this LGIP [such 
Interconnection Requests had executed Interconnection System Impact 
Study Agreements received by Transmission Provider] more than 
[[timeline as listed in Transmission Provider's LGIP]]one hundred 
fifty (150) Calendar Days before the reporting quarter end,
    (D) Mean time (in days), [Interconnection System Impact 
Studies]Cluster Restudies completed within Transmission Provider's 
coordinated region during the reporting quarter, from the date when 
Transmission Provider notifies Interconnection Customers in the 
Cluster that a Cluster Restudy is required pursuant to Section 
7.5(4) of this LGIP [received the executed Interconnection System 
Impact Study Agreement] to the date when Transmission Provider 
provided the completed [Interconnection System Impact Study]Cluster 
Restudy Report to [the]Interconnection Customer,
    (E) Mean time (in days), Cluster Restudies completed within 
Transmission Provider's coordinated region during the reporting 
quarter, from the close of the Cluster Request Window to the date 
when Transmission Provider provided the completed Cluster Restudy 
Report to Interconnection Customer.
    [(E)](F) Percentage of [Interconnection System Impact 
Studies]Cluster Restudies exceeding [[timeline as listed in 
Transmission Provider's LGIP]]one hundred fifty (150) Calendar Days 
to complete this reporting quarter, calculated as the sum of 
3.5.2.2(B) plus 3.5.2.2(C) divided by the sum of 3.5.2.2(A) plus 
3.5.2.2(C)).

3.5.2.3 Interconnection Facilities Studies Processing Time

    (A) Number of Interconnection Requests that had Interconnection 
Facilities Studies that are completed within Transmission Provider's 
coordinated region during the reporting quarter,
    (B) Number of Interconnection Requests that had Interconnection 
Facilities Studies that are completed within Transmission Provider's 
coordinated region during the reporting quarter that were completed 
more than {timeline as listed in Transmission Provider's LGIP{time}  
after receipt by Transmission Provider of the Interconnection 
Customer's executed Interconnection Facilities Study Agreement,
    (C) At the end of the reporting quarter, the number of active 
valid Interconnection Service requests with ongoing incomplete 
Interconnection Facilities Studies where such Interconnection 
Requests had executed Interconnection Facilities Studies Agreement 
received by Transmission Provider more than {timeline as listed in 
Transmission Provider's LGIP{time}  before the reporting quarter 
end,
    (D) Mean time (in days), for Interconnection Facilities Studies 
completed within Transmission Provider's coordinated region during 
the reporting quarter, calculated from the date when Transmission 
Provider received the executed Interconnection Facilities Study 
Agreement to the date when Transmission Provider provided the 
completed Interconnection Facilities Study to the Interconnection 
Customer,
    (E) Mean time (in days), Interconnection Facilities Studies 
completed within Transmission Provider's coordinated region during 
the reporting quarter, from the close of the Cluster Request Window 
to the date when Transmission Provider provided the completed 
Interconnection Facilities Study to Interconnection Customer.
    [(E)](F) Percentage of delayed Interconnection Facilities 
Studies this reporting quarter, calculated as the sum of 3.5.2.3(B) 
plus 3.5.2.3(C) divided by the sum of 3.5.2.3(A) plus 3.5.2.3(C)).

3.5.2.4 Interconnection Service Requests Withdrawn From Interconnection 
Queue

    (A) Number of Interconnection Requests withdrawn from 
Transmission Provider's interconnection queue during the reporting 
quarter,
    (B) Number of Interconnection Requests withdrawn from 
Transmission Provider's interconnection queue during the reporting 
quarter before completion of any interconnection studies or 
execution of any interconnection study agreements,

[[Page 61273]]

    (C) Number of Interconnection Requests withdrawn from 
Transmission Provider's interconnection queue during the reporting 
quarter before completion of [an Interconnection System Impact]a 
Cluster Study,
    (D) Number of Interconnection Requests withdrawn from 
Transmission Provider's interconnection queue during the reporting 
quarter before completion of an Interconnection Facilities Study,
    (E) Number of Interconnection Requests withdrawn from 
Transmission Provider's interconnection queue after execution of a 
generator interconnection agreement or Interconnection Customer 
requests the filing of an unexecuted, new interconnection agreement,
    (F) Mean time (in days), for all withdrawn Interconnection 
Requests, from the date when the request was determined to be valid 
to when Transmission Provider received the request to withdraw from 
the queue.

3.5.3

    Transmission Provider is required to post on OASIS or its 
website the measures in paragraph 3.5.2.1(A) through paragraph 
3.5.2.4(F) for each calendar quarter within 30 days of the end of 
the calendar quarter. Transmission Provider will keep the quarterly 
measures posted on OASIS or its website for three calendar years 
with the first required report to be in the first quarter of 2020. 
If Transmission Provider retains this information on its website, a 
link to the information must be provided on Transmission Provider's 
OASIS site.

3.5.4

    In the event that any of the values calculated in paragraphs 
3.5.2.1(E), 3.5.2.2(E) or 3.5.2.3(E) exceeds 25 percent for two 
consecutive calendar quarters, Transmission Provider will have to 
comply with the measures below for the next four consecutive 
calendar quarters and must continue reporting this information until 
Transmission Provider reports four consecutive calendar quarters 
without the values calculated in 3.5.2.1(E), 3.5.2.2(E) or 
3.5.2.3(E) exceeding 25 percent for two consecutive calendar 
quarters:
    (i) Transmission Provider must submit a report to the Commission 
describing the reason for each Cluster Study, Cluster Restudy, or 
individual Interconnection Facilities S[s]tudy [or group of 
clustered studies]pursuant to[an] one or more Interconnection 
Request(s) that exceeded its deadline (i.e., [45,]150, 90 or 180 
days) for completion [(excluding any allowance for Reasonable 
Efforts)]. Transmission Provider must describe the reasons for each 
study delay and any steps taken to remedy these specific issues and, 
if applicable, prevent such delays in the future. The report must be 
filed at the Commission within 45 days of the end of the calendar 
quarter.
    (ii) Transmission Provider shall aggregate the total number of 
employee-hours and third party consultant hours expended towards 
interconnection studies within its coordinated region that quarter 
and post on OASIS or its website. If Transmission Provider posts 
this information on its website, a link to the information must be 
provided on Transmission Provider's OASIS site. This information is 
to be posted within 30 days of the end of the calendar quarter.

3.6 Coordination With Affected Systems

    Transmission Provider will coordinate the conduct of any studies 
required to determine the impact of the Interconnection Request on 
Affected Systems with Affected System Operators[and, if possible, 
include those results in its applicable Interconnection Study within 
the time frame specified in this LGIP. Transmission Provider will 
include such Affected System Operators in all meetings held with 
Interconnection Customer as required by this LGIP]. Interconnection 
Customer will cooperate with Transmission Provider and Affected 
System Operator in all matters related to the conduct of studies and 
the determination of modifications to Affected Systems.
    A Transmission Provider whose system may be impacted by a 
proposed interconnection on another transmission provider's 
transmission system [which may be an Affected System] shall 
cooperate with the [T]transmission [P]provider with whom 
interconnection has been requested in all matters related to the 
conduct of studies and the determination of modifications to 
Transmission Provider's Transmission System[Affected Systems].

3.6.1 Initial Notification

    Transmission Provider must notify Affected System Operator of a 
potential Affected System impact caused by an Interconnection 
Request within ten (10) Business Days of the completion of the 
Cluster Study or, if the potential Affected System impact is only 
determined in the Cluster Restudy, the completion of the Cluster 
Restudy.
    At the time of initial notification, Transmission Provider must 
provide Interconnection Customer with a list of potential Affected 
Systems, along with relevant contact information.

3.7 Withdrawal

    Interconnection Customer may withdraw its Interconnection 
Request at any time by written notice of such withdrawal to 
Transmission Provider. In addition, if Interconnection Customer 
fails to adhere to all requirements of this LGIP, except as provided 
in Section 13.5 (Disputes), Transmission Provider shall deem the 
Interconnection Request to be withdrawn and shall provide written 
notice to Interconnection Customer of the deemed withdrawal and an 
explanation of the reasons for such deemed withdrawal. Upon receipt 
of such written notice, Interconnection Customer shall have fifteen 
(15) Business Days in which to either respond with information or 
actions that cures the deficiency or to notify Transmission Provider 
of its intent to pursue Dispute Resolution.
    Withdrawal shall result in the loss of Interconnection 
Customer's Queue Position. If an Interconnection Customer disputes 
the withdrawal and loss of its Queue Position, then during Dispute 
Resolution, Interconnection Customer's Interconnection Request is 
eliminated from the queue until such time that the outcome of 
Dispute Resolution would restore its Queue Position. An 
Interconnection Customer that withdraws or is deemed to have 
withdrawn its Interconnection Request shall pay to Transmission 
Provider all costs that Transmission Provider prudently incurs with 
respect to that Interconnection Request prior to Transmission 
Provider's receipt of notice described above. Interconnection 
Customer must pay all monies due to Transmission Provider before it 
is allowed to obtain any Interconnection Study data or results.
    If Interconnection Customer withdraws its Interconnection 
Request or is deemed withdrawn by Transmission Provider under 
Section 3.7 of this LGIP, Transmission Provider shall (i) update the 
OASIS Queue Position posting; (ii) impose the Withdrawal Penalty 
described in Section 3.7.1 of this LGIP; and (iii) refund to 
Interconnection Customer any portion of the refundable portion of 
Interconnection Customer's study deposit [or study payments] that 
exceeds the costs that Transmission Provider has incurred, including 
interest calculated in accordance with Section 35.19a(a)(2) of 
FERC's regulations. Transmission Provider shall also refund any 
portion of the Commercial Readiness Deposit not applied to the 
Withdrawal Penalty and, if applicable, the deposit in lieu of site 
control. In the event of such withdrawal, Transmission Provider, 
subject to the confidentiality provisions of Section 13.1 of this 
LGIP, shall provide, at Interconnection Customer's request, all 
information that Transmission Provider developed for any completed 
study conducted up to the date of withdrawal of the Interconnection 
Request.

3.7.1 Withdrawal Penalty

    Interconnection Customer shall be subject to a Withdrawal 
Penalty if it withdraws its Interconnection Request or is deemed 
withdrawn, or the Generating Facility does not otherwise reach 
Commercial Operation unless: (1) the withdrawal does not have a 
material impact on the cost or timing of any Interconnection Request 
with an equal or lower Queue Position; (2) Interconnection Customer 
withdraws after receiving Interconnection Customer's most recent 
Cluster Restudy Report and the Network Upgrade costs assigned to the 
Interconnection Request identified in that report have increased by 
more than twenty-five percent (25%) compared to costs identified in 
Interconnection Customer's preceding Cluster Study Report or Cluster 
Restudy Report; or (3) Interconnection Customer withdraws after 
receiving Interconnection Customer's Interconnection Facilities 
Study Report and the Network Upgrade costs assigned to the 
Interconnection Request identified in that report have increased by 
more than one hundred percent (100%) compared to costs identified in 
the Cluster Study Report.

3.7.1.1 Calculation of the Withdrawal Penalty

    If Interconnection Customer withdraws its Interconnection 
Request or is deemed withdrawn prior to the commencement of the 
initial Cluster Study, Interconnection Customer shall not be subject 
to a

[[Page 61274]]

Withdrawal Penalty. If Interconnection Customer withdraws, is deemed 
withdrawn, or otherwise does not reach Commercial Operation at any 
point after the commencement of the initial Cluster Study, that 
Interconnection Customer's Withdrawal Penalty will be the greater 
of: (1) the Interconnection Customer's study deposit required under 
Section 3.1.1.1 of this LGIP; or (2) as follows in (a)-(d):
    (a) If Interconnection Customer withdraws or is deemed withdrawn 
during the Cluster Study or after receipt of a Cluster Study Report, 
but prior to commencement of the Cluster Restudy or Interconnection 
Facilities Study, Interconnection Customer shall be charged two (2) 
times its actual allocated cost of all studies performed for 
Interconnection Customers in the Cluster up until that point in the 
interconnection study process.
    (b) If Interconnection Customer withdraws or is deemed withdrawn 
during the Cluster Restudy or after receipt of any applicable 
restudy reports issued pursuant to Section 7.5 of this LGIP, but 
prior to commencement of the Interconnection Facilities Study, 
Interconnection Customer shall be charged five percent (5%) its 
estimated Network Upgrade costs.
    (c) If Interconnection Customer withdraws or is deemed withdrawn 
during the Interconnection Facilities Study, after receipt of the 
Interconnection Facilities Study Report issued pursuant to Section 
8.3 of this LGIP, or after receipt of the draft LGIA but before 
Interconnection Customer has executed an LGIA or has requested that 
its LGIA be filed unexecuted, and has satisfied the other 
requirements described in Section 11.3 of this LGIP (i.e., Site 
Control demonstration, LGIA Deposit, reasonable evidence of one or 
more milestones in the development of the Generating Facility), 
Interconnection Customer shall be charged ten percent (10%) its 
estimated Network Upgrade costs.
    (d) If Interconnection Customer has executed an LGIA or has 
requested that its LGIA be filed unexecuted and has satisfied the 
other requirements described in Section 11.3 of this LGIP (i.e., 
Site Control demonstration, LGIA Deposit, reasonable evidence of one 
or more milestones in the development of the Generating Facility) 
and subsequently withdraws its Interconnection Request or if 
Interconnection Customer's Generating Facility otherwise does not 
reach Commercial Operation, that Interconnection Customer's 
Withdrawal Penalty shall be twenty percent (20%) its estimated 
Network Upgrade costs.

3.7.1.2 Distribution of the Withdrawal Penalty

3.7.1.2.1 Initial Distribution of Withdrawal Penalties Prior To 
Assessment of Network Upgrade Costs Previously Shared With 
Withdrawn Interconnection Customers in the Same Cluster

    For a single cluster, Transmission Provider shall hold all 
Withdrawal Penalty funds until all Interconnection Customers in that 
Cluster have either: (1) withdrawn or been deemed withdrawn; (2) 
executed an LGIA; or (3) requested an LGIA to be filed unexecuted. 
Any Withdrawal Penalty funds collected from the Cluster shall first 
be used to fund studies conducted under the Cluster Study Process 
for Interconnection Customers in the same Cluster that have executed 
the LGIA or requested the LGIA to be filed unexecuted. Next, after 
the Withdrawal Penalty funds are applied to relevant study costs in 
the same Cluster, Transmission Provider will apply the remaining 
Withdrawal Penalty funds to reduce net increases, for 
Interconnection Customers in the same Cluster, in Interconnection 
Customers' Network Upgrade cost assignment and associated financial 
security requirements under Article 11.5 of the pro forma LGIA 
attributable to the impacts of withdrawn Interconnection Customers 
that shared an obligation with the remaining Interconnection 
Customers to fund a Network Upgrade, as described in more detail in 
Sections 3.7.1.2.3 and 3.7.1.2.4.
    Withdrawal Penalty funds shall first be applied as a refund to 
invoiced study costs for Interconnection Customers in the same 
Cluster that did not withdraw within 30 Calendar Days of such 
Interconnection Customers executing their LGIA or requesting to have 
their LGIA filed unexecuted. Distribution of Withdrawal Penalty 
funds within one specific Cluster Study for study costs shall not 
exceed the total actual Cluster Study costs. Withdrawal Penalty 
funds applied to study costs shall be allocated within the same 
Cluster to Interconnection Customers in a manner consistent with the 
Transmission Provider's method in Section 13.3 of this LGIP for 
allocating the costs of interconnection studies conducted on a 
clustered basis. Transmission Provider shall post the balance of 
Withdrawal Penalty funds held by Transmission Provider but not yet 
dispersed on its OASIS site and update this posting on a quarterly 
basis.
    If an Interconnection Customer withdraws after it executes, or 
requests the unexecuted filing of, its LGIA, Transmission Provider 
shall first apply such Interconnection Customer's Withdrawal Penalty 
funds to any restudy costs required due to the Interconnection 
Customer's withdrawal as a credit to as-yet-to be invoiced study 
costs to be charged to the remaining Interconnection Customers in 
the same Cluster in a manner consistent with the Transmission 
Provider's method in Section 13.3 of this LGIP for allocating the 
costs of interconnection studies conducted on a clustered basis. 
Distribution of the Withdrawal Penalty funds for such restudy costs 
shall not exceed the total actual restudy costs.

3.7.1.2.2 Assessment of Network Upgrade Costs Previously Shared 
With Withdrawn Interconnection Customers in the Same Cluster

    If Withdrawal Penalty funds remain for the same Cluster after 
the Withdrawal Penalty funds are applied to relevant study costs, 
Transmission Provider will determine if the withdrawn 
Interconnection Customers, at any point in the Cluster Study 
Process, shared cost assignment for one or more Network Upgrades 
with any remaining Interconnection Customers in the same Cluster 
based on the Cluster Study Report, Cluster Restudy Report(s), 
Interconnection Facilities Study Report, and any subsequent issued 
restudy report issued for the Cluster.
    In section 3.7.1.2 of this LGIP, shared cost assignments for 
Network Upgrades refers to the cost of Network Upgrades still needed 
for the same Cluster for which an Interconnection Customer, prior to 
withdrawing its Interconnection Request, shared the obligation to 
fund along with Interconnection Customers that have executed an 
LGIA, or requested the LGIA to filed unexecuted.
    If Transmission Provider's assessment determines that there are 
no shared cost assignments for any Network Upgrades in the same 
Cluster for the withdrawn Interconnection Customer, or determines 
that the withdrawn Interconnection Customer's withdrawal did not 
cause a net increase in the shared cost assignment for any remaining 
Interconnection Customers' Network Upgrade(s) in the same Cluster, 
Transmission Provider will return any remaining Withdrawal Penalty 
funds to the withdrawn Interconnection Customer(s). Such remaining 
Withdrawal Penalty funds will be returned to withdrawn 
Interconnection Customers based on the proportion of each withdrawn 
Interconnection Customer's contribution to the total amount of 
Withdrawal Penalty funds collected for the Cluster (i.e., the total 
amount before the initial disbursement required under Section 
3.7.1.2.1 of this LGIP). Transmission Provider must make such 
disbursement within sixty (60) Calendar Days of the date on which 
all Interconnection Customers in the same Cluster have either: (1) 
withdrawn or been deemed withdrawn; (2) executed an LGIA; or (3) 
requested an LGIA to be filed unexecuted. For the withdrawn 
Interconnection Customers that Transmission Provider determines have 
caused a net increase in the shared cost assignment for one or more 
Network Upgrade(s) in the same Cluster under subsection 
3.7.1.2.3(a), Transmission Provider will determine each such 
withdrawn Interconnection Customers' Withdrawal Penalty funds 
remaining balance that will be applied toward net increases in 
Network Upgrade shared costs calculated under subsections 
3.7.1.2.3(a) and 3.7.1.2.3(b) based on each such withdrawn 
Interconnection Customer's proportional contribution to the total 
amount of Withdrawal Penalty funds collected for the same Cluster 
(i.e., the total amount before the initial disbursement requirement 
under Section 3.7.1.2.1 of this LGIP).
    If the Transmission Provider's assessment determines that there 
are shared cost assignments for Network Upgrades in the same 
Cluster, Transmission Provider will calculate the remaining 
Interconnection Customers' net increase in cost assignment for 
Network Upgrades due to a shared cost assignment for Network 
Upgrades with the withdrawn Interconnection Customer and distribute 
Withdrawal Penalty funds as described in Section 3.7.1.2.3, 
depending on whether the withdrawal occurred before the withdrawing 
Interconnection Customer executed the LGIA (or filed unexecuted), as 
described in subsection 3.7.1.2.3(a), or after such execution (or 
filing unexecuted) of an LGIA, as described in subsection 
3.7.1.2.3(b).
    As discussed in subsection 3.7.1.2.4, Transmission Provider will 
amend executed (or filed unexecuted) LGIAs of the remaining

[[Page 61275]]

Interconnection Customers in the same Cluster to apply the remaining 
Withdrawal Penalty funds to reduce net increases in Interconnection 
Customers' Network Upgrade cost assignment and associated financial 
security requirements under Article 11.5 of the pro forma LGIA 
attributable to the impacts of withdrawn Interconnection Customers 
on Interconnection Customers remaining in the same Cluster that had 
a shared cost assignment for Network Upgrades with the withdrawn 
Interconnection Customers.

3.7.1.2.3 Impact Calculations

3.7.1.2.3(a) Impact Calculation for Withdrawals During the Cluster 
Study Process

    If an Interconnection Customer withdraws before it executes, or 
requests the unexecuted filing of, its LGIA, the Transmission 
Provider will distribute in the following manner the Withdrawal 
Penalty funds to reduce the Network Upgrade cost impact on the 
remaining Interconnection Customers in the same Cluster who had a 
shared cost assignment for a Network Upgrade with the withdrawn 
Interconnection Customer.
    To calculate the reduction in the remaining Interconnection 
Customers' net increase in Network Upgrade costs and associated 
financial security requirements under Article 11.5 of the pro forma 
LGIA, the Transmission Provider will determine the financial impact 
of a withdrawing Interconnection Customer on other Interconnection 
Customers in the same Cluster that shared an obligation to fund the 
same Network Upgrade(s). Transmission Provider shall calculate this 
financial impact once all the Interconnection Customers in the same 
Cluster either: (1) have withdrawn or have been deemed withdrawn; 
(2) executed an LGIA; or (3) request an LGIA to be filed unexecuted. 
Transmission Provider will perform the financial impact calculation 
using the following steps.
    First, Transmission Provider must determine which withdrawn 
Interconnection Customers shared an obligation to fund Network 
Upgrades with Interconnection Customers from the same Cluster that 
have LGIAs that are executed or have been requested to be filed 
unexecuted. Next, Transmission Provider shall perform the 
calculation of the financial impact of a withdrawal on another 
Interconnection Request in the same Cluster by performing a 
comparison of the Network Upgrade cost estimates between each of the 
following:
    (1) Cluster Study phase to Cluster Restudy phase (if Cluster 
Restudy was necessary);
    (2) Cluster Restudy phase to Facilities Study phase (if a 
Cluster Restudy was necessary);
    (3) Cluster Study phase to Facilities Study phase (if no Cluster 
Restudy was performed);
    (4) Facilities Study phase to any subsequent restudy that was 
performed before the execution or filing of an unexecuted LGIA;
    (5) the restudy to the executed, or filed unexecuted, LGIA (if a 
restudy was performed after the Facilities Study phase and before 
the execution or filing of an unexecuted LGIA).
    If, based on the above calculations, Transmission Provider 
determines:
    (i) that the costs assigned to an Interconnection Customer in 
the same Cluster for Network Upgrades that a withdrawn 
Interconnection Customer shared cost assignment for increased 
between any two studies, and
    (ii) after the impacted Interconnection Customer's LGIA was 
executed or filed unexecuted, the Interconnection Customer's cost 
assignment for the relevant Network Upgrade is greater than it was 
prior to the withdrawal of the Interconnection Customer in the same 
Cluster that shared cost assignment for the Network Upgrade,

    then Transmission Provider shall apply the withdrawn 
Interconnection Customer's Withdrawal Penalty funds that has not 
already been applied to study costs in the amount of the financial 
impact by reducing, in the same Cluster, the remaining 
Interconnection Customer's Network Upgrade costs and associated 
financial security requirements under Article 11.5 of the pro forma 
LGIA.
    If Transmission Provider determines that more than one 
Interconnection Customer in the same Cluster was financially 
impacted by the same withdrawn Interconnection Customer, 
Transmission Provider will apply the relevant withdrawn 
Interconnection Customer's Withdrawal Penalty funds that has not 
already been applied to study costs to reduce the financial impact 
to each Interconnection Customer based on each Interconnection 
Customer's proportional share of the financial impact, as determined 
by either the proportional impact method if it is a System Network 
Upgrade or on a per capita basis if it is a Substation Network 
Upgrade, as described under Section 4.2.1 of this LGIP.

3.7.1.2.3(b) Impact Calculation for Withdrawals in the Same Cluster 
After the Cluster Study Process

    If an Interconnection Customer withdraws after it executes, or 
requests the unexecuted filing of, its LGIA, Transmission Provider 
will distribute in the following manner the remaining Withdrawal 
Penalty funds to reduce the Network Upgrade cost impact on the 
remaining Interconnection Customers in the same Cluster who had a 
shared cost assignment with the withdrawn Interconnection Customer 
for one or more Network Upgrades.
    Transmission Provider will determine the financial impact on the 
remaining Interconnection Customers in the same Cluster within 30 
calendar days after the withdrawal occurs. The Transmission Provider 
will determine that financial impact by comparing the Network 
Upgrade cost funding obligations the Interconnection Customers 
shared with the withdrawn Interconnection Customer before the 
withdrawal of the Interconnection Customer and after the withdrawal 
of the Interconnection Customer. If that comparison indicates an 
increase in Network Upgrade costs for an Interconnection Customer, 
Transmission Provider shall apply the withdrawn Interconnection 
Customer's Withdrawal Penalty funds to the increased costs each 
impacted Interconnection Customer in the same Cluster experienced 
associated with such Network Upgrade(s) in proportion to each 
Interconnection Customer's increased cost assignment, as determined 
by Transmission Provider.

3.7.1.2.4 Amending LGIA To Apply Reductions To Interconnection 
Customer's Assigned Network Upgrade Costs and Associated Financial 
Security Requirement With Respect To Withdrawals in the Same Cluster

    Within 30 Calendar Days of all Interconnection Customers in the 
same Cluster having: (1) withdrawn or been deemed withdrawn; (2) 
executed an LGIA; or (3) requested an LGIA to be filed unexecuted, 
Transmission Provider must perform the calculations described in 
subsection 3.7.1.2.3(a) of this LGIP and provide such 
Interconnection Customers with an amended LGIA that provides the 
reduction in Network Upgrade cost assignment and associated 
reduction to the Interconnection Customer's financial security 
requirements, under Article 11.5 of the pro forma LGIA, due from the 
Interconnection Customer to the Transmission Provider.
    Where an Interconnection Customer executes the LGIA (or requests 
the filing of an unexecuted LGIA) and is later withdrawn or its LGIA 
is terminated, Transmission Provider must, within 30 Calendar Days 
of such withdrawal or termination, perform the calculations 
described in subsection 3.7.1.2.3(b) of this LGIP and provide such 
Interconnection Customers in the same Cluster with an amended LGIA 
that provides the reduction in Network Upgrade cost assignment and 
associated reduction to the Interconnection Customer's financial 
security requirements, under Article 11.5 of the pro forma LGIA, due 
from the Interconnection Customer to Transmission Provider.
    Any repayment by Transmission Provider to Interconnection 
Customer under Article 11.4 of the pro forma LGIA of amounts 
advanced for Network Upgrades after the Generating Facility achieves 
Commercial Operation shall be limited to the Interconnection 
Customer's total amount of Network Upgrade costs paid and associated 
financial security provided to Transmission Provider under Article 
11.5 of the pro forma LGIA.

3.7.1.2.5 Final Distribution of Withdrawal Penalty Funds

    If Withdrawal Penalty funds remain for the Cluster after the 
Withdrawal Penalty funds are applied to relevant study costs and net 
increases in shared cost assignments for Network Upgrades to 
remaining Interconnection Customers, Transmission Provider will 
return any remaining Withdrawal Penalty funds to the withdrawn 
Interconnection Customers in the same Cluster net of the amount of 
each withdrawn Interconnection Customer's Withdrawal Penalty funds 
applied to study costs and net increases in shared cost assignments 
for Network Upgrades to remaining Interconnection Customers.

3.8 Identification of Contingent Facilities

    Transmission Provider shall post in this section a method for 
identifying the

[[Page 61276]]

Contingent Facilities to be provided to Interconnection Customer at 
the conclusion of the [System Impact]Cluster Study and included in 
Interconnection Customer's Large Generator Interconnection 
Agreement. The method shall be sufficiently transparent to determine 
why a specific Contingent Facility was identified and how it relates 
to the Interconnection Request. Transmission Provider shall also 
provide, upon request of [the]Interconnection Customer, the 
estimated Interconnection Facility and/or Network Upgrade costs and 
estimated in-service completion time of each identified Contingent 
Facility when this information is readily available and not 
commercially sensitive.

3.9 Penalties for Failure To Meet Study Deadlines

    (1) Transmission Provider shall be subject to a penalty if it 
fails to complete a Cluster Study, Cluster Restudy, Interconnection 
Facilities Study, or Affected Systems Study by the applicable 
deadline set forth in this LGIP. Transmission Provider must pay the 
penalty for each late Cluster Study, Cluster Restudy, and 
Interconnection Facilities Study on a pro rata basis per 
Interconnection Request to all Interconnection Customer(s) included 
in the relevant study that did not withdraw, or were not deemed 
withdrawn, from Transmission Provider's interconnection queue before 
the missed study deadline. Transmission Provider must pay the 
penalty for a late Affected Systems Study on a pro rata basis per 
interconnection request to all Affected System Interconnection 
Customer(s) included in the relevant Affected System Study that did 
not withdraw, or were not deemed withdrawn, from the host 
transmission provider's interconnection queue before the missed 
study deadline. The study delay penalty for each late study shall be 
distributed no later than forty-five (45) Calendar Days after the 
late study has been completed.
    (2) For penalties assessed in accordance with this Section, the 
penalty amount will be equal to: $1,000 per Business Day for delays 
of Cluster Studies beyond the applicable deadline set forth in this 
LGIP; $2,000 per Business Day for delays of Cluster Re-Studies 
beyond the applicable deadline set forth in this LGIP; $2,000 per 
Business Day for delays of Affected System Studies beyond the 
applicable deadline set forth in this LGIP; and $2,500 per Business 
Day for delays of Interconnection Facilities Studies beyond the 
applicable deadline set forth in this LGIP. The total amount of a 
penalty assessed under this Section shall not exceed: (a) one 
hundred percent (100%) of the initial study deposit(s) received for 
all of the Interconnection Requests in the Cluster for Cluster 
Studies and Cluster Restudies; (b) one hundred percent (100%) of the 
initial study deposit received for the single Interconnection 
Request in the study for Facilities Studies; and (c) one hundred 
percent (100%) of the study deposit(s) that Transmission Provider 
collects for conducting the Affected System Study.
    (3) Transmission Provider may appeal to the Commission any 
penalties imposed under this Section. Any such appeal must be filed 
no later than forty-five (45) Calendar Days after the late study has 
been completed. While an appeal to the Commission is pending, 
Transmission Provider shall remain liable for the penalty, but need 
not distribute the penalty until forty-five (45) Calendar Days after 
(1) the deadline for filing a rehearing request has ended, if no 
requests for rehearing of the appeal have been filed, or (2) the 
date that any requests for rehearing of the Commission's decision on 
the appeal are no longer pending before the Commission. The 
Commission may excuse Transmission Provider from penalties under 
this Section for good cause.
    (4) No penalty will be assessed under this Section where a study 
is delayed by ten (10) Business Days or less. If the study is 
delayed by more than ten (10) Business Days, the penalty amount will 
be calculated from the first Business Day the Transmission Provider 
misses the applicable study deadline.
    (5) If (a) Transmission Provider needs to extend the deadline 
for a particular study subject to penalties under this Section and 
(b) all Interconnection Customers or Affected System Interconnection 
Customers included in the relevant study mutually agree to such an 
extension, the deadline for that study shall be extended thirty (30) 
Business Days from the original deadline. In such a scenario, no 
penalty will be assessed for Transmission Provider missing the 
original deadline.
    (6) No penalties shall be assessed until the third Cluster Study 
cycle (including any Transitional Cluster Study cycle, but not 
Transitional Serial Studies) after the Commission-approved effective 
date of Transmission Provider's filing made in compliance with the 
Final rule in Docket No. RM22-14-000.
    (7) Transmission Provider must maintain on its OASIS or its 
public website summary statistics related to penalties assessed 
under this Section, updated quarterly. For each calendar quarter, 
Transmission Provider must calculate and post (1) the total amount 
of penalties assessed under this Section during the previous 
reporting quarter and (2) the highest penalty assessed under this 
Section paid to a single Interconnection Customer or Affected System 
Interconnection Customer during the previous reporting quarter. 
Transmission Provider must post on its OASIS or its website these 
penalty amounts for each calendar quarter within thirty (30) 
Calendar Days of the end of the calendar quarter. Transmission 
Provider must maintain the quarterly measures posted on its OASIS or 
its website for three (3) calendar years with the first required 
posting to be the third Cluster Study cycle (including any 
Transitional Cluster Study cycle, but not Transitional Serial 
Studies) after Transmission Provider transitions to the Cluster 
Study Process.

Section 4. Interconnection Request Evaluation Process [Queue Position]

    Once an Interconnection Customer has submitted a valid 
Interconnection Request pursuant to Section 3.4 of this LGIP, such 
Interconnection Request shall become part of the Transmission 
Provider's interconnection queue for further processing pursuant to 
the following procedures.

4.1 Queue Position [General]

4.1.1 Assignment of Queue Position

    Transmission Provider shall assign a Queue Position as follows: 
the Queue Position within the queue shall be assigned based upon the 
date and time of receipt of all items required pursuant to the 
provisions of Section 3.4 of this LGIP. All Interconnection Requests 
submitted and validated in a single Cluster Request Window shall be 
considered equally queued. [based upon the date and time of receipt 
of the valid Interconnection Request; provided that, if the sole 
reason an Interconnection Request is not valid is the lack of 
required information on the application form, and Interconnection 
Customer provides such information in accordance with Section 3.4.3, 
then Transmission Provider shall assign Interconnection Customer a 
Queue Position based on the date the application form was originally 
filed. Moving a Point of Interconnection shall result in a lowering 
of Queue Position if it is deemed a Material Modification under 
Section 4.4.3.]
    [The Queue Position of each Interconnection Request will be used 
to determine the order of performing the Interconnection Studies and 
determination of cost responsibility for the facilities necessary to 
accommodate the Interconnection Request. A higher queued]

4.1.2 Higher Queue Position

    A higher Queue Position assigned to an Interconnection Request 
is one that has been placed ``earlier'' in the queue in relation to 
another Interconnection Request that is [lower queued. Transmission 
Provider may allocate the cost of the common upgrades for clustered 
Interconnection Requests without regard to Queue Position.]assigned 
a lower Queue Position. All requests studied in a single Cluster 
shall be considered equally queued. Interconnection Customers that 
are part of Clusters initiated earlier in time than an instant Queue 
shall be considered to have a higher Queue Position than 
Interconnection Customers that are part of Clusters initiated later 
than an instant Queue.

[4.2 Clustering

    At Transmission Provider's option, Interconnection Requests may 
be studied serially or in clusters for the purpose of the 
Interconnection System Impact Study.
    Clustering shall be implemented on the basis of Queue Position. 
If Transmission Provider elects to study Interconnection Requests 
using Clustering, all Interconnection Requests received within a 
period not to exceed one hundred and eighty (180) Calendar Days, 
hereinafter referred to as the ``Queue Cluster Window'' shall be 
studied together without regard to the nature of the underlying 
Interconnection Service, whether Energy Resource Interconnection 
Service or Network Resource Interconnection Service. The deadline 
for completing all Interconnection System Impact Studies for which 
an Interconnection System Impact Study Agreement has been executed 
during a Queue Cluster Window shall be in accordance with Section 
7.4, for all Interconnection Requests assigned to the same Queue 
Cluster Window. Transmission

[[Page 61277]]

Provider may study an Interconnection Request separately to the 
extent warranted by Good Utility Practice based upon the electrical 
remoteness of the proposed Large Generating Facility.]

4.2 General Study Process

    [Clustering Interconnection System Impact 
Studies]Interconnection Studies performed within the Cluster Study 
Process shall be conducted in such a manner to ensure the efficient 
implementation of the applicable regional transmission expansion 
plan in light of the Transmission System's capabilities at the time 
of each study and consistent with Good Utility Practice.
    Transmission Provider may use subgroups in the Cluster Study 
Process. In all instances in which Transmission Provider elects to 
use subgroups in the cluster study process, Transmission Provider 
must publish the criteria used to define and determine subgroups on 
its OASIS or public website.
    [The Queue Cluster Window shall have a fixed time interval based 
on fixed annual opening and closing dates. Any changes to the 
established Queue Cluster Window interval and opening or closing 
dates shall be announced with a posting on Transmission Provider's 
OASIS beginning at least one hundred and eighty (180) Calendar Days 
in advance of the change and continuing thereafter through the end 
date of the first Queue Cluster Window that is to be modified.]

4.2.1 Cost Allocation for Interconnection Facilities and Network 
Upgrades

    (1) For Network Upgrades identified in Cluster Studies, 
Transmission Provider shall calculate each Interconnection 
Customer's share of the costs as follows:
    (a) Substation Network Upgrades, including all switching 
stations, shall be allocated per capita to each Generating Facility 
interconnecting at the same substation.
    (b) System Network Upgrades shall be allocated based on the 
proportional impact of each individual Generating Facility in the 
Cluster Study on the need for a specific System Network Upgrade. 
{Transmission Provider shall include in this section a description 
of how cost for each facility type designated as a network upgrade 
will be allocated using its proportional impact method.{time} 
    (c) An Interconnection Customer that funds Substation Network 
Upgrades and/or System Network Upgrades shall be entitled to 
transmission credits as provided in Article 11.4 of the LGIA.
    (2) The costs of any needed Interconnection Facilities 
identified in the Cluster Study Process will be directly assigned to 
the Interconnection Customer(s) using such facilities. Where 
Interconnection Customers in the Cluster agree to share 
Interconnection Facilities, the cost of such Interconnection 
Facilities shall be allocated based on the number of Generating 
Facilities sharing use of such Interconnection Facilities on a per 
capita basis (i.e., on a per Generating Facility basis), unless 
Parties mutually agree to a different cost sharing arrangement.

4.3 Transferability of Queue Position

    An Interconnection Customer may transfer its Queue Position to 
another entity only if such entity acquires the specific Generating 
Facility identified in the Interconnection Request and the Point of 
Interconnection does not change.

4.4 Modifications

    Interconnection Customer shall submit to Transmission Provider, 
in writing, modifications to any information provided in the 
Interconnection Request. Interconnection Customer shall retain its 
Queue Position if the modifications are in accordance with Sections 
4.4.1, 4.4.2, or 4.4.5 of this LGIP, or are determined not to be 
Material Modifications pursuant to Section 4.4.3 of this LGIP.
    Notwithstanding the above, during the course of the 
Interconnection Studies, either Interconnection Customer or 
Transmission Provider may identify changes to the planned 
interconnection that may improve the costs and benefits (including 
reliability) of the interconnection, and the ability of the proposed 
change to accommodate the Interconnection Request. To the extent the 
identified changes are acceptable to Transmission Provider[,] and 
Interconnection Customer, such acceptance not to be unreasonably 
withheld, Transmission Provider shall modify the Point of 
Interconnection prior to return of the executed Cluster Study 
Agreement, [and/or configuration in accordance with such changes and 
proceed with any re-studies necessary to do so in accordance with 
Section 6.4, Section 7.6 and Section 8.5 as applicable] and 
Interconnection Customer shall retain its Queue Position.
    4.4.1 Prior to the return of the executed [Interconnection 
System Impact]Cluster Study Agreement to Transmission Provider, 
modifications permitted under this Section shall include 
specifically: (a) a decrease of up to 60 percent of electrical 
output (MW) of the proposed project, through either (1) a decrease 
in plant size or (2) a decrease in Interconnection Service level 
(consistent with the process described in Section 3.1 of this LGIP) 
accomplished by applying Transmission Provider-approved injection-
limiting equipment; (b) modifying the technical parameters 
associated with the Large Generating Facility technology or the 
Large Generating Facility step-up transformer impedance 
characteristics; and (c) modifying the interconnection 
configuration. For plant increases, the incremental increase in 
plant output will go [to]in the [end of the queue]next Cluster Study 
Window for the purposes of cost allocation and study analysis.
    4.4.2 Prior to the return of the executed Interconnection 
Facilit[y]ies Study Agreement to Transmission Provider, the 
modifications permitted under this Section shall include 
specifically: (a) additional 15 percent decrease of electrical 
output of the proposed project through either (1) a decrease in 
plant size (MW) or (2) a decrease in Interconnection Service level 
(consistent with the process described in Section 3.1) accomplished 
by applying Transmission Provider-approved injection-limiting 
equipment; (b) Large Generating Facility technical parameters 
associated with modifications to Large Generating Facility 
technology and transformer impedances; provided, however, the 
incremental costs associated with those modifications are the 
responsibility of the requesting Interconnection Customer; and (c) a 
Permissible Technological Advancement for the Large Generating 
Facility after the submission of the Interconnection Request. 
Section 4.4.6 specifies a separate technological change procedure 
including the requisite information and process that will be 
followed to assess whether the Interconnection Customer's proposed 
technological advancement under Section 4.4.2(c) is a Material 
Modification. Section 1 contains a definition of Permissible 
Technological Advancement.
    4.4.3 Prior to making any modification other than those 
specifically permitted by Sections 4.4.1, 4.4.2, and 4.4.5 of this 
LGIP, Interconnection Customer may first request that Transmission 
Provider evaluate whether such modification is a Material 
Modification. In response to Interconnection Customer's request, 
Transmission Provider shall evaluate the proposed modifications 
prior to making them and inform Interconnection Customer in writing 
of whether the modifications would constitute a Material 
Modification. Any change to the Point of Interconnection, except 
those deemed acceptable under Sections 3.1.2 or 4.4 of this LGIP[.1, 
6.1, 7.2] or so allowed elsewhere, shall constitute a Material 
Modification. Interconnection Customer may then withdraw the 
proposed modification or proceed with a new Interconnection Request 
for such modification. Transmission Provider shall study the 
addition of a Generating Facility that includes at least one 
electric storage resource using operating assumptions (i.e., whether 
the interconnecting Generating Facility will or will not charge at 
peak load) that reflect the proposed charging behavior of the 
Generating Facility as requested by Interconnection Customer, unless 
Transmission Provider determines that Good Utility Practice, 
including Applicable Reliability Standards, otherwise requires the 
use of different operating assumptions.
    {Transmission Providers using fuel-based dispatch assumptions in 
Interconnection Studies are not required to include Section 4.4.3.1 
because it does not apply to them{time} 
    4.4.3.1 Interconnection Customer may request, and Transmission 
Provider shall evaluate, the addition to the Interconnection Request 
of a Generating Facility with the same Point of Interconnection 
indicated in the initial Interconnection Request, if the addition of 
the Generating Facility does not increase the requested 
Interconnection Service level. Transmission Provider must evaluate 
such modifications prior to deeming them a Material Modification, 
but only if Interconnection Customer submits them prior to the 
return of the executed Facilities Study Agreement by Interconnection 
Customer to Transmission Provider. Interconnection Customers 
requesting that such a modification be evaluated must demonstrate 
the required Site Control at the time such request is made.

[[Page 61278]]

    4.4.4 Upon receipt of Interconnection Customer's request for 
modification permitted under this Section 4.4, Transmission Provider 
shall commence and perform any necessary additional studies as soon 
as practicable, but in no event shall Transmission Provider commence 
such studies later than thirty (30) Calendar Days after receiving 
notice of Interconnection Customer's request. Any additional studies 
resulting from such modification shall be done at Interconnection 
Customer's cost. Any such request for modification of the 
Interconnection Request must be accompanied by any resulting updates 
to the models described in Attachment A to Appendix 1 of this LGIP.
    4.4.5 Extensions of less than three (3) cumulative years in the 
Commercial Operation Date of the Large Generating Facility to which 
the Interconnection Request relates are not material and should be 
handled through construction sequencing. For purposes of this 
section, the Commercial Operation Date reflected in the initial 
Interconnection Request shall be used to calculate the permissible 
extension prior to Interconnection Customer executing an LGIA or 
requesting that the LGIA be filed unexecuted. After an LGIA is 
executed or requested to be filed unexecuted, the Commercial 
Operation Date reflected in the LGIA shall be used to calculate the 
permissible extension. Such cumulative extensions may not exceed 
three years including both extensions requested after execution of 
the LGIA by Interconnection Customer or the filing of an unexecuted 
LGIA by Transmission Provider and those requested prior to execution 
of the LGIA by Interconnection Customer or the filing of an 
unexecuted LGIA by Transmission Provider.

4.4.6 Technological Change Procedures

    {Insert technological change procedure here{time} 

Section 5. Procedures for Interconnection Requests Submitted Prior to 
Effective Date of the Cluster Study Revisions[Standard Large Generator 
Interconnection Procedures]

5.1 Procedures for Transitioning to the Cluster Study Process [Queue 
Position for Pending Requests.]

5.1.1

    [Any Interconnection Customer assigned a Queue Position prior to 
the effective date of this LGIP shall retain that Queue Position.]
    Any Interconnection Customer assigned a Queue Position as of 
thirty (30) Calendar Days after {Transmission Provider to insert 
filing date{time}  (the filing date of this LGIP) shall retain that 
Queue Position subject to the requirements in Sections 5.1.1.1 and 
5.1.1.2 of this LGIP. Any Interconnection Customer that fails to 
meet these requirements shall have its Interconnection Request 
deemed withdrawn by Transmission Provider pursuant to Section 3.7 of 
this LGIP. In such case, Transmission Provider shall not assess the 
Interconnection Customer any Withdrawal Penalty.
    Any Interconnection Customer that has received a final 
Interconnection Facilities Study Report before the commencement of 
the studies under the transition process set forth in this section 
shall be tendered an LGIA pursuant to Section 11 of this LGIP, and 
shall not be required to enter this transition process.

5.1.1.1 Transitional Serial Study

    [If an Interconnection Study Agreement has not been executed as 
of the effective date of this LGIP, then such Interconnection Study, 
and any subsequent Interconnection Studies, shall be processed in 
accordance with this LGIP.]
    An Interconnection Customer that has been tendered an 
Interconnection Facilities Study Agreement as of thirty (30) 
Calendar Days after {Transmission Provider to insert filing 
date{time}  (the filing date of this LGIP) may opt to proceed with 
an Interconnection Facilities Study. Transmission Provider shall 
tender each eligible Interconnection Customer a Transitional Serial 
Interconnection Facilities Study Agreement, in the form of Appendix 
8 to this LGIP, no later than the Commission-approved effective date 
of this LGIP. Transmission Provider shall proceed with the 
Interconnection Facilities Study, provided that the Interconnection 
Customer: (1) meets each of the following requirements; and (2) 
executes the Transitional Serial Interconnection Facilities Study 
Agreement within sixty (60) Calendar Days of the Commission-approved 
effective date of this LGIP. If an eligible Interconnection Customer 
does not meet these requirements, its Interconnection Request shall 
be deemed withdrawn without penalty. Transmission Provider must 
commence the Transitional Serial Interconnection Facilities Study at 
the conclusion of this sixty (60) Calendar Day period. Transitional 
Serial Interconnection Facilities Study costs shall be allocated 
according to the method described in Section 13.3 of this LGIP.
    All of the following must be included when an Interconnection 
Customer returns the Transitional Serial Interconnection Facilities 
Study Agreement:
    (1) A deposit equal to one hundred percent (100%) of the costs 
identified for Transmission Provider's Interconnection Facilities 
and Network Upgrades in Interconnection Customer's system impact 
study report. If Interconnection Customer does not withdraw, the 
deposit shall be trued up to actual costs once they are known and 
applied to future construction costs described in Interconnection 
Customer's eventual LGIA. Any amounts in excess of the actual 
construction costs shall be returned to Interconnection Customer 
within thirty (30) Calendar Days of the issuance of a final invoice 
for construction costs, in accordance with Article 12.2 of the pro 
forma LGIA. If Interconnection Customer withdraws or otherwise does 
not reach Commercial Operation, Transmission Provider shall refund 
the remaining deposit after the final invoice for study costs and 
Withdrawal Penalty is settled. The deposit shall be in the form of 
an irrevocable letter of credit or cash where cash deposits shall be 
treated according to Section 3.7 of this LGIP.
    (2) Exclusive Site Control for 100% of the proposed Generating 
Facility.
    Transmission Provider shall conduct each Transitional Serial 
Interconnection Facilities Study and issue the associated 
Transitional Serial Interconnection Facilities Study Report within 
one hundred fifty (150) Calendar Days of the Commission-approved 
effective date of this LGIP.
    After Transmission Provider issues each Transitional 
Interconnection Facilities Study Report, Interconnection Customer 
shall proceed pursuant to Section 11 of this LGIP. If 
Interconnection Customer withdraws its Interconnection Request or if 
Interconnection Customer's Generating Facility otherwise does not 
reach Commercial Operation, a Withdrawal Penalty shall be imposed on 
Interconnection Customer equal to nine (9) times Interconnection 
Customer's total study cost incurred since entering the Transmission 
Provider's interconnection queue (including the cost of studies 
conducted under Section 5 of this LGIP).

5.1.1.2 Transitional Cluster Study

    [If an Interconnection Study Agreement has been executed prior 
to the effective date of this LGIP, such Interconnection Study shall 
be completed in accordance with the terms of such agreement. With 
respect to any remaining studies for which an Interconnection 
Customer has not signed an Interconnection Study Agreement prior to 
the effective date of the LGIP, Transmission Provider must offer 
Interconnection Customer the option of either continuing under 
Transmission Provider's existing interconnection study process or 
going forward with the completion of the necessary Interconnection 
Studies (for which it does not have a signed Interconnection Studies 
Agreement) in accordance with this LGIP.]
    An Interconnection Customer with an assigned Queue Position as 
of thirty (30) Calendar Days after {Transmission Provider to insert 
filing date{time}  (the filing date of this LGIP) may opt to proceed 
with a Transitional Cluster Study. Transmission Provider shall 
tender each eligible Interconnection Customer a Transitional Cluster 
Study Agreement, in the form of Appendix 7 to this LGIP, no later 
than the Commission-approved effective date of this LGIP. 
Transmission Provider shall proceed with the Transitional Cluster 
Study that includes each Interconnection Customer that: (1) meets 
each of the following requirements listed as (1)-(3) in this 
section; and (2) executes the Transitional Cluster Study Agreement 
within sixty (60) Calendar Days of the Commission-approved effective 
date of this LGIP. All Interconnection Requests that enter the 
Transitional Cluster Study shall be considered to have an equal 
Queue Position that is lower than Interconnection Customer(s) 
proceeding with Transitional Serial Interconnection Facilities 
Study. If an eligible Interconnection Customer does not meet these 
requirements, its Interconnection Request shall be deemed withdrawn 
without penalty. Transmission Provider must commence the 
Transitional Cluster Study at the conclusion of this sixty (60) 
Calendar Day period. All identified Transmission Provider's 
Interconnection Facilities and Network Upgrade costs shall be 
allocated according to Section 4.2.1 of this LGIP. Transitional 
Cluster Study costs shall be allocated according to the method 
described in Section 13.3 of this LGIP.

[[Page 61279]]

    Interconnection Customer may make a one-time extension to its 
requested Commercial Operation Date upon entry into the Transitional 
Cluster Study, where any such extension shall not result in a 
Commercial Operation Date later than December 31, 2027.
    All of the following must be included when an Interconnection 
Customer returns the Transitional Cluster Study Agreement:
    (1) A selection of either Energy Resource Interconnection 
Service or Network Resource Interconnection Service.
    (2) A deposit of five million dollars ($5,000,000) in the form 
of an irrevocable letter of credit or cash where cash deposits will 
be treated according to Section 3.7 of this LGIP. If Interconnection 
Customer does not withdraw, the deposit shall be reconciled with and 
applied towards future construction costs described in the LGIA. Any 
amounts in excess of the actual construction costs shall be returned 
to Interconnection Customer within thirty (30) Calendar Days of the 
issuance of a final invoice for construction costs, in accordance 
with Article 12.2 of the pro forma LGIA. If Interconnection Customer 
withdraws or otherwise does not reach Commercial Operation, 
Transmission Provider must refund the remaining deposit once the 
final invoice for study costs and Withdrawal Penalty is settled.
    (3) Exclusive Site Control for 100% of the proposed Generating 
Facility.
    Transmission Provider shall conduct the Transitional Cluster 
Study and issue both an associated interim Transitional Cluster 
Study Report and an associated final Transitional Cluster Study 
Report. The interim Transitional Cluster Study Report shall provide 
the following information:

--identification of any circuit breaker short circuit capability 
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations 
resulting from the interconnection;
--identification of any instability or inadequately damped response 
to system disturbances resulting from the interconnection; and
--Transmission Provider's Interconnection Facilities and Network 
Upgrades that are expected to be required as a result of the 
Interconnection Request(s) and a non-binding, good faith estimate of 
cost responsibility and a non-binding, good faith estimated time to 
construct.

    In addition to the information provided in the interim 
Transitional Cluster Study Report, the final Transitional Cluster 
Study Report shall provide a description of, estimated cost of, and 
schedule for construction of the Transmission Provider's 
Interconnection Facilities and Network Upgrades required to 
interconnect the Generating Facility to the Transmission System that 
resolve issues identified in the interim Transitional Cluster Study 
Report.
    The interim and final Transitional Cluster Study Reports shall 
be issued within three hundred (300) and three hundred sixty (360) 
Calendar Days of the Commission-approved effective date of this 
LGIP, respectively, and shall be posted on Transmission Provider's 
OASIS consistent with the posting of other study results pursuant to 
Section 3.5.1 of this LGIP. Interconnection Customer shall have 
thirty (30) Calendar Days to comment on the interim Transitional 
Cluster Study Report, once it has been received.
    After Transmission Provider issues the final Transitional 
Cluster Study Report, Interconnection Customer shall proceed 
pursuant to Section 11 of this LGIP. If Interconnection Customer 
withdraws its Interconnection Request or if Interconnection 
Customer's Generating Facility otherwise does not reach Commercial 
Operation, a Withdrawal Penalty will be imposed om Interconnection 
Customer equal to nine (9) times Interconnection Customer's total 
study cost incurred since entering the Transmission Provider's 
interconnection queue (including the cost of studies conducted under 
Section 5 of this LGIP).
    [5.1.1.3 If an LGIA has been submitted to FERC for approval 
before the effective date of the LGIP, then the LGIA would be 
grandfathered.

5.1.2 Transition Period

    To the extent necessary, Transmission Provider and 
Interconnection Customers with an outstanding request (i.e., an 
Interconnection Request for which an LGIA has not been submitted to 
FERC for approval as of the effective date of this LGIP) shall 
transition to this LGIP within a reasonable period of time not to 
exceed sixty (60) Calendar Days. The use of the term ``outstanding 
request'' herein shall mean any Interconnection Request, on the 
effective date of this LGIP: (i) that has been submitted but not yet 
accepted by Transmission Provider; (ii) where the related 
interconnection agreement has not yet been submitted to FERC for 
approval in executed or unexecuted form, (iii) where the relevant 
Interconnection Study Agreements have not yet been executed, or (iv) 
where any of the relevant Interconnection Studies are in process but 
not yet completed. Any Interconnection Customer with an outstanding 
request as of the effective date of this LGIP may request a 
reasonable extension of any deadline, otherwise applicable, if 
necessary to avoid undue hardship or prejudice to its 
Interconnection Request. A reasonable extension shall be granted by 
Transmission Provider to the extent consistent with the intent and 
process provided for under this LGIP.]

5.2 New Transmission Provider

    If Transmission Provider transfers control of its Transmission 
System to a successor Transmission Provider during the period when 
an Interconnection Request is pending, the original Transmission 
Provider shall transfer to the successor Transmission Provider any 
amount of the deposit or payment with interest thereon that exceeds 
the cost that it incurred to evaluate the request for 
interconnection. Any difference between such net amount and the 
deposit or payment required by this LGIP shall be paid by or 
refunded to the Interconnection Customer, as appropriate. The 
original Transmission Provider shall coordinate with the successor 
Transmission Provider to complete any Interconnection Study, as 
appropriate, that the original Transmission Provider has begun but 
has not completed. If Transmission Provider has tendered a draft 
LGIA to Interconnection Customer but Interconnection Customer has 
not either executed the LGIA or requested the filing of an 
unexecuted LGIA with FERC, unless otherwise provided, 
Interconnection Customer must complete negotiations with the 
successor Transmission Provider.

Section 6. Interconnection Information Access [Feasibility Study]

6.1 Publicly Posted Interconnection Information

    Transmission Provider shall maintain and make publicly 
available: (1) an interactive visual representation of the estimated 
incremental injection capacity (in megawatts) available at each 
point of interconnection in Transmission Provider's footprint under 
N-1 conditions, and (2) a table of metrics concerning the estimated 
impact of a potential Generating Facility on Transmission Provider's 
Transmission System based on a user-specified addition of a 
particular number of megawatts at a particular voltage level at a 
particular point of interconnection. At a minimum, for each 
transmission facility impacted by the user-specified megawatt 
addition, the following information will be provided in the table: 
(1) the distribution factor; (2) the megawatt impact (based on the 
megawatt values of the proposed Generating Facility and the 
distribution factor); (3) the percentage impact on each impacted 
transmission facility (based on the megawatt values of the proposed 
Generating Facility and the facility rating); (4) the percentage of 
power flow on each impacted transmission facility before the 
injection of the proposed project; (5) the percentage power flow on 
each impacted transmission facility after the injection of the 
proposed Generating Facility. These metrics must be calculated based 
on the power flow model of the Transmission System with the transfer 
simulated from each point of interconnection to the whole 
Transmission Provider's footprint (to approximate Network Resource 
Interconnection Service), and with the incremental capacity at each 
point of interconnection decremented by the existing and queued 
Generating Facilities (based on the existing or requested 
interconnection service limit of the generation). These metrics must 
be updated within thirty (30) Calendar Days after the completion of 
each Cluster Study and Cluster Restudy. This information must be 
publicly posted, without a password or a fee. The website will 
define all underlying assumptions, including the name of the most 
recent Cluster Study or Restudy used in the Base Case.

[6.1 Interconnection Feasibility Study Agreement

    Simultaneously with the acknowledgement of a valid 
Interconnection Request Transmission Provider shall provide to 
Interconnection Customer an Interconnection Feasibility Study 
Agreement in the form of Appendix 2. The Interconnection Feasibility 
Study Agreement shall: specify that Interconnection Customer is 
responsible for the actual cost of the Interconnection Feasibility 
Study. Within five (5) Business

[[Page 61280]]

Days following the Scoping Meeting Interconnection Customer shall 
specify for inclusion in the attachment to the Interconnection 
Feasibility Study Agreement the Point(s) of Interconnection and any 
reasonable alternative Point(s) of Interconnection. Within five (5) 
Business Days following Transmission Provider's receipt of such 
designation, Transmission Provider shall tender to Interconnection 
Customer the Interconnection Feasibility Study Agreement signed by 
Transmission Provider, which includes a good faith estimate of the 
cost for completing the Interconnection Feasibility Study. 
Interconnection Customer shall execute and deliver to Transmission 
Provider the Interconnection Feasibility Study Agreement along with 
a $10,000 deposit no later than thirty (30) Calendar Days after its 
receipt.
    On or before the return of the executed Feasibility Study 
Agreement to Transmission Provider, Interconnection Customer shall 
provide the technical data called for in Appendix 1, Attachment A.
    If the Interconnection Feasibility Study uncovers any unexpected 
result(s) not contemplated during the Scoping Meeting, a substitute 
Point of Interconnection identified by either Interconnection 
Customer or Transmission Provider, and acceptable to the other, such 
acceptance not to be unreasonably withheld, will be substituted for 
the designated Point of Interconnection specified above without loss 
of Queue Position, and Re-studies shall be completed pursuant to 
Section 6.4 as applicable. For the purpose of this Section 6.1, if 
Transmission Provider and Interconnection Customer cannot agree on 
the substituted Point of Interconnection, then Interconnection 
Customer may direct that one of the alternatives as specified in the 
Interconnection Feasibility Study Agreement, as specified pursuant 
to Section 3.4.4, shall be the substitute.
    If Interconnection Customer and Transmission Provider agree to 
forgo the Interconnection Feasibility Study, Transmission Provider 
will initiate an Interconnection System Impact Study under Section 7 
of this LGIP and apply the $10,000 deposit towards the 
Interconnection System Impact Study.]

[6.2 Scope of Interconnection Feasibility Study

    The Interconnection Feasibility Study shall preliminarily 
evaluate the feasibility of the proposed interconnection to the 
Transmission System.
    The Interconnection Feasibility Study will consider the Base 
Case as well as all generating facilities (and with respect to 
(iii), any identified Network Upgrades) that, on the date the 
Interconnection Feasibility Study is commenced: (i) are directly 
interconnected to the Transmission System; (ii) are interconnected 
to Affected Systems and may have an impact on the Interconnection 
Request; (iii) have a pending higher queued Interconnection Request 
to interconnect to the Transmission System; and (iv) have no Queue 
Position but have executed an LGIA or requested that an unexecuted 
LGIA be filed with FERC. The Interconnection Feasibility Study will 
consist of a power flow and short circuit analysis. The 
Interconnection Feasibility Study will provide a list of facilities 
and a non-binding good faith estimate of cost responsibility and a 
non-binding good faith estimated time to construct.]

[6.3 Interconnection Feasibility Study Procedures

    Transmission Provider shall utilize existing studies to the 
extent practicable when it performs the study. Transmission Provider 
shall use Reasonable Efforts to complete the Interconnection 
Feasibility Study no later than forty-five (45) Calendar Days after 
Transmission Provider receives the fully executed Interconnection 
Feasibility Study Agreement. At the request of Interconnection 
Customer or at any time Transmission Provider determines that it 
will not meet the required time frame for completing the 
Interconnection Feasibility Study, Transmission Provider shall 
notify Interconnection Customer as to the schedule status of the 
Interconnection Feasibility Study. If Transmission Provider is 
unable to complete the Interconnection Feasibility Study within that 
time period, it shall notify Interconnection Customer and provide an 
estimated completion date with an explanation of the reasons why 
additional time is required. Upon request, Transmission Provider 
shall provide Interconnection Customer supporting documentation, 
workpapers and relevant power flow, short circuit and stability 
databases for the Interconnection Feasibility Study, subject to 
confidentiality arrangements consistent with Section 13.1.
    Transmission Provider shall study the Interconnection Request at 
the level of service requested by the Interconnection Customer, 
unless otherwise required to study the full Generating Facility 
Capacity due to safety or reliability concerns.]

[6.3.1 Meeting With Transmission Provider

    Within ten (10) Business Days of providing an Interconnection 
Feasibility Study report to Interconnection Customer, Transmission 
Provider and Interconnection Customer shall meet to discuss the 
results of the Interconnection Feasibility Study.]

[6.4 Re-Study

    If Re-Study of the Interconnection Feasibility Study is required 
due to a higher queued project dropping out of the queue, or a 
modification of a higher queued project subject to Section 4.4, or 
re-designation of the Point of Interconnection pursuant to Section 
6.1 Transmission Provider shall notify Interconnection Customer in 
writing. Such Re-Study shall take not longer than forty-five (45) 
Calendar Days from the date of the notice. Any cost of Re-Study 
shall be borne by the Interconnection Customer being re-studied.]

Section 7. [Interconnection System Impact] Cluster Study

7.1 [Interconnection System Impact] Cluster Study Agreement

    [Unless otherwise agreed, pursuant to the Scoping Meeting 
provided in Section 3.4.4, simultaneously with the delivery of the 
Interconnection Feasibility Study to Interconnection Customer] No 
later than five (5) Business Days after the close of a Cluster 
Request Window, Transmission Provider shall [provide ] tender to 
each Interconnection Customer [an] that submitted a valid 
Interconnection[ System Impact] Request a Cluster Study Agreement in 
the form of Appendix 2[3] to this LGIP. The [Interconnection System 
Impact] Cluster Study Agreement shall [provide that ] require 
Interconnection Customer [shall] to compensate Transmission Provider 
for the actual cost of the [Interconnection System Impact 
Study.]Cluster Study pursuant to Section 13.3 of this LGIP. The 
specifications, assumptions, or other provisions in the appendices 
of the Cluster Study Agreement provided pursuant to Section 7.1 of 
this LGIP shall be subject to change by Transmission Provider 
following the conclusion of the Scoping Meeting. [Within three (3) 
Business Days following the Interconnection Feasibility Study 
results meeting, Transmission Provider shall provide to 
Interconnection Customer a non-binding good faith estimate of the 
cost and timeframe for completing the Interconnection System Impact 
Study.]

7.2 Execution of [Interconnection System Impact]Cluster Study Agreement

    Interconnection Customer shall execute the [Interconnection 
System Impact]Cluster Study Agreement and deliver the executed 
[Interconnection System Impact]Cluster Study Agreement to 
Transmission Provider no later than [thirty (30) Calendar Days after 
its receipt along with demonstration of Site Control, and a $50,000 
deposit] the close of the Customer Engagement Window.
    If Interconnection Customer does not provide all [such] required 
technical data when it delivers the [Interconnection System 
Impact]Cluster Study Agreement, Transmission Provider shall notify 
Interconnection Customer of the deficiency within five (5) Business 
Days of the receipt of the executed [Interconnection System Impact] 
Cluster Study Agreement and Interconnection Customer shall cure the 
deficiency within ten (10) Business Days of receipt of the notice, 
provided, however, such deficiency does not include failure to 
deliver the executed [Interconnection System Impact]Cluster Study 
Agreement or Study Deposit.
    [If the Interconnection System Impact Study uncovers any 
unexpected result(s) not contemplated during the Scoping Meeting and 
the Interconnection Feasibility Study, a substitute Point of 
Interconnection identified by either Interconnection Customer or 
Transmission Provider, and acceptable to the other, such acceptance 
not to be unreasonably withheld, will be substituted for the 
designated Point of Interconnection specified above without loss of 
Queue Position, and restudies shall be completed pursuant to Section 
7.6 as applicable. For the purpose of this Section 7.2, if 
Transmission Provider and Interconnection Customer cannot agree on 
the substituted Point of Interconnection, then Interconnection 
Customer may direct that one of the alternatives as specified in the 
Interconnection Feasibility Study Agreement,

[[Page 61281]]

as specified pursuant to Section 3.4.4, shall be the substitute.]

7.3 Scope of [Interconnection System Impact] Cluster Study

    The [Interconnection System Impact]Cluster Study shall evaluate 
the impact of the proposed interconnection on the reliability of the 
Transmission System. The [Interconnection System Impact] Cluster 
Study will consider the Base Case as well as all Generating 
Facilities (and with respect to (iii) below, any identified Network 
Upgrades associated with such higher queued interconnection) that, 
on the date the [Interconnection System Impact] Cluster Study is 
commenced: (i) are directly interconnected to the Transmission 
System; (ii) are interconnected to Affected Systems and may have an 
impact on the Interconnection Request; (iii) have a pending higher 
queued Interconnection Request to interconnect to the Transmission 
System; and (iv) have no Queue Position but have executed an LGIA or 
requested that an unexecuted LGIA be filed with FERC.
    For purposes of determining necessary Interconnection Facilities 
and Network Upgrades, the Cluster Study shall use the level of 
Interconnection Service requested by Interconnection Customers in 
the Cluster, except where the Transmission Provider otherwise 
determines that it must study the full Generating Facility Capacity 
due to safety or reliability concerns.
    The [Interconnection System Impact] Cluster Study will consist 
of [a short circuit analysis, a] power flow, stability [analysis, 
and a power flow analysis. The Interconnection System Impact Study], 
and short circuit analyses, the results of which are documented in a 
single Cluster Study Report, as applicable. At the conclusion of the 
Cluster Study, Transmission Provider shall issue a Cluster Study 
Report. The Cluster Study Report will state the assumptions upon 
which it is based; state the results of the analyses; and provide 
the requirements or potential impediments to providing the requested 
interconnection service, including a preliminary indication of the 
cost and length of time that would be necessary to correct any 
problems identified in those analyses and implement the 
interconnection. [For purposes of determining necessary] The Cluster 
Study Report shall identify the Interconnection Facilities and 
Network Upgrades [, the System Impact Study shall consider the level 
of Interconnection Service requested by the Interconnection 
Customer, unless otherwise required to study the full Generating 
Facility Capacity due to safety or reliability concerns.] expected 
to be required to reliably interconnect the Generating Facilities in 
that Cluster Study at the requested Interconnection Service level 
and shall provide non-binding cost estimates for required Network 
Upgrades. The Cluster Study Report shall identify each 
Interconnection Customer's estimated allocated costs for 
Interconnection Facilities and Network Upgrades pursuant to the 
method in Section 4.2.1 of this LGIP. Transmission Provider shall 
hold an open stakeholder meeting pursuant to Section 7.4 of this 
LGIP.
    For purposes of determining necessary Interconnection Facilities 
and Network Upgrades, the Cluster Study shall use operating 
assumptions (i.e., whether the interconnecting Generating Facility 
will or will not charge at peak load) that reflect the proposed 
charging behavior of a Generating Facility that includes at least 
one electric storage resource as requested by Interconnection 
Customer, unless Transmission Provider determines that Good Utility 
Practice, including Applicable Reliability Standards, otherwise 
requires the use of different operating assumptions. Transmission 
Provider may require the inclusion of control technologies 
sufficient to limit the operation of the Generating Facility per the 
operating assumptions as set forth in the Interconnection Request 
and to respond to dispatch instructions by Transmission Provider. As 
determined by Transmission Provider, Interconnection Customer may be 
subject to testing and validation of those control technologies 
consistent with Article 6 of the LGIA.
    [The Interconnection System Impact Study] The Cluster Study 
Report will provide a list of facilities that are required as a 
result of the Interconnection [Request] Requests within the Cluster 
and a non-binding good faith estimate of cost responsibility and a 
non-binding good faith estimated time to construct.
    Upon issuance of a Cluster Study Report, or Cluster Restudy 
Report, if any, Transmission Provider shall simultaneously tender a 
draft Interconnection Facilities Study Agreement to each 
Interconnection Customer within the Cluster, subject to the 
conditions in Section 8.1 of this LGIP.
    The Cluster Study shall evaluate the use of static synchronous 
compensators, static VAR compensators, advanced power flow control 
devices, transmission switching, synchronous condensers, voltage 
source converters, advanced conductors, and tower lifting. 
Transmission Provider shall determine whether the above technologies 
should be used, consistent with Good Utility Practice and other 
applicable regulatory requirements. Transmission Provider shall 
include an explanation of the results of the Transmission Provider's 
evaluation for each technology in the Cluster Study Report.

7.4 [Interconnection System Impact] Cluster Study Procedures

    Transmission Provider shall coordinate the [Interconnection 
System Impact] Cluster Study with any Affected System that is 
affected by the Interconnection Request pursuant to Section 3.6 
[above] of this LGIP. Transmission Provider shall utilize existing 
studies to the extent practicable when it performs the [study] 
Cluster Study. Interconnection Requests for a Cluster Study may be 
submitted only within the Cluster Request Window and Transmission 
Provider shall [use Reasonable Efforts to complete the 
Interconnection System Impact Study within ninety (90) Calendar Days 
after the receipt of the Interconnection System Impact Study 
Agreement or notification to proceed, study payment, and technical 
data. If Transmission Provider uses Clustering, Transmission 
Provider shall use Reasonable Efforts to deliver a completed 
Interconnection System Impact Study within ninety (90) Calendar Days 
after the close of the Queue Cluster Window.] initiate the Cluster 
Study process pursuant to Section 7 of this LGIP.
    Transmission Provider shall complete the Cluster Study within 
one hundred fifty (150) Calendar Days of the close of the Customer 
Engagement Window.
    Within ten (10) Business Days of simultaneously furnishing a 
Cluster Study Report to each Interconnection Customer within the 
Cluster and posting such report on OASIS, Transmission Provider 
shall convene a Cluster Study Report Meeting.
    At the request of Interconnection Customer or at any time 
Transmission Provider determines that it will not meet the required 
time frame for completing the [Interconnection System Impact] 
Cluster Study, Transmission Provider shall notify Interconnection 
Customers as to the schedule status of the [Interconnection System 
Impact] Cluster Study. If Transmission Provider is unable to 
complete the [Interconnection System Impact] Cluster Study within 
the time period, it shall notify Interconnection Customers and 
provide an estimated completion date with an explanation of the 
reasons why additional time is required. Upon request, Transmission 
Provider shall provide to Interconnection Customers all supporting 
documentation, workpapers and relevant pre-Interconnection Request 
and post-Interconnection Request power flow, short circuit and 
stability databases for the [Interconnection System Impact] Cluster 
Study, subject to confidentiality arrangements consistent with 
Section 13.1 of this LGIP.

7.5 Cluster Study Restudies

    (1) Within twenty (20) Calendar Days after the Cluster Study 
Report Meeting, Interconnection Customer must provide the following:
    (a) Demonstration of continued Site Control pursuant to Section 
3.4.2(iii) of this LGIP; and
    (b) An additional deposit that brings the total Commercial 
Readiness Deposit submitted to Transmission Provider to five percent 
(5%) of the Interconnection Customer's Network Upgrade cost 
assignment identified in the Cluster Study in the form of an 
irrevocable letter of credit or cash. Transmission Provider shall 
refund the deposit to Interconnection Customer upon withdrawal in 
accordance with Section 3.7 of this LGIP.
    Interconnection Customer shall promptly inform Transmission 
Provider of any material change to Interconnection Customer's 
demonstration of Site Control under Section 3.4.2(iii) of this LGIP. 
Upon Transmission Provider determining that Interconnection Customer 
no longer satisfies the Site Control requirement, Transmission 
Provider shall notify Interconnection Customer. Within ten (10) 
Business Days of such notification, Interconnection Customer must 
demonstrate compliance with the applicable requirement subject to 
Transmission Provider's approval, not to be unreasonably withheld. 
Absent such demonstration, Transmission Provider shall deem the 
subject Interconnection Request

[[Page 61282]]

withdrawn pursuant to Section 3.7 of this LGIP.
    (2) If no Interconnection Customer withdraws from the Cluster 
after completion of the Cluster Study or Cluster Restudy or is 
deemed withdrawn pursuant to Section 3.7 of this LGIP after 
completion of the Cluster Study or Cluster Restudy, Transmission 
Provider shall notify Interconnection Customers in the Cluster that 
a Cluster Restudy is not required.
    (3) If one or more Interconnection Customers withdraw from the 
Cluster or are deemed withdrawn pursuant to Section 3.7 of this 
LGIP, Transmission Provider shall determine if a Cluster Restudy is 
necessary within thirty (30) Calendar Days after the Cluster Study 
Report Meeting. If Transmission Provider determines a Cluster 
Restudy is not necessary, Transmission Provider shall notify 
Interconnection Customers in the Cluster that a Cluster Restudy is 
not required and Transmission Provider shall provide an updated 
Cluster Study Report within thirty (30) Calendar Days of such 
determination.
    (4) If one or more Interconnection Customers withdraws from the 
Cluster or is deemed withdrawn pursuant to Section 3.7 of this LGIP, 
and Transmission Provider determines a Cluster Restudy is necessary 
as a result, Transmission Provider shall notify Interconnection 
Customers in the Cluster and post on OASIS that a Cluster Restudy is 
required within thirty (30) Calendar Days after the Cluster Study 
Report Meeting. Transmission Provider shall continue with such 
restudies until Transmission Provider determines that no further 
restudies are required. If an Interconnection Customer withdraws or 
is deemed withdrawn pursuant to Section 3.7 of this LGIP during the 
Interconnection Facilities Study, or after other Interconnection 
Customers in the same Cluster have executed LGIAs, or requested that 
unexecuted LGIAs be filed, and Transmission Provider determines a 
Cluster Restudy is necessary, the Cluster shall be restudied.
    (5) The scope of any Cluster Restudy shall be consistent with 
the scope of an initial Cluster Study pursuant to Section 7.3 of 
this LGIP. Transmission Provider shall complete the Cluster Restudy 
within one hundred fifty (150) Calendar Days of the Transmission 
Provider informing the Interconnection Customers in the cluster that 
restudy is needed. The results of the Cluster Restudy shall be 
combined into a single report (Cluster Restudy Report). Transmission 
Provider shall hold a meeting with the Interconnection Customers in 
the cluster (Cluster Restudy Report Meeting) within ten (10) 
Business Days of simultaneously furnishing the Cluster Restudy 
Report to each Interconnection Customer in the Cluster Restudy and 
publishing the Cluster Restudy Report on OASIS.
    If additional restudies are required, Interconnection Customer 
and Transmission Provider shall follow the procedures of this 
Section 7.5 of this LGIP until such time that Transmission Provider 
determines that no further restudies are required. Transmission 
Provider shall notify each Interconnection Customer within the 
Cluster when no further restudies are required.

[Meeting With Transmission Provider

    Within ten (10) Business Days of providing an Interconnection 
System Impact Study report to Interconnection Customer, Transmission 
Provider and Interconnection Customer shall meet to discuss the 
results of the Interconnection System Impact Study.

7.6 Re-Study

    If Re-Study of the Interconnection System Impact Study is 
required due to a higher queued project dropping out of the queue, 
or a modification of a higher queued project subject to 4.4, or re-
designation of the Point of Interconnection pursuant to Section 7.2 
Transmission Provider shall notify Interconnection Customer in 
writing. Such Re-Study shall take no longer than sixty (60) Calendar 
Days from the date of notice. Any cost of Re-Study shall be borne by 
the Interconnection Customer being re-studied.]

Section 8. Interconnection Facilities Study

8.1 Interconnection Facilities Study Agreement

    Simultaneously with the delivery of the [Interconnection System 
Impact Study to Interconnection Customer] Cluster Study Report, or 
Cluster Restudy Report if applicable, Transmission Provider shall 
provide to Interconnection Customer an Interconnection Facilities 
Study Agreement in the form of Appendix 3[4] to this LGIP. [The 
Interconnection Facilities Study Agreement shall provide that] 
Interconnection Customer shall compensate Transmission Provider for 
the actual cost of the Interconnection Facilities Study. Within five 
(5) Business Days following the Cluster Report Meeting or Cluster 
Restudy Report Meeting if applicable, [Interconnection System Impact 
Study results meeting], Transmission Provider shall provide to 
Interconnection Customer a non-binding good faith estimate of the 
cost and timeframe for completing the Interconnection Facilities 
Study.
    Interconnection Customer shall execute the Interconnection 
Facilities Study Agreement and deliver the executed Interconnection 
Facilities Study Agreement to Transmission Provider within thirty 
(30) Calendar Days after its receipt, together with [the]:
    (1) any required technical data[and the greater of $100,000 or 
Interconnection Customer's portion of the estimated monthly cost of 
conducting the Interconnection Facilities Study.];
    (2) Demonstration of one-hundred percent (100%) Site Control or 
demonstration of a regulatory limitation and applicable deposit in 
lieu of Site Control provided to the Transmission Provider in 
accordance with section 3.4.2 of this LGIP; and
    (3) An additional deposit that brings the total Commercial 
Readiness Deposit submitted to the Transmission Provider to ten 
percent (10%) of the Interconnection Customer's Network Upgrade cost 
assignment identified in the Cluster Study or Cluster Restudy, if 
applicable, in the form of an irrevocable letter of credit or cash. 
Transmission Provider shall refund the deposit to Interconnection 
Customer upon withdrawal in accordance with Section 3.7 of this 
LGIP.
    Interconnection Customer shall promptly inform Transmission 
Provider of any material change to Interconnection Customer's 
demonstration of Site Control under Section 3.4.2(iii) of this LGIP. 
Upon Transmission Provider determining separately that 
Interconnection Customer no longer satisfies the Site Control 
requirement, Transmission Provider shall notify Interconnection 
Customer. Within ten (10) Business Days of such notification, 
Interconnection Customer must demonstrate compliance with the 
applicable requirement subject to Transmission Provider's approval, 
not to be unreasonably withheld. Absent such demonstration, 
Transmission Provider shall deem the subject Interconnection Request 
withdrawn pursuant to Section 3.7 of this LGIP.
    [8.1.1 Transmission Provider shall invoice Interconnection 
Customer on a monthly basis for the work to be conducted on the 
Interconnection Facilities Study each month. Interconnection 
Customer shall pay invoiced amounts within thirty (30) Calendar Days 
of receipt of invoice. Transmission Provider shall continue to hold 
the amounts on deposit until settlement of the final invoice.]

8.2 Scope of Interconnection Facilities Study

    The Interconnection Facilities Study shall be specific to each 
Interconnection Request and performed on an individual, i.e., non-
clustered, basis. The Interconnection Facilities Study shall specify 
and provide a non-binding estimate of the cost of the equipment, 
engineering, procurement and construction work needed to implement 
the conclusions of the [Interconnection System Impact Study]Cluster 
Study Report (and any associated restudies) in accordance with Good 
Utility Practice to physically and electrically connect the 
Interconnection [Facility ] Facilities to the Transmission System. 
The Interconnection Facilities Study shall also identify the 
electrical switching configuration of the connection equipment, 
including, without limitation: the transformer, switchgear, meters, 
and other station equipment; the nature and estimated cost of any 
Transmission Provider's Interconnection Facilities and Network 
Upgrades necessary to accomplish the interconnection; and an 
estimate of the time required to complete the construction and 
installation of such facilities. The Interconnection Facilities 
Study will also identify any potential control equipment for 
[requests for](1) requests for Interconnection Service that are 
lower than the Generating Facility Capacity[.], and/or (2) requests 
to study a Generating Facility that includes at least one electric 
storage resource using operating assumptions (i.e., whether the 
interconnecting Generating Facility will or will not charge at peak 
load) that reflect its proposed charging behavior, as requested by 
Interconnection Customer, unless Transmission Provider determines 
that Good Utility Practice, including Applicable Reliability 
Standards, otherwise require the use of different operating 
assumptions.

[[Page 61283]]

8.3 Interconnection Facilities Study Procedures

    Transmission Provider shall coordinate the Interconnection 
Facilities Study with any Affected System pursuant to Section 3.6 of 
this LGIP. Transmission Provider shall utilize existing studies to 
the extent practicable in performing the Interconnection Facilities 
Study. Transmission Provider shall [use Reasonable Efforts to] 
complete the study and issue a draft Interconnection Facilities 
Study [r]Report to Interconnection Customer within the following 
number of days after receipt of an executed Interconnection 
Facilities Study Agreement: ninety (90) Calendar Days after receipt 
of an executed Interconnection Facilities Study Agreement, with no 
more than a +/-20 percent cost estimate contained in the report; or 
one hundred eighty (180) Calendar Days, if Interconnection Customer 
requests a +/-10 percent cost estimate.
    At the request of Interconnection Customer or at any time 
Transmission Provider determines that it will not meet the required 
time frame for completing the Interconnection Facilities Study, 
Transmission Provider shall notify Interconnection Customer as to 
the schedule status of the Interconnection Facilities Study. If 
Transmission Provider is unable to complete the Interconnection 
Facilities Study and issue a draft Interconnection Facilities Study 
[r]Report within the time required, it shall notify Interconnection 
Customer and provide an estimated completion date and an explanation 
of the reasons why additional time is required.
    Interconnection Customer may, within thirty (30) Calendar Days 
after receipt of the draft Interconnection Facilities Study 
[r]Report, provide written comments to Transmission Provider, which 
Transmission Provider shall include in completing the final 
Interconnection Facilities Study [r]Report. Transmission Provider 
shall issue the final Interconnection Facilities Study [r]Report 
within fifteen (15) Business Days of receiving Interconnection 
Customer's comments or promptly upon receiving Interconnection 
Customer's statement that it will not provide comments. Transmission 
Provider may reasonably extend such fifteen[-day] (15) Business Day 
period upon notice to Interconnection Customer if Interconnection 
Customer's comments require Transmission Provider to perform 
additional analyses or make other significant modifications prior to
the issuance of the final Interconnection Facilities Study Report. 
Upon request, Transmission Provider shall provide Interconnection 
Customer supporting documentation, workpapers, and databases or data 
developed in the preparation of the Interconnection Facilities 
Study, subject to confidentiality arrangements consistent with 
Section 13.1 of this LGIP.

8.4 Meeting With Transmission Provider

    Within ten (10) Business Days of providing a draft 
Interconnection Facilities Study [r]Report to Interconnection 
Customer, Transmission Provider and Interconnection Customer shall 
meet to discuss the results of the Interconnection Facilities Study.

8.5 [Re-Study]Restudy

    If [Re-Study]Restudy of the Interconnection Facilities Study is 
required due to a higher or equally queued project [dropping out of] 
withdrawing from the queue or a modification of a higher or equally 
queued project pursuant to Section 4.4 of this LGIP, Transmission 
Provider shall so notify Interconnection Customer in writing. 
[Such]Transmission Provider shall ensure that such [Re-Study]Restudy 
[shall] takes no longer than sixty (60) Calendar Days from the date 
of notice. Except as provided in Section 3.7 of this LGIP in the 
case of withdrawing Interconnection Customers, any cost of [Re-
Study]Restudy shall be borne by [the]Interconnection Customer being 
[re-studied]restudied.

Section 9 [Engineering & Procurement (`E&P') Agreement] Affected System 
Study

9.1 Applicability

    This Section 9 outlines the duties of Transmission Provider when 
it receives notification that an Affected System Interconnection 
Customer's proposed interconnection to its host transmission 
provider may impact Transmission Provider's Transmission System.

9.2 Response to Initial Notification

    When Transmission Provider receives notification that an 
Affected System Interconnection Customer's proposed interconnection 
to its host transmission provider may impact Transmission Provider's 
Transmission System, Transmission Provider must respond in writing 
within twenty (20) Business Days whether it intends to conduct an 
Affected System Study.
    By fifteen (15) Business Days after the Transmission Provider 
responds with its affirmative intent to conduct an Affected System 
Study, Transmission Provider shall share with Affected System 
Interconnection Customer(s) and the Affected System Interconnection 
Customer's host transmission provider a non-binding good faith 
estimate of the cost and the schedule to complete the Affected 
System Study.

9.3 Affected System Queue Position

    Transmission Provider must assign an Affected System Queue 
Position to Affected System Interconnection Customer(s) that 
require(s) an Affected System Study. Such Affected System Queue 
Position shall be assigned based upon the date of execution of the 
Affected System Study Agreement. Relative to the Transmission 
Provider's Interconnection Customers, this Affected System Queue 
Position shall be higher-queued than any Cluster that has not yet 
received its Cluster Study Report and shall be lower-queued than any 
Cluster that has already received its Cluster Study Report. 
Consistent with Section 9.7 of this LGIP, Transmission Provider 
shall study the Affected System Interconnection Customer(s) via 
Clustering, and all Affected System Interconnection Customers 
studied in the same Cluster under Section 9.7 shall be equally 
queued. For Affected System Interconnection Customers that are 
equally queued, the Affected System Queue Position shall have no 
bearing on the assignment of Affected System Network Upgrades 
identified in the applicable Affected System Study. The costs of the 
Affected System Network Upgrades shall be allocated among the 
Affected System Interconnection Customers in accordance with Section 
9.9 of this LGIP.

9.4 Affected System Study Agreement/Multiparty Affected System 
Study Agreement

    Unless otherwise agreed, Transmission Provider shall provide to 
Affected System Interconnection Customer(s) an Affected System Study 
Agreement/Multiparty Affected System Study Agreement, in the form of 
Appendix 9 or Appendix 10 to this LGIP, as applicable, within ten 
(10) Business Days of Transmission Provider sharing the schedule for 
the Affected System Study per Section 9.2 of this LGIP.
    Upon Affected System Interconnection Customer(s)' receipt of the 
Affected System Study Report, Affected System Interconnection 
Customer(s) shall compensate Transmission Provider for the actual 
cost of the Affected System Study. Any difference between the study 
deposit and the actual cost of the Affected System Study shall be 
paid by or refunded to the Affected System Interconnection 
Customer(s). Any invoices for the Affected System Study shall 
include a detailed and itemized accounting of the cost of the study. 
Affected System Interconnection Customer(s) shall pay any excess 
costs beyond the already-paid Affected System Study deposit or be 
reimbursed for any costs collected over the actual cost of the 
Affected System Study within thirty (30) Calendar Days of receipt of 
an invoice thereof. If Affected System Interconnection Customer(s) 
fail to pay such undisputed costs within the time allotted, it shall 
lose its Affected System Queue Position. Transmission Provider shall 
notify Affected System Interconnection Customer's host transmission 
provider of such failure to pay.

9.5 Execution of Affected System Study Agreement/Multiparty 
Affected System Study Agreement

    Affected System Interconnection Customer(s) shall execute the 
Affected System Study Agreement/Multiparty Affected System Study 
Agreement, deliver the executed Affected System Study Agreement/
Multiparty Affected System Study Agreement to Transmission Provider, 
and provide the Affected System Study deposit within ten (10) 
Business Days of receipt.
    If Affected System Interconnection Customer does not provide all 
required technical data when it delivers the Affected System Study 
Agreement/Multiparty Affected System Study Agreement, Transmission 
Provider shall notify the deficient Affected System Interconnection 
Customer, as well as the host transmission provider with which 
Affected System Interconnection Customer seeks to interconnect, of 
the deficiency within five (5) Business Days of the receipt of the 
executed Affected System Study Agreement/Multiparty Affected System 
Study Agreement and the deficient Affected System Interconnection 
Customer shall cure the deficiency within ten (10) Business Days of 
receipt of the notice: provided, however, that

[[Page 61284]]

such deficiency does not include failure to deliver the executed 
Affected System Study Agreement/Multiparty Affected System Study 
Agreement or deposit for the Affected System Study Agreement/
Multiparty Affected System Study Agreement. If Affected System 
Interconnection Customer does not cure the deficiency or fails to 
execute the Affected System Study Agreement/Multiparty Affected 
System Study Agreement or provide the deposit, the Affected System 
Interconnection Customer shall lose its Affected System Queue 
Position.

9.6 Scope of Affected System Study

    The Affected System Study shall evaluate the impact that any 
Affected System Interconnection Customer's proposed interconnection 
to another transmission provider's transmission system will have on 
the reliability of Transmission Provider's Transmission System. The 
Affected System Study shall consider the Base Case as well as all 
Generating Facilities (and with respect to (iii) below, any 
identified Affected System Network Upgrades associated with such 
higher-queued Interconnection Request) that, on the date the 
Affected System Study is commenced: (i) are directly interconnected 
to Transmission Provider's Transmission System; (ii) are directly 
interconnected to another transmission provider's transmission 
system and may have an impact on Affected System Interconnection 
Customer's interconnection request; (iii) have a pending higher-
queued Interconnection Request to interconnect to Transmission 
Provider's Transmission System; and (iv) have no queue position but 
have executed an LGIA or requested that an unexecuted LGIA be filed 
with FERC. Transmission Provider has no obligation to study impacts 
of Affected System Interconnection Customers of which it is not 
notified.
    The Affected System Study shall consist of a power flow, 
stability, and short circuit analysis. The Affected System Study 
will: state the assumptions upon which it is based; state the 
results of the analyses; and provide the potential impediments to 
Affected System Interconnection Customer's receipt if 
interconnection service on its host transmission provider's 
transmission system, including a preliminary indication of the cost 
and length of time that would be necessary to correct any problems 
identified in those analyses and implement the interconnection. For 
purposes of determining necessary Affected System Network Upgrades, 
the Affected System Study shall consider the level of 
interconnection service requested in megawatts by Affected System 
Interconnection Customer, unless otherwise required to study the 
full generating facility capacity due to safety or reliability 
concerns. The Affected System Study shall provide a list of 
facilities that are required as a result of Affected System 
Interconnection Customer's proposed interconnection to another 
transmission provider's system, a non-binding good faith estimate of 
cost responsibility, and a non-binding good faith estimated time to 
construct. The Affected System Study may consist of a system impact 
study, a facilities study, or some combination thereof.

9.7 Affected System Study Procedures

    Transmission Provider shall use Clustering in conducting the 
Affected System Study and shall use existing studies to the extent 
practicable, when multiple Affected System Interconnection Customers 
that are part of a single Cluster may cause the need for Affected 
System Network Upgrades. Transmission Provider shall complete the 
Affected System Study and provide the Affected System Study Report 
to Affected System Interconnection Customer(s) and the host 
transmission provider with whom interconnection has been requested 
within one hundred fifty (150) Calendar Days after the receipt of 
the Affected System Study Agreement and deposit.
    At the request of Affected System Interconnection Customer, 
Transmission Provider shall notify Affected System Interconnection 
Customer as to the status of the Affected System Study. If 
Transmission Provider is unable to complete the Affected System 
Study within the requisite time period, it shall notify Affected 
System Interconnection Customer(s), as well as the transmission 
provider with which Affected System Interconnection Customer seeks 
to interconnect, and shall provide an estimated completion date with 
an explanation of the reasons why additional time is required. If 
Transmission Provider does not meet the deadlines in this section, 
Transmission Provider shall be subject to the financial penalties as 
described in Section 3.9 of this LGIP. Upon request, Transmission 
Provider shall provide Affected System Interconnection Customer(s) 
with all supporting documentation, workpapers and relevant power 
flow, short circuit and stability databases for the Affected System 
Study, subject to confidentiality arrangements consistent with 
Section 13.1 of this LGIP.
    Transmission Provider must study an Affected System 
Interconnection Customer using the Energy Resource Interconnection 
Service modeling standard used for Interconnection Requests on its 
own Transmission System, regardless of the level of interconnection 
service that Affected System Interconnection Customer is seeking 
from the host transmission provider with whom it seeks to 
interconnect.

9.8 Meeting With Transmission Provider

    Within ten (10) Business Days of providing the Affected System 
Study Report to Affected System Interconnection Customer(s), 
Transmission Provider and Affected System Interconnection 
Customer(s) shall meet to discuss the results of the Affected System 
Study.

9.9 Affected System Cost Allocation

    Transmission Provider shall allocate Affected System Network 
Upgrade costs identified during the Affected System Study to 
Affected System Interconnection Customer(s) using a proportional 
impact method, consistent with Section 4.2.1(1)(b) of this LGIP.

9.10 Tender of Affected Systems Facilities Construction Agreement/
Multiparty Affected System Facilities Construction Agreement

    Transmission Provider shall tender to Affected System 
Interconnection Customer(s) an Affected System Facilities 
Construction Agreement/Multiparty Affected System Facilities 
Construction Agreement, as applicable, in the form of Appendix 11 or 
12 to this LGIP, within thirty (30) Calendar Days of providing the 
Affected System Study Report. Within ten (10) Business Days of the 
receipt of the Affected System Facilities Construction Agreement/
Multiparty Affected System Facilities Construction Agreement, the 
Affected System Interconnection Customer(s) must execute the 
agreement or request the agreement to be filed unexecuted with FERC. 
Transmission Provider shall execute the agreement or file the 
agreement unexecuted within five (5) Business Days after receiving 
direction from Affected System Interconnection Customer(s). Affected 
System Interconnection Customer's failure to execute the Affected 
System Facilities Construction Agreement/Multiparty Affected System 
Facilities Construction Agreement, or failure to request the 
agreement to be filed unexecuted with FERC, shall result in the loss 
of its Affected System Queue Position.

9.11 Restudy

    If restudy of the Affected System Study is required, 
Transmission Provider shall notify Affected System Interconnection 
Customer(s) in writing within thirty (30) Calendar Days of discovery 
of the need for restudy. Such restudy shall take no longer than 
sixty (60) Calendar Days from the date of notice. Any cost of 
restudy shall be borne by the Affected System Interconnection 
Customer(s) being restudied.
    [Prior to executing an LGIA, an Interconnection Customer may, in 
order to advance the implementation of its interconnection, request 
and Transmission Provider shall offer the Interconnection Customer, 
an E&P Agreement that authorizes Transmission Provider to begin 
engineering and procurement of long lead-time items necessary for 
the establishment of the interconnection. However, Transmission 
Provider shall not be obligated to offer an E&P Agreement if 
Interconnection Customer is in Dispute Resolution as a result of an 
allegation that Interconnection Customer has failed to meet any 
milestones or comply with any prerequisites specified in other parts 
of the LGIP. The E&P Agreement is an optional procedure and it will 
not alter the Interconnection Customer's Queue Position or In-
Service Date. The E&P Agreement shall provide for Interconnection 
Customer to pay the cost of all activities authorized by 
Interconnection Customer and to make advance payments or provide 
other satisfactory security for such costs.
    Interconnection Customer shall pay the cost of such authorized 
activities and any cancellation costs for equipment that is already 
ordered for its interconnection, which cannot be mitigated as 
hereafter described, whether or not such items or equipment later 
become unnecessary. If Interconnection Customer withdraws its

[[Page 61285]]

application for interconnection or either Party terminates the E&P 
Agreement, to the extent the equipment ordered can be canceled under 
reasonable terms, Interconnection Customer shall be obligated to pay 
the associated cancellation costs. To the extent that the equipment 
cannot be reasonably canceled, Transmission Provider may elect: (i) 
to take title to the equipment, in which event Transmission Provider 
shall refund Interconnection Customer any amounts paid by 
Interconnection Customer for such equipment and shall pay the cost 
of delivery of such equipment, or (ii) to transfer title to and 
deliver such equipment to Interconnection Customer, in which event 
Interconnection Customer shall pay any unpaid balance and cost of 
delivery of such equipment.]

Section 10. Optional Interconnection Study

10.1 Optional Interconnection Study Agreement

    On or after the date when Interconnection Customer receives 
[Interconnection System Impact Study] Cluster Study results, 
Interconnection Customer may request, and Transmission Provider 
shall perform a reasonable number of Optional Studies. The request 
shall describe the assumptions that Interconnection Customer wishes 
Transmission Provider to study within the scope described in Section 
10.2. Within five (5) Business Days after receipt of a request for 
an Optional Interconnection Study, Transmission Provider shall 
provide to Interconnection Customer an Optional Interconnection 
Study Agreement in the form of Appendix 4[5].
    The Optional Interconnection Study Agreement shall: (i) specify 
the technical data that Interconnection Customer must provide for 
each phase of the Optional Interconnection Study, (ii) specify 
Interconnection Customer's assumptions as to which Interconnection 
Requests with earlier queue priority dates will be excluded from the 
Optional Interconnection Study case and assumptions as to the type 
of interconnection service for Interconnection Requests remaining in 
the Optional Interconnection Study case, and (iii) Transmission 
Provider's estimate of the cost of the Optional Interconnection 
Study. To the extent known by Transmission Provider, such estimate 
shall include any costs expected to be incurred by any Affected 
System whose participation is necessary to complete the Optional 
Interconnection Study. Notwithstanding the above, Transmission 
Provider shall not be required as a result of an Optional 
Interconnection Study request to conduct any additional 
Interconnection Studies with respect to any other Interconnection 
Request.
    Interconnection Customer shall execute the Optional 
Interconnection Study Agreement within ten (10) Business Days of 
receipt and deliver the Optional Interconnection Study Agreement, 
the technical data and a $10,000 deposit to Transmission Provider.

10.2 Scope of Optional Interconnection Study

    The Optional Interconnection Study will consist of a sensitivity 
analysis based on the assumptions specified by Interconnection 
Customer in the Optional Interconnection Study Agreement. The 
Optional Interconnection Study will also identify Transmission 
Provider's Interconnection Facilities and the Network Upgrades, and 
the estimated cost thereof, that may be required to provide 
transmission service or Interconnection Service based upon the 
results of the Optional Interconnection Study. The Optional 
Interconnection Study shall be performed solely for informational 
purposes. Transmission Provider shall use Reasonable Efforts to 
coordinate the study with any Affected Systems that may be affected 
by the types of Interconnection Services that are being studied. 
Transmission Provider shall utilize existing studies to the extent 
practicable in conducting the Optional Interconnection Study.

10.3 Optional Interconnection Study Procedures

    The executed Optional Interconnection Study Agreement, the 
prepayment, and technical and other data called for therein must be 
provided to Transmission Provider within ten (10) Business Days of 
Interconnection Customer receipt of the Optional Interconnection 
Study Agreement. Transmission Provider shall use Reasonable Efforts 
to complete the Optional Interconnection Study within a mutually 
agreed upon time period specified within the Optional 
Interconnection Study Agreement. If Transmission Provider is unable 
to complete the Optional Interconnection Study within such time 
period, it shall notify Interconnection Customer and provide an 
estimated completion date and an explanation of the reasons why 
additional time is required. Any difference between the study 
payment and the actual cost of the study shall be paid to 
Transmission Provider or refunded to Interconnection Customer, as 
appropriate. Upon request, Transmission Provider shall provide 
Interconnection Customer supporting documentation and workpapers and 
databases or data developed in the preparation of the Optional 
Interconnection Study, subject to confidentiality arrangements 
consistent with Section 13.1.

Section 11. Standard Large Generator Interconnection Agreement (LGIA)

11.1 Tender

    Interconnection Customer shall tender comments on the draft 
Interconnection Facilities Study Report within thirty (30) Calendar 
Days of receipt of the report. Within thirty (30) Calendar Days 
after the comments are submitted or after Interconnection Customer 
notifies Transmission Provider that it will not provide comments, 
Transmission Provider shall tender a draft LGIA, together with draft 
appendices. The draft LGIA shall be in the form of Transmission 
Provider's FERC-approved standard form LGIA, which is in Appendix 
5[6]. Interconnection Customer shall execute and return the LGIA and 
completed draft appendices within thirty (30) Calendar Days, unless 
(1) the sixty (60) Calendar Day negotiation period under Section 
11.2 of this LGIP has commenced, or (2) LGIA execution, or filing 
unexecuted, has been delayed to await the Affected System Study 
Report pursuant to Section 11.2.1 of this LGIP.

11.2 Negotiation

    Notwithstanding Section 11.1, at the request of Interconnection 
Customer Transmission Provider shall begin negotiations with 
Interconnection Customer concerning the appendices to the LGIA at 
any time after Interconnection Customer executes the Interconnection 
Facilities Study Agreement. Transmission Provider and 
Interconnection Customer shall negotiate concerning any disputed 
provisions of the appendices to the draft LGIA for not more than 
sixty (60) Calendar Days after tender of the final Interconnection 
Facilities Study Report. If Interconnection Customer determines that 
negotiations are at an impasse, it may request termination of the 
negotiations at any time after tender of the draft LGIA pursuant to 
Section 11.1 and request submission of the unexecuted LGIA with FERC 
or initiate Dispute Resolution procedures pursuant to Section 13.5. 
If Interconnection Customer requests termination of the 
negotiations, but within sixty (60) Calendar Days thereafter fails 
to request either the filing of the unexecuted LGIA or initiate 
Dispute Resolution, it shall be deemed to have withdrawn its 
Interconnection Request. Unless otherwise agreed by the Parties, if 
Interconnection Customer has not executed the LGIA, requested filing 
of an unexecuted LGIA, or initiated Dispute Resolution procedures 
pursuant to Section 13.5 within sixty (60) Calendar Days of tender 
of draft LGIA, it shall be deemed to have withdrawn its 
Interconnection Request. Transmission Provider shall provide to 
Interconnection Customer a final LGIA within fifteen (15) Business 
Days after the completion of the negotiation process.

11.2.1 Delay in LGIA Execution, or Filing Unexecuted, To Await 
Affected System Study Report

    If Interconnection Customer has not received its Affected System 
Study Report from the Affected System Operator prior to the date 
that it would be required to execute its LGIA (or request that its 
LGIA be filed unexecuted) pursuant to Section 11.1 of this LGIP, 
Transmission Provider shall, upon request of Interconnection 
Customer, extend this deadline to thirty (30) Calendar Days after 
Interconnection Customer's receipt of the Affected System Study 
Report. If Interconnection Customer, after delaying LGIA execution, 
or requesting unexecuted filing, to await Affected System Study 
Results, decides to proceed to LGIA execution, or request unexecuted 
filing, without those results, it may notify Transmission Provider 
of its intent to proceed with LGIA execution (or request that its 
LGIA be filed unexecuted) pursuant to Section 11.1 of this LGIP. If 
Transmission Provider determines that further delay to the LGIA 
execution date would cause a material impact on the cost or timing 
of an equal- or lower-queued interconnection customer, Transmission 
Provider must notify Interconnection Customer of such impacts and 
set the deadline to execute the LGIA (or

[[Page 61286]]

request that the LGIA be filed unexecuted) to thirty (30) Calendar 
Days after such notice is provided.

11.3 Execution and Filing

    Simultaneously with submitting the executed LGIA to Transmission 
Provider, or within ten (10) Business Days after the Interconnection 
Customer requests that the Transmission Provider file the LGIA 
unexecuted at the Commission, [Within fifteen (15) Business Days 
after receipt of the final executed LGIA,]Interconnection Customer 
shall provide Transmission Provider with [(A) reasonable evidence 
that continued Site Control or (B) posting of $250,000, non-
refundable additional security, which shall be applied toward future 
construction costs](1) demonstration of continued Site Control 
pursuant to Section 8.1(2) of this LGIP; and (2) the LGIA Deposit 
equal to twenty percent (20%) of Interconnection Customer's 
estimated Network Upgrade costs identified in the draft LGIA minus 
the total amount of Commercial Readiness Deposits that 
Interconnection Customer has provided to Transmission Provider for 
its Interconnection Request. Transmission Provider shall use LGIA 
Deposit as (or as a portion of) the Interconnection Customer's 
security required under LGIA Article 11.5. Interconnection Customer 
may not request to suspend its LGIA under LGIA Article 5.16 until 
Interconnection Customer has provided (1) and (2) to Transmission 
Provider. If Interconnection Customer fails to provide (1) and (2) 
to Transmission Provider within the thirty (30) Calendar Days 
allowed for returning the executed LGIA and appendices under LGIP 
Section 11.1, or within ten (10) Business Days after Interconnection 
Customer requests that Transmission Provider file the LGIA 
unexecuted at the Commission as allowed in this Section 11.3 of this 
LGIP, the Interconnection Request will be deemed withdrawn pursuant 
to Section 3.7 of this LGIP.
    At the same time, Interconnection Customer also shall provide 
reasonable evidence that one or more of the following milestones in 
the development of the Large Generating Facility, at Interconnection 
Customer election, has been achieved (unless such milestone is 
inapplicable due to the characteristics of the Generating Facility): 
(i) the execution of a contract for the supply or transportation of 
fuel to the Large Generating Facility; (ii) the execution of a 
contract for the supply of cooling water to the Large Generating 
Facility; (iii) execution of a contract for the engineering for, 
procurement of major equipment for, or construction of, the Large 
Generating Facility; (iv) execution of a contract (or comparable 
evidence) for the sale of electric energy or capacity from the Large 
Generating Facility; or (v) application for an air, water, or land 
use permit.
    Interconnection Customer shall either: (i) execute two originals 
of the tendered LGIA and return them to Transmission Provider; or 
(ii) request in writing that Transmission Provider file with FERC an 
LGIA in unexecuted form. As soon as practicable, but not later than 
ten (10) Business Days after receiving either the two executed 
originals of the tendered LGIA (if it does not conform with a FERC-
approved standard form of interconnection agreement) or the request 
to file an unexecuted LGIA, Transmission Provider shall file the 
LGIA with FERC, together with its explanation of any matters as to 
which Interconnection Customer and Transmission Provider disagree 
and support for the costs that Transmission Provider proposes to 
charge to Interconnection Customer under the LGIA. An unexecuted 
LGIA should contain terms and conditions deemed appropriate by 
Transmission Provider for the Interconnection Request. If the 
Parties agree to proceed with design, procurement, and construction 
of facilities and upgrades under the agreed-upon terms of the 
unexecuted LGIA, they may proceed pending FERC action.

11.4 Commencement of Interconnection Activities

    If Interconnection Customer executes the final LGIA, 
Transmission Provider and Interconnection Customer shall perform 
their respective obligations in accordance with the terms of the 
LGIA, subject to modification by FERC. Upon submission of an 
unexecuted LGIA, Interconnection Customer and Transmission Provider 
shall promptly comply with the unexecuted LGIA, subject to 
modification by FERC.

Section 12. Construction of Transmission Provider's Interconnection 
Facilities and Network Upgrades

12.1 Schedule

    Transmission Provider and Interconnection Customer shall 
negotiate in good faith concerning a schedule for the construction 
of Transmission Provider's Interconnection Facilities and the 
Network Upgrades.

12.2 Construction Sequencing

12.2.1 General

    In general, the In-Service Date of an Interconnection Customers 
seeking interconnection to the Transmission System will determine 
the sequence of construction of Network Upgrades.

12.2.2 Advance Construction of Network Upgrades That Are an Obligation 
of an Entity Other Than Interconnection Customer

    An Interconnection Customer with an LGIA, in order to maintain 
its In-Service Date, may request that Transmission Provider advance 
to the extent necessary the completion of Network Upgrades that: (i) 
were assumed in the Interconnection Studies for such Interconnection 
Customer, (ii) are necessary to support such In-Service Date, and 
(iii) would otherwise not be completed, pursuant to a contractual 
obligation of an entity other than Interconnection Customer that is 
seeking interconnection to the Transmission System, in time to 
support such In-Service Date. Upon such request, Transmission 
Provider will use Reasonable Efforts to advance the construction of 
such Network Upgrades to accommodate such request; provided that 
Interconnection Customer commits to pay Transmission Provider: (i) 
any associated expediting costs and (ii) the cost of such Network 
Upgrades. Transmission Provider will refund to Interconnection 
Customer both the expediting costs and the cost of Network Upgrades, 
in accordance with Article 11.4 of the LGIA. Consequently, the 
entity with a contractual obligation to construct such Network 
Upgrades shall be obligated to pay only that portion of the costs of 
the Network Upgrades that Transmission Provider has not refunded to 
Interconnection Customer. Payment by that entity shall be due on the 
date that it would have been due had there been no request for 
advance construction. Transmission Provider shall forward to 
Interconnection Customer the amount paid by the entity with a 
contractual obligation to construct the Network Upgrades as payment 
in full for the outstanding balance owed to Interconnection 
Customer. Transmission Provider then shall refund to that entity the 
amount that it paid for the Network Upgrades, in accordance with 
Article 11.4 of the LGIA.

12.2.3 Advancing Construction of Network Upgrades That Are Part of an 
Expansion Plan of the Transmission Provider

    An Interconnection Customer with an LGIA, in order to maintain 
its In-Service Date, may request that Transmission Provider advance 
to the extent necessary the completion of Network Upgrades that: (i) 
are necessary to support such In-Service Date and (ii) would 
otherwise not be completed, pursuant to an expansion plan of 
Transmission Provider, in time to support such In-Service Date. Upon 
such request, Transmission Provider will use Reasonable Efforts to 
advance the construction of such Network Upgrades to accommodate 
such request; provided that Interconnection Customer commits to pay 
Transmission Provider any associated expediting costs. 
Interconnection Customer shall be entitled to transmission credits, 
if any, for any expediting costs paid.

12.2.4 Amended Interconnection [System Impact]Cluster Study Report

    An Interconnection [System Impact]Cluster Study Report will be 
amended to determine the facilities necessary to support the 
requested In-Service Date. This amended study report will include 
those transmission and Large Generating Facilities that are expected 
to be on or before the requested In-Service Date.

Section 13. Miscellaneous

13.1 Confidentiality

    Confidential Information shall include, without limitation, all 
information relating to a Party's technology, research and 
development, business affairs, and pricing, and any information 
supplied by either of the Parties to the other prior to the 
execution of an LGIA.
    Information is Confidential Information only if it is clearly 
designated or marked in writing as confidential on the face of the 
document, or, if the information is conveyed orally or by 
inspection, if the Party providing the information orally informs 
the Party receiving the information that the information is 
confidential.
    If requested by either Party, the other Party shall provide in 
writing, the basis for asserting that the information referred to in

[[Page 61287]]

this Article warrants confidential treatment, and the requesting 
Party may disclose such writing to the appropriate Governmental 
Authority. Each Party shall be responsible for the costs associated 
with affording confidential treatment to its information.

13.1.1 Scope

    Confidential Information shall not include information that the 
receiving Party can demonstrate: (1) is generally available to the 
public other than as a result of a disclosure by the receiving 
Party; (2) was in the lawful possession of the receiving Party on a 
non-confidential basis before receiving it from the disclosing 
Party; (3) was supplied to the receiving Party without restriction 
by a third party, who, to the knowledge of the receiving Party after 
due inquiry, was under no obligation to the disclosing Party to keep 
such information confidential; (4) was independently developed by 
the receiving Party without reference to Confidential Information of 
the disclosing Party; (5) is, or becomes, publicly known, through no 
wrongful act or omission of the receiving Party or Breach of the 
LGIA; or (6) is required, in accordance with Section 13.1.6, Order 
of Disclosure, to be disclosed by any Governmental Authority or is 
otherwise required to be disclosed by law or subpoena, or is 
necessary in any legal proceeding establishing rights and 
obligations under the LGIA. Information designated as Confidential 
Information will no longer be deemed confidential if the Party that 
designated the information as confidential notifies the other Party 
that it no longer is confidential.

13.1.2 Release of Confidential Information

    Neither Party shall release or disclose Confidential Information 
to any other person, except to its Affiliates (limited by the 
Standards of Conduct requirements), employees, consultants, or to 
parties who may be or considering providing financing to or equity 
participation with Interconnection Customer, or to potential 
purchasers or assignees of Interconnection Customer, on a need-to-
know basis in connection with these procedures, unless such person 
has first been advised of the confidentiality provisions of this 
Section 13.1 and has agreed to comply with such provisions. 
Notwithstanding the foregoing, a Party providing Confidential 
Information to any person shall remain primarily responsible for any 
release of Confidential Information in contravention of this Section 
13.1.

13.1.3 Rights

    Each Party retains all rights, title, and interest in the 
Confidential Information that each Party discloses to the other 
Party. The disclosure by each Party to the other Party of 
Confidential Information shall not be deemed a waiver by either 
Party or any other person or entity of the right to protect the 
Confidential Information from public disclosure.

13.1.4 No Warranties

    By providing Confidential Information, neither Party makes any 
warranties or representations as to its accuracy or completeness. In 
addition, by supplying Confidential Information, neither Party 
obligates itself to provide any particular information or 
Confidential Information to the other Party nor to enter into any 
further agreements or proceed with any other relationship or joint 
venture.

13.1.5 Standard of Care

    Each Party shall use at least the same standard of care to 
protect Confidential Information it receives as it uses to protect 
its own Confidential Information from unauthorized disclosure, 
publication or dissemination. Each Party may use Confidential 
Information solely to fulfill its obligations to the other Party 
under these procedures or its regulatory requirements.

13.1.6 Order of Disclosure

    If a court or a Government Authority or entity with the right, 
power, and apparent authority to do so requests or requires either 
Party, by subpoena, oral deposition, interrogatories, requests for 
production of documents, administrative order, or otherwise, to 
disclose Confidential Information, that Party shall provide the 
other Party with prompt notice of such request(s) or requirement(s) 
so that the other Party may seek an appropriate protective order or 
waive compliance with the terms of the LGIA. Notwithstanding the 
absence of a protective order or waiver, the Party may disclose such 
Confidential Information which, in the opinion of its counsel, the 
Party is legally compelled to disclose. Each Party will use 
Reasonable Efforts to obtain reliable assurance that confidential 
treatment will be accorded any Confidential Information so 
furnished.

13.1.7 Remedies

    The Parties agree that monetary damages would be inadequate to 
compensate a Party for the other Party's Breach of its obligations 
under this Section 13.1. Each Party accordingly agrees that the 
other Party shall be entitled to equitable relief, by way of 
injunction or otherwise, if the first Party Breaches or threatens to 
Breach its obligations under this Section 13.1, which equitable 
relief shall be granted without bond or proof of damages, and the 
receiving Party shall not plead in defense that there would be an 
adequate remedy at law. Such remedy shall not be deemed an exclusive 
remedy for the Breach of this Section 13.1, but shall be in addition 
to all other remedies available at law or in equity. The Parties 
further acknowledge and agree that the covenants contained herein 
are necessary for the protection of legitimate business interests 
and are reasonable in scope. No Party, however, shall be liable for 
indirect, incidental, or consequential or punitive damages of any 
nature or kind resulting from or arising in connection with this 
Section 13.1.

13.1.8 Disclosure to FERC, its Staff, or a State

    Notwithstanding anything in this Section 13.1 to the contrary, 
and pursuant to 18 CFR 1b.20, if FERC or its staff, during the 
course of an investigation or otherwise, requests information from 
one of the Parties that is otherwise required to be maintained in 
confidence pursuant to the LGIP, the Party shall provide the 
requested information to FERC or its staff, within the time provided 
for in the request for information. In providing the information to 
FERC or its staff, the Party must, consistent with 18 CFR 388.112, 
request that the information be treated as confidential and non-
public by FERC and its staff and that the information be withheld 
from public disclosure. Parties are prohibited from notifying the 
other Party prior to the release of the Confidential Information to 
FERC or its staff. The Party shall notify the other Party to the 
LGIA when its is notified by FERC or its staff that a request to 
release Confidential Information has been received by FERC, at which 
time either of the Parties may respond before such information would 
be made public, pursuant to 18 CFR 388.112. Requests from a state 
regulatory body conducting a confidential investigation shall be 
treated in a similar manner, consistent with applicable state rules 
and regulations.

13.1.9

    Subject to the exception in Section 13.1.8 of this LGIP, any 
information that a Party claims is competitively sensitive, 
commercial or financial information (``Confidential Information'') 
shall not be disclosed by the other Party to any person not employed 
or retained by the other Party, except to the extent disclosure is 
(i) required by law; (ii) reasonably deemed by the disclosing Party 
to be required to be disclosed in connection with a dispute between 
or among the Parties, or the defense of litigation or dispute; (iii) 
otherwise permitted by consent of the other Party, such consent not 
to be unreasonably withheld; or (iv) necessary to fulfill its 
obligations under this LGIP or as a transmission service provider or 
a [Control Area]Balancing Authority Area operator including 
disclosing the Confidential Information to an RTO or ISO or to a 
subregional, regional or national reliability organization or 
planning group. The Party asserting confidentiality shall notify the 
other Party in writing of the information it claims is confidential. 
Prior to any disclosures of the other Party's Confidential 
Information under this subparagraph, or if any third party or 
Governmental Authority makes any request or demand for any of the 
information described in this subparagraph, the disclosing Party 
agrees to promptly notify the other Party in writing and agrees to 
assert confidentiality and cooperate with the other Party in seeking 
to protect the Confidential Information from public disclosure by 
confidentiality agreement, protective order or other reasonable 
measures.

13.1.10

    This provision shall not apply to any information that was or is 
hereafter in the public domain (except as a result of a Breach of 
this provision).

13.1.11

    Transmission Provider shall, at Interconnection Customer's 
election, destroy, in a confidential manner, or return the 
Confidential Information provided at the time of Confidential 
Information is no longer needed.

13.2 Delegation of Responsibility

    Transmission Provider may use the services of subcontractors as 
it deems

[[Page 61288]]

appropriate to perform its obligations under this LGIP. Transmission 
Provider shall remain primarily liable to Interconnection Customer 
for the performance of such subcontractors and compliance with its 
obligations of this LGIP. The subcontractor shall keep all 
information provided confidential and shall use such information 
solely for the performance of such obligation for which it was 
provided and no other purpose.

13.3 Obligation for Study Costs

    In the event an Interconnection Customer withdraws its 
Interconnection Request prior to the commencement of the Cluster 
Study, Interconnection Customer must pay Transmission Provider the 
actual costs of processing its Interconnection Request. In the event 
an Interconnection Customer withdraws after the commencement of the 
Cluster Study, Transmission Provider shall charge and 
Interconnection Customer shall pay the actual costs of the 
Interconnection Studies. The costs of any interconnection study 
conducted on a clustered basis shall be allocated among each 
Interconnection Customer within the cluster as follows: 
{Transmission Provider shall include in this section a description 
of how the cost of any clustered interconnection study will be 
allocated.{time} 
    Any difference between the study deposit and the actual cost of 
the applicable Interconnection Study shall be paid by or refunded, 
except as otherwise provided herein, to Interconnection 
[Customer]Customers or offset against the cost of any future 
Interconnection Studies associated with the applicable 
[Interconnection Request]Cluster prior to beginning of any such 
future Interconnection Studies. Any invoices for Interconnection 
Studies shall include a detailed and itemized accounting of the cost 
of each Interconnection Study. Interconnection [Customer]Customers 
shall pay any such undisputed costs within thirty (30) Calendar Days 
of receipt of an invoice therefor. If an Interconnection Customer 
fails to pay such undisputed costs within the time allotted, its 
Interconnection Request shall be deemed withdrawn from the Cluster 
Study Process and will be subject to Withdrawal Penalties pursuant 
to Section 3.7 of this LGIP. [Transmission Provider shall not be 
obligated to perform or continue to perform any studies unless 
Interconnection Customer has paid all undisputed amounts in 
compliance herewith.]

13.4 Third Parties Conducting Studies

    If (i) at the time of the signing of an Interconnection Study 
Agreement there is disagreement as to the estimated time to complete 
an Interconnection Study, (ii) Interconnection Customer receives 
notice pursuant to Sections 6.3, 7.4 or 8.3 that Transmission 
Provider will not complete an Interconnection Study within the 
applicable timeframe for such Interconnection Study, or (iii) 
Interconnection Customer receives neither the Interconnection Study 
nor a notice under Sections 6.3, 7.4 or 8.3 within the applicable 
timeframe for such Interconnection Study, then Interconnection 
Customer may require Transmission Provider to utilize a third party 
consultant reasonably acceptable to Interconnection Customer and 
Transmission Provider to perform such Interconnection Study under 
the direction of Transmission Provider. At other times, Transmission 
Provider may also utilize a third party consultant to perform such 
Interconnection Study, either in response to a general request of 
Interconnection Customer, or on its own volition.
    In all cases, use of a third party consultant shall be in accord 
with Article 26 of the LGIA (Subcontractors) and limited to 
situations where Transmission Provider determines that doing so will 
help maintain or accelerate the study process for Interconnection 
Customer's pending Interconnection Request and not interfere with 
Transmission Provider's progress on Interconnection Studies for 
other pending Interconnection Requests. In cases where 
Interconnection Customer requests use of a third party consultant to 
perform such Interconnection Study, Interconnection Customer and 
Transmission Provider shall negotiate all of the pertinent terms and 
conditions, including reimbursement arrangements and the estimated 
study completion date and study review deadline. Transmission 
Provider shall convey all workpapers, data bases, study results and 
all other supporting documentation prepared to date with respect to 
the Interconnection Request as soon as soon as practicable upon 
Interconnection Customer's request subject to the confidentiality 
provision in Section 13.1. In any case, such third party contract 
may be entered into with either Interconnection Customer or 
Transmission Provider at Transmission Provider's discretion. In the 
case of (iii) Interconnection Customer maintains its right to submit 
a claim to Dispute Resolution to recover the costs of such third 
party study. Such third party consultant shall be required to comply 
with this LGIP, Article 26 of the LGIA (Subcontractors), and the 
relevant Tariff procedures and protocols as would apply if 
Transmission Provider were to conduct the Interconnection Study and 
shall use the information provided to it solely for purposes of 
performing such services and for no other purposes. Transmission 
Provider shall cooperate with such third party consultant and 
Interconnection Customer to complete and issue the Interconnection 
Study in the shortest reasonable time.

13.5 Disputes

13.5.1 Submission

    In the event either Party has a dispute, or asserts a claim, 
that arises out of or in connection with the LGIA, the LGIP, or 
their performance, such Party (the ``disputing Party'') shall 
provide the other Party with written notice of the dispute or claim 
(``Notice of Dispute''). Such dispute or claim shall be referred to 
a designated senior representative of each Party for resolution on 
an informal basis as promptly as practicable after receipt of the 
Notice of Dispute by the other Party. In the event the designated 
representatives are unable to resolve the claim or dispute through 
unassisted or assisted negotiations within thirty (30) Calendar Days 
of the other Party's receipt of the Notice of Dispute, such claim or 
dispute may, upon mutual agreement of the Parties, be submitted to 
arbitration and resolved in accordance with the arbitration 
procedures set forth below. In the event the Parties do not agree to 
submit such claim or dispute to arbitration, each Party may exercise 
whatever rights and remedies it may have in equity or at law 
consistent with the terms of this LGIA.

13.5.2 External Arbitration Procedures

    Any arbitration initiated under these procedures shall be 
conducted before a single neutral arbitrator appointed by the 
Parties. If the Parties fail to agree upon a single arbitrator 
within ten (10) Calendar Days of the submission of the dispute to 
arbitration, each Party shall choose one arbitrator who shall sit on 
a three-member arbitration panel. The two arbitrators so chosen 
shall within twenty (20) Calendar Days select a third arbitrator to 
chair the arbitration panel. In either case, the arbitrators shall 
be knowledgeable in electric utility matters, including electric 
transmission and bulk power issues, and shall not have any current 
or past substantial business or financial relationships with any 
party to the arbitration (except prior arbitration). The 
arbitrator(s) shall provide each of the Parties an opportunity to be 
heard and, except as otherwise provided herein, shall conduct the 
arbitration in accordance with the Commercial Arbitration Rules of 
the American Arbitration Association (``Arbitration Rules'') and any 
applicable FERC regulations or RTO rules; provided, however, in the 
event of a conflict between the Arbitration Rules and the terms of 
this Section 13, the terms of this Section 13 shall prevail.

13.5.3 Arbitration Decisions

    Unless otherwise agreed by the Parties, the arbitrator(s) shall 
render a decision within ninety (90) Calendar Days of appointment 
and shall notify the Parties in writing of such decision and the 
reasons therefor. The arbitrator(s) shall be authorized only to 
interpret and apply the provisions of the LGIA and LGIP and shall 
have no power to modify or change any provision of the LGIA and LGIP 
in any manner. The decision of the arbitrator(s) shall be final and 
binding upon the Parties, and judgment on the award may be entered 
in any court having jurisdiction. The decision of the arbitrator(s) 
may be appealed solely on the grounds that the conduct of the 
arbitrator(s), or the decision itself, violated the standards set 
forth in the Federal Arbitration Act or the Administrative Dispute 
Resolution Act. The final decision of the arbitrator must also be 
filed with FERC if it affects jurisdictional rates, terms and 
conditions of service, Interconnection Facilities, or Network 
Upgrades.

13.5.4 Costs

    Each Party shall be responsible for its own costs incurred 
during the arbitration process and for the following costs, if 
applicable: (1) the cost of the arbitrator chosen by the Party to 
sit on the three member panel and one half of the cost of the third 
arbitrator chosen; or (2) one half the cost of the single arbitrator 
jointly chosen by the Parties.

[[Page 61289]]

13.5.5 Non-Binding Dispute Resolution Procedures

    If a Party has submitted a Notice of Dispute pursuant to 
S[s]ection 13.5.1, and the Parties are unable to resolve the claim 
or dispute through unassisted or assisted negotiations within the 
thirty (30) Calendar Days provided in that section, and the Parties 
cannot reach mutual agreement to pursue the S[s]ection 13.5 
arbitration process, a Party may request that Transmission Provider 
engage in Non-binding Dispute Resolution pursuant to this section by 
providing written notice to Transmission Provider (``Request for 
Non-binding Dispute Resolution''). Conversely, either Party may file 
a Request for Non-binding Dispute Resolution pursuant to this 
section without first seeking mutual agreement to pursue the 
S[s]ection 13.5 arbitration process. The process in S[s]ection 
13.5.5 shall serve as an alternative to, and not a replacement of, 
the section 13.5 arbitration process. Pursuant to this process, a 
Transmission Provider must within 30 days of receipt of the Request 
for Non-binding Dispute Resolution appoint a neutral decision-maker 
that is an independent subcontractor that shall not have any current 
or past substantial business or financial relationships with either 
Party. Unless otherwise agreed by the Parties, the decision-maker 
shall render a decision within sixty (60) Calendar Days of 
appointment and shall notify the Parties in writing of such decision 
and reasons therefore. This decision-maker shall be authorized only 
to interpret and apply the provisions of the LGIP and LGIA and shall 
have no power to modify or change any provision of the LGIP and LGIA 
in any manner. The result reached in this process is not binding, 
but, unless otherwise agreed, the Parties may cite the record and 
decision in the non-binding dispute resolution process in future 
dispute resolution processes, including in a S[s]ection 13.5 
arbitration, or in a Federal Power Act section 206 complaint. Each 
Party shall be responsible for its own costs incurred during the 
process and the cost of the decision-maker shall be divided equally 
among each Party to the dispute.

13.6 Local Furnishing Bonds

13.6.1 Transmission Providers That Own Facilities Financed by Local 
Furnishing Bonds

    This provision is applicable only to a Transmission Provider 
that has financed facilities for the local furnishing of electric 
energy with tax-exempt bonds, as described in Section 142(f) of the 
Internal Revenue Code (``local furnishing bonds''). Notwithstanding 
any other provision of this LGIA and LGIP, Transmission Provider 
shall not be required to provide Interconnection Service to 
Interconnection Customer pursuant to this LGIA and LGIP if the 
provision of such Transmission Service would jeopardize the tax-
exempt status of any local furnishing bond(s) used to finance 
Transmission Provider's facilities that would be used in providing 
such Interconnection Service.

13.6.2 Alternative Procedures for Requesting Interconnection Service

    If Transmission Provider determines that the provision of 
Interconnection Service requested by Interconnection Customer would 
jeopardize the tax-exempt status of any local furnishing bond(s) 
used to finance its facilities that would be used in providing such 
Interconnection Service, it shall advise the Interconnection 
Customer within thirty (30) Calendar Days of receipt of the 
Interconnection Request.
    Interconnection Customer thereafter may renew its request for 
interconnection using the process specified in Article 5.2(ii) of 
the Transmission Provider's Tariff.

Section [9]13.7 Engineering & Procurement (`E&P') Agreement

    Prior to executing an LGIA, an Interconnection Customer may, in 
order to advance the implementation of its interconnection, request 
and Transmission Provider shall offer Interconnection Customer, an 
E&P Agreement that authorizes Transmission Provider to begin 
engineering and procurement of long lead-time items necessary for 
the establishment of the interconnection. However, Transmission 
Provider shall not be obligated to offer an E&P Agreement if 
Interconnection Customer is in Dispute Resolution as a result of an 
allegation that Interconnection Customer has failed to meet any 
milestones or comply with any prerequisites specified in other parts 
of the LGIP. The E&P Agreement is an optional procedure and it will 
not alter Interconnection Customer's Queue Position or In-Service 
Date. The E&P Agreement shall provide for Interconnection Customer 
to pay the cost of all activities authorized by Interconnection 
Customer and to make advance payments or provide other satisfactory 
security for such costs.
    Interconnection Customer shall pay the cost of such authorized 
activities and any cancellation costs for equipment that is already 
ordered for its interconnection, which cannot be mitigated as 
hereafter described, whether or not such items or equipment later 
become unnecessary. If Interconnection Customer withdraws its 
Interconnection Request or either Party terminates the E&P 
Agreement, to the extent the equipment ordered can be canceled under 
reasonable terms, Interconnection Customer shall be obligated to pay 
the associated cancellation costs. To the extent that the equipment 
cannot be reasonably canceled, Transmission Provider may elect: (i) 
to take title to the equipment, in which event Transmission Provider 
shall refund Interconnection Customer any amounts paid by 
Interconnection Customer for such equipment and shall pay the cost 
of delivery of such equipment, or (ii) to transfer title to and 
deliver such equipment to Interconnection Customer, in which event 
Interconnection Customer shall pay any unpaid balance and cost of 
delivery of such equipment.

Appendix 1 to LGIP

INTERCONNECTION REQUEST FOR A LARGE GENERATING FACILITY

1. The undersigned Interconnection Customer submits this request to 
interconnect its Large Generating Facility with Transmission 
Provider's Transmission System pursuant to a Tariff.
    2.
2. This Interconnection Request is for (check one):

    3. __ A proposed new Large Generating Facility.
    4. __ An increase in the generating capacity or a Material 
Modification of an existing Generating Facility.

3. The type of interconnection service requested (check one):

    5. __ Energy Resource Interconnection Service
    6. __ Network Resource Interconnection Service

4. __ Check here only if Interconnection Customer requesting Network 
Resource Interconnection Service also seeks to have its Generating 
Facility studied for Energy Resource Interconnection Service
    7.
5. Interconnection Customer provides the following information:
    a. Address or location or the proposed new Large Generating 
Facility site (to the extent known) or, in the case of an existing 
Generating Facility, the name and specific location of the existing 
Generating Facility;
    b. Maximum summer at __ degrees C and winter at __ degrees C 
megawatt electrical output of the proposed new Large Generating 
Facility or the amount of megawatt increase in the generating 
capacity of an existing Generating Facility;
    c. General description of the equipment configuration;
    d. Commercial Operation Date (Day, Month, and Year);
    e. Name, address, telephone number, and email address of 
Interconnection Customer's contact person;
    f. Approximate location of the proposed Point of Interconnection 
(optional);
    g. Interconnection Customer Data (set forth in Attachment A);
    h. Primary frequency response operating range for electric 
storage resources;
    i. Requested capacity (in MW) of Interconnection Service (if 
lower than the Generating Facility Capacity)[.];
    j. If applicable, (1) the requested operating assumptions (i.e., 
whether the interconnecting Generating Facility will or will not 
charge at peak load) to be used by Transmission Provider that 
reflect the proposed charging behavior of a Generating Facility that 
includes at least one electric storage resource, and (2) a 
description of any control technologies (software and/or hardware) 
that will limit the operation of the Generating Facility to its 
intended operation.
6. Applicable deposit amount as specified in the LGIP.
    8.
7. Evidence of Site Control as specified in the LGIP (check one)
    9.

[[Page 61290]]

10. __ Is attached to this Interconnection Request
11. __ Will be provided at a later date in accordance with this LGIP

8. This Interconnection Request shall be submitted to the 
representative indicated below:
    12. {To be completed by Transmission Provider{time} 
9. Representative of Interconnection Customer to contact:
    13. [To be completed by Interconnection Customer]
10. This Interconnection Request is submitted by:
    14.

15. Name of Interconnection Customer:

By (signature):--------------------------------------------------------
Name (type or print):--------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Attachment A to Appendix 1 Interconnection Request

Large Generating Facility Data Unit Ratings

kVA __ [deg]F __ Voltage __
Power Factor __
Speed (RPM) __ Connection (e.g. Wye) __
Short Circuit Ratio __ Frequency, Hertz __
Stator Amperes at Rated kVA __ Field Volts __
Max Turbine __ MW [deg]F __

    Primary frequency response operating range for electric storage 
resources:

Minimum State of Charge:-----------------------------------------------
Maximum State of Charge:-----------------------------------------------

Combined Turbine-Generator-Exciter Inertia Data

Inertia Constant, H = __ kW sec/kVA
Moment-of-Inertia, WR\2\ = __ lb. ft.\2\

Reactance Data (per Unit-Rated KVA)

------------------------------------------------------------------------
                                      Direct axis       Quadrature axis
------------------------------------------------------------------------
Synchronous--saturated..........  Xdv ___             Xqv ___
Synchronous--unsaturated........  Xdi ___             Xqi ___
Transient--saturated............  X'dv ___            X'qv ___
Transient--unsaturated..........  X'di ___            X'qi ___
Subtransient--saturated.........  X''dv ___           X''qv ___
Subtransient--unsaturated.......  X''di ___           X''qi ___
Negative Sequence--saturated....  X2v ___
Negative Sequence--unsaturated..  X2i ___
Zero Sequence--saturated........  X0v ___
Zero Sequence--unsaturated......  X0i ___
Leakage Reactance...............  Xlm ___
------------------------------------------------------------------------

Field Time Constant Data (SEC)

 
 
 
Open Circuit................  T'do ___              T'qo ___
Three-Phase Short Circuit     T'd3 ___              T'q ___
 Transient.
Line to Line Short Circuit    T'd2 ___
 Transient.
Line to Neutral Short         T'd1 ___
 Circuit Transient.
Short Circuit Subtransient..  T''d ___              T''q ___
Open Circuit Subtransient...  T''do ___             T''qo ___
 

Armature Time Constant Data (SEC)

    Three Phase Short Circuit--Ta3 ___
    Line to Line Short Circuit--Ta2 ___
    Line to Neutral Short Circuit--Ta1 ___

    Note: If requested information is not applicable, indicate by 
marking ``N/A.''

MW Capability and Plant Configuration Large Generating Facility Data

Armature Winding Resistance Data (per Unit)

    Positive--R1 ___
    Negative--R2 ___
    Zero--R0 ___
    Rotor Short Time Thermal Capacity I2\2\t = ___
    Field Current at Rated kVA, Armature Voltage and PF = ___ amps
    Field Current at Rated kVA and Armature Voltage, 0 PF = ___ amps
    Three Phase Armature Winding Capacitance = ___ microfarad
    Field Winding Resistance = ___ ohms ___ [deg]C
    Armature Winding Resistance (Per Phase) = ___ ohms ___[deg]C

Curves

    Provide Saturation, Vee, Reactive Capability, Capacity 
Temperature Correction curves. Designate normal and emergency 
Hydrogen Pressure operating range for multiple curves.

Generator Step-Up Transformer Data Ratings

Capacity Self-cooled/Maximum Nameplate
___/___ kVA
Voltage Ratio(Generator Side/System side/Tertiary)
___/___/___kV
Winding Connections (Low V/High V/Tertiary V (Delta or Wye))
___/___/___
Fixed Taps Available---------------------------------------------------
Present Tap Setting----------------------------------------------------

Impedance

    Positive Z1 (on self-cooled kVA rating) ___ % ___ X/R
    Zero Z0 (on self-cooled kVA rating) ___ % ___ X/R

Excitation System Data

    Identify appropriate IEEE model block diagram of excitation 
system and power system stabilizer (PSS) for computer representation 
in power system stability simulations and the corresponding 
excitation system and PSS constants for use in the model.

Governor System Data

    Identify appropriate IEEE model block diagram of governor system 
for computer representation in power system stability simulations 
and the corresponding governor system constants for use in the 
model.

Wind Generators

    Number of generators to be interconnected pursuant to this 
Interconnection Request: ___
Elevation:-------------------------------------------------------------
____ Single Phase
____ Three Phase
    Inverter manufacturer, model name, number, and version:
-----------------------------------------------------------------------
    List of adjustable setpoints for the protective equipment or 
software:
-----------------------------------------------------------------------

    Note:  A completed General Electric Company Power Systems Load 
Flow (PSLF) data sheet or other compatible formats, such as IEEE and 
PTI power flow models, must be supplied with the Interconnection 
Request. If other data sheets are more appropriate to the proposed 
device, then they shall be provided and discussed at Scoping 
Meeting.

Induction Generators

(*) Field Volts:-------------------------------------------------------
(*) Field Amperes:-----------------------------------------------------
(*) Motoring Power (kW):-----------------------------------------------
(*) Neutral Grounding Resistor (If Applicable):------------------------
(*) I2\2\t or K (Heating Time Constant):--------------------
(*) Rotor Resistance:--------------------------------------------------

[[Page 61291]]

(*) Stator Resistance:-------------------------------------------------
(*) Stator Reactance:--------------------------------------------------
(*) Rotor Reactance:---------------------------------------------------
(*) Magnetizing Reactance:---------------------------------------------
(*) Short Circuit Reactance:-------------------------------------------
(*) Exciting Current:--------------------------------------------------
(*) Temperature Rise:--------------------------------------------------
(*) Frame Size:--------------------------------------------------------
(*) Design Letter:-----------------------------------------------------
(*) Reactive Power Required In Vars (No Load):-------------------------
(*) Reactive Power Required In Vars (Full Load):-----------------------
(*) Total Rotating Inertia, H:___ Per Unit on KVA Base

    Note:  Please consult Transmission Provider prior to submitting 
the Interconnection Request to determine if the information 
designated by (*) is required.

Models for Non-Synchronous Generators

    For a non-synchronous Large Generating Facility, Interconnection 
Customer shall provide (1) a validated user-defined root mean 
squared (RMS) positive sequence dynamics model; (2) an appropriately 
parameterized generic library RMS positive sequence dynamics model, 
including model block diagram of the inverter control and plant 
control systems, as defined by the selection in Table 1 or a model 
otherwise approved by the Western Electricity Coordinating Council, 
that corresponds to Interconnection Customer's Large Generating 
Facility; and (3) if applicable, a validated electromagnetic 
transient model if Transmission Provider performs an electromagnetic 
transient study as part of the interconnection study process. A 
user-defined model is a set of programming code created by equipment 
manufacturers or developers that captures the latest features of 
controllers that are mainly software based and represents the 
entities' control strategies but does not necessarily correspond to 
any generic library model. Interconnection Customer must also 
demonstrate that the model is validated by providing evidence that 
the equipment behavior is consistent with the model behavior (e.g., 
an attestation from Interconnection Customer that the model 
accurately represents the entire Large Generating Facility; 
attestations from each equipment manufacturer that the user defined 
model accurately represents the component of the Large Generating 
Facility; or test data).

                    Table 1--Acceptable Generic Library RMS Positive Sequence Dynamics Models
----------------------------------------------------------------------------------------------------------------
         GE PSLF               Siemens PSS/E*       PowerWorld Simulator                Description
----------------------------------------------------------------------------------------------------------------
pvd1....................  .......................  PVD1..................  Distributed PV system model.
der_a...................  DERAU1.................  DER_A.................  Distributed energy resource model.
regc_a..................  REGCAU1, REGCA1........  REGC_A................  Generator/converter model.
regc_b..................  REGCBU1................  REGC_B................  Generator/converter model.
wt1g....................  WT1G1..................  WT1G and WT1G1........  Wind turbine model for Type-1 wind
                                                                            turbines (conventional directly
                                                                            connected induction generator).
wt2g....................  WT2G1..................  WT2G and WT2G1........  Generator model for generic Type-2
                                                                            wind turbines.
wt2e....................  WT2E1..................  WT2E and WT2E1........  Rotor resistance control model for
                                                                            wound-rotor induction wind-turbine
                                                                            generator wt2g.
reec_a..................  REECAU1, REECA1........  REEC_A................  Renewable energy electrical control
                                                                            model.
reec_c..................  REECCU1................  REEC_C................  Electrical control model for battery
                                                                            energy storage system.
reec_d..................  REECDU1................  REEC_D................  Renewable energy electrical control
                                                                            model.
wt1t....................  WT12T1.................  WT1T and WT12T1.......  Wind turbine model for Type-1 wind
                                                                            turbines (conventional directly
                                                                            connected induction generator).
wt1p_b..................  wt1p_b.................  WT12A1U_B.............  Generic wind turbine pitch controller
                                                                            for WTGs of Types 1 and 2.
wt2t....................  WT12T1.................  WT2T..................  Wind turbine model for Type-2 wind
                                                                            turbines (directly connected
                                                                            induction generator wind turbines
                                                                            with an external rotor resistance).
wtgt_a..................  WTDTAU1, WTDTA1........  WTGT_A................  Wind turbine drive train model.
wtga_a..................  WTARAU1, WTARA1........  WTGA_A................  Simple aerodynamic model.
wtgp_a..................  WTPTAU1, WTPTA1........  WTGPT_A...............  Wind Turbine Generator Pitch
                                                                            controller.
wtgq_a..................  WTTQAU1, WTTQA1........  WTGTRQ_A..............  Wind Turbine Generator Torque
                                                                            controller.
wtgwgo_a................  WTGWGOAU...............  WTGWGO_A..............  Supplementary control model for Weak
                                                                            Grids.
wtgibffr_a..............  WTGIBFFRA..............  WTGIBFFR_A............  Inertial-base fast frequency response
                                                                            control.
wtgp_b..................  WTPTBU1................  WTGPT_B...............  Wind Turbine Generator Pitch
                                                                            controller.
wtgt_b..................  WTDTBU1................  WTGT_B................  Drive train model.
repc_a..................  Type 4: REPCAU1 (v33),   REPC_A................  Power Plant Controller.
                           REPCA1 (v34).
                          Type 3: REPCTAU1 (v33),
                           REPCTA1 (v34).
repc_b..................  PLNTBU1................  REPC_B................  Power Plant Level Controller for
                                                                            controlling several plants/devices.
                                                                           In regard to Siemens PSS/E*:Names of
                                                                            other models for interface with
                                                                            other devices:
                                                                           REA3XBU1, REAX4BU1--for interface
                                                                            with Type 3 and 4 renewable
                                                                            machines.
                                                                           SWSAXBU1--for interface with SVC
                                                                            (modeled as switched shunt in
                                                                            powerflow).
                                                                           SYNAXBU1--for interface with
                                                                            synchronous condenser.
                                                                           FCTAXBU1--for interface with FACTS
                                                                            device.
repc_c..................  REPCCU.................  REPC_C................  Power plant controller.
----------------------------------------------------------------------------------------------------------------

Appendix 2 to LGIP

[Interconnection Feasibility Study Agreement]

    [This agreement is made and entered into this _ day of ___, 20 _ 
by and between_____, a _____ organized and existing under the laws 
of _____ the State of (``Interconnection Customer''), and _____, a 
_____ existing under the laws of the State of _____(``Transmission 
Provider''). Interconnection Customer and Transmission Provider each 
may be referred to as a ``Party,'' or collectively as the 
``Parties.'']

[Recitals]

    [Whereas, Interconnection Customer is proposing to develop a 
Large Generating Facility or generating capacity addition to an 
existing Generating Facility consistent with the Interconnection 
Request submitted by Interconnection customer dated ___; and]
    [Whereas, Interconnection Customer desires to interconnect the 
Large Generating Facility with the Transmission System; and]
    [Whereas, Interconnection Customer has requested Transmission 
Provider to perform an Interconnection Feasibility Study to assess 
the feasibility of interconnecting the

[[Page 61292]]

proposed Large Generating Facility to the Transmission System, and 
of any Affected Systems;]
    [Now, therefore, in consideration of and subject to the mutual 
covenants contained herein the Parties agree as follows:]
    [1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in 
Transmission Provider's FERC-approved LGIP]
    [2.0 Interconnection Customer elects and Transmission Provider 
shall cause to be performed an Interconnection Feasibility Study 
consistent with Section 6.0 of this LGIP in accordance with the 
Tariff].
    [3.0 The scope of the Interconnection Feasibility Study shall be 
subject to the assumptions set forth in Attachment A to this 
Agreement.]
    [4.0 The Interconnection Feasibility Study shall be based on the 
technical information provided by Interconnection Customer in the 
Interconnection Request, as may be modified as the result of the 
Scoping Meeting. Transmission Provider reserves the right to request 
additional technical information from Interconnection Customer as 
may reasonably become necessary consistent with Good Utility 
Practice during the course of the Interconnection Feasibility Study 
and as designated in accordance with Section 3.4.4 of the LGIP. If, 
after the designation of the Point of Interconnection pursuant to 
Section 3.4.4 of the LGIP, Interconnection Customer modifies its 
Interconnection Request pursuant to Section 4.4, the time to 
complete the Interconnection Feasibility Study may be extended.]
    [5.0 The Interconnection Feasibility Study report shall provide 
the following information:]

--[preliminary identification of any circuit breaker short circuit 
capability limits exceeded as a result of the interconnection;]
--[preliminary identification of any thermal overload or voltage 
limit violations resulting from the interconnection; and]
--[preliminary description and non-bonding estimated cost of 
facilities required to interconnect the Large Generating Facility to 
the Transmission System and to address the identified short circuit 
and power flow issues.]

    [6.0 Interconnection Customer shall provide a deposit of $10,000 
for the performance of the Interconnection Feasibility Study.]
    [Upon receipt of the Interconnection Feasibility Study, 
Transmission Provider shall charge and Interconnection Customer 
shall pay the actual costs of the Interconnection Feasibility 
Study.]
    [Any difference between the deposit and the actual cost of the 
study shall be paid by or refunded to Interconnection Customer, as 
appropriate.]
    [7.0 Miscellaneous. The Interconnection Feasibility Study 
Agreement shall include standard miscellaneous terms including, but 
not limited to, indemnities, representations, disclaimers, 
warranties, governing law, amendment, execution, waiver, 
enforceability and assignment, that reflect best practices in the 
electric industry, and that are consistent with regional practices, 
Applicable Laws and Regulations, and the organizational nature of 
each Party. All of these provisions, to the extent practicable, 
shall be consistent with the provisions of this LGIP and the LGIA.]
    [In witness whereof, the Parties have caused this Agreement to 
be duly executed by their duly authorized officers or agents on the 
day and year first above written.
{Insert name of Transmission Provider or Transmission Owner, if 
applicable{time} 
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of prospective Interconnection Customer{time} 
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date: ]----------------------------------------------------------------

[Attachment A to Appendix 2 Interconnection Feasibility Study 
Agreement]

[Assumptions Used in Conducting the Interconnection Feasibility Study]

    [The Informational Interconnection Feasibility Study will be 
based upon the information set forth in the Interconnection Request 
and agreed upon in the Scoping Meeting held on ____:
    Designation of Point of Interconnection and configuration to be 
studied.
    Designation of alternative Point(s) of Interconnection and 
configuration.
    {Above assumptions to be completed by Interconnection Customer 
and other assumptions to be provided by Interconnection Customer and 
Transmission Provider{time} ]

Appendix 2[3] to LGIP

[Interconnection System Impact]Cluster Study Agreement

    This agreement is made and entered into this day of ______, 20 
__ by and between ______, a ______organized and existing under the 
laws of the State of ______, (``Interconnection Customer,'') and 
______, a ______ organized and existing under the laws of the State 
of ______ (``Transmission Provider''). Interconnection Customer and 
Transmission Provider each may be referred to as a ``Party,'' or 
collectively as the ``Parties.''

Recitals

    Whereas, Interconnection Customer is proposing to develop a 
Large Generating Facility or generating capacity addition to an 
existing Generating Facility consistent with the Interconnection 
Request submitted by Interconnection Customer dated ______; and
    Whereas, Interconnection Customer desires to interconnect the 
Large Generating Facility with the Transmission System;
    [Whereas, Transmission Provider has completed an Interconnection 
Feasibility Study (the ``[Feasibility] Study'') and provided the 
results of said study to Interconnection Customer (This recital to 
be omitted if Transmission Provider does not require the 
Interconnection Feasibility Study.); and]
    Whereas, Interconnection Customer has requested Transmission 
Provider to perform [an Interconnection System Impact]a Cluster 
Study to assess the impact of interconnecting the Large Generating 
Facility to the Transmission System, and of any Affected Systems;
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agreed as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in this LGIP.
    2.0 Interconnection Customer elects and Transmission Provider 
shall cause to be performed [an Interconnection System Impact]a 
Cluster Study consistent with Section 7.0 of this LGIP in accordance 
with the Tariff.
    16.
    3.0 The scope of the [Interconnection System Impact]Cluster 
Study shall be subject to the assumptions set forth in Attachment A 
to this Agreement.
    17.
    4.0 The [Interconnection System Impact]Cluster Study will be 
based upon the [results of the Interconnection Feasibility Study 
and] the technical information provided by Interconnection Customer 
in the Interconnection Request, subject to any modifications in 
accordance with Section 4.4 of this LGIP. Transmission Provider 
reserves the right to request additional technical information from 
Interconnection Customer as may reasonably become necessary 
consistent with Good Utility Practice during the course of the 
[Interconnection Customer System Impact]Cluster Study. [If 
Interconnection Customer modifies its designated Point of 
Interconnection, Interconnection Request, or the technical 
information provided therein, the time to complete the 
Interconnection System Impact Study may be extended.]
    18.
    5.0 The [Interconnection System Impact]Cluster Study 
[report]Report shall provide the following information:

--identification of any circuit breaker short circuit capability 
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations 
resulting from the interconnection;
--identification of any instability or inadequately damped response 
to system disturbances resulting from the interconnection; and
--description and non-binding, good faith estimated cost of 
facilities required to interconnect the Large Generating Facility to 
the Transmission System and to address the identified short circuit, 
instability, and power flow issues.

    6.0 [Interconnection Customer shall provide a deposit of $50,000 
for the performance of the Interconnection System Impact 
Study.]Transmission Provider's good faith estimate for the time of 
completion of the [Interconnection System Impact]Cluster Study is 
{insert date{time} .

[[Page 61293]]

    Upon receipt of the [Interconnection System Impact]Cluster Study 
Report, Transmission Provider shall charge and Interconnection 
Customer shall pay its share of the actual costs of the 
[Interconnection System Impact]Cluster Study, consistent with 
Section 13.3 of this LGIP.
    Any difference between the deposit and the actual cost of the 
study shall be paid by or refunded to Interconnection Customer, as 
appropriate.
    7.0 Miscellaneous. The [Interconnection System Impact]Cluster 
Study Agreement shall include standard miscellaneous terms 
including, but not limited to, indemnities, representations, 
disclaimers, warranties, governing law, amendment, execution, 
waiver, enforceability and assignment, that reflect best practices 
in the electric industry, that are consistent with regional 
practices, Applicable Laws and Regulations and the organizational 
nature of each Party. All of these provisions, to the extent 
practicable, shall be consistent with the provisions of this LGIP 
and LGIA.
    In witness thereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.
{Insert name of Transmission Provider or Transmission Owner, if 
applicable{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of Interconnection Customer{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Attachment A to Appendix 2[3]

[Interconnection System Impact]Cluster Study Agreement

Assumptions Used in Conducting the [Interconnection System 
Impact]Cluster Study

    The [Interconnection System Impact]Cluster Study will be based 
upon the technical information provided by Interconnection Customer 
in the Interconnection Request, [results of the Interconnection 
Feasibility Study,] subject to any modifications in accordance with 
Section 4.4 of this[e] LGIP, and the following assumptions:
    Designation of Point of Interconnection and configuration to be 
studied.
    Designation of alternative Point(s) of Interconnection and 
configuration.
    {Above assumptions to be completed by Interconnection Customer 
and other assumptions to be provided by Interconnection Customer and 
Transmission Provider{time} 

Appendix 3[4] to LGIP

Interconnection Facilities Study Agreement

    This Agreement is made and entered into this__day of_____, 
20__by and between_____, a_____organized and existing under the laws 
of the State of_____, (``Interconnection Customer,'') 
and_____a______ existing under the laws of the State of____, 
(``Transmission Provider ''). Interconnection Customer and 
Transmission Provider each may be referred to as a ``Party,'' or 
collectively as the ``Parties.''

Recitals

    Whereas, Interconnection Customer is proposing to develop a 
Large Generating Facility or generating capacity addition to an 
existing Generating Facility consistent with the Interconnection 
Request submitted by Interconnection Customer dated____; and
    Whereas, Interconnection Customer desires to interconnect the 
Large Generating Facility with the Transmission System;
    Whereas, Transmission Provider has completed an Interconnection 
[System Impact]Cluster Study (the ``[System Impact]Cluster Study'') 
and provided the results of said study to Interconnection Customer; 
and
    Whereas, Interconnection Customer has requested Transmission 
Provider to perform an Interconnection Facilities Study to specify 
and estimate the cost of the equipment, engineering, procurement and 
construction work needed to implement the conclusions of the 
[Interconnection System Impact]Cluster Study in accordance with Good 
Utility Practice to physically and electrically connect the Large 
Generating Facility to the Transmission System.
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein the Parties agreed as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in 
Transmission Provider's FERC-approved LGIP.
    2.0 Interconnection Customer elects and Transmission Provider 
shall cause an Interconnection Facilities Study consistent with 
Section 8.0 of this LGIP to be performed in accordance with the 
Tariff.
    3.0 The scope of the Interconnection Facilities Study shall be 
subject to the assumptions set forth in Attachment A and the data 
provided in Attachment B to this Agreement.
    4.0 The Interconnection Facilities Study [r]Report (i) shall 
provide a description, estimated cost of (consistent with Attachment 
A), schedule for required facilities to interconnect the Large 
Generating Facility to the Transmission System and (ii) shall 
address the short circuit, instability, and power flow issues 
identified in the [Interconnection System Impact]Cluster Study.
    5.0 Interconnection Customer shall provide a Commercial 
Readiness Deposit per Section 8.1 of this LGIP to enter [deposit of 
$100,000 for the performance of] the Interconnection Facilities 
Study. The time for completion of the Interconnection Facilities 
Study is specified in Attachment A.
    [Transmission Provider shall invoice Interconnection Customer on 
a monthly basis for the work to be conducted on the Interconnection 
Facilities Study each month. Interconnection Customer shall pay 
invoiced amounts within thirty (30) Calendar Days of receipt of 
invoice. Transmission Provider shall continue to hold the amounts on 
deposit until settlement of the final invoice.]
    6.0 Miscellaneous. The Interconnection Facilit[y]ies Study 
Agreement shall include standard miscellaneous terms including, but 
not limited to, indemnities, representations, disclaimers, 
warranties, governing law, amendment, execution, waiver, 
enforceability and assignment, that reflect best practices in the 
electric industry, and that are consistent with regional practices, 
Applicable Laws and Regulations, and the organizational nature of 
each Party. All of these provisions, to the extent practicable, 
shall be consistent with the provisions of the LGIP and the LGIA.
    In witness whereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.
[Insert name of Transmission Provider or Transmission Owner, if 
applicable]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Attachment A to Appendix 3[4]

Interconnection Facilities Study Agreement

Interconnection Customer Schedule Election for Conducting the 
Interconnection Facilities Study

    Transmission Provider shall [use Reasonable Efforts to]complete 
the study and issue a draft Interconnection Facilities Study 
[r]Report to Interconnection Customer within the following number of 
days after [of]receipt of an executed copy of this Interconnection 
Facilities Study Agreement:
--ninety (90) Calendar Days with no more than a  20 
percent cost estimate contained in the report, or
--one hundred eighty (180) Calendar Days with no more than a  10 percent cost estimate contained in the report.

Attachment B to Appendix 3[4] Interconnection Facilities Study 
Agreement

Data Form To Be Provided by Interconnection Customer With the 
Interconnection Facilities Study Agreement

    Provide location plan and simplified one-line diagram of the 
plant and station facilities. For staged projects, please indicate 
future generation, transmission circuits, etc.
    One set of metering is required for each generation connection 
to the new ring bus or existing Transmission Provider station. 
Number of generation connections:
    On the one line diagram indicate the generation capacity 
attached at each metering location. (Maximum load on CT/PT)
    On the one line diagram indicate the location of auxiliary 
power. (Minimum load on CT/PT) Amps
    Will an alternate source of auxiliary power be available during 
CT/PT maintenance? __Yes __No
    Will a transfer bus on the generation side of the metering 
require that each meter set be

[[Page 61294]]

designed for the total plant generation? __Yes __No (Please indicate 
on one line diagram).
    What type of control system or PLC will be located at 
Interconnection Customer's Large Generating Facility?
-----------------------------------------------------------------------
    What protocol does the control system or PLC use?
-----------------------------------------------------------------------
    Please provide a 7.5-minute quadrangle of the site. Sketch the 
plant, station, transmission line, and property line.

    Physical dimensions of the proposed interconnection station:
-----------------------------------------------------------------------
    Bus length from generation to interconnection station:
-----------------------------------------------------------------------
    Line length from interconnection station to Transmission 
Provider's transmission line.
-----------------------------------------------------------------------

    Tower number observed in the field. (Painted on tower leg) *
-----------------------------------------------------------------------
    Number of third party easements required for transmission lines 
*:
-----------------------------------------------------------------------
    * To be completed in coordination with Transmission Provider.
    Is the Large Generating Facility in the Transmission Provider's 
service area? __Yes __No
    Local provider:
-----------------------------------------------------------------------
    Please provide proposed schedule dates:

Begin Construction
Date:------------------------------------------------------------------
Generator step-up transformer receives back feed power
Date:------------------------------------------------------------------
Generation Testing
Date:------------------------------------------------------------------
Commercial Operation
Date:------------------------------------------------------------------

Appendix 4[5] to LGIP

Optional Interconnection Study Agreement

    This Agreement is made and entered into this__day of______, 
20__by and between ______, a ______organized and existing under the 
laws of the State of______, (``Interconnection Customer,'') and 
______ a ______ existing under the laws of the State of ______, 
(``Transmission Provider ''). Interconnection Customer and 
Transmission Provider each may be referred to as a ``Party,'' or 
collectively as the ``Parties.''

Recitals

    Whereas, Interconnection Customer is proposing to develop a 
Large Generating Facility or generating capacity addition to an 
existing Generating Facility consistent with the Interconnection 
Request submitted by Interconnection Customer dated ______;
    Whereas, Interconnection Customer is proposing to establish an 
interconnection with the Transmission System; and
    Whereas, Interconnection Customer has submitted to Transmission 
Provider an Interconnection Request; and
    Whereas, on or after the date when Interconnection Customer 
receives the [Interconnection System Impact] Cluster Study results, 
Interconnection Customer has further requested that Transmission 
Provider prepare an Optional Interconnection Study;
    Now, Therefore, in consideration of and subject to the mutual 
covenants contained herein the Parties agree as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in 
Transmission Provider's FERC-approved LGIP.
    2.0 Interconnection Customer elects and Transmission Provider 
shall cause an Optional Interconnection Study consistent with 
Section 10.0 of this LGIP to be performed in accordance with the 
Tariff.
    3.0 The scope of the Optional Interconnection Study shall be 
subject to the assumptions set forth in Attachment A to this 
Agreement.
    4.0 The Optional Interconnection Study shall be performed solely 
for informational purposes.
    5.0 The Optional Interconnection Study report shall provide a 
sensitivity analysis based on the assumptions specified by 
Interconnection Customer in Attachment A to this Agreement. The 
Optional Interconnection Study will identify Transmission Provider's 
Interconnection Facilities and the Network Upgrades, and the 
estimated cost thereof, that may be required to provide transmission 
service or interconnection service based upon the assumptions 
specified by Interconnection Customer in Attachment A.
    6.0 Interconnection Customer shall provide a deposit of $10,000 
for the performance of the Optional Interconnection Study. 
Transmission Provider's good faith estimate for the time of 
completion of the Optional Interconnection Study is [insert date].
    Upon receipt of the Optional Interconnection Study, Transmission 
Provider shall charge and Interconnection Customer shall pay the 
actual costs of the Optional Study.
    Any difference between the initial payment and the actual cost 
of the study shall be paid by or refunded to Interconnection 
Customer, as appropriate.
    7.0 Miscellaneous. The Optional Interconnection Study Agreement 
shall include standard miscellaneous terms including, but not 
limited to, indemnities, representations, disclaimers, warranties, 
governing law, amendment, execution, waiver, enforceability and 
assignment, that reflect best practices in the electric industry, 
and that are consistent with regional practices, Applicable Laws and 
Regulations, and the organizational nature of each Party. All of 
these provisions, to the extent practicable, shall be consistent 
with the provisions of the LGIP and the LGIA.
    In witness whereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.

[Insert name of Transmission Provider or Transmission Owner, if 
applicable]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------

Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Appendix 5[6] to LGIP

Large Generator Interconnection Agreement (See LGIA)

Appendix 6[7]

Interconnection Procedures for A Wind Generating Plant

    Appendix 6[7] sets forth procedures specific to a wind 
generating plant. All other requirements of this LGIP continue to 
apply to wind generating plant interconnections.

A. Special Procedures Applicable to Wind Generators

    The wind plant Interconnection Customer, in completing the 
Interconnection Request required by S[s]ection 3.3 of this LGIP, may 
provide to the Transmission Provider a set of preliminary electrical 
design specifications depicting the wind plant as a single 
equivalent generator. Upon satisfying these and other applicable 
Interconnection Request conditions, the wind plant may enter the 
queue and receive the base case data as provided for in this LGIP.
    No later than six months after submitting an Interconnection 
Request completed in this manner, the wind plant Interconnection 
Customer must submit completed detailed electrical design 
specifications and other data (including collector system layout 
data) needed to allow the Transmission Provider to complete the 
[System Impact]Cluster Study.

Appendix 7 to LGIP

Transitional Cluster Study Agreement

    This Agreement is made and entered into this __ day of ______, 
20 __ by and between ______, a ______ organized and existing under 
the laws of the State of ______ (``Interconnection Customer''), and 
______, a ______ organized and existing under the laws of the State 
of ______ (``Transmission Provider''). Interconnection Customer and 
Transmission Provider each may be referred to as a ``Party,'' or 
collectively as the ``Parties.''

Recitals

    Whereas, Interconnection Customer is proposing to develop a 
Large Generating Facility or generating capacity addition to an 
existing Generating Facility consistent with the Interconnection 
Request submitted by Interconnection Customer dated ______;
    Whereas, Interconnection Customer desires to interconnect the 
Large Generating Facility with the Transmission System; and
    Whereas, Interconnection Customer has requested Transmission 
Provider to perform a ``Transitional Cluster Study,'' which combines 
the Cluster Study and Interconnection Facilities Study, in a single

[[Page 61295]]

cluster study, followed by any needed restudies, to specify and 
estimate the cost of the equipment, engineering, procurement, and 
construction work needed to physically and electrically connect the 
Large Generating Facility to Transmission Provider's Transmission 
System; and
    Whereas, Interconnection Customer has a valid Queue Position as 
of the {Transmission Provider to insert effective date of compliance 
filing{time} .
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agree as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in this LGIP.
    2.0 Interconnection Customer elects, and Transmission Provider 
shall cause to be performed, a Transitional Cluster Study.
    3.0 The Transitional Cluster Study shall be based upon the 
technical information provided by Interconnection Customer in the 
Interconnection Request. Transmission Provider reserves the right to 
request additional technical information from Interconnection 
Customer as may reasonably become necessary consistent with Good 
Utility Practice during the course of the Transitional Cluster Study 
and Interconnection Customer shall provide such data as quickly as 
reasonable.
    4.0 Pursuant to Section 5.1.1.2 of this LGIP, the interim 
Transitional Cluster Study Report shall provide the information 
below:

--identification of any circuit breaker short circuit capability 
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations 
resulting from the interconnection;

    19.

--identification of any instability or inadequately damped response 
to system disturbances resulting from the interconnection; and
--Transmission Provider's Interconnection Facilities and Network 
Upgrades that are expected to be required as a result of the 
Interconnection Request(s) and a non-binding, good faith estimate of 
cost responsibility and a non-binding, good faith estimated time to 
construct.

    5.0 Pursuant to Section 5.1.1.2 of this LGIP, the final 
Transitional Cluster Study Report shall: (1) provide all the 
information included in the interim Transitional Cluster Study 
Report; (2) provide a description of, estimated cost of, and 
schedule for required facilities to interconnect the Generating 
Facility to the Transmission System; and (3) address the short 
circuit, instability, and power flow issues identified in the 
interim Transitional Cluster Study Report.
    6.0 Interconnection Customer has met the requirements described 
in Section 5.1.1.2 of this LGIP.
    20.
    7.0 Interconnection Customer previously provided a deposit for 
the performance of Interconnection Studies. Upon receipt of the 
final Transitional Cluster Study Report, Transmission Provider shall 
charge and Interconnection Customer shall pay the actual costs of 
the Transitional Cluster Study. Any difference between the study 
deposit and the actual cost of the study shall be paid by or 
refunded to Interconnection Customer, in accordance with the 
provisions of Section 13.3 of this LGIP.
    8.0 Miscellaneous. The Transitional Cluster Study Agreement 
shall include standard miscellaneous terms including, but not 
limited to, indemnities, representations, disclaimers, warranties, 
governing law, amendment, execution, waiver, enforceability and 
assignment, that reflect best practices in the electric industry, 
and that are consistent with regional practices, Applicable Laws and 
Regulations, and the organizational nature of each Party. All of 
these provisions, to the extent practicable, shall be consistent 
with the provisions of this LGIP and the LGIA.
    In Witness Whereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.

{Insert name of Transmission Provider or Transmission Owner, if 
applicable{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

{Insert name of Interconnection Customer{time} ------------------------

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Appendix 8 to LGIP

Transitional Serial Interconnection Facilities Study Agreement

    This Agreement is made and entered into this __ day of ______, 
20__, by and between ______, a ______ organized and existing under 
the laws of the State of ______(``Interconnection Customer'') and 
______, a ______organized and existing under the laws of the State 
of ______ (``Transmission Provider''). Interconnection Customer and 
Transmission Provider each may be referred to as a ``Party,'' or 
collectively as the ``Parties.''

Recitals

    Whereas, Interconnection Customer is proposing to develop a 
Large Generating Facility or generating capacity addition to an 
existing Large Generating Facility consistent with the 
Interconnection Request submitted by Interconnection Customer dated 
______; and
    Whereas, Interconnection Customer desires to interconnect the 
Large Generating Facility with the Transmission System; and
    Whereas, Interconnection Customer has requested Transmission 
Provider to continue processing its Interconnection Facilities Study 
to specify and estimate the cost of the equipment, engineering, 
procurement, and construction work needed to implement the 
conclusions of the final interconnection system impact study (from 
the previously effective serial study process) in accordance with 
Good Utility Practice to physically and electrically connect the 
Large Generating Facility to the Transmission System; and
    Whereas, Transmission Provider has provided an Interconnection 
Facilities Study Agreement to the Interconnection Customer on or 
before {Transmission Provider to insert effective date of compliance 
filing{time} .
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agree as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in this LGIP.
    2.0 Interconnection Customer elects and Transmission Provider 
shall cause to be performed an Interconnection Facilities Study 
consistent with Section 8 of this LGIP.
    3.0 The scope of the Interconnection Facilities Study shall be 
subject to the assumptions set forth in Attachment A to this 
Agreement, which shall be the same assumptions as the previous 
Interconnection Facilities Study Agreement executed by the 
Interconnection Customer.
    4.0 The Interconnection Facilities Study Report shall: (1) 
provide a description, estimated cost of (consistent with Attachment 
A), and schedule for required facilities to interconnect the Large 
Generating Facility to the Transmission System; and (2) address the 
short circuit, instability, and power flow issues identified in the 
most recently published Cluster Study Report.
    5.0 Interconnection Customer has met the requirements described 
in Section 5.1.1.1 of this LGIP. The time for completion of the 
Interconnection Facilities Study is specified in Attachment A, and 
shall be no later than 150 Calendar Days after {Transmission 
Provider to insert effective date accepted on compliance{time} .
    6.0 Interconnection Customer previously provided a deposit of 
______ dollars ($ __) for the performance of the Interconnection 
Facilities Study.
    7.0 Upon receipt of the Interconnection Facilities Study 
results, Transmission Provider shall charge and Interconnection 
Customer shall pay the actual costs of the Interconnection 
Facilities Study.
    8.0 Any difference between the study deposit and the actual cost 
of the study shall be paid by or refunded to Interconnection 
Customer, as appropriate.
    9.0 Miscellaneous. The Interconnection Facilities Study 
Agreement shall include standard miscellaneous terms including, but 
not limited to, indemnities, representations, disclaimers, 
warranties, governing law, amendment, execution, waiver, 
enforceability and assignment, that reflect best practices in the 
electric industry, and that are consistent with regional practices, 
Applicable Laws and Regulations, and the organizational nature of 
each Party. All of these provisions, to the extent practicable, 
shall be consistent with the provisions of this LGIP and this LGIA.
    In Witness Whereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.

{Insert name of Transmission Provider or Transmission Owner, if 
applicable{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

{Insert name of Interconnection Customer{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------

[[Page 61296]]

Date:------------------------------------------------------------------

Attachment A to Appendix 8

Transitional Serial Interconnection Facilities Study Agreement

Assumptions Used In Conducting The Transitional Serial Interconnection 
Facilities Study

{Assumptions to be completed by Interconnection Customer and 
Transmission Provider{time} 

Appendix 9 to LGIP

Two-Party Affected System Study Agreement

    This Agreement is made and entered into this __ day of ______, 
20__, by and between ______, a ______ organized and existing under 
the laws of the State of ______ (Affected System Interconnection 
Customer) and ______, a ______ organized and existing under the laws 
of the State of ______ (Transmission Provider). Affected System 
Interconnection Customer and Transmission Provider each may be 
referred to as a ``Party,'' or collectively as the ``Parties.''

Recitals

    Whereas, Affected System Interconnection Customer is proposing 
to develop a {description of generating facility or generating 
capacity addition to an existing generating facility{time}  
consistent with the interconnection request submitted by Affected 
System Interconnection Customer to {name of host transmission 
provider{time} , dated ______, for which {name of host transmission 
provider{time}  found impacts on Transmission Provider's 
Transmission System; and
    Whereas, Affected System Interconnection Customer desires to 
interconnect the {generating facility{time}  with {name of host 
transmission provider{time} 's transmission system;
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agree as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in this LGIP.
    2.0 Transmission Provider shall coordinate with Affected System 
Interconnection Customer to perform an Affected System Study 
consistent with Section 9 of this LGIP.
    3.0 The scope of the Affected System Study shall be subject to 
the assumptions set forth in Attachment A to this Agreement.
    4.0 The Affected System Study will be based upon the technical 
information provided by Affected System Interconnection Customer and 
{name of host transmission provider{time} . Transmission Provider 
reserves the right to request additional technical information from 
Affected System Interconnection Customer as may reasonably become 
necessary consistent with Good Utility Practice during the course of 
the Affected System Study.
    5.0 The Affected System Study shall provide the following 
information:

--identification of any circuit breaker short circuit capability 
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations 
resulting from the interconnection;
--identification of any instability or inadequately damped response 
to system disturbances resulting from the interconnection;
--non-binding, good faith estimated cost and time required to 
construct facilities required on Transmission Provider's 
Transmission System to accommodate the interconnection of the 
{generating facility{time}  to the transmission system of the host 
transmission provider; and
--description of how such facilities will address the identified 
short circuit, instability, and power flow issues.

    6.0 Affected System Interconnection Customer shall provide a 
deposit of __ for performance of the Affected System Study. Upon 
receipt of the results of the Affected System Study by the Affected 
System Interconnection Customer, Transmission Provider shall charge, 
and Affected System Interconnection Customer shall pay, the actual 
cost of the Affected System Study. Any difference between the 
deposit and the actual cost of the Affected System Study shall be 
paid by or refunded to Affected System Interconnection Customer, as 
appropriate, including interest calculated in accordance with 
section 35.19a(a)(2) of FERC's regulations.
    7.0 This Agreement shall include standard miscellaneous terms 
including, but not limited to, indemnities, representations, 
disclaimers, warranties, governing law, amendment, execution, 
waiver, enforceability, and assignment, which reflect best practices 
in the electric industry, that are consistent with regional 
practices, Applicable Laws and Regulations and the organizational 
nature of each Party. All of these provisions, to the extent 
practicable, shall be consistent with the provisions of the LGIP.
    In witness thereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.

{Insert name of Transmission Provider{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

{Insert name of Affected System Interconnection Customer{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Project No.------------------------------------------------------------

Attachment A to Appendix 9--Two-Party Affected System Study Agreement

Assumptions Used In Conducting The Affected System Study

    The Affected System Study will be based upon the following 
assumptions:

{Assumptions to be completed by Affected System Interconnection 
Customer and Transmission Provider{time} 

Appendix 10 to LGIP

Multiparty Affected System Study Agreement

    This Agreement is made and entered into this __ day of ______, 
20__, by and among ______, a ______ organized and existing under the 
laws of the State of ______ (Affected System Interconnection 
Customer); ______, a ______ organized and existing under the laws of 
the State of ______ (Affected System Interconnection Customer); and 
______, a ______ organized and existing under the laws of the State 
of ______ (Transmission Provider). Affected System Interconnection 
Customers and Transmission Provider each may be referred to as a 
``Party,'' or collectively as the ``Parties.'' When it is not 
important to differentiate among them, Affected System 
Interconnection Customers each may be referred to as ``Affected 
System Interconnection Customer'' or collectively as the ``Affected 
System Interconnection Customers.''

Recitals

    Whereas, Affected System Interconnection Customers are proposing 
to develop {description of generating facilities or generating 
capacity additions to an existing generating facility{time} , 
consistent with the interconnection requests submitted by Affected 
System Interconnection Customers to {name of host transmission 
provider{time} , dated ______, for which {name of host transmission 
provider{time}  found impacts on Transmission Provider's 
Transmission System; and
    Whereas, Affected System Interconnection Customers desire to 
interconnect the {generating facilities{time}  with {name of host 
transmission provider{time} 's transmission system;
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agree as follows:
    1.0 When used in this Agreement, with initial capitalization, 
the terms specified shall have the meanings indicated in this LGIP.
    2.0 Transmission Provider shall coordinate with Affected System 
Interconnection Customers to perform an Affected System Study 
consistent with Section 9 of this LGIP.
    3.0 The scope of the Affected System Study shall be subject to 
the assumptions set forth in Attachment A to this Agreement.
    4.0 The Affected System Study will be based upon the technical 
information provided by Affected System Interconnection Customers 
and {name of host transmission provider{time} . Transmission 
Provider reserves the right to request additional technical 
information from Affected System Interconnection Customers as may 
reasonably become necessary consistent with Good Utility Practice 
during the course of the Affected System Study.
    5.0 The Affected System Study shall provide the following 
information:

[[Page 61297]]

--identification of any circuit breaker short circuit capability 
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations 
resulting from the interconnection;
--identification of any instability or inadequately damped response 
to system disturbances resulting from the interconnection;
--non-binding, good faith estimated cost and time required to 
construct facilities required on Transmission Provider's 
Transmission System to accommodate the interconnection of the 
{generating facilities{time}  to the transmission system of the host 
transmission provider; and
--description of how such facilities will address the identified 
short circuit, instability, and power flow issues.

    6.0 Affected System Interconnection Customers shall each provide 
a deposit of __ for performance of the Affected System Study. Upon 
receipt of the results of the Affected System Study by the Affected 
System Interconnection Customers, Transmission Provider shall 
charge, and Affected System Interconnection Customers shall pay, the 
actual cost of the Affected System Study. Any difference between the 
deposit and the actual cost of the Affected System Study shall be 
paid by or refunded to Affected System Interconnection Customers, as 
appropriate, including interest calculated in accordance with 
section 35.19a(a)(2) of FERC's regulations.
    7.0 This Agreement shall include standard miscellaneous terms 
including, but not limited to, indemnities, representations, 
disclaimers, warranties, governing law, amendment, execution, 
waiver, enforceability, and assignment, which reflect best practices 
in the electric industry, that are consistent with regional 
practices, Applicable Laws and Regulations, and the organizational 
nature of each Party. All of these provisions, to the extent 
practicable, shall be consistent with the provisions of the LGIP.
    In witness thereof, the Parties have caused this Agreement to be 
duly executed by their duly authorized officers or agents on the day 
and year first above written.

{Insert name of Transmission Provider{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

{Insert name of Affected System Interconnection Customer{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Project No.------------------------------------------------------------

{Insert name of Affected System Interconnection Customer{time} 

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Project No.------------------------------------------------------------

Attachment A to Appendix 10--Multiparty Affected System Study Agreement

Assumptions Used in Conducting the Multiparty Affected System Study

    The Affected System Study will be based upon the following 
assumptions: {Assumptions to be completed by Affected System 
Interconnection Customers and Transmission Provider{time} 

Appendix 11 to LGIP

Two-Party Affected System Facilities Construction Agreement

    This Agreement is made and entered into this __ day of ______, 
20__, by and between ______, organized and existing under the laws 
of the State of ______ (Affected System Interconnection Customer) 
and ______, an entity organized under the laws of the State of 
______ (Transmission Provider). Affected System Interconnection 
Customer and Transmission Provider each may be referred to as a 
``Party'' or collectively as the ``Parties.''

Recitals

    Whereas, Affected System Interconnection Customer is proposing 
to develop a {description of generating facility or generating 
capacity addition to an existing generating facility{time}  
consistent with the interconnection request submitted by Affected 
System Interconnection Customer to {name of host transmission 
provider{time} , dated ______, for which {name of host transmission 
provider{time}  found impacts on Transmission Provider's 
Transmission System; and
    Whereas, Affected System Interconnection Customer desires to 
interconnect the {generating facility{time}  to {name of host 
transmission provider{time} 's transmission system; and
    Whereas, additions, modifications, and upgrade(s) must be made 
to certain existing facilities of Transmission Provider's 
Transmission System to accommodate such interconnection; and
    Whereas, Affected System Interconnection Customer has requested, 
and Transmission Provider has agreed, to enter into this Agreement 
for the purpose of facilitating the construction of necessary 
Affected System Network Upgrade(s);
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agree as follows:

Article 1--Definitions

    When used in this Agreement, with initial capitalization, the 
terms specified and not otherwise defined in this Agreement shall 
have the meanings indicated in this LGIP.

Article 2--Term of Agreement

    2.1 Effective Date. This Agreement shall become effective upon 
execution by the Parties subject to acceptance by FERC (if 
applicable), or if filed unexecuted, upon the date specified by 
FERC.
    2.2 Term.
    2.2.1 General. This Agreement shall become effective as provided 
in Article 2.1 and shall continue in full force and effect until the 
earlier of (1) the final repayment, where applicable, by 
Transmission Provider of the amount funded by Affected System 
Interconnection Customer for Transmission Provider's design, 
procurement, construction and installation of the Affected System 
Network Upgrade(s) provided in Appendix A; (2) the Parties agree to 
mutually terminate this Agreement; (3) earlier termination is 
permitted or provided for under Appendix A of this Agreement; or (4) 
Affected System Interconnection Customer terminates this Agreement 
after providing Transmission Provider with written notice at least 
sixty (60) Calendar Days prior to the proposed termination date, 
provided that Affected System Interconnection Customer has no 
outstanding contractual obligations to Transmission Provider under 
this Agreement. No termination of this Agreement shall be effective 
until the Parties have complied with all Applicable Laws and 
Regulations applicable to such termination. The term of this 
Agreement may be adjusted upon mutual agreement of the Parties if 
(1) the commercial operation date for the {generating 
facility{time}  is adjusted in accordance with the rules and 
procedures established by {name of host transmission provider{time}  
or (2) the in-service date for the Affected System Network 
Upgrade(s) is adjusted in accordance with the rules and procedures 
established by Transmission Provider.
    2.2.2 Termination Upon Default. Default shall mean the failure 
of a Breaching Party to cure its Breach in accordance with Article 5 
of this Agreement where Breach and Breaching Party are defined in 
Article 5. Defaulting Party shall mean the Party that is in Default. 
In the event of a Default by a Party, the non-Defaulting Party shall 
have the termination rights described in Articles 5 and 6; provided, 
however, Transmission Provider may not terminate this Agreement if 
Affected System Interconnection Customer is the Defaulting Party and 
compensates Transmission Provider within thirty (30) Calendar Days 
for the amount of damages billed to Affected System Interconnection 
Customer by Transmission Provider for any such damages, including 
costs and expenses, incurred by Transmission Provider as a result of 
such Default.
    2.2.3 Consequences of Termination. In the event of a termination 
by either Party, other than a termination by Affected System 
Interconnection Customer due to a Default by Transmission Provider, 
Affected System Interconnection Customer shall be responsible for 
the payment to Transmission Provider of all amounts then due and 
payable for construction and installation of the Affected System 
Network Upgrade(s) (including, without limitation, any equipment 
ordered related to such construction), plus all out-of-pocket 
expenses incurred by Transmission Provider in connection with the 
construction and installation of the Affected System Network 
Upgrade(s), through the date of termination, and, in the event of 
the termination of the entire Agreement, any actual costs which 
Transmission Provider reasonably incurs in (1) winding up work and 
construction demobilization and (2) ensuring the safety of

[[Page 61298]]

persons and property and the integrity and safe and reliable 
operation of Transmission Provider's Transmission System. 
Transmission Provider shall use Reasonable Efforts to minimize such 
costs.
    2.2.4 Reservation of Rights. Transmission Provider shall have 
the right to make a unilateral filing with FERC to modify this 
Agreement with respect to any rates, terms and conditions, charges, 
classifications of service, rule or regulation under section 205 or 
any other applicable provision of the Federal Power Act and FERC's 
rules and regulations thereunder, and Affected System 
Interconnection Customer shall have the right to make a unilateral 
filing with FERC to modify this Agreement pursuant to section 206 or 
any other applicable provision of the Federal Power Act and FERC's 
rules and regulations thereunder; provided that each Party shall 
have the right to protest any such filing by the other Party and to 
participate fully in any proceeding before FERC in which such 
modifications may be considered. Nothing in this Agreement shall 
limit the rights of the Parties or of FERC under sections 205 or 206 
of the Federal Power Act and FERC's rules and regulations 
thereunder, except to the extent that the Parties otherwise mutually 
agree as provided herein.
    2.3 Filing. Transmission Provider shall file this Agreement (and 
any amendment hereto) with the appropriate Governmental Authority, 
if required. Affected System Interconnection Customer may request 
that any information so provided be subject to the confidentiality 
provisions of Article 8. If Affected System Interconnection Customer 
has executed this Agreement, or any amendment thereto, Affected 
System Interconnection Customer shall reasonably cooperate with 
Transmission Provider with respect to such filing and to provide any 
information reasonably requested by Transmission Provider needed to 
comply with applicable regulatory requirements.
    2.4 Survival. This Agreement shall continue in effect after 
termination, to the extent necessary, to provide for final billings 
and payments and for costs incurred hereunder, including billings 
and payments pursuant to this Agreement; to permit the determination 
and enforcement of liability and indemnification obligations arising 
from acts or events that occurred while this Agreement was in 
effect; and to permit each Party to have access to the lands of the 
other Party pursuant to this Agreement or other applicable 
agreements, to disconnect, remove, or salvage its own facilities and 
equipment.
    2.5 Termination Obligations. Upon any termination pursuant to 
this Agreement, Affected System Interconnection Customer shall be 
responsible for the payment of all costs or other contractual 
obligations incurred prior to the termination date, including 
previously incurred capital costs, penalties for early termination, 
and costs of removal and site restoration.

Article 3--Construction of Affected System Network Upgrade(s)

    3.1 Construction.
    3.1.1 Transmission Provider Obligations. Transmission Provider 
shall (or shall cause such action to) design, procure, construct, 
and install, and Affected System Interconnection Customer shall pay, 
consistent with Article 3.2, the costs of all Affected System 
Network Upgrade(s) identified in Appendix A. All Affected System 
Network Upgrade(s) designed, procured, constructed, and installed by 
Transmission Provider pursuant to this Agreement shall satisfy all 
requirements of applicable safety and/or engineering codes and 
comply with Good Utility Practice, and further, shall satisfy all 
Applicable Laws and Regulations. Transmission Provider shall not be 
required to undertake any action which is inconsistent with its 
standard safety practices, its material and equipment 
specifications, its design criteria and construction procedures, its 
labor agreements, or any Applicable Laws and Regulations.
    3.1.2 Suspension of Work.
    3.1.2.1 Right to Suspend. Affected System Interconnection 
Customer must provide to Transmission Provider written notice of its 
request for suspension. Only the milestones described in the 
Appendices of this Agreement are subject to suspension under this 
Article 3.1.2. Affected System Network Upgrade(s) will be 
constructed on the schedule described in the Appendices of this 
Agreement unless: (1) construction is prevented by the order of a 
Governmental Authority; (2) the Affected System Network Upgrade(s) 
are not needed by any other Interconnection Customer; or (3) 
Transmission Provider determines that a Force Majeure event prevents 
construction. In the event of (1), (2), or (3), any security paid to 
Transmission Provider under Article 4.1 of this Agreement shall be 
released by Transmission Provider upon the determination by 
Transmission Provider that the Affected System Network Upgrade(s) 
will no longer be constructed. If suspension occurs, Affected System 
Interconnection Customer shall be responsible for the costs which 
Transmission Provider incurs (i) in accordance with this Agreement 
prior to the suspension; (ii) in suspending such work, including any 
costs incurred to perform such work as may be necessary to ensure 
the safety of persons and property and the integrity of Transmission 
Provider's Transmission System and, if applicable, any costs 
incurred in connection with the cancellation of contracts and orders 
for material which Transmission Provider cannot reasonably avoid; 
and (iii) reasonably incurs in winding up work and construction 
demobilization; provided, however, that, prior to canceling any such 
contracts or orders, Transmission Provider shall obtain Affected 
System Interconnection Customer's authorization. Affected System 
Interconnection Customer shall be responsible for all costs incurred 
in connection with Affected System Interconnection Customer's 
failure to authorize cancellation of such contracts or orders.
    Interest on amounts paid by Affected System Interconnection 
Customer to Transmission Provider for the design, procurement, 
construction, and installation of the Affected System Network 
Upgrade(s) shall not accrue during periods in which Affected System 
Interconnection Customer has suspended construction under this 
Article 3.1.2.
    Transmission Provider shall invoice Affected System 
Interconnection Customer pursuant to Article 4 and will use 
Reasonable Efforts to minimize its costs. In the event Affected 
System Interconnection Customer suspends work by Affected System 
Transmission Provider required under this Agreement pursuant to this 
Article 3.1.2.1, and has not requested Affected System Transmission 
Provider to recommence the work required under this Agreement on or 
before the expiration of three (3) years following commencement of 
such suspension, this Agreement shall be deemed terminated. The 
three-year period shall begin on the date the suspension is 
requested, or the date of the written notice to Affected System 
Transmission Provider, whichever is earlier, if no effective date of 
suspension is specified.
    3.1.2.2 Recommencing of Work. If Affected System Interconnection 
Customer requests that Transmission Provider recommence construction 
of Affected System Network Upgrade(s), Transmission Provider shall 
have no obligation to afford such work the priority it would have 
had but for the prior actions of Affected System Interconnection 
Customer to suspend the work. In such event, Affected System 
Interconnection Customer shall be responsible for any costs incurred 
in recommencing the work. All recommenced work shall be completed 
pursuant to an amended schedule for the interconnection agreed to by 
the Parties. Transmission Provider has the right to conduct a 
restudy of the Affected System Study if conditions have materially 
changed subsequent to the request to suspend. Affected System 
Interconnection Customer shall be responsible for the costs of any 
studies or restudies required.
    3.1.2.3 Right to Suspend Due to Default. Transmission Provider 
reserves the right, upon written notice to Affected System 
Interconnection Customer, to suspend, at any time, work by 
Transmission Provider due to Default by Affected System 
Interconnection Customer. Affected System Interconnection Customer 
shall be responsible for any additional expenses incurred by 
Transmission Provider associated with the construction and 
installation of the Affected System Network Upgrade(s) (as set forth 
in Article 2.2.3) upon the occurrence of either a Breach that 
Affected System Interconnection Customer is unable to cure-pursuant 
to Article 5 or a Default pursuant to Article 5. Any form of 
suspension by Transmission Provider shall not be barred by Articles 
2.2.2, 2.2.3, or 5.2.2, nor shall it affect Transmission Provider's 
right to terminate the work or this Agreement pursuant to Article 6.
    3.1.3 Construction Status. Transmission Provider shall keep 
Affected System Interconnection Customer advised periodically as to 
the progress of its design, procurement and construction efforts, as 
described in Appendix A. Affected System Interconnection Customer 
may, at any time

[[Page 61299]]

and reasonably, request a progress report from Transmission 
Provider. If, at any time, Affected System Interconnection Customer 
determines that the completion of the Affected System Network 
Upgrade(s) will not be required until after the specified in-service 
date, Affected System Interconnection Customer will provide written 
notice to Transmission Provider of such later date upon which the 
completion of the Affected System Network Upgrade(s) would be 
required. Transmission Provider may delay the in-service date of the 
Affected System Network Upgrade(s) accordingly.
    3.1.4 Timely Completion. Transmission Provider shall use 
Reasonable Efforts to design, procure, construct, install, and test 
the Affected System Network Upgrade(s) in accordance with the 
schedule set forth in Appendix A, which schedule may be revised from 
time to time by mutual agreement of the Parties. If any event occurs 
that will affect the time or ability to complete the Affected System 
Network Upgrade(s), Transmission Provider shall promptly notify 
Affected System Interconnection Customer. In such circumstances, 
Transmission Provider shall, within fifteen (15) Calendar Days of 
such notice, convene a meeting with Affected System Interconnection 
Customer to evaluate the alternatives available to Affected System 
Interconnection Customer. Transmission Provider shall also make 
available to Affected System Interconnection Customer all studies 
and work papers related to the event and corresponding delay, 
including all information that is in the possession of Transmission 
Provider that is reasonably needed by Affected System 
Interconnection Customer to evaluate alternatives, subject to 
confidentiality arrangements consistent with Article 8. Transmission 
Provider shall, at Affected System Interconnection Customer's 
request and expense, use Reasonable Efforts to accelerate its work 
under this Agreement to meet the schedule set forth in Appendix A, 
provided that (1) Affected System Interconnection Customer 
authorizes such actions, such authorization to be withheld, 
conditioned, or delayed by Affected System Interconnection Customer 
only if it can demonstrate that the acceleration would have a 
material adverse effect on it; and (2) the Affected System 
Interconnection Customer funds costs associated therewith in 
advance.
    3.2 Interconnection Costs.
    3.2.1 Costs. Affected System Interconnection Customer shall pay 
to Transmission Provider costs (including taxes and financing costs) 
associated with seeking and obtaining all necessary approvals and of 
designing, engineering, constructing, and testing the Affected 
System Network Upgrade(s), as identified in Appendix A, in 
accordance with the cost recovery method provided herein. Unless 
Transmission Provider elects to fund the Affected System Network 
Upgrade(s), they shall be initially funded by Affected System 
Interconnection Customer.
    3.2.1.1 Lands of Other Property Owners. If any part of the 
Affected System Network Upgrade(s) is to be installed on property 
owned by persons other than Affected System Interconnection Customer 
or Transmission Provider, Transmission Provider shall, at Affected 
System Interconnection Customer's expense, use efforts similar in 
nature and extent to those that it typically undertakes on its own 
behalf or on behalf of its Affiliates, including use of its eminent 
domain authority to the extent permitted and consistent with 
Applicable Laws and Regulations and, to the extent consistent with 
such Applicable Laws and Regulations, to procure from such persons 
any rights of use, licenses, rights-of-way, and easements that are 
necessary to construct, operate, maintain, test, inspect, replace, 
or remove the Affected System Network Upgrade(s) upon such property.
    3.2.2 Repayment.
    3.2.2.1 Repayment. Consistent with Articles 11.4.1 and 11.4.2 of 
the Transmission Provider's pro forma LGIA, Affected System 
Interconnection Customer shall be entitled to a cash repayment by 
Transmission Provider of the amount paid to Transmission Provider, 
if any, for the Affected System Network Upgrade(s), including any 
tax gross-up or other tax-related payments associated with the 
Affected System Network Upgrade(s), and not refunded to Affected 
System Interconnection Customer pursuant to Article 3.3.1 or 
otherwise. The Parties may mutually agree to a repayment schedule, 
to be outlined in Appendix A, not to exceed twenty (20) years from 
the commercial operation date, for the complete repayment for all 
applicable costs associated with the Affected System Network 
Upgrade(s). Any repayment shall include interest calculated in 
accordance with the methodology set forth in FERC's regulations at 
18 CFR 35.19 a(a)(2)(iii) from the date of any payment for Affected 
System Network Upgrade(s) through the date on which Affected System 
Interconnection Customer receives a repayment of such payment 
pursuant to this subparagraph. Interest shall not accrue during 
periods in which Affected System Interconnection Customer has 
suspended construction pursuant to Article 3.1.2. Affected System 
Interconnection Customer may assign such repayment rights to any 
person.
    3.2.2.2 Impact of Failure to Achieve Commercial Operation. If 
the Affected System Interconnection Customer's generating facility 
fails to achieve commercial operation, but it or another generating 
facility is later constructed and makes use of the Affected System 
Network Upgrade(s), Transmission Provider shall at that time 
reimburse Affected System Interconnection Customer for the amounts 
advanced for the Affected System Network Upgrade(s). Before any such 
reimbursement can occur, Affected System Interconnection Customer 
(or the entity that ultimately constructs the generating facility, 
if different), is responsible for identifying the entity to which 
the reimbursement must be made.
    3.3 Taxes.
    3.3.1 Indemnification for Contributions in Aid of Construction. 
With regard only to payments made by Affected System Interconnection 
Customer to Transmission Provider for the installation of the 
Affected System Network Upgrade(s), Transmission Provider shall not 
include a gross-up for income taxes in the amounts it charges 
Affected System Interconnection Customer for the installation of the 
Affected System Network Upgrade(s) unless (1) Transmission Provider 
has determined, in good faith, that the payments or property 
transfers made by Affected System Interconnection Customer to 
Transmission Provider should be reported as income subject to 
taxation, or (2) any Governmental Authority directs Transmission 
Provider to report payments or property as income subject to 
taxation. Affected System Interconnection Customer shall reimburse 
Transmission Provider for such costs on a fully grossed-up basis, in 
accordance with this Article, within thirty (30) Calendar Days of 
receiving written notification from Transmission Provider of the 
amount due, including detail about how the amount was calculated.
    The indemnification obligation shall terminate at the earlier of 
(1) the expiration of the ten (10)-year testing period and the 
applicable statute of limitation, as it may be extended by 
Transmission Provider upon request of the Internal Revenue Service, 
to keep these years open for audit or adjustment, or (2) the 
occurrence of a subsequent taxable event and the payment of any 
related indemnification obligations as contemplated by this Article. 
Notwithstanding the foregoing provisions of this Article 3.3.1, and 
to the extent permitted by law, to the extent that the receipt of 
such payments by Transmission Provider is determined by any 
Governmental Authority to constitute income by Transmission Provider 
subject to taxation, Affected System Interconnection Customer shall 
protect, indemnify, and hold harmless Transmission Provider and its 
Affiliates, from all claims by any such Governmental Authority for 
any tax, interest, and/or penalties associated with such 
determination. Upon receiving written notification of such 
determination from the Governmental Authority, Transmission Provider 
shall provide Affected System Interconnection Customer with written 
notification within thirty (30) Calendar Days of such determination 
and notification. Transmission Provider, upon the timely written 
request by Affected System Interconnection Customer and at Affected 
System Interconnection Customer's expense, shall appeal, protest, 
seek abatement of, or otherwise oppose such determination. 
Transmission Provider reserves the right to make all decisions with 
regard to the prosecution of such appeal, protest, abatement or 
other contest, including the compromise or settlement of the claim; 
provided that Transmission Provider shall cooperate and consult in 
good faith with Affected System Interconnection Customer regarding 
the conduct of such contest. Affected System Interconnection 
Customer shall not be required to pay Transmission Provider for the 
tax, interest, and/or penalties prior to the seventh (7th) Calendar 
Day before the date on which Transmission Provider (1) is required 
to pay the tax, interest, and/or penalties or other amount in lieu 
thereof pursuant to a compromise or settlement of the appeal, 
protest, abatement, or other contest; (2) is required to pay the 
tax, interest, and/or penalties as the result of a

[[Page 61300]]

final, non-appealable order by a Governmental Authority; or (3) is 
required to pay the tax, interest, and/or penalties as a 
prerequisite to an appeal, protest, abatement, or other contest. In 
the event such appeal, protest, abatement, or other contest results 
in a determination that Transmission Provider is not liable for any 
portion of any tax, interest, and/or penalties for which Affected 
System Interconnection Customer has already made payment to 
Transmission Provider, Transmission Provider shall promptly refund 
to Affected System Interconnection Customer any payment attributable 
to the amount determined to be non-taxable, plus any interest 
(calculated in accordance with 18 CFR 35.19a(a)(2)(iii)) or other 
payments Transmission Provider receives or which Transmission 
Provider may be entitled with respect to such payment. Affected 
System Interconnection Customer shall provide Transmission Provider 
with credit assurances sufficient to meet Affected System 
Interconnection Customer's estimated liability for reimbursement of 
Transmission Provider for taxes, interest, and/or penalties under 
this Article 3.3.1. Such estimated liability shall be stated in 
Appendix A.
    To the extent that Transmission Provider is a limited liability 
company and not a corporation, and has elected to be taxed as a 
partnership, then the following shall apply: Transmission Provider 
represents, and the Parties acknowledge, that Transmission Provider 
is a limited liability company and is treated as a partnership for 
federal income tax purposes. Any payment made by Affected System 
Interconnection Customer to Transmission Provider for Affected 
System Network Upgrade(s) is to be treated as an upfront payment. It 
is anticipated by the Parties that any amounts paid by Affected 
System Interconnection Customer to Transmission Provider for 
Affected System Network Upgrade(s) will be reimbursed to Affected 
System Interconnection Customer in accordance with the terms of this 
Agreement, provided Affected System Interconnection Customer 
fulfills its obligations under this Agreement.
    3.3.2 Private Letter Ruling. At Affected System Interconnection 
Customer's request and expense, Transmission Provider shall file 
with the Internal Revenue Service a request for a private letter 
ruling as to whether any property transferred or sums paid, or to be 
paid, by Affected System Interconnection Customer to Transmission 
Provider under this Agreement are subject to federal income 
taxation. Affected System Interconnection Customer will prepare the 
initial draft of the request for a private letter ruling and will 
certify under penalties of perjury that all facts represented in 
such request are true and accurate to the best of Affected System 
Interconnection Customer's knowledge. Transmission Provider and 
Affected System Interconnection Customer shall cooperate in good 
faith with respect to the submission of such request.
    3.3.3 Other Taxes. Upon the timely request by Affected System 
Interconnection Customer, and at Affected System Interconnection 
Customer's sole expense, Transmission Provider shall appeal, 
protest, seek abatement of, or otherwise contest any tax (other than 
federal or state income tax) asserted or assessed against 
Transmission Provider for which Affected System Interconnection 
Customer may be required to reimburse Transmission Provider under 
the terms of this Agreement. Affected System Interconnection 
Customer shall pay to Transmission Provider on a periodic basis, as 
invoiced by Transmission Provider, Transmission Provider's 
documented reasonable costs of prosecuting such appeal, protest, 
abatement, or other contest. Affected System Interconnection 
Customer and Transmission Provider shall cooperate in good faith 
with respect to any such contest. Unless the payment of such taxes 
is a prerequisite to an appeal or abatement or cannot be deferred, 
no amount shall be payable by Affected System Interconnection 
Customer to Transmission Provider for such taxes until they are 
assessed by a final, non-appealable order by any court or agency of 
competent jurisdiction. In the event that a tax payment is withheld 
and ultimately due and payable after appeal, Affected System 
Interconnection Customer will be responsible for all taxes, interest 
and penalties, other than penalties attributable to any delay caused 
by Transmission Provider. Each Party shall cooperate with the other 
Party to maintain each Party's tax status. Nothing in this Agreement 
is intended to adversely affect any Party's tax-exempt status with 
respect to the issuance of bonds including, but not limited to, 
local furnishing bonds, as described in section 142(f) of the 
Internal Revenue Code.

Article 4

Security, Billing, and Payments

    4.1 Provision of Security. By the earlier of (1) thirty (30) 
Calendar Days prior to the due date for Affected System 
Interconnection Customer's first payment under the payment schedule 
specified in Appendix A, or (2) the first date specified in Appendix 
A for the ordering of equipment by Transmission Provider for 
installing the Affected System Network Upgrade(s), Affected System 
Interconnection Customer shall provide Transmission Provider, at 
Affected System Interconnection Customer's option, a guarantee, a 
surety bond, letter of credit or other form of security that is 
reasonably acceptable to Transmission Provider. Such security for 
payment shall be in an amount sufficient to cover the costs for 
constructing, procuring, and installing the applicable portion of 
Affected System Network Upgrade(s) and shall be reduced on a dollar-
for-dollar basis for payments made to Transmission Provider for 
these purposes.
    The guarantee must be made by an entity that meets the 
creditworthiness requirements of Transmission Provider and contain 
terms and conditions that guarantee payment of any amount that may 
be due from Affected System Interconnection Customer, up to an 
agreed-to maximum amount. The letter of credit must be issued by a 
financial institution reasonably acceptable to Transmission Provider 
and must specify a reasonable expiration date. The surety bond must 
be issued by an insurer reasonably acceptable to Transmission 
Provider and must specify a reasonable expiration date.
    4.2 Invoice. Each Party shall submit to the other Party, on a 
monthly basis, invoices of amounts due, if any, for the preceding 
month. Each invoice shall state the month to which the invoice 
applies and fully describe the services and equipment provided. The 
Parties may discharge mutual debts and payment obligations due and 
owing to each other on the same date through netting, in which case 
all amounts a Party owes to the other Party under this Agreement, 
including interest payments, shall be netted so that only the net 
amount remaining due shall be paid by the owing Party.
    4.3 Payment. Invoices shall be rendered to the paying Party at 
the address specified by the Parties. The Party receiving the 
invoice shall pay the invoice within thirty (30) Calendar Days of 
receipt. All payments shall be made in immediately available funds 
payable to the other Party, or by wire transfer to a bank named and 
account designated by the invoicing Party. Payment of invoices by a 
Party will not constitute a waiver of any rights or claims that 
Party may have under this Agreement.
    4.4 Final Invoice. Within six (6) months after completion of the 
construction of the Affected System Network Upgrade(s), Transmission 
Provider shall provide an invoice of the final cost of the 
construction of the Affected System Network Upgrade(s) and shall set 
forth such costs in sufficient detail to enable Affected System 
Interconnection Customer to compare the actual costs with the 
estimates and to ascertain deviations, if any, from the cost 
estimates. Transmission Provider shall refund, with interest 
(calculated in accordance with 18 CFR 35.19a(a)(2)(iii)), to 
Affected System Interconnection Customer any amount by which the 
actual payment by Affected System Interconnection Customer for 
estimated costs exceeds the actual costs of construction within 
thirty (30) Calendar Days of the issuance of such final construction 
invoice.
    4.5 Interest. Interest on any unpaid amounts shall be calculated 
in accordance with 18 CFR 35.19a(a)(2)(iii).
    4.6 Payment During Dispute. In the event of a billing dispute 
among the Parties, Transmission Provider shall continue to construct 
the Affected System Network Upgrade(s) under this Agreement as long 
as Affected System Interconnection Customer: (1) continues to make 
all payments not in dispute; and (2) pays to Transmission Provider 
or into an independent escrow account the portion of the invoice in 
dispute, pending resolution of such dispute. If Affected System 
Interconnection Customer fails to meet these two requirements, then 
Transmission Provider may provide notice to Affected System 
Interconnection Customer of a Default pursuant to Article 5. Within 
thirty (30) Calendar Days after the resolution of the dispute, the 
Party that owes money to another Party shall pay the amount due with 
interest calculated in accordance with the methodology set forth in 
18 CFR 35.19a(a)(2)(iii).

Article 5

Breach, Cure and Default

    5.1 Events of Breach. A Breach of this Agreement shall include 
the:

[[Page 61301]]

    (a) Failure to pay any amount when due;
    (b) Failure to comply with any material term or condition of 
this Agreement, including but not limited to any material Breach of 
a representation, warranty, or covenant made in this Agreement;
    (c) Failure of a Party to provide such access rights, or a 
Party's attempt to revoke access or terminate such access rights, as 
provided under this Agreement; or
    (d) Failure of a Party to provide information or data to another 
Party as required under this Agreement, provided the Party entitled 
to the information or data under this Agreement requires such 
information or data to satisfy its obligations under this Agreement.
    5.2 Definition. Breaching Party shall mean the Party that is in 
Breach.
    5.3 Notice of Breach, Cure, and Default. Upon the occurrence of 
an event of Breach, the Party not in Breach, when it becomes aware 
of the Breach, shall give written notice of the Breach to the 
Breaching Party and to any other person representing a Party to this 
Agreement identified in writing to the other Party in advance. Such 
notice shall set forth, in reasonable detail, the nature of the 
Breach, and where known and applicable, the steps necessary to cure 
such Breach.
    5.3.1 Upon receiving written notice of the Breach hereunder, the 
Breaching Party shall have a period to cure such Breach (hereinafter 
referred to as the ``Cure Period'') which shall be sixty (60) 
Calendar Days.
    5.3.2 In the event the Breaching Party fails to cure within the 
Cure Period, the Breaching Party will be in Default of this 
Agreement, and the non--Defaulting Party may terminate this 
Agreement in accordance with Article 6.2 of this Agreement or take 
whatever action at law or in equity as may appear necessary or 
desirable to enforce the performance or observance of any rights, 
remedies, obligations, agreement, or covenants under this Agreement.
    5.4 Rights in the Event of Default. Notwithstanding the 
foregoing, upon the occurrence of a Default, the non-Defaulting 
Party shall be entitled to exercise all rights and remedies it may 
have in equity or at law.

Article 6

Termination of Agreement

    6.1 Expiration of Term. Except as otherwise specified in this 
Article 6, the Parties' obligations under this Agreement shall 
terminate at the conclusion of the term of this Agreement.
    6.2 Termination. In addition to the termination provisions set 
forth in Article 2.2, a Party may terminate this Agreement upon the 
Default of the other Party in accordance with Article 5.2.2 of this 
Agreement. Subject to the limitations set forth in Article 6.3, in 
the event of a Default, the termination of this Agreement by the 
non-Defaulting Party shall require a filing at FERC of a notice of 
termination, which filing must be accepted for filing by FERC.
    6.3 Disposition of Facilities Upon Termination of Agreement.
    6.3.1 Transmission Provider Obligations. Upon termination of 
this Agreement, unless otherwise agreed to by the Parties in 
writing, Transmission Provider:
    (a) shall, prior to the construction and installation of any 
portion of the Affected System Network Upgrade(s) and to the extent 
possible, cancel any pending orders of, or return, such equipment or 
material for such Affected System Network Upgrade(s);
    (b) may keep in place any portion of the Affected System Network 
Upgrade(s) already constructed and installed; and,
    (c) shall perform such work as may be necessary to ensure the 
safety of persons and property and to preserve the integrity of 
Transmission Provider's Transmission System (e.g., construction 
demobilization to return the system to its original state, wind-up 
work).
    6.3.2 Affected System Interconnection Customer Obligations. Upon 
billing by Transmission Provider, Affected System Interconnection 
Customer shall reimburse Transmission Provider for any costs 
incurred by Transmission Provider in performance of the actions 
required or permitted by Article 6.3.1 and for the cost of any 
Affected System Network Upgrade(s) described in Appendix A. 
Transmission Provider shall use Reasonable Efforts to minimize costs 
and shall offset the amounts owed by any salvage value of 
facilities, if applicable. Affected System Interconnection Customer 
shall pay these costs pursuant to Article 4.3 of this Agreement.
    6.3.3 Pre-construction or Installation. Upon termination of this 
Agreement and prior to the construction and installation of any 
portion of the Affected System Network Upgrade(s), Transmission 
Provider may, at its option, retain any portion of such Affected 
System Network Upgrade(s) not cancelled or returned in accordance 
with Article 6.3.1(a), in which case Transmission Provider shall be 
responsible for all costs associated with procuring such Affected 
System Network Upgrade(s). To the extent that Affected System 
Interconnection Customer has already paid Transmission Provider for 
any or all of such costs, Transmission Provider shall refund 
Affected System Interconnection Customer for those payments. If 
Transmission Provider elects to not retain any portion of such 
facilities, Transmission Provider shall convey and make available to 
Affected System Interconnection Customer such facilities as soon as 
practicable after Affected System Interconnection Customer's payment 
for such facilities.
    6.4 Survival of Rights. Termination or expiration of this 
Agreement shall not relieve either Party of any of its liabilities 
and obligations arising hereunder prior to the date termination 
becomes effective, and each Party may take whatever judicial or 
administrative actions as appear necessary or desirable to enforce 
its rights hereunder. The applicable provisions of this Agreement 
will continue in effect after expiration, or early termination 
hereof to the extent necessary to provide for (1) final billings, 
billing adjustments, and other billing procedures set forth in this 
Agreement; (2) the determination and enforcement of liability and 
indemnification obligations arising from acts or events that 
occurred while this Agreement was in effect; and (3) the 
confidentiality provisions set forth in Article 8.

Article 7

Subcontractors

    7.1 Subcontractors. Nothing in this Agreement shall prevent a 
Party from utilizing the services of subcontractors, as it deems 
appropriate, to perform its obligations under this Agreement; 
provided, however, that each Party shall require its subcontractors 
to comply with all applicable terms and conditions of this Agreement 
in providing such services, and each Party shall remain primarily 
liable to the other Party for the performance of such subcontractor.
    7.1.1 Responsibility of Principal. The creation of any 
subcontract relationship shall not relieve the hiring Party of any 
of its obligations under this Agreement. In accordance with the 
provisions of this Agreement, each Party shall be fully responsible 
to the other Party for the acts or omissions of any subcontractor it 
hires as if no subcontract had been made. Any applicable obligation 
imposed by this Agreement upon a Party shall be equally binding 
upon, and shall be construed as having application to, any 
subcontractor of such Party.
    7.1.2 No Third-Party Beneficiary. Except as may be specifically 
set forth to the contrary herein, no subcontractor or any other 
party is intended to be, nor will it be deemed to be, a third-party 
beneficiary of this Agreement.
    7.1.3 No Limitation by Insurance. The obligations under this 
Article 7 will not be limited in any way by any limitation of any 
insurance policies or coverages, including any subcontractor's 
insurance.

Article 8

Confidentiality

    8.1 Confidentiality. Confidential Information shall include, 
without limitation, all information relating to a Party's 
technology, research and development, business affairs, and pricing, 
and any information supplied to the other Party prior to the 
execution of this Agreement.
    Information is Confidential Information only if it is clearly 
designated or marked in writing as confidential on the face of the 
document, or, if the information is conveyed orally or by 
inspection, if the Party providing the information orally informs 
the Party receiving the information that the information is 
confidential. The Parties shall maintain as confidential any 
information that is provided and identified by a Party as Critical 
Energy Infrastructure Information (CEII), as that term is defined in 
18 CFR 388.113(c).
    Such confidentiality will be maintained in accordance with this 
Article 8. If requested by the receiving Party, the disclosing Party 
shall provide in writing, the basis for asserting that the 
information referred to in this Article warrants confidential 
treatment, and the requesting Party may disclose such writing to the 
appropriate Governmental Authority. Each Party shall be responsible 
for the costs associated with affording confidential treatment to 
its information.
    8.1.1 Term. During the term of this Agreement, and for a period 
of three (3) years after the expiration or termination of this

[[Page 61302]]

Agreement, except as otherwise provided in this Article 8 or with 
regard to CEII, each Party shall hold in confidence and shall not 
disclose to any person Confidential Information. CEII shall be 
treated in accordance with FERC policies and regulations.
    8.1.2 Scope. Confidential Information shall not include 
information that the receiving Party can demonstrate: (1) is 
generally available to the public other than as a result of a 
disclosure by the receiving Party; (2) was in the lawful possession 
of the receiving Party on a non-confidential basis before receiving 
it from the disclosing Party; (3) was supplied to the receiving 
Party without restriction by a non-Party, who, to the knowledge of 
the receiving Party after due inquiry, was under no obligation to 
the disclosing Party to keep such information confidential; (4) was 
independently developed by the receiving Party without reference to 
Confidential Information of the disclosing Party; (5) is, or 
becomes, publicly known, through no wrongful act or omission of the 
receiving Party or Breach of this Agreement; or (6) is required, in 
accordance with Article 8.1.6 of this Agreement, to be disclosed by 
any Governmental Authority or is otherwise required to be disclosed 
by law or subpoena, or is necessary in any legal proceeding 
establishing rights and obligations under this Agreement. 
Information designated as Confidential Information will no longer be 
deemed confidential if the Party that designated the information as 
confidential notifies the receiving Party that it no longer is 
confidential.
    8.1.3 Release of Confidential Information. No Party shall 
release or disclose Confidential Information to any other person, 
except to its Affiliates (limited by the Standards of Conduct 
requirements), subcontractors, employees, agents, consultants, or to 
non-Parties that may be or are considering providing financing to or 
equity participation with Affected System Interconnection Customer, 
or to potential purchasers or assignees of Affected System 
Interconnection Customer, on a need-to-know basis in connection with 
this Agreement, unless such person has first been advised of the 
confidentiality provisions of this Article 8 and has agreed to 
comply with such provisions. Notwithstanding the foregoing, a Party 
providing Confidential Information to any person shall remain 
primarily responsible for any release of Confidential Information in 
contravention of this Article 8.
    8.1.4 Rights. Each Party shall retain all rights, title, and 
interest in the Confidential Information that it discloses to the 
receiving Party. The disclosure by a Party to the receiving Party of 
Confidential Information shall not be deemed a waiver by the 
disclosing Party or any other person or entity of the right to 
protect the Confidential Information from public disclosure.
    8.1.5 Standard of Care. Each Party shall use at least the same 
standard of care to protect Confidential Information it receives as 
it uses to protect its own Confidential Information from 
unauthorized disclosure, publication, or dissemination. Each Party 
may use Confidential Information solely to fulfill its obligations 
to the other Party under this Agreement or its regulatory 
requirements.
    8.1.6 Order of Disclosure. If a court or a Government Authority 
or entity with the right, power, and apparent authority to do so 
requests or requires either Party, by subpoena, oral deposition, 
interrogatories, requests for production of documents, 
administrative order, or otherwise, to disclose Confidential 
Information, that Party shall provide the disclosing Party with 
prompt notice of such request(s) or requirement(s) so that the 
disclosing Party may seek an appropriate protective order or waive 
compliance with the terms of this Agreement. Notwithstanding the 
absence of a protective order or waiver, the Party may disclose such 
Confidential Information which, in the opinion of its counsel, the 
Party is legally compelled to disclose. Each Party will use 
Reasonable Efforts to obtain reliable assurance that confidential 
treatment will be accorded any Confidential Information so 
furnished.
    8.1.7 Termination of Agreement. Upon termination of this 
Agreement for any reason, each Party shall, within ten (10) Business 
Days of receipt of a written request from the other Party, use 
Reasonable Efforts to destroy, erase, or delete (with such 
destruction, erasure, and deletion certified in writing to the 
requesting Party) or return to the requesting Party any and all 
written or electronic Confidential Information received from the 
requesting Party, except that each Party may keep one copy for 
archival purposes, provided that the obligation to treat it as 
Confidential Information in accordance with this Article 8 shall 
survive such termination.
    8.1.8 Remedies. The Parties agree that monetary damages would be 
inadequate to compensate a Party for the other Party's Breach of its 
obligations under this Article 8. Each Party accordingly agrees that 
the disclosing Party shall be entitled to equitable relief, by way 
of injunction or otherwise, if the receiving Party Breaches or 
threatens to Breach its obligations under this Article 8, which 
equitable relief shall be granted without bond or proof of damages, 
and the breaching Party shall not plead in defense that there would 
be an adequate remedy at law. Such remedy shall not be deemed an 
exclusive remedy for the Breach of this Article 8, but it shall be 
in addition to all other remedies available at law or in equity. The 
Parties further acknowledge and agree that the covenants contained 
herein are necessary for the protection of legitimate business 
interests and are reasonable in scope. Neither Party, however, shall 
be liable for indirect, incidental, or consequential or punitive 
damages of any nature or kind resulting from or arising in 
connection with this Article 8.
    8.1.9 Disclosure to FERC, its Staff, or a State Regulatory Body. 
Notwithstanding anything in this Article 8 to the contrary, and 
pursuant to 18 CFR 1b.20, if FERC or its staff, during the course of 
an investigation or otherwise, requests information from a Party 
that is otherwise required to be maintained in confidence pursuant 
to this Agreement, the Party shall provide the requested information 
to FERC or its staff, within the time provided for in the request 
for information. In providing the information to FERC or its staff, 
the Party must, consistent with 18 CFR 388.112, request that the 
information be treated as confidential and non-public by FERC and 
its staff and that the information be withheld from public 
disclosure. Parties are prohibited from notifying the other Party to 
this Agreement prior to the release of the Confidential Information 
to FERC or its staff. The Party shall notify the other Party to the 
Agreement when it is notified by FERC or its staff that a request to 
release Confidential Information has been received by FERC, at which 
time either of the Parties may respond before such information would 
be made public, pursuant to 18 CFR 388.112. Requests from a state 
regulatory body conducting a confidential investigation shall be 
treated in a similar manner if consistent with the applicable state 
rules and regulations.
    8.1.10 Subject to the exception in Article 8.1.9, any 
information that a disclosing Party claims is competitively 
sensitive, commercial, or financial information under this Agreement 
shall not be disclosed by the receiving Party to any person not 
employed or retained by the receiving Party, except to the extent 
disclosure is (1) required by law; (2) reasonably deemed by the 
disclosing Party to be required to be disclosed in connection with a 
dispute between or among the Parties, or the defense of litigation 
or dispute; (3) otherwise permitted by consent of the disclosing 
Party, such consent not to be unreasonably withheld; or (4) 
necessary to fulfill its obligations under this Agreement or as the 
Transmission Provider or a balancing authority, including disclosing 
the Confidential Information to a regional or national reliability 
organization. The Party asserting confidentiality shall notify the 
receiving Party in writing of the information that Party claims is 
confidential. Prior to any disclosures of that Party's Confidential 
Information under this subparagraph, or if any non-Party or 
Governmental Authority makes any request or demand for any of the 
information described in this subparagraph, the Party that received 
the Confidential Information from the disclosing Party agrees to 
promptly notify the disclosing Party in writing and agrees to assert 
confidentiality and cooperate with the disclosing Party in seeking 
to protect the Confidential Information from public disclosure by 
confidentiality agreement, protective order, or other reasonable 
measures.

Article 9

Information Access and Audit Rights

    9.1 Information Access. Each Party shall make available to the 
other Party information necessary to verify the costs incurred by 
the other Party for which the requesting Party is responsible under 
this Agreement and carry out obligations and responsibilities under 
this Agreement, provided that the Parties shall not use such 
information for purposes other than those set forth in this Article 
9.1 and to enforce their rights under this Agreement.
    9.2 Audit Rights. Subject to the requirements of confidentiality 
under Article

[[Page 61303]]

8 of this Agreement, the accounts and records related to the design, 
engineering, procurement, and construction of the Affected System 
Network Upgrade(s) shall be subject to audit during the period of 
this Agreement and for a period of twenty-four (24) months following 
Transmission Provider's issuance of a final invoice in accordance 
with Article 4.4. Affected System Interconnection Customer at its 
expense shall have the right, during normal business hours, and upon 
prior reasonable notice to Transmission Provider, to audit such 
accounts and records. Any audit authorized by this Article 9.2 shall 
be performed at the offices where such accounts and records are 
maintained and shall be limited to those portions of such accounts 
and records that relate to obligations under this Agreement.

Article 10

Notices

    10.1 General. Any notice, demand, or request required or 
permitted to be given by a Party to the other Party, and any 
instrument required or permitted to be tendered or delivered by a 
Party in writing to another Party, may be so given, tendered, or 
delivered, as the case may be, by depositing the same with the 
United States Postal Service with postage prepaid, for transmission 
by certified or registered mail, addressed to the Parties, or 
personally delivered to the Parties, at the address set out below:

To Transmission Provider:
To Affected System Interconnection Customer:

    10.2 Billings and Payments. Billings and payments shall be sent 
to the addresses shown in Article 10.1 unless otherwise agreed to by 
the Parties.
    10.3 Alternative Forms of Notice. Any notice or request required 
or permitted to be given by a Party to the other Party and not 
required by this Agreement to be given in writing may be so given by 
telephone, facsimile or email to the telephone numbers and email 
addresses set out below:

To Transmission Provider:
To Affected System Interconnection Customer:

    10.4 Execution and Filing. Affected System Interconnection 
Customer shall either: (i) execute two originals of this tendered 
Agreement and return them to Transmission Provider; or (ii) request 
in writing that Transmission Provider file with FERC this Agreement 
in unexecuted form. As soon as practicable, but not later than ten 
(10) Business Days after receiving either the two executed originals 
of this tendered Agreement (if it does not conform with a FERC-
approved standard form of this Agreement) or the request to file 
this Agreement unexecuted, Transmission Provider shall file this 
Agreement with FERC, together with its explanation of any matters as 
to which Affected System Interconnection Customer and Transmission 
Provider disagree and support for the costs that Transmission 
Provider proposes to charge to Affected System Interconnection 
Customer under this Agreement. An unexecuted version of this 
Agreement should contain terms and conditions deemed appropriate by 
Transmission Provider for the Affected System Interconnection 
Customer's generating facility. If the Parties agree to proceed with 
design, procurement, and construction of facilities and upgrades 
under the agreed-upon terms of the unexecuted version of this 
Agreement, they may proceed pending FERC action.

Article 11

Miscellaneous

    11.1 This Agreement shall include standard miscellaneous terms 
including, but not limited to, indemnities, representations, 
disclaimers, warranties, governing law, amendment, execution, 
waiver, enforceability and assignment, which reflect best practices 
in the electric industry, that are consistent with regional 
practices, Applicable Laws and Regulations and the organizational 
nature of each Party. All of these provisions, to the extent 
practicable, shall be consistent with the provisions of this LGIP.

[Signature Page to Follow]
    In witness whereof, the Parties have executed this Agreement in 
multiple originals, each of which shall constitute and be an 
original Agreement among the Parties.

Transmission Provider
{Transmission Provider{time} 

By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------

Affected System Interconnection Customer

{Affected System Interconnection Customer{time} 
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------
Project No.__

Attachment A to Appendix 11

Two-Party Affected System Facilities Construction Agreement

Affected System Network Upgrade(s), Cost Estimates and Responsibility, 
Construction Schedule and Monthly Payment Schedule

    This Appendix A is a part of the Affected System Facilities 
Construction Agreement between Affected System Interconnection 
Customer and Transmission Provider.
    1.1 Affected System Network Upgrade(s) to be installed by 
Transmission Provider.

{description{time} 

    1.2 First Equipment Order (including permitting).

{description{time} 

    1.2.1. Permitting and Land Rights--Transmission Provider 
Affected System Network Upgrade(s)

{description{time} 

    1.3 Construction Schedule. Where applicable, construction of the 
Affected System Network Upgrade(s) is scheduled as follows and will 
be periodically updated as necessary:

         Table 1--Transmission Provider Construction Activities
------------------------------------------------------------------------
                                                      Start
        Milestone number            Description        date     End date
------------------------------------------------------------------------
 
------------------------------------------------------------------------
 
------------------------------------------------------------------------
 
------------------------------------------------------------------------
 
------------------------------------------------------------------------
 
------------------------------------------------------------------------

[[Page 61304]]

    Note: Construction schedule assumes that Transmission Provider 
has obtained final authorizations and security from Affected System 
Interconnection Customer and all necessary permits from Governmental 
Authorities as necessary prerequisites to commence construction of 
any of the Affected System Network Upgrade(s).

    1.4 Payment Schedule.
    1.4.1 Timing of and Adjustments to Affected System 
Interconnection Customer's Payments and Security.

{description{time} 

    1.4.2 Monthly Payment Schedule. Affected System Interconnection 
Customer's payment schedule is as follows.

{description{time} 

  Table 2--Affected System Interconnection Customer's Payment/Security
           Obligations for Affected System Network Upgrade(s).
------------------------------------------------------------------------
          Milestone number                  Description           Date
------------------------------------------------------------------------
                                      .......................
                                      .......................
                                      .......................
                                      .......................
                                      .......................
------------------------------------------------------------------------

    Note: Affected System Interconnection Customer's payment or 
provision of security as provided in this Agreement operates as a 
condition precedent to Transmission Provider's obligations to 
construct any Affected System Network Upgrade(s), and failure to 
meet this schedule will constitute a Breach pursuant to Article 5.1 
of this Agreement.

    1.5 Permits, Licenses, and Authorizations.

{description{time} 

Attachment B to Appendix 11

Two-Party Affected System Facilities Construction Agreement

Notification of Completed Construction

    This Appendix B is a part of the Affected System Facilities 
Construction Agreement between Affected System Interconnection 
Customer and Transmission Provider. Where applicable, when 
Transmission Provider has completed construction of the Affected 
System Network Upgrade(s), Transmission Provider shall send notice 
to Affected System Interconnection Customer in substantially the 
form following:

{Date{time} 
{Affected System Interconnection Customer Address{time} 
Re: Completion of Affected System Network Upgrade(s)
Dear {Name or Title{time} :

    This letter is sent pursuant to the Affected System Facilities 
Construction Agreement between {Transmission Provider{time}  and 
{Affected System Interconnection Customer{time} , dated ______, 
20__.
    On {Date{time} , Transmission Provider completed to its 
satisfaction all work on the Affected System Network Upgrade(s) 
required to facilitate the safe and reliable interconnection and 
operation of Affected System Interconnection Customer's {description 
of generating facility{time} . Transmission Provider confirms that 
the Affected System Network Upgrade(s) are in place.

Thank you.

    {Signature{time} 
{Transmission Provider Representative{time} 

Attachment C to Appendix 11

Two-Party Affected System Facilities Construction Agreement

Exhibits

    This Appendix C is a part of the Affected System Facilities 
Construction Agreement among Affected System Interconnection 
Customer and Transmission Provider.

Exhibit A1

Transmission Provider Site Map

Exhibit A2

Site Plan

Exhibit A3

Affected System Network Upgrade(s) Plan & Profile

Exhibit A4

Estimated Cost of Affected System Network Upgrade(s)

------------------------------------------------------------------------
                                             Facilities to
                                             be constructed  Estimate in
                                  Location  by transmission    dollars
                                                provider
------------------------------------------------------------------------
 
                                                     Total:
------------------------------------------------------------------------

Appendix 12 to LGIP

Multiparty Affected System Facilities Construction Agreement

    This agreement is made and entered into this ____ day of _____, 
20__ by and among ________, organized and existing under the laws of 
the State of _____ (Affected System Interconnection Customer); 
_____, a _____ organized and existing under the laws of the State of 
_____ (Affected System Interconnection Customer); and _____, an 
entity organized under the laws of the State of ____ (Transmission 
Provider). Affected System Interconnection Customers and 
Transmission Provider each may be referred to as a ``Party'' or 
collectively as the ``Parties.'' When it is not important to 
differentiate among them, Affected System Interconnection Customers 
each may be referred to as ``Affected System Interconnection 
Customer'' or collectively as ``Affected System Interconnection 
Customers.''

Recitals

    Whereas, Affected System Interconnection Customers are proposing 
to develop {description of generating facilities or generating 
capacity additions to an existing generating facility{time} , 
consistent with the interconnection requests submitted by Affected 
System Interconnection Customers to {name of host transmission 
provider{time} , dated ____, for which {name of host transmission 
provider{time}  found impacts on Transmission Provider's 
Transmission System; and
    Whereas, Affected System Interconnection Customers desire to 
interconnect the {generating facilities{time}  to {name of host 
transmission provider{time} 's transmission system; and
    Whereas, additions, modifications, and upgrade(s) must be made 
to certain existing facilities of Transmission Provider's 
Transmission System to accommodate such interconnection; and
    Whereas, Affected System Interconnection Customers have 
requested, and Transmission Provider has agreed, to enter into this 
Agreement for the purpose of facilitating the construction of 
necessary Affected System Network Upgrade(s);
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, the Parties agree as follows:

Article 1

Definitions

    When used in this Agreement, with initial capitalization, the 
terms specified and not otherwise defined in this Agreement shall 
have the meanings indicated in this LGIP.

Article 2

Term of Agreement

    2.1 Effective Date. This Agreement shall become effective upon 
execution by the Parties subject to acceptance by FERC (if 
applicable), or if filed unexecuted, upon the date specified by 
FERC.
    2.2 Term.
    2.2.1 General. This Agreement shall become effective as provided 
in Article 2.1 and shall continue in full force and effect until the 
earlier of (1) the final repayment, where applicable, by 
Transmission Provider of the amount funded by Affected System 
Interconnection Customers for Transmission Provider's design, 
procurement, construction, and installation of the Affected System 
Network Upgrade(s) provided in Appendix A; (2) the Parties agree to 
mutually terminate this Agreement; (3) earlier termination is 
permitted or provided for under Appendix A of this Agreement; or (4) 
Affected System Interconnection Customers terminate this Agreement 
after providing Transmission Provider with written notice at least 
sixty (60) Calendar Days prior to the proposed termination date, 
provided that Affected System Interconnection Customers have no 
outstanding contractual obligations to Transmission Provider under 
this Agreement. No termination of this Agreement shall be effective 
until the Parties have complied with all Applicable Laws and 
Regulations applicable to such termination. The term of this 
Agreement may be adjusted upon mutual agreement of the Parties if 
the commercial operation date(s) for the {generating 
facilities{time}  is adjusted in accordance with the rules and 
procedures established by {name of host transmission provider{time}  
or the in-service

[[Page 61305]]

date for the Affected System Network Upgrade(s) is adjusted in 
accordance with the rules and procedures established by Transmission 
Provider.
    2.2.2 Termination Upon Default. Default shall mean the failure 
of a Breaching Party to cure its Breach in accordance with Article 5 
of this Agreement where Breach and Breaching Party are defined in 
Article 5. Defaulting Party shall mean the Party that is in Default. 
In the event of a Default by a Party, each non-Defaulting Party 
shall have the termination rights described in Articles 5 and 6; 
provided, however, Transmission Provider may not terminate this 
Agreement if an Affected System Interconnection Customer is the 
Defaulting Party and compensates Transmission Provider within thirty 
(30) Calendar Days for the amount of damages billed to Affected 
System Interconnection Customer(s) by Transmission Provider for any 
such damages, including costs and expenses incurred by Transmission 
Provider as a result of such Default. Notwithstanding the foregoing, 
Default by one or more Affected System Interconnection Customers 
shall not provide the other Affected System Interconnection 
Customer(s), either individually or in concert, with the right to 
terminate the entire Agreement. The non-Defaulting Party/Parties 
may, individually or in concert, initiate the removal of an Affected 
System Interconnection Customer that is a Defaulting Party from this 
Agreement. Transmission Provider shall not terminate this Agreement 
or the participation of any Affected System Interconnection Customer 
without provision being made for Transmission Provider to be fully 
reimbursed for all of its costs incurred under this Agreement.
    2.2.3 Consequences of Termination. In the event of a termination 
by a Party, other than a termination by Affected System 
Interconnection Customer(s) due to a Default by Transmission 
Provider, each Affected System Interconnection Customer whose 
participation in this Agreement is terminated shall be responsible 
for the payment to Transmission Provider of all amounts then due and 
payable for construction and installation of the Affected System 
Network Upgrade(s) (including, without limitation, any equipment 
ordered related to such construction), plus all out-of-pocket 
expenses incurred by Transmission Provider in connection with the 
construction and installation of the Affected System Network 
Upgrade(s), through the date of termination, and, in the event of 
the termination of the entire Agreement, any actual costs which 
Transmission Provider reasonably incurs in (1) winding up work and 
construction demobilization and (2) ensuring the safety of persons 
and property and the integrity and safe and reliable operation of 
Transmission Provider's Transmission System. Transmission Provider 
shall use Reasonable Efforts to minimize such costs. The cost 
responsibility of other Affected System Interconnection Customers 
shall be adjusted, as necessary, based on the payments by an 
Affected System Interconnection Customer that is terminated from the 
Agreement.
    2.2.4 Reservation of Rights. Transmission Provider shall have 
the right to make a unilateral filing with FERC to modify this 
Agreement with respect to any rates, terms and conditions, charges, 
classifications of service, rule or regulation under section 205 or 
any other applicable provision of the Federal Power Act and FERC's 
rules and regulations thereunder, and Affected System 
Interconnection Customers shall have the right to make a unilateral 
filing with FERC to modify this Agreement pursuant to section 206 or 
any other applicable provision of the Federal Power Act and FERC's 
rules and regulations thereunder; provided that each Party shall 
have the right to protest any such filing by the other Party and to 
participate fully in any proceeding before FERC in which such 
modifications may be considered. Nothing in this Agreement shall 
limit the rights of the Parties or of FERC under sections 205 or 206 
of the Federal Power Act and FERC's rules and regulations 
thereunder, except to the extent that the Parties otherwise mutually 
agree as provided herein.
    2.3 Filing. Transmission Provider shall file this Agreement (and 
any amendment hereto) with the appropriate Governmental Authority, 
if required. Affected System Interconnection Customers may request 
that any information so provided be subject to the confidentiality 
provisions of Article 8. Each Affected System Interconnection 
Customer that has executed this Agreement, or any amendment thereto, 
shall reasonably cooperate with Transmission Provider with respect 
to such filing and to provide any information reasonably requested 
by Transmission Provider needed to comply with applicable regulatory 
requirements.
    2.4 Survival. This Agreement shall continue in effect after 
termination, to the extent necessary, to provide for final billings 
and payments and for costs incurred hereunder, including billings 
and payments pursuant to this Agreement; to permit the determination 
and enforcement of liability and indemnification obligations arising 
from acts or events that occurred while this Agreement was in 
effect; and to permit each Party to have access to the lands of the 
other Party pursuant to this Agreement or other applicable 
agreements, to disconnect, remove, or salvage its own facilities and 
equipment.
    2.5 Termination Obligations. Upon any termination pursuant to 
this Agreement or termination of the participation in this Agreement 
of an Affected System Interconnection Customer, each Affected System 
Interconnection Customer shall be responsible for the payment of its 
proportionate share of all costs or other contractual obligations 
incurred prior to the termination date, including previously 
incurred capital costs, penalties for early termination, and costs 
of removal and site restoration. The cost responsibility of the 
other Affected System Interconnection Customers shall be adjusted as 
necessary.

Article 3

Construction of Affected System Network Upgrade(s)

    3.1 Construction.
    3.1.1 Transmission Provider Obligations. Transmission Provider 
shall (or shall cause such action to) design, procure, construct, 
and install, and Affected System Interconnection Customers shall 
pay, consistent with Article 3.2, the costs of all Affected System 
Network Upgrade(s) identified in Appendix A. All Affected System 
Network Upgrade(s) designed, procured, constructed, and installed by 
Transmission Provider pursuant to this Agreement shall satisfy all 
requirements of applicable safety and/or engineering codes and 
comply with Good Utility Practice, and further, shall satisfy all 
Applicable Laws and Regulations. Transmission Provider shall not be 
required to undertake any action which is inconsistent with its 
standard safety practices, its material and equipment 
specifications, its design criteria and construction procedures, its 
labor agreements, or any Applicable Laws and Regulations.
    3.1.2 Suspension of Work.
    3.1.2.1 Right to Suspend. Affected System Interconnection 
Customers must jointly provide to Transmission Provider written 
notice of their request for suspension. Only the milestones 
described in the Appendices of this Agreement are subject to 
suspension under this Article 3.1.2. Affected System Network 
Upgrade(s) will be constructed on the schedule described in the 
Appendices of this Agreement unless: (1) construction is prevented 
by the order of a Governmental Authority; (2) the Affected System 
Network Upgrade(s) are not needed by any other Interconnection 
Customer; or (3) Transmission Provider determines that a Force 
Majeure event prevents construction. In the event of (1), (2), or 
(3), any security paid to Transmission Provider under Article 4.1 of 
this Agreement shall be released by Transmission Provider upon the 
determination by Transmission Provider that the Affected System 
Network Upgrade(s) will no longer be constructed. If suspension 
occurs, Affected System Interconnection Customers shall be 
responsible for the costs which Transmission Provider incurs (i) in 
accordance with this Agreement prior to the suspension; (ii) in 
suspending such work, including any costs incurred to perform such 
work as may be necessary to ensure the safety of persons and 
property and the integrity of Transmission Provider's Transmission 
System and, if applicable, any costs incurred in connection with the 
cancellation of contracts and orders for material which Transmission 
Provider cannot reasonably avoid; and (iii) reasonably incurs in 
winding up work and construction demobilization; provided, however, 
that, prior to canceling any such contracts or orders, Transmission 
Provider shall obtain Affected System Interconnection Customers' 
authorization. Affected System Interconnection Customers shall be 
responsible for all costs incurred in connection with Affected 
System Interconnection Customers' failure to authorize cancellation 
of such contracts or orders.
    Interest on amounts paid by Affected System Interconnection 
Customers to Transmission Provider for the design, procurement, 
construction, and installation of the Affected System Network 
Upgrade(s) shall not accrue during periods in which

[[Page 61306]]

Affected System Interconnection Customers have suspended 
construction under this Article 3.1.2.
    Transmission Provider shall invoice Affected System 
Interconnection Customers pursuant to Article 4 and will use 
Reasonable Efforts to minimize its costs. In the event Affected 
System Interconnection Customers suspend work by Affected System 
Transmission Provider required under this Agreement pursuant to this 
Article 3.1.2.1, and have not requested Affected System Transmission 
Provider to recommence the work required under this Agreement on or 
before the expiration of three (3) years following commencement of 
such suspension, this Agreement shall be deemed terminated. The 
three-year period shall begin on the date the suspension is 
requested, or the date of the written notice to Affected System 
Transmission Provider, whichever is earlier, if no effective date of 
suspension is specified.
    3.1.2.2 Recommencing of Work. If Affected System Interconnection 
Customers request that Transmission Provider recommence construction 
of Affected System Network Upgrade(s), Transmission Provider shall 
have no obligation to afford such work the priority it would have 
had but for the prior actions of Affected System Interconnection 
Customers to suspend the work. In such event, Affected System 
Interconnection Customers shall be responsible for any costs 
incurred in recommencing the work. All recommenced work shall be 
completed pursuant to an amended schedule for the interconnection 
agreed to by the Parties. Transmission Provider has the right to 
conduct a restudy of the Affected System Study if conditions have 
materially changed subsequent to the request to suspend. Affected 
System Interconnection Customers shall be responsible for the costs 
of any studies or restudies required.
    3.1.2.3 Right to Suspend Due to Default. Transmission Provider 
reserves the right, upon written notice to Affected System 
Interconnection Customers, to suspend, at any time, work by 
Transmission Provider due to a Default by Affected System 
Interconnection Customer(s). Defaulting-Affected System 
Interconnection Customer(s) shall be responsible for any additional 
expenses incurred by Transmission Provider associated with the 
construction and installation of the Affected System Network 
Upgrade(s) (as set forth in Article 2.2.3) upon the occurrence of a 
Default pursuant to Article 5. Any form of suspension by 
Transmission Provider shall not be barred by Articles 2.2.2, 2.2.3, 
or 5.2.2, nor shall it affect Transmission Provider's right to 
terminate the work or this Agreement pursuant to Article 6.
    3.1.3 Construction Status. Transmission Provider shall keep 
Affected System Interconnection Customers advised periodically as to 
the progress of its design, procurement, and construction efforts, 
as described in Appendix A. An Affected System Interconnection 
Customer may, at any time and reasonably, request a progress report 
from Transmission Provider. If, at any time, an Affected System 
Interconnection Customer determines that the completion of the 
Affected System Network Upgrade(s) will not be required until after 
the specified in-service date, such Affected System Interconnection 
Customer will provide written notice to all other Parties of such 
later date for which the completion of the Affected System Network 
Upgrade(s) would be required. Transmission Provider may delay the 
in-service date of the Affected System Network Upgrade(s) 
accordingly, but only if agreed to by all other Affected System 
Interconnection Customers.
    3.1.4 Timely Completion. Transmission Provider shall use 
Reasonable Efforts to design, procure, construct, install, and test 
the Affected System Network Upgrade(s) in accordance with the 
schedule set forth in Appendix A, which schedule may be revised from 
time to time by mutual agreement of the Parties. If any event occurs 
that will affect the time or ability to complete the Affected System 
Network Upgrade(s), Transmission Provider shall promptly notify all 
other Parties. In such circumstances, Transmission Provider shall, 
within fifteen (15) Calendar Days of such notice, convene a meeting 
with Affected System Interconnection Customers to evaluate the 
alternatives available to Affected System Interconnection Customers. 
Transmission Provider shall also make available to Affected System 
Interconnection Customers all studies and work papers related to the 
event and corresponding delay, including all information that is in 
the possession of Transmission Provider that is reasonably needed by 
Affected System Interconnection Customers to evaluate alternatives, 
subject to confidentiality arrangements consistent with Article 8. 
Transmission Provider shall, at any Affected System Interconnection 
Customer's request and expense, use Reasonable Efforts to accelerate 
its work under this Agreement to meet the schedule set forth in 
Appendix A, provided that (1) Affected System Interconnection 
Customers jointly authorize such actions, such authorizations to be 
withheld, conditioned, or delayed by a given Affected System 
Interconnection Customer only if it can demonstrate that the 
acceleration would have a material adverse effect on it; and (2) the 
requesting Affected System Interconnection Customer(s) funds the 
costs associated therewith in advance, or all Affected System 
Interconnection Customers agree in advance to fund such costs based 
on such other allocation method as they may adopt.
    3.2 Interconnection Costs.
    3.2.1 Costs. Affected System Interconnection Customers shall pay 
to Transmission Provider costs (including taxes and financing costs) 
associated with seeking and obtaining all necessary approvals and of 
designing, engineering, constructing, and testing the Affected 
System Network Upgrade(s), as identified in Appendix A, in 
accordance with the cost recovery method provided herein. Except as 
expressly otherwise agreed, Affected System Interconnection 
Customers shall be collectively responsible for these costs, based 
on their proportionate share of cost responsibility, as provided in 
Appendix A. Unless Transmission Provider elects to fund the Affected 
System Network Upgrade(s), they shall be initially funded by the 
applicable Affected System Interconnection Customer.
    3.2.1.1 Lands of Other Property Owners. If any part of the 
Affected System Network Upgrade(s) is to be installed on property 
owned by persons other than Affected System Interconnection 
Customers or Transmission Provider, Transmission Provider shall, at 
Affected System Interconnection Customers' expense, use efforts 
similar in nature and extent to those that it typically undertakes 
on its own behalf or on behalf of its Affiliates, including use of 
its eminent domain authority to the extent permitted and consistent 
with Applicable Laws and Regulations and, to the extent consistent 
with such Applicable Laws and Regulations, to procure from such 
persons any rights of use, licenses, rights-of-way, and easements 
that are necessary to construct, operate, maintain, test, inspect, 
replace, or remove the Affected System Network Upgrade(s) upon such 
property.
    3.2.2 Repayment.
    3.2.2.1 Repayment. Consistent with articles 11.4.1 and 11.4.2 of 
the Transmission Provider's pro forma LGIA, each Affected System 
Interconnection Customer shall be entitled to a cash repayment by 
Transmission Provider of the amount each Affected System 
Interconnection Customer paid to Transmission Provider, if any, for 
the Affected System Network Upgrade(s), including any tax gross-up 
or other tax-related payments associated with the Affected System 
Network Upgrade(s), and not refunded to Affected System 
Interconnection Customer pursuant to Article 3.3.1 or otherwise. The 
Parties may mutually agree to a repayment schedule, to be outlined 
in Appendix A, not to exceed twenty (20) years from the commercial 
operation date, for the complete repayment for all applicable costs 
associated with the Affected System Network Upgrade(s). Any 
repayment shall include interest calculated in accordance with the 
methodology set forth in FERC's regulations at 18 CFR 35.19 
a(a)(2)(iii) from the date of any payment for Affected System 
Network Upgrade(s) through the date on which Affected System 
Interconnection Customers receive a repayment of such payment 
pursuant to this subparagraph. Interest shall not accrue during 
periods in which Affected System Interconnection Customers have 
suspended construction pursuant to Article 3.1.2.1. Affected System 
Interconnection Customers may assign such repayment rights to any 
person.
    3.2.2.2 Impact of Failure to Achieve Commercial Operation. If an 
Affected System Interconnection Customer's generating facility fails 
to achieve commercial operation, but it or another generating 
facility is later constructed and makes use of the Affected System 
Network Upgrade(s), Transmission Provider shall at that time 
reimburse such Affected System Interconnection Customers for the 
portion of the Affected System Network Upgrade(s) it funded. Before 
any such reimbursement can occur, Affected System Interconnection 
Customer (or the entity that ultimately constructs the generating 
facility, if different),

[[Page 61307]]

is responsible for identifying the entity to which the reimbursement 
must be made.
    3.3 Taxes.
    3.3.1 Indemnification for Contributions in Aid of Construction. 
With regard only to payments made by Affected System Interconnection 
Customers to Transmission Provider for the installation of the 
Affected System Network Upgrade(s), Transmission Provider shall not 
include a gross-up for income taxes in the amounts it charges 
Affected System Interconnection Customers for the installation of 
the Affected System Network Upgrade(s) unless (1) Transmission 
Provider has determined, in good faith, that the payments or 
property transfers made by Affected System Interconnection Customers 
to Transmission Provider should be reported as income subject to 
taxation, or (2) any Governmental Authority directs Transmission 
Provider to report payments or property as income subject to 
taxation. Affected System Interconnection Customers shall reimburse 
Transmission Provider for such costs on a fully grossed-up basis, in 
accordance with this Article, within thirty (30) Calendar Days of 
receiving written notification from Transmission Provider of the 
amount due, including detail about how the amount was calculated.
    The indemnification obligation shall terminate at the earlier of 
(1) the expiration of the ten (10)-year testing period and the 
applicable statute of limitation, as it may be extended by 
Transmission Provider upon request of the Internal Revenue Service, 
to keep these years open for audit or adjustment, or (2) the 
occurrence of a subsequent taxable event and the payment of any 
related indemnification obligations as contemplated by this Article. 
Notwithstanding the foregoing provisions of this Article 3.3.1, and 
to the extent permitted by law, to the extent that the receipt of 
such payments by Transmission Provider is determined by any 
Governmental Authority to constitute income by Transmission Provider 
subject to taxation, Affected System Interconnection Customers shall 
protect, indemnify, and hold harmless Transmission Provider and its 
Affiliates, from all claims by any such Governmental Authority for 
any tax, interest, and/or penalties associated with such 
determination. Upon receiving written notification of such 
determination from the Governmental Authority, Transmission Provider 
shall provide Affected System Interconnection Customers with written 
notification within thirty (30) Calendar Days of such determination 
and notification. Transmission Provider, upon the timely written 
request by any one or more Affected System Interconnection 
Customer(s) and at the expense of such Affected System 
Interconnection Customer(s), shall appeal, protest, seek abatement 
of, or otherwise oppose such determination. Transmission Provider 
reserves the right to make all decisions with regard to the 
prosecution of such appeal, protest, abatement or other contest, 
including the compromise or settlement of the claim; provided that 
Transmission Provider shall cooperate and consult in good faith with 
the requesting Affected System Interconnection Customer(s) regarding 
the conduct of such contest. Affected System Interconnection 
Customer(s) shall not be required to pay Transmission Provider for 
the tax, interest, and/or penalties prior to the seventh (7th) 
Calendar Day before the date on which Transmission Provider (1) is 
required to pay the tax, interest, and/or penalties or other amount 
in lieu thereof pursuant to a compromise or settlement of the 
appeal, protest, abatement, or other contest; (2) is required to pay 
the tax, interest, and/or penalties as the result of a final, non-
appealable order by a Governmental Authority; or (3) is required to 
pay the tax, interest, and/or penalties as a prerequisite to an 
appeal, protest, abatement, or other contest. In the event such 
appeal, protest, abatement, or other contest results in a 
determination that Transmission Provider is not liable for any 
portion of any tax, interest, and/or penalties for which any 
Affected System Interconnection Customer(s) has already made payment 
to Transmission Provider, Transmission Provider shall promptly 
refund to such Affected System Interconnection Customer(s) any 
payment attributable to the amount determined to be non-taxable, 
plus any interest (calculated in accordance with 18 CFR 
35.19a(a)(2)(iii)) or other payments Transmission Provider receives 
or to which Transmission Provider may be entitled with respect to 
such payment. Each Affected System Interconnection Customer shall 
provide Transmission Provider with credit assurances sufficient to 
meet each Affected System Interconnection Customer's estimated 
liability for reimbursement of Transmission Provider for taxes, 
interest, and/or penalties under this Article 3.3.1. Such estimated 
liability shall be stated in Appendix A.
    To the extent that Transmission Provider is a limited liability 
company and not a corporation, and has elected to be taxed as a 
partnership, then the following shall apply: Transmission Provider 
represents, and the Parties acknowledge, that Transmission Provider 
is a limited liability company and is treated as a partnership for 
federal income tax purposes. Any payment made by Affected System 
Interconnection Customers to Transmission Provider for Affected 
System Network Upgrade(s) is to be treated as an upfront payment. It 
is anticipated by the Parties that any amounts paid by each Affected 
System Interconnection Customer to Transmission Provider for 
Affected System Network Upgrade(s) will be reimbursed to such 
Affected System Interconnection Customer in accordance with the 
terms of this Agreement, provided such Affected System 
Interconnection Customer fulfills its obligations under this 
Agreement.
    3.3.2 Private Letter Ruling. At the request and expense of any 
Affected System Interconnection Customer(s), Transmission Provider 
shall file with the Internal Revenue Service a request for a private 
letter ruling as to whether any property transferred or sums paid, 
or to be paid, by such Affected System Interconnection Customer(s) 
to Transmission Provider under this Agreement are subject to federal 
income taxation. Each Affected System Interconnection Customer 
desiring such a request will prepare the initial draft of the 
request for a private letter ruling and will certify under penalties 
of perjury that all facts represented in such request are true and 
accurate to the best of such Affected System Interconnection 
Customer's knowledge. Transmission Provider and such Affected System 
Interconnection Customer(s) shall cooperate in good faith with 
respect to the submission of such request.
    3.3.3 Other Taxes. Upon the timely request by any one or more 
Affected System Interconnection Customer(s), and at such Affected 
System Interconnection Customer(s)' sole expense, Transmission 
Provider shall appeal, protest, seek abatement of, or otherwise 
contest any tax (other than federal or state income tax) asserted or 
assessed against Transmission Provider for which such Affected 
System Interconnection Customer(s) may be required to reimburse 
Transmission Provider under the terms of this Agreement. Affected 
System Interconnection Customer(s) who requested the action shall 
pay to Transmission Provider on a periodic basis, as invoiced by 
Transmission Provider, Transmission Provider's documented reasonable 
costs of prosecuting such appeal, protest, abatement, or other 
contest. The requesting Affected System Interconnection Customer(s) 
and Transmission Provider shall cooperate in good faith with respect 
to any such contest. Unless the payment of such taxes is a 
prerequisite to an appeal or abatement or cannot be deferred, no 
amount shall be payable by Affected System Interconnection 
Customer(s) to Transmission Provider for such taxes until they are 
assessed by a final, non-appealable order by any court or agency of 
competent jurisdiction. In the event that a tax payment is withheld 
and ultimately due and payable after appeal, Affected System 
Interconnection Customer(s) will be responsible for all taxes, 
interest, and penalties, other than penalties attributable to any 
delay caused by Transmission Provider. Each Party shall cooperate 
with the other Party to maintain each Party's tax status. Nothing in 
this Agreement is intended to adversely affect any Party's tax-
exempt status with respect to the issuance of bonds including, but 
not limited to, local furnishing bonds, as described in section 
142(f) of the Internal Revenue Code.

Article 4

Security, Billing, and Payments

    4.1 Provision of Security. By the earlier of (1) thirty (30) 
Calendar Days prior to the due date for each Affected System 
Interconnection Customer's first payment under the payment schedule 
specified in Appendix A, or (2) the first date specified in Appendix 
A for the ordering of equipment by Transmission Provider for 
installing the Affected System Network Upgrade(s), each Affected 
System Interconnection Customer shall provide Transmission Provider, 
at each Affected System Interconnection Customer's option, a 
guarantee, a surety bond, letter of credit, or other form of 
security that is reasonably acceptable to Transmission Provider. 
Such security for payment shall be in an amount sufficient to cover 
the costs for constructing, procuring, and installing the applicable 
portion of Affected System Network Upgrade(s) and shall be reduced 
on a dollar-for-dollar basis for payments made to Transmission 
Provider for these purposes.

[[Page 61308]]

    The guarantee must be made by an entity that meets the 
creditworthiness requirements of Transmission Provider and contain 
terms and conditions that guarantee payment of any amount that may 
be due from such Affected System Interconnection Customer, up to an 
agreed-to maximum amount. The letter of credit must be issued by a 
financial institution reasonably acceptable to Transmission Provider 
and must specify a reasonable expiration date. The surety bond must 
be issued by an insurer reasonably acceptable to Transmission 
Provider and must specify a reasonable expiration date.
    4.2 Invoice. Each Party shall submit to the other Parties, on a 
monthly basis, invoices of amounts due, if any, for the preceding 
month. Each invoice shall state the month to which the invoice 
applies and fully describe the services and equipment provided. The 
Parties may discharge mutual debts and payment obligations due and 
owing to each other on the same date through netting, in which case 
all amounts a Party owes to another Party under this Agreement, 
including interest payments, shall be netted so that only the net 
amount remaining due shall be paid by the owing Party.
    4.3 Payment. Invoices shall be rendered to the paying Party at 
the address specified by the Parties. The Party receiving the 
invoice shall pay the invoice within thirty (30) Calendar Days of 
receipt. All payments shall be made in immediately available funds 
payable to the other Party, or by wire transfer to a bank named and 
account designated by the invoicing Party. Payment of invoices by a 
Party will not constitute a waiver of any rights or claims that 
Party may have under this Agreement.
    4.4 Final Invoice. Within six (6) months after completion of the 
construction of the Affected System Network Upgrade(s) Transmission 
Provider shall provide an invoice of the final cost of the 
construction of the Affected System Network Upgrade(s) and shall set 
forth such costs in sufficient detail to enable each Affected System 
Interconnection Customer to compare the actual costs with the 
estimates and to ascertain deviations, if any, from the cost 
estimates. Transmission Provider shall refund, with interest 
(calculated in accordance with 18 CFR 35.19a(a)(2)(iii)), to each 
Affected System Interconnection Customer any amount by which the 
actual payment by Affected System Interconnection Customer for 
estimated costs exceeds the actual costs of construction within 
thirty (30) Calendar Days of the issuance of such final construction 
invoice.
    4.5 Interest. Interest on any unpaid amounts shall be calculated 
in accordance with 18 CFR 35.19a(a)(2)(iii).
    4.6 Payment During Dispute. In the event of a billing dispute 
among the Parties, Transmission Provider shall continue to construct 
the Affected System Network Upgrade(s) under this Agreement as long 
as each Affected System Interconnection Customer: (1) continues to 
make all payments not in dispute; and (2) pays to Transmission 
Provider or into an independent escrow account the portion of the 
invoice in dispute, pending resolution of such dispute. If any 
Affected System Interconnection Customer fails to meet these two 
requirements, then Transmission Provider may provide notice to such 
Affected System Interconnection Customer of a Default pursuant to 
Article 5. Within thirty (30) Calendar Days after the resolution of 
the dispute, the Party that owes money to another Party shall pay 
the amount due with interest calculated in accordance with the 
methodology set forth in 18 CFR 35.19a(a)(2)(iii).

Article 5

Breach, Cure, and Default

    5.1 Events of Breach. A Breach of this Agreement shall include 
the:
    (a) Failure to pay any amount when due;
    (b) Failure to comply with any material term or condition of 
this Agreement, including but not limited to any material Breach of 
a representation, warranty, or covenant made in this Agreement;
    (c) Failure of a Party to provide such access rights, or a 
Party's attempt to revoke access or terminate such access rights, as 
provided under this Agreement; or
    (d) Failure of a Party to provide information or data to another 
Party as required under this Agreement, provided the Party entitled 
to the information or data under this Agreement requires such 
information or data to satisfy its obligations under this Agreement.
    5.2 Definition. Breaching Party shall mean the Party that is in 
Breach.
    5.3 Notice of Breach, Cure, and Default. Upon the occurrence of 
an event of Breach, any Party aggrieved by the Breach, when it 
becomes aware of the Breach, shall give written notice of the Breach 
to the Breaching Party and to any other person representing a Party 
to this Agreement identified in writing to the other Party in 
advance. Such notice shall set forth, in reasonable detail, the 
nature of the Breach, and where known and applicable, the steps 
necessary to cure such Breach.
    5.2.1 Upon receiving written notice of the Breach hereunder, the 
Breaching Party shall have a period to cure such Breach (hereinafter 
referred to as the ``Cure Period'') which shall be sixty (60) 
Calendar Days. If an Affected System Interconnection Customer is the 
Breaching Party and the Breach results from a failure to provide 
payments or security under Article 4.1 of this Agreement, the other 
Affected System Interconnection Customers, either individually or in 
concert, may cure the Breach by paying the amounts owed or by 
providing adequate security, without waiver of contribution rights 
against the breaching Affected System Interconnection Customer. Such 
cure for the Breach of an Affected System Interconnection Customer 
is subject to the reasonable consent of Transmission Provider. 
Transmission Provider may also cure such Breach by funding the 
proportionate share of the Affected System Network Upgrade costs 
related to the Breach of Affected System Interconnection Customer. 
Transmission Provider must notify all Parties that it will exercise 
this option within thirty (30) Calendar Days of notification that an 
Affected System Interconnection Customer has failed to provide 
payments or security under Article 4.1.
    5.2.2 In the event the Breach is not cured within the Cure 
Period, the Breaching Party will be in Default of this Agreement, 
and the non-Defaulting Parties may (1) act in concert to amend the 
Agreement to remove an Affected System Interconnection Customer that 
is in Default from this Agreement for cause and to make other 
changes as necessary, or (2) either in concert or individually take 
whatever action at law or in equity as may appear necessary or 
desirable to enforce the performance or observance of any rights, 
remedies, obligations, agreement, or covenants under this Agreement.
    5.3 Rights in the Event of Default. Notwithstanding the 
foregoing, upon the occurrence of Default, the non-Defaulting 
Parties shall be entitled to exercise all rights and remedies it may 
have in equity or at law.

Article 6

Termination of Agreement

    6.1 Expiration of Term. Except as otherwise specified in this 
Article 6, the Parties' obligations under this Agreement shall 
terminate at the conclusion of the term of this Agreement.
    6.2 Termination and Removal. Subject to the limitations set 
forth in Article 6.3, in the event of a Default, termination of this 
Agreement, as to a given Affected System Interconnection Customer or 
in its entirety, shall require a filing at FERC of a notice of 
termination, which filing must be accepted for filing by FERC.
    6.3 Disposition of Facilities Upon Termination of Agreement.
    6.3.1 Transmission Provider Obligations. Upon termination of 
this Agreement, unless otherwise agreed to by the Parties in 
writing, Transmission Provider:
    (a) shall, prior to the construction and installation of any 
portion of the Affected System Network Upgrade(s) and to the extent 
possible, cancel any pending orders of, or return, such equipment or 
material for such Affected System Network Upgrade(s);
    (b) may keep in place any portion of the Affected System Network 
Upgrade(s) already constructed and installed; and,
    (c) shall perform such work as may be necessary to ensure the 
safety of persons and property and to preserve the integrity of 
Transmission Provider's Transmission System (e.g., construction 
demobilization to return the system to its original state, wind-up 
work).
    6.3.2 Affected System Interconnection Customer Obligations. Upon 
billing by Transmission Provider, each Affected System 
Interconnection Customer shall reimburse Transmission Provider for 
its share of any costs incurred by Transmission Provider in 
performance of the actions required or permitted by Article 6.3.1 
and for its share of the cost of any Affected System Network 
Upgrade(s) described in Appendix A. Transmission Provider shall use 
Reasonable Efforts to minimize costs and shall offset the amounts 
owed by any salvage value of facilities, if applicable. Each 
Affected System Interconnection Customer shall pay these costs 
pursuant to Article 4.3 of this Agreement.
    6.3.3 Pre-construction or Installation. Upon termination of this 
Agreement and

[[Page 61309]]

prior to the construction and installation of any portion of the 
Affected System Network Upgrade(s), Transmission Provider may, at 
its option, retain any portion of such Affected System Network 
Upgrade(s) not cancelled or returned in accordance with Article 
6.3.1(a), in which case Transmission Provider shall be responsible 
for all costs associated with procuring such Affected System Network 
Upgrade(s). To the extent that an Affected System Interconnection 
Customer has already paid Transmission Provider for any or all of 
such costs, Transmission Provider shall refund Affected System 
Interconnection Customer for those payments. If Transmission 
Provider elects to not retain any portion of such facilities, and 
one or more of Affected System Interconnection Customers wish to 
purchase such facilities, Transmission Provider shall convey and 
make available to the applicable Affected System Interconnection 
Customer(s) such facilities as soon as practicable after Affected 
System Interconnection Customer(s)' payment for such facilities.
    6.4 Survival of Rights. Termination or expiration of this 
Agreement shall not relieve any Party of any of its liabilities and 
obligations arising hereunder prior to the date termination becomes 
effective, and each Party may take whatever judicial or 
administrative actions as appear necessary or desirable to enforce 
its rights hereunder. The applicable provisions of this Agreement 
will continue in effect after expiration, or early termination 
hereof, to the extent necessary to provide for (1) final billings, 
billing adjustments, and other billing procedures set forth in this 
Agreement; (2) the determination and enforcement of liability and 
indemnification obligations arising from acts or events that 
occurred while this Agreement was in effect; and (3) the 
confidentiality provisions set forth in Article 8.

Article 7

Subcontractors

    7.1 Subcontractors. Nothing in this Agreement shall prevent a 
Party from utilizing the services of subcontractors, as it deems 
appropriate, to perform its obligations under this Agreement; 
provided, however, that each Party shall require its subcontractors 
to comply with all applicable terms and conditions of this Agreement 
in providing such services, and each Party shall remain primarily 
liable to the other Parties for the performance of such 
subcontractor.
    7.1.1 Responsibility of Principal. The creation of any 
subcontract relationship shall not relieve the hiring Party of any 
of its obligations under this Agreement. In accordance with the 
provisions of this Agreement, each Party shall be fully responsible 
to the other Parties for the acts or omissions of any subcontractor 
it hires as if no subcontract had been made. Any applicable 
obligation imposed by this Agreement upon a Party shall be equally 
binding upon, and shall be construed as having application to, any 
subcontractor of such Party.
    7.1.2 No Third-Party Beneficiary. Except as may be specifically 
set forth to the contrary herein, no subcontractor or any other 
party is intended to be, nor will it be deemed to be, a third-party 
beneficiary of this Agreement.
    7.1.3 No Limitation by Insurance. The obligations under this 
Article 7 will not be limited in any way by any limitation of any 
insurance policies or coverages, including any subcontractor's 
insurance.

Article 8

Confidentiality

    8.1 Confidentiality. Confidential Information shall include, 
without limitation, all information relating to a Party's 
technology, research and development, business affairs, and pricing, 
and any information supplied to the other Parties prior to the 
execution of this Agreement.
    Information is Confidential Information only if it is clearly 
designated or marked in writing as confidential on the face of the 
document, or, if the information is conveyed orally or by 
inspection, if the Party providing the information orally informs 
the Party receiving the information that the information is 
confidential. The Parties shall maintain as confidential any 
information that is provided and identified by a Party as Critical 
Energy Infrastructure Information (CEII), as that term is defined in 
18 CFR 388.113(c).
    Such confidentiality will be maintained in accordance with this 
Article 8. If requested by the receiving Party, the disclosing Party 
shall provide in writing, the basis for asserting that the 
information referred to in this Article warrants confidential 
treatment, and the requesting Party may disclose such writing to the 
appropriate Governmental Authority. Each Party shall be responsible 
for the costs associated with affording confidential treatment to 
its information.
    8.1.1 Term. During the term of this Agreement, and for a period 
of three (3) years after the expiration or termination of this 
Agreement, except as otherwise provided in this Article 8 or with 
regard to CEII, each Party shall hold in confidence and shall not 
disclose to any person Confidential Information. CEII shall be 
treated in accordance with FERC policies and regulations.
    8.1.2 Scope. Confidential Information shall not include 
information that the receiving Party can demonstrate: (1) is 
generally available to the public other than as a result of a 
disclosure by the receiving Party; (2) was in the lawful possession 
of the receiving Party on a non-confidential basis before receiving 
it from the disclosing Party; (3) was supplied to the receiving 
Party without restriction by a non-Party, who, to the knowledge of 
the receiving Party after due inquiry, was under no obligation to 
the disclosing Party to keep such information confidential; (4) was 
independently developed by the receiving Party without reference to 
Confidential Information of the disclosing Party; (5) is, or 
becomes, publicly known, through no wrongful act or omission of the 
receiving Party or Breach of this Agreement; or (6) is required, in 
accordance with Article 8.1.6 of this Agreement, to be disclosed by 
any Governmental Authority or is otherwise required to be disclosed 
by law or subpoena, or is necessary in any legal proceeding 
establishing rights and obligations under this Agreement. 
Information designated as Confidential Information will no longer be 
deemed confidential if the Party that designated the information as 
confidential notifies the receiving Party that it no longer is 
confidential.
    8.1.3 Release of Confidential Information. No Party shall 
release or disclose Confidential Information to any other person, 
except to its Affiliates (limited by the Standards of Conduct 
requirements), subcontractors, employees, agents, consultants, or to 
non-Parties that may be or are considering providing financing to or 
equity participation with Affected System Interconnection 
Customer(s), or to potential purchasers or assignees of Affected 
System Interconnection Customer(s), on a need-to-know basis in 
connection with this Agreement, unless such person has first been 
advised of the confidentiality provisions of this Article 8 and has 
agreed to comply with such provisions. Notwithstanding the 
foregoing, a Party providing Confidential Information to any person 
shall remain primarily responsible for any release of Confidential 
Information in contravention of this Article 8.
    8.1.4 Rights. Each Party shall retain all rights, title, and 
interest in the Confidential Information that it discloses to the 
receiving Party. The disclosure by a Party to the receiving Party of 
Confidential Information shall not be deemed a waiver by the 
disclosing Party or any other person or entity of the right to 
protect the Confidential Information from public disclosure.
    8.1.5 Standard of Care. Each Party shall use at least the same 
standard of care to protect Confidential Information it receives as 
it uses to protect its own Confidential Information from 
unauthorized disclosure, publication, or dissemination. Each Party 
may use Confidential Information solely to fulfill its obligations 
to the other Party under this Agreement or its regulatory 
requirements.
    8.1.6 Order of Disclosure. If a court or a Government Authority 
or entity with the right, power, and apparent authority to do so 
requests or requires any Party, by subpoena, oral deposition, 
interrogatories, requests for production of documents, 
administrative order, or otherwise, to disclose Confidential 
Information, that Party shall provide the disclosing Party with 
prompt notice of such request(s) or requirement(s) so that the 
disclosing Party may seek an appropriate protective order or waive 
compliance with the terms of this Agreement. Notwithstanding the 
absence of a protective order or waiver, the Party may disclose such 
Confidential Information which, in the opinion of its counsel, the 
Party is legally compelled to disclose. Each Party will use 
Reasonable Efforts to obtain reliable assurance that confidential 
treatment will be accorded any Confidential Information so 
furnished.
    8.1.7 Termination of Agreement. Upon termination of this 
Agreement for any reason, each Party shall, within ten (10) Business 
Days of receipt of a written request from the other Party, use 
Reasonable Efforts to destroy, erase, or delete (with such

[[Page 61310]]

destruction, erasure, and deletion certified in writing to the 
requesting Party) or return to the requesting Party any and all 
written or electronic Confidential Information received from the 
requesting Party, except that each Party may keep one copy for 
archival purposes, provided that the obligation to treat it as 
Confidential Information in accordance with this Article 8 shall 
survive such termination.
    8.1.8 Remedies. The Parties agree that monetary damages would be 
inadequate to compensate a Party for another Party's Breach of its 
obligations under this Article 8. Each Party accordingly agrees that 
the disclosing Party shall be entitled to equitable relief, by way 
of injunction or otherwise, if the receiving Party Breaches or 
threatens to Breach its obligations under this Article 8, which 
equitable relief shall be granted without bond or proof of damages, 
and the Breaching Party shall not plead in defense that there would 
be an adequate remedy at law. Such remedy shall not be deemed an 
exclusive remedy for the Breach of this Article 8, but it shall be 
in addition to all other remedies available at law or in equity. The 
Parties further acknowledge and agree that the covenants contained 
herein are necessary for the protection of legitimate business 
interests and are reasonable in scope. No Party, however, shall be 
liable for indirect, incidental, or consequential or punitive 
damages of any nature or kind resulting from or arising in 
connection with this Article 8.
    8.1.9 Disclosure to FERC, its Staff, or a State Regulatory Body. 
Notwithstanding anything in this Article 8 to the contrary, and 
pursuant to 18 CFR 1b.20, if FERC or its staff, during the course of 
an investigation or otherwise, requests information from a Party 
that is otherwise required to be maintained in confidence pursuant 
to this Agreement, the Party shall provide the requested information 
to FERC or its staff, within the time provided for in the request 
for information. In providing the information to FERC or its staff, 
the Party must, consistent with 18 CFR 388.112, request that the 
information be treated as confidential and non-public by FERC and 
its staff and that the information be withheld from public 
disclosure. Parties are prohibited from notifying the other Parties 
to this Agreement prior to the release of the Confidential 
Information to FERC or its staff. The Party shall notify the other 
Parties to the Agreement when it is notified by FERC or its staff 
that a request to release Confidential Information has been received 
by FERC, at which time either of the Parties may respond before such 
information would be made public, pursuant to 18 CFR 388.112. 
Requests from a state regulatory body conducting a confidential 
investigation shall be treated in a similar manner if consistent 
with the applicable state rules and regulations.
    8.1.10 Subject to the exception in Article 8.1.9, any 
information that a disclosing Party claims is competitively 
sensitive, commercial, or financial information under this Agreement 
shall not be disclosed by the receiving Party to any person not 
employed or retained by the receiving Party, except to the extent 
disclosure is (1) required by law; (2) reasonably deemed by the 
disclosing Party to be required to be disclosed in connection with a 
dispute between or among the Parties, or the defense of litigation 
or dispute; (3) otherwise permitted by consent of the disclosing 
Party, such consent not to be unreasonably withheld; or (4) 
necessary to fulfill its obligations under this Agreement or as 
Transmission Provider or a balancing authority, including disclosing 
the Confidential Information to a regional or national reliability 
organization. The Party asserting confidentiality shall notify the 
receiving Party in writing of the information that Party claims is 
confidential. Prior to any disclosures of that Party's Confidential 
Information under this subparagraph, or if any non-Party or 
Governmental Authority makes any request or demand for any of the 
information described in this subparagraph, the Party that received 
the Confidential Information from the disclosing Party agrees to 
promptly notify the disclosing Party in writing and agrees to assert 
confidentiality and cooperate with the disclosing Party in seeking 
to protect the Confidential Information from public disclosure by 
confidentiality agreement, protective order, or other reasonable 
measures.

Article 9

Information Access and Audit Rights

    9.1 Information Access. Each Party shall make available to the 
other Parties information necessary to verify the costs incurred by 
the other Parties for which the requesting Party is responsible 
under this Agreement and carry out obligations and responsibilities 
under this Agreement, provided that the Parties shall not use such 
information for purposes other than those set forth in this Article 
9.1 and to enforce their rights under this Agreement.
    9.2 Audit Rights. Subject to the requirements of confidentiality 
under Article 8 of this Agreement, the accounts and records related 
to the design, engineering, procurement, and construction of the 
Affected System Network Upgrade(s) shall be subject to audit during 
the period of this Agreement and for a period of twenty-four (24) 
months following Transmission Provider's issuance of a final invoice 
in accordance with Article 4.4. Affected System Interconnection 
Customers may, jointly or individually, at the expense of the 
requesting Party(ies), during normal business hours, and upon prior 
reasonable notice to Transmission Provider, audit such accounts and 
records. Any audit authorized by this Article 9.2 shall be performed 
at the offices where such accounts and records are maintained and 
shall be limited to those portions of such accounts and records that 
relate to obligations under this Agreement.

Article 10

Notices

    10.1 General. Any notice, demand, or request required or 
permitted to be given by a Party to the other Parties, and any 
instrument required or permitted to be tendered or delivered by a 
Party in writing to another Party, may be so given, tendered, or 
delivered, as the case may be, by depositing the same with the 
United States Postal Service with postage prepaid, for transmission 
by certified or registered mail, addressed to the Parties, or 
personally delivered to the Parties, at the address set out below:

To Transmission Provider:
To Affected System Interconnection Customers:

    10.2 Billings and Payments. Billings and payments shall be sent 
to the addresses shown in Article 10.1 unless otherwise agreed to by 
the Parties.
    10.3 Alternative Forms of Notice. Any notice or request required 
or permitted to be given by a Party to the other Parties and not 
required by this Agreement to be given in writing may be so given by 
telephone, facsimile, or email to the telephone numbers and email 
addresses set out below:

To Transmission Provider:
To Affected System Interconnection Customers:

    10.4 Execution and Filing. Affected System Interconnection 
Customers shall either: (i) execute two originals of this tendered 
Agreement and return them to Transmission Provider; or (ii) request 
in writing that Transmission Provider file with FERC this Agreement 
in unexecuted form. As soon as practicable, but not later than ten 
(10) Business Days after receiving either the two executed originals 
of this tendered Agreement (if it does not conform with a FERC-
approved standard form of this Agreement) or the request to file 
this Agreement unexecuted, Transmission Provider shall file this 
Agreement with FERC, together with its explanation of any matters as 
to which Affected System Interconnection Customers and Transmission 
Provider disagree and support for the costs that Transmission 
Provider proposes to charge to Affected System Interconnection 
Customers under this Agreement. An unexecuted version of this 
Agreement should contain terms and conditions deemed appropriate by 
Transmission Provider for the Affected System Interconnection 
Customers' generating facilities. If the Parties agree to proceed 
with design, procurement, and construction of facilities and 
upgrades under the agreed-upon terms of the unexecuted version of 
this Agreement, they may proceed pending FERC action.

Article 11--Miscellaneous

    11.1 This Agreement shall include standard miscellaneous terms 
including, but not limited to, indemnities, representations, 
disclaimers, warranties, governing law, amendment, execution, 
waiver, enforceability, and assignment, which reflect best practices 
in the electric industry, that are consistent with regional 
practices, Applicable Laws and Regulations, and the organizational 
nature of each Party. All of these provisions, to the extent 
practicable, shall be consistent with the provisions of this LGIP.

[Signature Page to Follow]

    In witness whereof, the Parties have executed this Agreement in 
multiple originals, each of which shall constitute and be an 
original Agreement among the Parties.

[[Page 61311]]

Transmission Provider
{Transmission Provider{time} 
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------

Affected System Interconnection Customer
{Affected System Interconnection Customer{time} 
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------

Project No. __

Affected System Interconnection Customer
{Affected System Interconnection Customer{time} 
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------

Project No. __

Attachment A to Appendix 12--Multiparty Affected System Facilities 
Construction Agreement

Affected System Network Upgrade(s), Cost Estimates and 
Responsibility, Construction Schedule, and Monthly Payment Schedule

    This Appendix A is a part of the Multiparty Affected System 
Facilities Construction Agreement between Affected System 
Interconnection Customers and Transmission Provider.

    1.1 Affected System Network Upgrade(s) to be installed by 
Transmission Provider.

{description{time} 

    1.2 First Equipment Order (including permitting).

{description{time} 

    1.2.1 Permitting and Land Rights--Transmission Provider Affected 
System Network Upgrade(s).

{description{time} 

    1.3 Construction Schedule. Where applicable, construction of the 
Affected System Network Upgrade(s) is scheduled as follows and will 
be periodically updated as necessary:

                             Table 3--Transmission Provider Construction Activities
----------------------------------------------------------------------------------------------------------------
           Milestone No.                    Description                Start date                End date
----------------------------------------------------------------------------------------------------------------
 
 
 
----------------------------------------------------------------------------------------------------------------

    Note: Construction schedule assumes that Transmission Provider 
has obtained final authorizations and security from Affected System 
Interconnection Customers and all necessary permits from 
Governmental Authorities as necessary prerequisites to commence 
construction of any of the Affected System Network Upgrade(s).

    1.4 Payment Schedule.
    1.4.1 Timing of and Adjustments to Affected System 
Interconnection Customers' Payments and Security.

{description{time} 

    1.4.2 Monthly Payment Schedule. Affected System Interconnection 
Customers' payment schedule is as follows.

{description{time} 

  Table 4--Affected System Interconnection Customers' Payment/Security
           Obligations for Affected System Network Upgrade(s)
------------------------------------------------------------------------
         Milestone No.                  Description              Date
------------------------------------------------------------------------
 
 
 
------------------------------------------------------------------------

    * Affected System Interconnection Customers' proportionate 
responsibility for each payment is as follows:

Affected System Interconnection Customer 1 __._%
Affected System Interconnection Customer 2 __._%
Affected System Interconnection Customer N __._%

    Note: Affected System Interconnection Customers' payment or 
provision of security as provided in this Agreement operates as a 
condition precedent to Transmission Provider's obligations to 
construct any Affected System Network Upgrade(s), and failure to 
meet this schedule will constitute a Breach pursuant to Article 5.1 
of this Agreement.

    1.5 Permits, Licenses, and Authorizations.

{description{time} 

Attachment B to Appendix 12--Multiparty Affected System Facilities 
Construction Agreement

Notification of Completed Construction

    This Appendix B is a part of the Multiparty Affected System 
Facilities Construction Agreement among Affected System 
Interconnection Customers and Transmission Provider. Where 
applicable, when Transmission Provider has completed construction of 
the Affected System Network Upgrade(s), Transmission Provider shall 
send notice to Affected System Interconnection Customers in 
substantially the form following:

{Date{time} 
{Affected System Interconnection Customers Addresses{time} 
Re: Completion of Affected System Network Upgrade(s)
Dear {Name or Title{time} :
    This letter is sent pursuant to the Multiparty Affected System 
Facilities Construction Agreement among {Transmission 
Provider{time}  and {Affected System Interconnection 
Customers{time} , dated ___, 20_.
    On {Date{time} , Transmission Provider completed to its 
satisfaction all work on the Affected System Network Upgrade(s) 
required to facilitate the safe and reliable interconnection and 
operation of Affected System Interconnection Customer's generating 
facilities. Transmission Provider confirms that the Affected System 
Network Upgrade(s) are in place.
    Thank you.

{Signature{time} 
{Transmission Provider Representative{time} 

Attachment C to Appendix 12--Multiparty Affected System Facilities 
Construction Agreement

Exhibits

    This Appendix C is a part of the Multiparty Affected System 
Facilities Construction Agreement among Affected System 
Interconnection Customers and Transmission Provider.

Exhibit A1--Transmission Provider Site Map

Exhibit A2--Site Plan

Exhibit A3--Affected System Network Upgrade(s) Plan & Profile

Exhibit A4--Estimated Cost of Affected System Network Upgrade(s)

------------------------------------------------------------------------
                                     Facilities to be
            Location                  constructed by        Estimate in
                                  transmission  provider      dollars
------------------------------------------------------------------------
 
                                 Total:
------------------------------------------------------------------------

[[Page 61312]]

Appendix D: Pro forma LGIA

    Note:  Deletions are in brackets and additions are in italics.

Standard Large Generator Interconnection Agreement

    THIS STANDARD LARGE GENERATOR INTERCONNECTION AGREEMENT 
(``Agreement'') is made and entered into this _ day of ___ 20_, by 
and between _____, a _____ organized and existing under the laws of 
the State/Commonwealth of ____ (``Interconnection Customer'' with a 
Large Generating Facility), and _____, a _____ organized and 
existing under the laws of the State/Commonwealth of ____ 
(``Transmission Provider and/or Transmission Owner''). 
Interconnection Customer and Transmission Provider each may be 
referred to as a ``Party'' or collectively as the ``Parties.''

Recitals

    Whereas, Transmission Provider operates the Transmission System; 
and
    Whereas, Interconnection Customer intends to own, lease and/or 
control and operate the Generating Facility identified as a Large 
Generating Facility in Appendix C to this Agreement; and,
    Whereas, Interconnection Customer and Transmission Provider have 
agreed to enter into this Agreement for the purpose of 
interconnecting the Large Generating Facility with the Transmission 
System;
    Now, therefore, in consideration of and subject to the mutual 
covenants contained herein, it is agreed:
    When used in this Standard Large Generator Interconnection 
Agreement, terms with initial capitalization that are not defined in 
Article 1 shall have the meanings specified in the Article in which 
they are used or the Open Access Transmission Tariff (Tariff).

Article 1. Definitions

    Adverse System Impact shall mean the negative effects due to 
technical or operational limits on conductors or equipment being 
exceeded that may compromise the safety and reliability of the 
electric system.
    Affected System shall mean an electric system other than [the] 
Transmission Provider's Transmission System that may be affected by 
the proposed interconnection.
    Affected System Operator shall mean the entity that operates an 
Affected System.
    Affiliate shall mean, with respect to a corporation, partnership 
or other entity, each such other corporation, partnership or other 
entity that directly or indirectly, through one or more 
intermediaries, controls, is controlled by, or is under common 
control with, such corporation, partnership or other entity.
    Ancillary Services shall mean those services that are necessary 
to support the transmission of capacity and energy from resources to 
loads while maintaining reliable operation of the Transmission 
Provider's Transmission System in accordance with Good Utility 
Practice.
    Applicable Laws and Regulations shall mean all duly promulgated 
applicable federal, state and local laws, regulations, rules, 
ordinances, codes, decrees, judgments, directives, or judicial or 
administrative orders, permits and other duly authorized actions of 
any Governmental Authority.
    [Applicable Reliability Council shall mean the reliability 
council applicable to the Transmission System to which the 
Generating Facility is directly interconnected.]
    Applicable Reliability Standards shall mean the requirements and 
guidelines of [NERC,]the [Applicable Reliability Council]Electric 
Reliability Organization and the [Control Area]Balancing Authority 
Area of the Transmission System to which the Generating Facility is 
directly interconnected.
    Balancing Authority shall mean an entity that integrates 
resource plans ahead of time, maintains demand and resource balance 
within a Balancing Authority Area, and supports interconnection 
frequency in real time.
    Balancing Authority Area shall mean the collection of 
generation, transmission, and loads within the metered boundaries of 
the Balancing Authority. The Balancing Authority maintains load-
resource balance within this area.
    Base Case shall mean the base case power flow, short circuit, 
and stability data bases used for the Interconnection Studies by 
[the] Transmission Provider or Interconnection Customer.
    Breach shall mean the failure of a Party to perform or observe 
any material term or condition of the Standard Large Generator 
Interconnection Agreement.
    Breaching Party shall mean a Party that is in Breach of the 
Standard Large Generator Interconnection Agreement.
    Business Day shall mean Monday through Friday, excluding Federal 
Holidays.
    Calendar Day shall mean any day including Saturday, Sunday or a 
Federal Holiday.
    Cluster shall mean a group of one or more Interconnection 
Requests that are studied together for the purpose of conducting a 
Cluster Study.
    Cluster Restudy shall mean a restudy of a Cluster Study 
conducted pursuant to Section 7.5 of the LGIP.
    Cluster Study shall mean the evaluation of one or 
more Interconnection Requests within a Cluster as described in 
Section 7 of the LGIP.
    Clustering shall mean the process whereby one or more [a group 
of]Interconnection Requests [is] are studied together, instead of 
serially, [for the purpose of conducting the Interconnection System 
Impact Study]as described in Section 7 of the LGIP.
    Commercial Operation shall mean the status of a Generating 
Facility that has commenced generating electricity for sale, 
excluding electricity generated during Trial Operation.
    Commercial Operation Date of a unit shall mean the date on which 
the Generating Facility commences Commercial Operation as agreed to 
by the Parties pursuant to Appendix E to the Standard Large 
Generator Interconnection Agreement.
    Confidential Information shall mean any confidential, 
proprietary or trade secret information of a plan, specification, 
pattern, procedure, design, device, list, concept, policy or 
compilation relating to the present or planned business of a Party, 
which is designated as confidential by the Party supplying the 
information, whether conveyed orally, electronically, in writing, 
through inspection, or otherwise.
    Contingent Facilities shall mean those unbuilt Interconnection 
Facilities and Network Upgrades upon which the Interconnection 
Request's costs, timing, and study findings are dependent, and if 
delayed or not built, could cause a need for restudies of the 
Interconnection Request or a reassessment of the Interconnection 
Facilities and/or Network Upgrades and/or costs and timing.
    [Control Area shall mean an electrical system or systems bounded 
by interconnection metering and telemetry, capable of controlling 
generation to maintain its interchange schedule with other Control 
Areas and contributing to frequency regulation of the 
interconnection. A Control Area must be certified by an Applicable 
Reliability Council.]
    Default shall mean the failure of a Breaching Party to cure its 
Breach in accordance with Article 17 of the Standard Large Generator 
Interconnection Agreement.
    Dispute Resolution shall mean the procedure for resolution of a 
dispute between the Parties in which they will first attempt to 
resolve the dispute on an informal basis.
    Distribution System shall mean the Transmission Provider's 
facilities and equipment used to transmit electricity to ultimate 
usage points such as homes and industries directly from nearby 
generators or from interchanges with higher voltage transmission 
networks which transport bulk power over longer distances. The 
voltage levels at which distribution systems operate differ among 
areas.
    Distribution Upgrades shall mean the additions, modifications, 
and upgrades to the Transmission Provider's Distribution System at 
or beyond the Point of Interconnection to facilitate interconnection 
of the Generating Facility and render the transmission service 
necessary to effect Interconnection Customer's wholesale sale of 
electricity in interstate commerce. Distribution Upgrades do not 
include Interconnection Facilities.
    Effective Date shall mean the date on which the Standard Large 
Generator Interconnection Agreement becomes effective upon execution 
by the Parties subject to acceptance by FERC, or if filed 
unexecuted, upon the date specified by FERC.
    Electric Reliability Organization shall mean the North American 
Electric Reliability Corporation or its successor organization.
    Emergency Condition shall mean a condition or situation: (1) 
that in the judgment of the Party making the claim is imminently 
likely to endanger life or property; or (2) that, in the case of a 
Transmission Provider, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the 
security of, or damage to Transmission Provider's Transmission 
System, Transmission Provider's Interconnection Facilities or the 
electric systems of others to

[[Page 61313]]

which the Transmission Provider's Transmission System is directly 
connected; or (3) that, in the case of Interconnection Customer, is 
imminently likely (as determined in a non-discriminatory manner) to 
cause a material adverse effect on the security of, or damage to, 
the Generating Facility or Interconnection Customer's 
Interconnection Facilities. System restoration and black start shall 
be considered Emergency Conditions; provided, that Interconnection 
Customer is not obligated by the Standard Large Generator 
Interconnection Agreement to possess black start capability.
    Energy Resource Interconnection Service shall mean an 
Interconnection Service that allows the Interconnection Customer to 
connect its Generating Facility to the Transmission Provider's 
Transmission System to be eligible to deliver the Generating 
Facility's electric output using the existing firm or nonfirm 
capacity of the Transmission Provider's Transmission System on an as 
available basis. Energy Resource Interconnection Service in and of 
itself does not convey transmission service.
    Engineering & Procurement (E&P) Agreement shall mean an 
agreement that authorizes the Transmission Provider to begin 
engineering and procurement of long lead-time items necessary for 
the establishment of the interconnection in order to advance the 
implementation of the Interconnection Request.
    Environmental Law shall mean Applicable Laws or Regulations 
relating to pollution or protection of the environment or natural 
resources.
    Federal Power Act shall mean the Federal Power Act, as amended, 
16 U.S.C. 791a et seq.
    FERC shall mean the Federal Energy Regulatory Commission 
(Commission) or its successor.
    Force Majeure shall mean any act of God, labor disturbance, act 
of the public enemy, war, insurrection, riot, fire, storm or flood, 
explosion, breakage or accident to machinery or equipment, any 
order, regulation or restriction imposed by governmental, military 
or lawfully established civilian authorities, or any other cause 
beyond a Party's control. A Force Majeure event does not include 
acts of negligence or intentional wrongdoing by the Party claiming 
Force Majeure.
    Generating Facility shall mean Interconnection Customer's 
[device] device(s) for the production and/or storage for later 
injection of electricity identified in the Interconnection Request, 
but shall not include [the]Interconnection Customer's 
Interconnection Facilities.
    Generating Facility Capacity shall mean the net capacity of the 
Generating Facility [and] or the aggregate net capacity of the 
Generating Facility where it includes [multiple energy production 
devices] more than one device for the production and/or storage for 
later injection of electricity.
    Good Utility Practice shall mean any of the practices, methods 
and acts engaged in or approved by a significant portion of the 
electric industry during the relevant time period, or any of the 
practices, methods and acts which, in the exercise of reasonable 
judgment in light of the facts known at the time the decision was 
made, could have been expected to accomplish the desired result at a 
reasonable cost consistent with good business practices, 
reliability, safety and expedition. Good Utility Practice is not 
intended to be limited to the optimum practice, method, or act to 
the exclusion of all others, but rather to be acceptable practices, 
methods, or acts generally accepted in the region.
    Governmental Authority shall mean any federal, state, local or 
other governmental regulatory or administrative agency, court, 
commission, department, board, or other governmental subdivision, 
legislature, rulemaking board, tribunal, or other governmental 
authority having jurisdiction over the Parties, their respective 
facilities, or the respective services they provide, and exercising 
or entitled to exercise any administrative, executive, police, or 
taxing authority or power; provided, however, that such term does 
not include Interconnection Customer, Transmission Provider, or any 
Affiliate thereof.
    Hazardous Substances shall mean any chemicals, materials or 
substances defined as or included in the definition of ``hazardous 
substances,'' ``hazardous wastes,'' ``hazardous materials,'' 
``hazardous constituents,'' ``restricted hazardous materials,'' 
``extremely hazardous substances,'' ``toxic substances,'' 
``radioactive substances,'' ``contaminants,'' ``pollutants,'' 
``toxic pollutants'' or words of similar meaning and regulatory 
effect under any applicable Environmental Law, or any other 
chemical, material or substance, exposure to which is prohibited, 
limited or regulated by any applicable Environmental Law.
    Initial Synchronization Date shall mean the date upon which the 
Generating Facility is initially synchronized and upon which Trial 
Operation begins.
    In-Service Date shall mean the date upon which the 
Interconnection Customer reasonably expects it will be ready to 
begin use of the Transmission Provider's Interconnection Facilities 
to obtain back feed power.
    Interconnection Customer shall mean any entity, including the 
Transmission Provider, Transmission Owner or any of the Affiliates 
or subsidiaries of either, that proposes to interconnect its 
Generating Facility with the Transmission Provider's Transmission 
System.
    Interconnection Customer's Interconnection Facilities shall mean 
all facilities and equipment, as identified in Appendix A of the 
Standard Large Generator Interconnection Agreement, that are located 
between the Generating Facility and the Point of Change of 
Ownership, including any modification, addition, or upgrades to such 
facilities and equipment necessary to physically and electrically 
interconnect the Generating Facility to the Transmission Provider's 
Transmission System. Interconnection Customer's Interconnection 
Facilities are sole use facilities.
    Interconnection Facilities shall mean [the]Transmission 
Provider's Interconnection Facilities and [the]Interconnection 
Customer's Interconnection Facilities. Collectively, Interconnection 
Facilities include all facilities and equipment between the 
Generating Facility and the Point of Interconnection, including any 
modification, additions or upgrades that are necessary to physically 
and electrically interconnect the Generating Facility to 
[the]Transmission Provider's Transmission System. Interconnection 
Facilities are sole use facilities and shall not include 
Distribution Upgrades, Stand Alone Network Upgrades or Network 
Upgrades.
    Interconnection Facilities Study shall mean a study conducted by 
[the]Transmission Provider or a third party consultant for 
[the]Interconnection Customer to determine a list of facilities 
(including Transmission Provider's Interconnection Facilities and 
Network Upgrades as identified in the [Interconnection System 
Impact]Cluster Study), the cost of those facilities, and the time 
required to interconnect the Generating Facility with [the] 
Transmission Provider's Transmission System. The scope of the study 
is defined in Section 8 of the LGIP[the Standard Large Generator 
Interconnection Procedures].
    Interconnection Facilities Study Agreement shall mean the form 
of agreement contained in Appendix 3[4] of the Standard Large 
Generator Interconnection Procedures for conducting the 
Interconnection Facilities Study.
    [Interconnection Feasibility Study shall mean a preliminary 
evaluation of the system impact and cost of interconnecting the 
Generating Facility to the Transmission Provider's Transmission 
System, the scope of which is described in Section 6 of the Standard 
Large Generator Interconnection Procedures.]
    [Interconnection Feasibility Study Agreement shall mean the form 
of agreement contained in Appendix 2 of the Standard Large Generator 
Interconnection Procedures for conducting the Interconnection 
Feasibility Study.]
    Interconnection Request shall mean an Interconnection Customer's 
request, in the form of Appendix 1 to the LGIP [the Standard Large 
Generator Interconnection Procedures], in accordance with the 
Tariff, to interconnect a new Generating Facility, or to increase 
the capacity of, or make a Material Modification to the operating 
characteristics of, an existing Generating Facility that is 
interconnected with the Transmission Provider's Transmission System.
    Interconnection Service shall mean the service provided by the 
Transmission Provider associated with interconnecting the 
Interconnection Customer's Generating Facility to the Transmission 
Provider's Transmission System and enabling it to receive electric 
energy and capacity from the Generating Facility at the Point of 
Interconnection, pursuant to the terms of the Standard Large 
Generator Interconnection Agreement and, if applicable, the 
Transmission Provider's Tariff.
    Interconnection Study shall mean any of the following studies: 
[the Interconnection Feasibility Study, the Interconnection System 
Impact Study,] the Cluster Study, the Cluster Restudy, the Surplus 
Interconnection Service System Impact Study, and the

[[Page 61314]]

Interconnection Facilities Study, described in the LGIP [the 
Standard Large Generator Interconnection Procedures].
    [Interconnection System Impact Study shall mean an engineering 
study that evaluates the impact of the proposed interconnection on 
the safety and reliability of Transmission Provider's Transmission 
System and, if applicable, an Affected System. The study shall 
identify and detail the system impacts that would result if the 
Generating Facility were interconnected without project 
modifications or system modifications, focusing on the Adverse 
System Impacts identified in the Interconnection Feasibility Study, 
or to study potential impacts, including but not limited to those 
identified in the Scoping Meeting as described in the Standard Large 
Generator Interconnection Procedures.]
    Interconnection System Impact Study Agreement shall mean the 
form of agreement contained in Appendix 3 of the Standard Large 
Generator Interconnection Procedures for conducting the 
Interconnection System Impact Study.]
    IRS shall mean the Internal Revenue Service.
    Joint Operating Committee shall be a group made up of 
representatives from Interconnection Customers and the Transmission 
Provider to coordinate operating and technical considerations of 
Interconnection Service.
    Large Generating Facility shall mean a Generating Facility 
having a Generating Facility Capacity of more than 20 MW.
    LGIA Deposit shall mean the deposit Interconnection Customer 
submits when returning the executed LGIA, or within 10 Business Days 
of requesting that the LGIA be filed unexecuted at the Commission, 
in accordance with Section 11.3 of the LGIP.
     Loss shall mean any and all losses relating to injury to or 
death of any person or damage to property, demand, suits, 
recoveries, costs and expenses, court costs, attorney fees, and all 
other obligations by or to third parties, arising out of or 
resulting from the other Party's performance, or non-performance of 
its obligations under the Standard Large Generator Interconnection 
Agreement on behalf of the Indemnifying Party, except in cases of 
gross negligence or intentional wrongdoing by the Indemnifying 
Party.
     Material Modification shall mean those modifications that have 
a material impact on the cost or timing of any Interconnection 
Request with an equal or later Queue Position[queue priority date].
    Metering Equipment shall mean all metering equipment installed 
or to be installed at the Generating Facility pursuant to the 
Standard Large Generator Interconnection Agreement at the metering 
points, including but not limited to instrument transformers, MWh-
meters, data acquisition equipment, transducers, remote terminal 
unit, communications equipment, phone lines, and fiber optics.
    [NERC shall mean the North American Electric Reliability Council 
or its successor organization.]
    Network Resource shall mean any designated generating resource 
owned, purchased, or leased by a Network Customer under the Network 
Integration Transmission Service Tariff. Network Resources do not 
include any resource, or any portion thereof, that is committed for 
sale to third parties or otherwise cannot be called upon to meet the 
Network Customer's Network Load on a non-interruptible basis.
    Network Resource Interconnection Service shall mean an 
Interconnection Service that allows the Interconnection Customer to 
integrate its Large Generating Facility with the Transmission 
Provider's Transmission System (1) in a manner comparable to that in 
which the Transmission Provider integrates its generating facilities 
to serve native load customers; or (2) in an RTO or ISO with market 
based congestion management, in the same manner as Network 
Resources. Network Resource Interconnection Service in and of itself 
does not convey transmission service.
    Network Upgrades shall mean the additions, modifications, and 
upgrades to the Transmission Provider's Transmission System required 
at or beyond the point at which the Interconnection Facilities 
connect to the Transmission Provider's Transmission System to 
accommodate the interconnection of the Large Generating Facility to 
the Transmission Provider's Transmission System.
    Notice of Dispute shall mean a written notice of a dispute or 
claim that arises out of or in connection with the Standard Large 
Generator Interconnection Agreement or its performance.
    Optional Interconnection Study shall mean a sensitivity analysis 
based on assumptions specified by the Interconnection Customer in 
the Optional Interconnection Study Agreement.
    Optional Interconnection Study Agreement shall mean the form of 
agreement contained in Appendix 4[5] of the LGIP [the Standard Large 
Generator Interconnection Procedures] for conducting the Optional 
Interconnection Study.
    Party or Parties shall mean Transmission Provider, Transmission 
Owner, Interconnection Customer or any combination of the above.
    Point of Change of Ownership shall mean the point, as set forth 
in Appendix A to the Standard Large Generator Interconnection 
Agreement, where the Interconnection Customer's Interconnection 
Facilities connect to the Transmission Provider's Interconnection 
Facilities.
    Point of Interconnection shall mean the point, as set forth in 
Appendix A to the Standard Large Generator Interconnection 
Agreement, where the Interconnection Facilities connect to the 
Transmission Provider's Transmission System.
    Proportional Impact Method shall mean a technical analysis 
conducted by Transmission Provider to determine the degree to which 
each Generating Facility in the Cluster Study contributes to the 
need for a specific System Network Upgrade.
    Provisional Interconnection Service shall mean Interconnection 
Service provided by Transmission Provider associated with 
interconnecting the Interconnection Customer's Generating Facility 
to Transmission Provider's Transmission System and enabling that 
Transmission System to receive electric energy and capacity from the 
Generating Facility at the Point of Interconnection, pursuant to the 
terms of the Provisional Large Generator Interconnection Agreement 
and, if applicable, the Tariff.
    Provisional Large Generator Interconnection Agreement shall mean 
the interconnection agreement for Provisional Interconnection 
Service established between Transmission Provider and/or the 
Transmission Owner and the Interconnection Customer. This agreement 
shall take the form of the Large Generator Interconnection 
Agreement, modified for provisional purposes.
    Queue Position shall mean the order of a valid Interconnection 
Request, relative to all other pending valid Interconnection 
Requests, [that is] established pursuant to Section 4.1 of the LGIP. 
[based upon the date and time of receipt of the valid 
Interconnection Request by the Transmission Provider.]
    Reasonable Efforts shall mean, with respect to an action 
required to be attempted or taken by a Party under the Standard 
Large Generator Interconnection Agreement, efforts that are timely 
and consistent with Good Utility Practice and are otherwise 
substantially equivalent to those a Party would use to protect its 
own interests.
    Scoping Meeting shall mean the meeting between representatives 
of [the]Interconnection Customer(s) and Transmission Provider 
conducted for the purpose of discussing the proposed Interconnection 
Request and any alternative interconnection options, 
[to]exchang[e]ing information including any transmission data and 
earlier study evaluations that would be reasonably expected to 
impact such interconnection options, refining information and models 
provided by Interconnection Customer(s), discussing the Cluster 
Study materials posted to OASIS pursuant to Section 3.5 of the LGIP, 
and [to]analyz[e]ing such information[, and to determine the 
potential feasible Points of Interconnection].
    Site Control shall mean [documentation reasonably demonstrating] 
the exclusive land right to develop, construct, operate, and 
maintain the Generating Facility over the term of expected operation 
of the Generating Facility. Site Control may be demonstrated by 
documentation establishing: (1) ownership of, a leasehold interest 
in, or a right to develop a site [for the purpose of constructing]of 
sufficient size to construct and operate the Generating Facility; 
(2) an option to purchase or acquire a leasehold site of sufficient 
size to construct and operate the Generating Facility for such 
purpose; or (3) [an exclusivity or other business relationship 
between]any other documentation that clearly demonstrates the right 
of Interconnection Customer[and the entity having the right to sell, 
lease or grant Interconnection Customer the right to possess or]to 
exclusively occupy a site [for such purpose.]of sufficient size to 
construct and operate the Generating Facility. Transmission Provider 
will maintain acreage requirements for each Generating Facility type 
on its OASIS or public website.

[[Page 61315]]

    Small Generating Facility shall mean a Generating Facility that 
has a Generating Facility Capacity of no more than 20 MW.
    Stand Alone Network Upgrades shall mean Network Upgrades that 
are not part of an Affected System that an Interconnection Customer 
may construct without affecting day-to-day operations of the 
Transmission System during their construction and the following 
conditions are met: (1) a Substation Network Upgrade must only be 
required for a single Interconnection Customer in the Cluster and no 
other Interconnection Customer in that Cluster is required to 
interconnect to the same Substation Network Upgrades, and (2) a 
System Network Upgrade must only be required for a single 
Interconnection Customer in the Cluster, as indicated under 
Transmission Provider's Proportional Impact Method. Both 
[the]Transmission Provider and [the]Interconnection Customer must 
agree as to what constitutes Stand Alone Network Upgrades and 
identify them in Appendix A to the Standard Large Generator 
Interconnection Agreement. If [the]Transmission Provider and 
Interconnection Customer disagree about whether a particular Network 
Upgrade is a Stand Alone Network Upgrade, [the]Transmission Provider 
must provide [the]Interconnection Customer a written technical 
explanation outlining why [the] Transmission Provider does not 
consider the Network Upgrade to be a Stand Alone Network Upgrade 
within 15 days of its determination.
    Standard Large Generator Interconnection Agreement (LGIA) shall 
mean the form of interconnection agreement applicable to an 
Interconnection Request pertaining to a Large Generating Facility 
that is included in the Transmission Provider's Tariff.
    Standard Large Generator Interconnection Procedures (LGIP) shall 
mean the interconnection procedures applicable to an Interconnection 
Request pertaining to a Large Generating Facility that are included 
in the Transmission Provider's Tariff.
    Substation Network Upgrades shall mean Network Upgrades that are 
required at the substation located at the Point of Interconnection.
    Surplus Interconnection Service shall mean any unneeded portion 
of Interconnection Service established in a Large Generator 
Interconnection Agreement, such that if Surplus Interconnection 
Service is utilized the total amount of Interconnection Service at 
the Point of Interconnection would remain the same.
    System Network Upgrades shall mean Network Upgrades that are 
required beyond the substation located at the Point of 
Interconnection.
    System Protection Facilities shall mean the equipment, including 
necessary protection signal communications equipment, required to 
protect (1) the Transmission Provider's Transmission System from 
faults or other electrical disturbances occurring at the Generating 
Facility and (2) the Generating Facility from faults or other 
electrical system disturbances occurring on the Transmission 
Provider's Transmission System or on other delivery systems or other 
generating systems to which the Transmission Provider's Transmission 
System is directly connected.
    Tariff shall mean the Transmission Provider's Tariff through 
which open access transmission service and Interconnection Service 
are offered, as filed with FERC, and as amended or supplemented from 
time to time, or any successor tariff.
    Transmission Owner shall mean an entity that owns, leases or 
otherwise possesses an interest in the portion of the Transmission 
System at the Point of Interconnection and may be a Party to the 
Standard Large Generator Interconnection Agreement to the extent 
necessary.
    Transmission Provider shall mean the public utility (or its 
designated agent) that owns, controls, or operates transmission or 
distribution facilities used for the transmission of electricity in 
interstate commerce and provides transmission service under the 
Tariff. The term Transmission Provider should be read to include the 
Transmission Owner when the Transmission Owner is separate from the 
Transmission Provider.
    Transmission Provider's Interconnection Facilities shall mean 
all facilities and equipment owned, controlled, or operated by 
[the]Transmission Provider from the Point of Change of Ownership to 
the Point of Interconnection as identified in Appendix A to the 
Standard Large Generator Interconnection Agreement, including any 
modifications, additions or upgrades to such facilities and 
equipment. Transmission Provider's Interconnection Facilities are 
sole use facilities and shall not include Distribution Upgrades, 
Stand Alone Network Upgrades or Network Upgrades.
    Transmission System shall mean the facilities owned, controlled 
or operated by the Transmission Provider or Transmission Owner that 
are used to provide transmission service under the Tariff.
    Trial Operation shall mean the period during which 
Interconnection Customer is engaged in on-site test operations and 
commissioning of the Generating Facility prior to Commercial 
Operation.
    Variable Energy Resource shall mean a device for the production 
of electricity that is characterized by an energy source that: (1) 
is renewable; (2) cannot be stored by the facility owner or 
operator; and (3) has variability that is beyond the control of the 
facility owner or operator.
    Withdrawal Penalty shall mean the penalty assessed by 
Transmission Provider to an Interconnection Customer that chooses to 
withdraw or is deemed withdrawn from Transmission Provider's 
interconnection queue or whose Generating Facility does not 
otherwise reach Commercial Operation. The calculation of the 
Withdrawal Penalty is set forth in Section 3.7.1 of the LGIP.

Article 2. Effective Date, Term, and Termination

    2.1 Effective Date. This LGIA shall become effective upon 
execution by the Parties subject to acceptance by FERC (if 
applicable), or if filed unexecuted, upon the date specified by 
FERC. Transmission Provider shall promptly file this LGIA with FERC 
upon execution in accordance with Article 3.1, if required.
    2.2 Term of Agreement. Subject to the provisions of Article 2.3, 
this LGIA shall remain in effect for a period of ten (10) years from 
the Effective Date or such other longer period as Interconnection 
Customer may request (Term to be specified in individual agreements) 
and shall be automatically renewed for each successive one-year 
period thereafter.
    2.3 Termination Procedures.
    2.3.1 Written Notice. This LGIA may be terminated by 
Interconnection Customer after giving Transmission Provider ninety 
(90) Calendar Days advance written notice, or by Transmission 
Provider notifying FERC after the Generating Facility permanently 
ceases Commercial Operation.
    2.3.2 Default. Either Party may terminate this LGIA in 
accordance with Article 17.
    2.3.3 Notwithstanding Articles 2.3.1 and 2.3.2, no termination 
shall become effective until the Parties have complied with all 
Applicable Laws and Regulations applicable to such termination, 
including the filing with FERC of a notice of termination of this 
LGIA, which notice has been accepted for filing by FERC.
    2.4 Termination Costs. If a Party elects to terminate this 
Agreement pursuant to Article 2.3 above, each Party shall pay all 
costs incurred (including any cancellation costs relating to orders 
or contracts for Interconnection Facilities and equipment) or 
charges assessed by the other Party, as of the date of the other 
Party's receipt of such notice of termination, that are the 
responsibility of the Terminating Party under this LGIA. In the 
event of termination by a Party, the Parties shall use commercially 
Reasonable Efforts to mitigate the costs, damages and charges 
arising as a consequence of termination. Upon termination of this 
LGIA, unless otherwise ordered or approved by FERC:
    2.4.1 With respect to any portion of Transmission Provider's 
Interconnection Facilities that have not yet been constructed or 
installed, Transmission Provider shall to the extent possible and 
with Interconnection Customer's authorization cancel any pending 
orders of, or return, any materials or equipment for, or contracts 
for construction of, such facilities; provided that in the event 
Interconnection Customer elects not to authorize such cancellation, 
Interconnection Customer shall assume all payment obligations with 
respect to such materials, equipment, and contracts, and 
Transmission Provider shall deliver such material and equipment, 
and, if necessary, assign such contracts, to Interconnection 
Customer as soon as practicable, at Interconnection Customer's 
expense. To the extent that Interconnection Customer has already 
paid Transmission Provider for any or all such costs of materials or 
equipment not taken by Interconnection Customer, Transmission 
Provider shall promptly refund such amounts to Interconnection 
Customer, less any costs, including penalties incurred by 
Transmission Provider to cancel any pending orders of or return such 
materials, equipment, or contracts.
    If an Interconnection Customer terminates this LGIA, it shall be 
responsible for all costs incurred in association with that

[[Page 61316]]

Interconnection Customer's interconnection, including any 
cancellation costs relating to orders or contracts for 
Interconnection Facilities and equipment, and other expenses 
including any Network Upgrades for which Transmission Provider has 
incurred expenses and has not been reimbursed by Interconnection 
Customer.
    2.4.2 Transmission Provider may, at its option, retain any 
portion of such materials, equipment, or facilities that 
Interconnection Customer chooses not to accept delivery of, in which 
case Transmission Provider shall be responsible for all costs 
associated with procuring such materials, equipment, or facilities.
    2.4.3 With respect to any portion of the Interconnection 
Facilities, and any other facilities already installed or 
constructed pursuant to the terms of this LGIA, Interconnection 
Customer shall be responsible for all costs associated with the 
removal, relocation or other disposition or retirement of such 
materials, equipment, or facilities.
    2.5 Disconnection. Upon termination of this LGIA, the Parties 
will take all appropriate steps to disconnect the Large Generating 
Facility from the Transmission System. All costs required to 
effectuate such disconnection shall be borne by the terminating 
Party, unless such termination resulted from the non-terminating 
Party's Default of this LGIA or such non-terminating Party otherwise 
is responsible for these costs under this LGIA.
    2.6 Survival. This LGIA shall continue in effect after 
termination to the extent necessary to provide for final billings 
and payments and for costs incurred hereunder, including billings 
and payments pursuant to this LGIA; to permit the determination and 
enforcement of liability and indemnification obligations arising 
from acts or events that occurred while this LGIA was in effect; and 
to permit each Party to have access to the lands of the other Party 
pursuant to this LGIA or other applicable agreements, to disconnect, 
remove or salvage its own facilities and equipment.

Article 3. Regulatory Filings

    3.1 Filing. Transmission Provider shall file this LGIA (and any 
amendment hereto) with the appropriate Governmental Authority, if 
required. Interconnection Customer may request that any information 
so provided be subject to the confidentiality provisions of Article 
22. If Interconnection Customer has executed this LGIA, or any 
amendment thereto, Interconnection Customer shall reasonably 
cooperate with Transmission Provider with respect to such filing and 
to provide any information reasonably requested by Transmission 
Provider needed to comply with applicable regulatory requirements.

Article 4. Scope of Service

    4.1 Interconnection Product Options. Interconnection Customer 
has selected the following (checked) type of Interconnection 
Service:

4.1.1 Energy Resource Interconnection Service

    4.1.1.1 The Product. Energy Resource Interconnection Service 
allows Interconnection Customer to connect the Large Generating 
Facility to the Transmission System and be eligible to deliver the 
Large Generating Facility's output using the existing firm or non-
firm capacity of the Transmission System on an ``as available'' 
basis. To the extent Interconnection Customer wants to receive 
Energy Resource Interconnection Service, Transmission Provider shall 
construct facilities identified in Attachment A.
    4.1.1.2 Transmission Delivery Service Implications. Under Energy 
Resource Interconnection Service, Interconnection Customer will be 
eligible to inject power from the Large Generating Facility into and 
deliver power across the interconnecting Transmission Provider's 
Transmission System on an ``as available'' basis up to the amount of 
MWs identified in the applicable stability and steady state studies 
to the extent the upgrades initially required to qualify for Energy 
Resource Interconnection Service have been constructed. Where 
eligible to do so (e.g., PJM, ISO-NE, NYISO), Interconnection 
Customer may place a bid to sell into the market up to the maximum 
identified Large Generating Facility output, subject to any 
conditions specified in the interconnection service approval, and 
the Large Generating Facility will be dispatched to the extent 
Interconnection Customer's bid clears. In all other instances, no 
transmission delivery service from the Large Generating Facility is 
assured, but Interconnection Customer may obtain Point-to-Point 
Transmission Service, Network Integration Transmission Service, or 
be used for secondary network transmission service, pursuant to 
Transmission Provider's Tariff, up to the maximum output identified 
in the stability and steady state studies. In those instances, in 
order for Interconnection Customer to obtain the right to deliver or 
inject energy beyond the Large Generating Facility Point of 
Interconnection or to improve its ability to do so, transmission 
delivery service must be obtained pursuant to the provisions of 
Transmission Provider's Tariff. The Interconnection Customer's 
ability to inject its Large Generating Facility output beyond the 
Point of Interconnection, therefore, will depend on the existing 
capacity of Transmission Provider's Transmission System at such time 
as a transmission service request is made that would accommodate 
such delivery. The provision of firm Point-to-Point Transmission 
Service or Network Integration Transmission Service may require the 
construction of additional Network Upgrades.

4.1.2 Network Resource Interconnection Service

    4.1.2.1 The Product. Transmission Provider must conduct the 
necessary studies and construct the Network Upgrades needed to 
integrate the Large Generating Facility (1) in a manner comparable 
to that in which Transmission Provider integrates its generating 
facilities to serve native load customers; or (2) in an ISO or RTO 
with market based congestion management, in the same manner as all 
Network Resources. To the extent Interconnection Customer wants to 
receive Network Resource Interconnection Service, Transmission 
Provider shall construct the facilities identified in Attachment A 
to this LGIA.
    4.1.2.2 Transmission Delivery Service Implications. Network 
Resource Interconnection Service allows Interconnection Customer's 
Large Generating Facility to be designated by any Network Customer 
under the Tariff on Transmission Provider's Transmission System as a 
Network Resource, up to the Large Generating Facility's full output, 
on the same basis as existing Network Resources interconnected to 
Transmission Provider's Transmission System, and to be studied as a 
Network Resource on the assumption that such a designation will 
occur. Although Network Resource Interconnection Service does not 
convey a reservation of transmission service, any Network Customer 
under the Tariff can utilize its network service under the Tariff to 
obtain delivery of energy from the interconnected Interconnection 
Customer's Large Generating Facility in the same manner as it 
accesses Network Resources. A Large Generating Facility receiving 
Network Resource Interconnection Service may also be used to provide 
Ancillary Services after technical studies and/or periodic analyses 
are performed with respect to the Large Generating Facility's 
ability to provide any applicable Ancillary Services, provided that 
such studies and analyses have been or would be required in 
connection with the provision of such Ancillary Services by any 
existing Network Resource. However, if an Interconnection Customer's 
Large Generating Facility has not been designated as a Network 
Resource by any load, it cannot be required to provide Ancillary 
Services except to the extent such requirements extend to all 
generating facilities that are similarly situated. The provision of 
Network Integration Transmission Service or firm Point-to-Point 
Transmission Service may require additional studies and the 
construction of additional upgrades. Because such studies and 
upgrades would be associated with a request for delivery service 
under the Tariff, cost responsibility for the studies and upgrades 
would be in accordance with FERC's policy for pricing transmission 
delivery services.
    Network Resource Interconnection Service does not necessarily 
provide Interconnection Customer with the capability to physically 
deliver the output of its Large Generating Facility to any 
particular load on Transmission Provider's Transmission System 
without incurring congestion costs. In the event of transmission 
constraints on Transmission Provider's Transmission System, 
Interconnection Customer's Large Generating Facility shall be 
subject to the applicable congestion management procedures in 
Transmission Provider's Transmission System in the same manner as 
Network Resources.
    There is no requirement either at the time of study or 
interconnection, or at any point in the future, that Interconnection 
Customer's Large Generating Facility be designated as a

[[Page 61317]]

Network Resource by a Network Service Customer under the Tariff or 
that Interconnection Customer identify a specific buyer (or sink). 
To the extent a Network Customer does designate the Large Generating 
Facility as a Network Resource, it must do so pursuant to 
Transmission Provider's Tariff.
    Once an Interconnection Customer satisfies the requirements for 
obtaining Network Resource Interconnection Service, any future 
transmission service request for delivery from the Large Generating 
Facility within Transmission Provider's Transmission System of any 
amount of capacity and/or energy, up to the amount initially 
studied, will not require that any additional studies be performed 
or that any further upgrades associated with such Large Generating 
Facility be undertaken, regardless of whether or not such Large 
Generating Facility is ever designated by a Network Customer as a 
Network Resource and regardless of changes in ownership of the Large 
Generating Facility. However, the reduction or elimination of 
congestion or redispatch costs may require additional studies and 
the construction of additional upgrades.
    To the extent Interconnection Customer enters into an 
arrangement for long term transmission service for deliveries from 
the Large Generating Facility outside Transmission Provider's 
Transmission System, such request may require additional studies and 
upgrades in order for Transmission Provider to grant such request.
    4.2 Provision of Service. Transmission Provider shall provide 
Interconnection Service for the Large Generating Facility at the 
Point of Interconnection.
    4.3 Performance Standards. Each Party shall perform all of its 
obligations under this LGIA in accordance with Applicable Laws and 
Regulations, Applicable Reliability Standards, and Good Utility 
Practice, and to the extent a Party is required or prevented or 
limited in taking any action by such regulations and standards, such 
Party shall not be deemed to be in Breach of this LGIA for its 
compliance therewith. If such Party is a Transmission Provider or 
Transmission Owner, then that Party shall amend the LGIA and submit 
the amendment to FERC for approval.
    4.4 No Transmission Delivery Service. The execution of this LGIA 
does not constitute a request for, nor the provision of, any 
transmission delivery service under Transmission Provider's Tariff, 
and does not convey any right to deliver electricity to any specific 
customer or Point of Delivery.
    4.5 Interconnection Customer Provided Services. The services 
provided by Interconnection Customer under this LGIA are set forth 
in Article 9.6 and Article 13.5.1. Interconnection Customer shall be 
paid for such services in accordance with Article 11.6.

Article 5. Interconnection Facilities Engineering, Procurement, & 
Construction

    5.1 Options. Unless otherwise mutually agreed to between the 
Parties, Interconnection Customer shall select the In-Service Date, 
Initial Synchronization Date, and Commercial Operation Date; and 
either the Standard Option or Alternate Option set forth below, and 
such dates and selected option shall be set forth in Appendix B, 
Milestones. At the same time, Interconnection Customer shall 
indicate whether it elects to exercise the Option to Build set forth 
in Article 5.1.3 below. If the dates designated by Interconnection 
Customer are not acceptable to Transmission Provider, Transmission 
Provider shall so notify Interconnection Customer within thirty (30) 
Calendar Days. Upon receipt of the notification that Interconnection 
Customer's designated dates are not acceptable to Transmission 
Provider, the Interconnection Customer shall notify Transmission 
Provider within thirty (30) Calendar Days whether it elects to 
exercise the Option to Build if it has not already elected to 
exercise the Option to Build.
    5.1.1 Standard Option. Transmission Provider shall design, 
procure, and construct Transmission Provider's Interconnection 
Facilities and Network Upgrades, using Reasonable Efforts to 
complete Transmission Provider's Interconnection Facilities and 
Network Upgrades by the dates set forth in Appendix B, Milestones. 
Transmission Provider shall not be required to undertake any action 
which is inconsistent with its standard safety practices, its 
material and equipment specifications, its design criteria and 
construction procedures, its labor agreements, and Applicable Laws 
and Regulations. In the event Transmission Provider reasonably 
expects that it will not be able to complete Transmission Provider's 
Interconnection Facilities and Network Upgrades by the specified 
dates, Transmission Provider shall promptly provide written notice 
to Interconnection Customer and shall undertake Reasonable Efforts 
to meet the earliest dates thereafter.
    5.1.2 Alternate Option. If the dates designated by 
Interconnection Customer are acceptable to Transmission Provider, 
Transmission Provider shall so notify Interconnection Customer 
within thirty (30) Calendar Days, and shall assume responsibility 
for the design, procurement and construction of Transmission 
Provider's Interconnection Facilities by the designated dates.
    If Transmission Provider subsequently fails to complete 
Transmission Provider's Interconnection Facilities by the In-Service 
Date, to the extent necessary to provide back feed power; or fails 
to complete Network Upgrades by the Initial Synchronization Date to 
the extent necessary to allow for Trial Operation at full power 
output, unless other arrangements are made by the Parties for such 
Trial Operation; or fails to complete the Network Upgrades by the 
Commercial Operation Date, as such dates are reflected in Appendix 
B, Milestones; Transmission Provider shall pay Interconnection 
Customer liquidated damages in accordance with Article 5.3, 
Liquidated Damages, provided, however, the dates designated by 
Interconnection Customer shall be extended day for day for each day 
that the applicable RTO or ISO refuses to grant clearances to 
install equipment.
    5.1.3 Option to Build. Interconnection Customer shall have the 
option to assume responsibility for the design, procurement and 
construction of Transmission Provider's Interconnection Facilities 
and Stand Alone Network Upgrades on the dates specified in Article 
5.1.2. Transmission Provider and Interconnection Customer must agree 
as to what constitutes Stand Alone Network Upgrades and identify 
such Stand Alone Network Upgrades in Appendix A. Except for Stand 
Alone Network Upgrades, Interconnection Customer shall have no right 
to construct Network Upgrades under this option.
    5.1.4 Negotiated Option. If the dates designated by 
Interconnection Customer are not acceptable to Transmission 
Provider, the Parties shall in good faith attempt to negotiate terms 
and conditions (including revision of the specified dates and 
liquidated damages, the provision of incentives, or the procurement 
and construction of all facilities other than Transmission 
Provider's Interconnection Facilities and Stand Alone Network 
Upgrades if the Interconnection Customer elects to exercise the 
Option to Build under Article 5.1.3). If the Parties are unable to 
reach agreement on such terms and conditions, then pursuant to 
Article 5.1.1 (Standard Option), Transmission Provider shall assume 
responsibility for the design, procurement and construction of all 
facilities other than Transmission Provider's Interconnection 
Facilities and Stand Alone Network Upgrades if the Interconnection 
Customer elects to exercise the Option to Build.
    5.2 General Conditions Applicable to Option to Build. If 
Interconnection Customer assumes responsibility for the design, 
procurement and construction of Transmission Provider's 
Interconnection Facilities and Stand Alone Network Upgrades,
    (1) Interconnection Customer shall engineer, procure equipment, 
and construct Transmission Provider's Interconnection Facilities and 
Stand Alone Network Upgrades (or portions thereof) using Good 
Utility Practice and using standards and specifications provided in 
advance by Transmission Provider;
    (2) Interconnection Customer's engineering, procurement and 
construction of Transmission Provider's Interconnection Facilities 
and Stand Alone Network Upgrades shall comply with all requirements 
of law to which Transmission Provider would be subject in the 
engineering, procurement or construction of Transmission Provider's 
Interconnection Facilities and Stand Alone Network Upgrades;
    (3) Transmission Provider shall review and approve the 
engineering design, equipment acceptance tests, and the construction 
of Transmission Provider's Interconnection Facilities and Stand 
Alone Network Upgrades;
    (4) prior to commencement of construction, Interconnection 
Customer shall provide to Transmission Provider a schedule for 
construction of Transmission Provider's Interconnection Facilities 
and Stand Alone Network Upgrades, and shall promptly respond to 
requests for information from Transmission Provider;
    (5) at any time during construction, Transmission Provider shall 
have the right to

[[Page 61318]]

gain unrestricted access to Transmission Provider's Interconnection 
Facilities and Stand Alone Network Upgrades and to conduct 
inspections of the same;
    (6) at any time during construction, should any phase of the 
engineering, equipment procurement, or construction of Transmission 
Provider's Interconnection Facilities and Stand Alone Network 
Upgrades not meet the standards and specifications provided by 
Transmission Provider, Interconnection Customer shall be obligated 
to remedy deficiencies in that portion of Transmission Provider's 
Interconnection Facilities and Stand Alone Network Upgrades;
    (7) Interconnection Customer shall indemnify Transmission 
Provider for claims arising from Interconnection Customer's 
construction of Transmission Provider's Interconnection Facilities 
and Stand Alone Network Upgrades under the terms and procedures 
applicable to Article 18.1 Indemnity;
    (8) Interconnection Customer shall transfer control of 
Transmission Provider's Interconnection Facilities and Stand Alone 
Network Upgrades to Transmission Provider;
    (9) Unless Parties otherwise agree, Interconnection Customer 
shall transfer ownership of Transmission Provider's Interconnection 
Facilities and Stand-Alone Network Upgrades to Transmission 
Provider;
    (10) Transmission Provider shall approve and accept for 
operation and maintenance Transmission Provider's Interconnection 
Facilities and Stand Alone Network Upgrades to the extent 
engineered, procured, and constructed in accordance with this 
Article 5.2; and
    (11) Interconnection Customer shall deliver to Transmission 
Provider ``as-built'' drawings, information, and any other documents 
that are reasonably required by Transmission Provider to assure that 
the Interconnection Facilities and Stand-Alone Network Upgrades are 
built to the standards and specifications required by Transmission 
Provider.
    (12) If Interconnection Customer exercises the Option to Build 
pursuant to Article 5.1.3, Interconnection Customer shall pay 
Transmission Provider the agreed upon amount of [$ PLACEHOLDER] for 
Transmission Provider to execute the responsibilities enumerated to 
Transmission Provider under Article 5.2. Transmission Provider shall 
invoice Interconnection Customer for this total amount to be divided 
on a monthly basis pursuant to Article 12.
    5.3 Liquidated Damages. The actual damages to Interconnection 
Customer, in the event Transmission Provider's Interconnection 
Facilities or Network Upgrades are not completed by the dates 
designated by Interconnection Customer and accepted by Transmission 
Provider pursuant to subparagraphs 5.1.2 or 5.1.4, above, may 
include Interconnection Customer's fixed operation and maintenance 
costs and lost opportunity costs. Such actual damages are uncertain 
and impossible to determine at this time. Because of such 
uncertainty, any liquidated damages paid by Transmission Provider to 
Interconnection Customer in the event that Transmission Provider 
does not complete any portion of Transmission Provider's 
Interconnection Facilities or Network Upgrades by the applicable 
dates, shall be an amount equal to \1/2\ of 1 percent per day of the 
actual cost of Transmission Provider's Interconnection Facilities 
and Network Upgrades, in the aggregate, for which Transmission 
Provider has assumed responsibility to design, procure and 
construct.
    However, in no event shall the total liquidated damages exceed 
20 percent of the actual cost of Transmission Provider's 
Interconnection Facilities and Network Upgrades for which 
Transmission Provider has assumed responsibility to design, procure, 
and construct. The foregoing payments will be made by Transmission 
Provider to Interconnection Customer as just compensation for the 
damages caused to Interconnection Customer, which actual damages are 
uncertain and impossible to determine at this time, and as 
reasonable liquidated damages, but not as a penalty or a method to 
secure performance of this LGIA. Liquidated damages, when the 
Parties agree to them, are the exclusive remedy for the Transmission 
Provider's failure to meet its schedule.
    No liquidated damages shall be paid to Interconnection Customer 
if: (1) Interconnection Customer is not ready to commence use of 
Transmission Provider's Interconnection Facilities or Network 
Upgrades to take the delivery of power for the Large Generating 
Facility's Trial Operation or to export power from the Large 
Generating Facility on the specified dates, unless Interconnection 
Customer would have been able to commence use of Transmission 
Provider's Interconnection Facilities or Network Upgrades to take 
the delivery of power for Large Generating Facility's Trial 
Operation or to export power from the Large Generating Facility, but 
for Transmission Provider's delay; (2) Transmission Provider's 
failure to meet the specified dates is the result of the action or 
inaction of Interconnection Customer or any other Interconnection 
Customer who has entered into an LGIA with Transmission Provider or 
any cause beyond Transmission Provider's reasonable control or 
reasonable ability to cure; (3) the Interconnection Customer has 
assumed responsibility for the design, procurement and construction 
of Transmission Provider's Interconnection Facilities and Stand 
Alone Network Upgrades; or (4) the Parties have otherwise agreed.
    5.4 Power System Stabilizers. [The]Interconnection Customer 
shall procure, install, maintain and operate Power System 
Stabilizers in accordance with the guidelines and procedures 
established by the [Applicable Reliability Council]Electric 
Reliability Organization. Transmission Provider reserves the right 
to reasonably establish minimum acceptable settings for any 
installed Power System Stabilizers, subject to the design and 
operating limitations of the Large Generating Facility. If the Large 
Generating Facility's Power System Stabilizers are removed from 
service or not capable of automatic operation, Interconnection 
Customer shall immediately notify Transmission Provider's system 
operator, or its designated representative. The requirements of this 
paragraph shall not apply to wind generators.
    5.5 Equipment Procurement. If responsibility for construction of 
Transmission Provider's Interconnection Facilities or Network 
Upgrades is to be borne by Transmission Provider, then Transmission 
Provider shall commence design of Transmission Provider's 
Interconnection Facilities or Network Upgrades and procure necessary 
equipment as soon as practicable after all of the following 
conditions are satisfied, unless the Parties otherwise agree in 
writing:
    5.5.1 Transmission Provider has completed the Facilities Study 
pursuant to the Facilities Study Agreement;
    5.5.2 Transmission Provider has received written authorization 
to proceed with design and procurement from Interconnection Customer 
by the date specified in Appendix B, Milestones; and
    5.5.3 Interconnection Customer has provided security to 
Transmission Provider in accordance with Article 11.5 by the dates 
specified in Appendix B, Milestones.
    5.6 Construction Commencement. Transmission Provider shall 
commence construction of Transmission Provider's Interconnection 
Facilities and Network Upgrades for which it is responsible as soon 
as practicable after the following additional conditions are 
satisfied:
    5.6.1 Approval of the appropriate Governmental Authority has 
been obtained for any facilities requiring regulatory approval;
    5.6.2 Necessary real property rights and rights-of-way have been 
obtained, to the extent required for the construction of a discrete 
aspect of Transmission Provider's Interconnection Facilities and 
Network Upgrades;
    5.6.3 Transmission Provider has received written authorization 
to proceed with construction from Interconnection Customer by the 
date specified in Appendix B, Milestones; and
    5.6.4 Interconnection Customer has provided security to 
Transmission Provider in accordance with Article 11.5 by the dates 
specified in Appendix B, Milestones.
    5.7 Work Progress. The Parties will keep each other advised 
periodically as to the progress of their respective design, 
procurement and construction efforts. Either Party may, at any time, 
request a progress report from the other Party. If, at any time, 
Interconnection Customer determines that the completion of 
Transmission Provider's Interconnection Facilities will not be 
required until after the specified In-Service Date, Interconnection 
Customer will provide written notice to Transmission Provider of 
such later date upon which the completion of Transmission Provider's 
Interconnection Facilities will be required.
    5.8 Information Exchange. As soon as reasonably practicable 
after the Effective Date, the Parties shall exchange information 
regarding the design and compatibility of the Parties' 
Interconnection Facilities and compatibility of the Interconnection 
Facilities with Transmission Provider's

[[Page 61319]]

Transmission System, and shall work diligently and in good faith to 
make any necessary design changes.
    5.9 Other Interconnection Options.
    5.9.1 Limited Operation. If any of Transmission Provider's 
Interconnection Facilities or Network Upgrades are not reasonably 
expected to be completed prior to the Commercial Operation Date of 
the Large Generating Facility, Transmission Provider shall, upon the 
request and at the expense of Interconnection Customer, perform 
operating studies on a timely basis to determine the extent to which 
the Large Generating Facility and Interconnection Customer's 
Interconnection Facilities may operate prior to the completion of 
Transmission Provider's Interconnection Facilities or Network 
Upgrades consistent with Applicable Laws and Regulations, Applicable 
Reliability Standards, Good Utility Practice, and this LGIA. 
Transmission Provider shall permit Interconnection Customer to 
operate the Large Generating Facility and Interconnection Customer's 
Interconnection Facilities in accordance with the results of such 
studies.
    5.9.2 Provisional Interconnection Service. Upon the request of 
Interconnection Customer, and prior to completion of requisite 
Interconnection Facilities, Network Upgrades, Distribution Upgrades, 
or System Protection Facilities Transmission Provider may execute a 
Provisional Large Generator Interconnection Agreement or 
Interconnection Customer may request the filing of an unexecuted 
Provisional Large Generator Interconnection Agreement with the 
Interconnection Customer for limited Interconnection Service at the 
discretion of Transmission Provider based upon an evaluation that 
will consider the results of available studies. Transmission 
Provider shall determine, through available studies or additional 
studies as necessary, whether stability, short circuit, thermal, 
and/or voltage issues would arise if Interconnection Customer 
interconnects without modifications to the Generating Facility or 
Transmission System. Transmission Provider shall determine whether 
any Interconnection Facilities, Network Upgrades, Distribution 
Upgrades, or System Protection Facilities that are necessary to meet 
the requirements of [NERC] the Electric Reliability Organization, or 
any applicable Regional Entity for the interconnection of a new, 
modified and/or expanded Generating Facility are in place prior to 
the commencement of Interconnection Service from the Generating 
Facility. Where available studies indicate that such, 
Interconnection Facilities, Network Upgrades, Distribution Upgrades, 
and/or System Protection Facilities that are required for the 
interconnection of a new, modified and/or expanded Generating 
Facility are not currently in place, Transmission Provider will 
perform a study, at the Interconnection Customer's expense, to 
confirm the facilities that are required for Provisional 
Interconnection Service. The maximum permissible output of the 
Generating Facility in the Provisional Large Generator 
Interconnection Agreement shall be studied and updated [on a 
frequency determined by Transmission Provider and at the 
Interconnection Customer's expense]. Interconnection Customer 
assumes all risk and liabilities with respect to changes between the 
Provisional Large Generator Interconnection Agreement and the Large 
Generator Interconnection Agreement, including changes in output 
limits and Interconnection Facilities, Network Upgrades, 
Distribution Upgrades, and/or System Protection Facilities cost 
responsibilities.
    5.10 Interconnection Customer's Interconnection Facilities 
('ICIF'). Interconnection Customer shall, at its expense, design, 
procure, construct, own and install the ICIF, as set forth in 
Appendix A, Interconnection Facilities, Network Upgrades and 
Distribution Upgrades.
    5.10.1 Interconnection Customer's Interconnection Facility 
Specifications. Interconnection Customer shall submit initial 
specifications for the ICIF, including System Protection Facilities, 
to Transmission Provider at least one hundred eighty (180) Calendar 
Days prior to the Initial Synchronization Date; and final 
specifications for review and comment at least ninety (90) Calendar 
Days prior to the Initial Synchronization Date. Transmission 
Provider shall review such specifications to ensure that the ICIF 
are compatible with the technical specifications, operational 
control, and safety requirements of Transmission Provider and 
comment on such specifications within thirty (30) Calendar Days of 
Interconnection Customer's submission. All specifications provided 
hereunder shall be deemed confidential.
    5.10.2 Transmission Provider's Review. Transmission Provider's 
review of Interconnection Customer's final specifications shall not 
be construed as confirming, endorsing, or providing a warranty as to 
the design, fitness, safety, durability or reliability of the Large 
Generating Facility, or the ICIF. Interconnection Customer shall 
make such changes to the ICIF as may reasonably be required by 
Transmission Provider, in accordance with Good Utility Practice, to 
ensure that the ICIF are compatible with the technical 
specifications, operational control, and safety requirements of 
Transmission Provider.
    5.10.3 ICIF Construction. The ICIF shall be designed and 
constructed in accordance with Good Utility Practice. Within one 
hundred twenty (120) Calendar Days after the Commercial Operation 
Date, unless the Parties agree on another mutually acceptable 
deadline, Interconnection Customer shall deliver to Transmission 
Provider ``as-built'' drawings, information and documents for the 
ICIF, such as: a one-line diagram, a site plan showing the Large 
Generating Facility and the ICIF, plan and elevation drawings 
showing the layout of the ICIF, a relay functional diagram, relaying 
AC and DC schematic wiring diagrams and relay settings for all 
facilities associated with Interconnection Customer's step-up 
transformers, the facilities connecting the Large Generating 
Facility to the step-up transformers and the ICIF, and the 
impedances (determined by factory tests) for the associated step-up 
transformers and the Large Generating Facility. The Interconnection 
Customer shall provide Transmission Provider specifications for the 
excitation system, automatic voltage regulator, Large Generating 
Facility control and protection settings, transformer tap settings, 
and communications, if applicable.
    5.11 Transmission Provider's Interconnection Facilities 
Construction. Transmission Provider's Interconnection Facilities 
shall be designed and constructed in accordance with Good Utility 
Practice. Upon request, within one hundred twenty (120) Calendar 
Days after the Commercial Operation Date, unless the Parties agree 
on another mutually acceptable deadline, Transmission Provider shall 
deliver to Interconnection Customer the following ``as-built'' 
drawings, information and documents for Transmission Provider's 
Interconnection Facilities [include appropriate drawings and relay 
diagrams].
    Transmission Provider will obtain control of Transmission 
Provider's Interconnection Facilities and Stand Alone Network 
Upgrades upon completion of such facilities.
    5.12 Access Rights. Upon reasonable notice and supervision by a 
Party, and subject to any required or necessary regulatory 
approvals, a Party (``Granting Party'') shall furnish at no cost to 
the other Party (``Access Party'') any rights of use, licenses, 
rights of way and easements with respect to lands owned or 
controlled by the Granting Party, its agents (if allowed under the 
applicable agency agreement), or any Affiliate, that are necessary 
to enable the Access Party to obtain ingress and egress to 
construct, operate, maintain, repair, test (or witness testing), 
inspect, replace or remove facilities and equipment to: (i) 
interconnect the Large Generating Facility with the Transmission 
System; (ii) operate and maintain the Large Generating Facility, the 
Interconnection Facilities and the Transmission System; and (iii) 
disconnect or remove the Access Party's facilities and equipment 
upon termination of this LGIA. In exercising such licenses, rights 
of way and easements, the Access Party shall not unreasonably 
disrupt or interfere with normal operation of the Granting Party's 
business and shall adhere to the safety rules and procedures 
established in advance, as may be changed from time to time, by the 
Granting Party and provided to the Access Party.
    5.13 Lands of Other Property Owners. If any part of Transmission 
Provider or Transmission Owner's Interconnection Facilities and/or 
Network Upgrades is to be installed on property owned by persons 
other than Interconnection Customer or Transmission Provider or 
Transmission Owner, Transmission Provider or Transmission Owner 
shall at Interconnection Customer's expense use efforts, similar in 
nature and extent to those that it typically undertakes on its own 
behalf or on behalf of its Affiliates, including use of its eminent 
domain authority, and to the extent consistent with state law, to 
procure from such persons any rights of use, licenses, rights of way 
and easements that are necessary to construct, operate, maintain, 
test, inspect, replace or remove Transmission

[[Page 61320]]

Provider or Transmission Owner's Interconnection Facilities and/or 
Network Upgrades upon such property.
    5.14 Permits. Transmission Provider or Transmission Owner and 
Interconnection Customer shall cooperate with each other in good 
faith in obtaining all permits, licenses, and authorizations that 
are necessary to accomplish the interconnection in compliance with 
Applicable Laws and Regulations. With respect to this paragraph, 
Transmission Provider or Transmission Owner shall provide permitting 
assistance to Interconnection Customer comparable to that provided 
to Transmission Provider's own, or an Affiliate's generation.
    5.15 Early Construction of Base Case Facilities. Interconnection 
Customer may request Transmission Provider to construct, and 
Transmission Provider shall construct, using Reasonable Efforts to 
accommodate Interconnection Customer's In-Service Date, all or any 
portion of any Network Upgrades required for Interconnection 
Customer to be interconnected to the Transmission System which are 
included in the Base Case of the Facilities Study for 
Interconnection Customer, and which also are required to be 
constructed for another Interconnection Customer, but where such 
construction is not scheduled to be completed in time to achieve 
Interconnection Customer's In-Service Date.
    5.16 Suspension. Interconnection Customer reserves the right, 
upon written notice to Transmission Provider, to suspend at any time 
all work by Transmission Provider associated with the construction 
and installation of Transmission Provider's Interconnection 
Facilities and/or Network Upgrades required under this LGIA with the 
condition that Transmission System shall be left in a safe and 
reliable condition in accordance with Good Utility Practice and 
Transmission Provider's safety and reliability criteria. In such 
event, Interconnection Customer shall be responsible for all 
reasonable and necessary costs which Transmission Provider (i) has 
incurred pursuant to this LGIA prior to the suspension and (ii) 
incurs in suspending such work, including any costs incurred to 
perform such work as may be necessary to ensure the safety of 
persons and property and the integrity of the Transmission System 
during such suspension and, if applicable, any costs incurred in 
connection with the cancellation or suspension of material, 
equipment and labor contracts which Transmission Provider cannot 
reasonably avoid; provided, however, that prior to canceling or 
suspending any such material, equipment or labor contract, 
Transmission Provider shall obtain Interconnection Customer's 
authorization to do so.
    Transmission Provider shall invoice Interconnection Customer for 
such costs pursuant to Article 12 and shall use due diligence to 
minimize its costs. In the event Interconnection Customer suspends 
work by Transmission Provider required under this LGIA pursuant to 
this Article 5.16, and has not requested Transmission Provider to 
recommence the work required under this LGIA on or before the 
expiration of three (3) years following commencement of such 
suspension, this LGIA shall be deemed terminated. The three-year 
period shall begin on the date the suspension is requested, or the 
date of the written notice to Transmission Provider, if no effective 
date is specified.
    5.17 Taxes.
    5.17.1 Interconnection Customer Payments Not Taxable. The 
Parties intend that all payments or property transfers made by 
Interconnection Customer to Transmission Provider for the 
installation of Transmission Provider's Interconnection Facilities 
and the Network Upgrades shall be non-taxable, either as 
contributions to capital, or as an advance, in accordance with the 
Internal Revenue Code and any applicable state income tax laws and 
shall not be taxable as contributions in aid of construction or 
otherwise under the Internal Revenue Code and any applicable state 
income tax laws.
    5.17.2 Representations and Covenants. In accordance with IRS 
Notice 2001-82 and IRS Notice 88-129, Interconnection Customer 
represents and covenants that (i) ownership of the electricity 
generated at the Large Generating Facility will pass to another 
party prior to the transmission of the electricity on the 
Transmission System, (ii) for income tax purposes, the amount of any 
payments and the cost of any property transferred to Transmission 
Provider for Transmission Provider's Interconnection Facilities will 
be capitalized by Interconnection Customer as an intangible asset 
and recovered using the straight-line method over a useful life of 
twenty (20) years, and (iii) any portion of Transmission Provider's 
Interconnection Facilities that is a ``dual-use intertie,'' within 
the meaning of IRS Notice 88-129, is reasonably expected to carry 
only a de minimis amount of electricity in the direction of the 
Large Generating Facility. For this purpose, ``de minimis amount'' 
means no more than 5 percent of the total power flows in both 
directions, calculated in accordance with the ``5 percent test'' set 
forth in IRS Notice 88-129. This is not intended to be an exclusive 
list of the relevant conditions that must be met to conform to IRS 
requirements for non-taxable treatment.
    At Transmission Provider's request, Interconnection Customer 
shall provide Transmission Provider with a report from an 
independent engineer confirming its representation in clause (iii), 
above. Transmission Provider represents and covenants that the cost 
of Transmission Provider's Interconnection Facilities paid for by 
Interconnection Customer will have no net effect on the base upon 
which rates are determined.
    5.17.3 Indemnification for the Cost Consequences of Current Tax 
Liability Imposed Upon the Transmission Provider. Notwithstanding 
Article 5.17.1, Interconnection Customer shall protect, indemnify 
and hold harmless Transmission Provider from the cost consequences 
of any current tax liability imposed against Transmission Provider 
as the result of payments or property transfers made by 
Interconnection Customer to Transmission Provider under this LGIA 
for Interconnection Facilities, as well as any interest and 
penalties, other than interest and penalties attributable to any 
delay caused by Transmission Provider.
    Transmission Provider shall not include a gross-up for the cost 
consequences of any current tax liability in the amounts it charges 
Interconnection Customer under this LGIA unless (i) Transmission 
Provider has determined, in good faith, that the payments or 
property transfers made by Interconnection Customer to Transmission 
Provider should be reported as income subject to taxation or (ii) 
any Governmental Authority directs Transmission Provider to report 
payments or property as income subject to taxation; provided, 
however, that Transmission Provider may require Interconnection 
Customer to provide security for Interconnection Facilities, in a 
form reasonably acceptable to Transmission Provider (such as a 
parental guarantee or a letter of credit), in an amount equal to the 
cost consequences of any current tax liability under this Article 
5.17. Interconnection Customer shall reimburse Transmission Provider 
for such costs on a fully grossed-up basis, in accordance with 
Article 5.17.4, within thirty (30) Calendar Days of receiving 
written notification from Transmission Provider of the amount due, 
including detail about how the amount was calculated.
    The indemnification obligation shall terminate at the earlier of 
(1) the expiration of the ten year testing period and the applicable 
statute of limitation, as it may be extended by Transmission 
Provider upon request of the IRS, to keep these years open for audit 
or adjustment, or (2) the occurrence of a subsequent taxable event 
and the payment of any related indemnification obligations as 
contemplated by this Article 5.17.
    5.17.4 Tax Gross-Up Amount. Interconnection Customer's liability 
for the cost consequences of any current tax liability under this 
Article 5.17 shall be calculated on a fully grossed-up basis. Except 
as may otherwise be agreed to by the parties, this means that 
Interconnection Customer will pay Transmission Provider, in addition 
to the amount paid for the Interconnection Facilities and Network 
Upgrades, an amount equal to (1) the current taxes imposed on 
Transmission Provider (``Current Taxes'') on the excess of (a) the 
gross income realized by Transmission Provider as a result of 
payments or property transfers made by Interconnection Customer to 
Transmission Provider under this LGIA (without regard to any 
payments under this Article 5.17) (the ``Gross Income Amount'') over 
(b) the present value of future tax deductions for depreciation that 
will be available as a result of such payments or property transfers 
(the ``Present Value Depreciation Amount''), plus (2) an additional 
amount sufficient to permit Transmission Provider to receive and 
retain, after the payment of all Current Taxes, an amount equal to 
the net amount described in clause (1).
    For this purpose, (i) Current Taxes shall be computed based on 
Transmission Provider's composite federal and state tax rates at the 
time the payments or property transfers are received and 
Transmission Provider will be treated as being subject to tax at the 
highest marginal rates in effect at that time (the ``Current Tax 
Rate''), and (ii) the Present Value Depreciation Amount shall be

[[Page 61321]]

computed by discounting Transmission Provider's anticipated tax 
depreciation deductions as a result of such payments or property 
transfers by Transmission Provider's current weighted average cost 
of capital. Thus, the formula for calculating Interconnection 
Customer's liability to Transmission Owner pursuant to this Article 
5.17.4 can be expressed as follows: (Current Tax Rate x (Gross 
Income Amount--Present Value of Tax Depreciation))/(1-Current Tax 
Rate). Interconnection Customer's estimated tax liability in the 
event taxes are imposed shall be stated in Appendix A, 
Interconnection Facilities, Network Upgrades and Distribution 
Upgrades.
    5.17.5 Private Letter Ruling or Change or Clarification of Law. 
At Interconnection Customer's request and expense, Transmission 
Provider shall file with the IRS a request for a private letter 
ruling as to whether any property transferred or sums paid, or to be 
paid, by Interconnection Customer to Transmission Provider under 
this LGIA are subject to federal income taxation. Interconnection 
Customer will prepare the initial draft of the request for a private 
letter ruling, and will certify under penalties of perjury that all 
facts represented in such request are true and accurate to the best 
of Interconnection Customer's knowledge. Transmission Provider and 
Interconnection Customer shall cooperate in good faith with respect 
to the submission of such request.
    Transmission Provider shall keep Interconnection Customer fully 
informed of the status of such request for a private letter ruling 
and shall execute either a privacy act waiver or a limited power of 
attorney, in a form acceptable to the IRS, that authorizes 
Interconnection Customer to participate in all discussions with the 
IRS regarding such request for a private letter ruling. Transmission 
Provider shall allow Interconnection Customer to attend all meetings 
with IRS officials about the request and shall permit 
Interconnection Customer to prepare the initial drafts of any 
follow-up letters in connection with the request.
    5.17.6 Subsequent Taxable Events. If, within 10 years from the 
date on which the relevant Transmission Provider's Interconnection 
Facilities are placed in service, (i) Interconnection Customer 
Breaches the covenants contained in Article 5.17.2, (ii) a 
``disqualification event'' occurs within the meaning of IRS Notice 
88-129, or (iii) this LGIA terminates and Transmission Provider 
retains ownership of the Interconnection Facilities and Network 
Upgrades, Interconnection Customer shall pay a tax gross-up for the 
cost consequences of any current tax liability imposed on 
Transmission Provider, calculated using the methodology described in 
Article 5.17.4 and in accordance with IRS Notice 90-60.
    5.17.7 Contests. In the event any Governmental Authority 
determines that Transmission Provider's receipt of payments or 
property constitutes income that is subject to taxation, 
Transmission Provider shall notify Interconnection Customer, in 
writing, within thirty (30) Calendar Days of receiving notification 
of such determination by a Governmental Authority. Upon the timely 
written request by Interconnection Customer and at Interconnection 
Customer's sole expense, Transmission Provider may appeal, protest, 
seek abatement of, or otherwise oppose such determination. Upon 
Interconnection Customer's written request and sole expense, 
Transmission Provider may file a claim for refund with respect to 
any taxes paid under this Article 5.17, whether or not it has 
received such a determination. Transmission Provider reserves the 
right to make all decisions with regard to the prosecution of such 
appeal, protest, abatement or other contest, including the selection 
of counsel and compromise or settlement of the claim, but 
Transmission Provider shall keep Interconnection Customer informed, 
shall consider in good faith suggestions from Interconnection 
Customer about the conduct of the contest, and shall reasonably 
permit Interconnection Customer or an Interconnection Customer 
representative to attend contest proceedings.
    Interconnection Customer shall pay to Transmission Provider on a 
periodic basis, as invoiced by Transmission Provider, Transmission 
Provider's documented reasonable costs of prosecuting such appeal, 
protest, abatement or other contest. At any time during the contest, 
Transmission Provider may agree to a settlement either with 
Interconnection Customer's consent or after obtaining written advice 
from nationally recognized tax counsel, selected by Transmission 
Provider, but reasonably acceptable to Interconnection Customer, 
that the proposed settlement represents a reasonable settlement 
given the hazards of litigation. Interconnection Customer's 
obligation shall be based on the amount of the settlement agreed to 
by Interconnection Customer, or if a higher amount, so much of the 
settlement that is supported by the written advice from nationally 
recognized tax counsel selected under the terms of the preceding 
sentence. The settlement amount shall be calculated on a fully 
grossed-up basis to cover any related cost consequences of the 
current tax liability. Any settlement without Interconnection 
Customer's consent or such written advice will relieve 
Interconnection Customer from any obligation to indemnify 
Transmission Provider for the tax at issue in the contest.
    5.17.8 Refund. In the event that (a) a private letter ruling is 
issued to Transmission Provider which holds that any amount paid or 
the value of any property transferred by Interconnection Customer to 
Transmission Provider under the terms of this LGIA is not subject to 
federal income taxation, (b) any legislative change or 
administrative announcement, notice, ruling or other determination 
makes it reasonably clear to Transmission Provider in good faith 
that any amount paid or the value of any property transferred by 
Interconnection Customer to Transmission Provider under the terms of 
this LGIA is not taxable to Transmission Provider, (c) any 
abatement, appeal, protest, or other contest results in a 
determination that any payments or transfers made by Interconnection 
Customer to Transmission Provider are not subject to federal income 
tax, or (d) if Transmission Provider receives a refund from any 
taxing authority for any overpayment of tax attributable to any 
payment or property transfer made by Interconnection Customer to 
Transmission Provider pursuant to this LGIA, Transmission Provider 
shall promptly refund to Interconnection Customer the following:
    (i) any payment made by Interconnection Customer under this 
Article 5.17 for taxes that is attributable to the amount determined 
to be non-taxable, together with interest thereon,
    (ii) interest on any amounts paid by Interconnection Customer to 
Transmission Provider for such taxes which Transmission Provider did 
not submit to the taxing authority, calculated in accordance with 
the methodology set forth in FERC's regulations at 18 CFR 
35.19a(a)(2)(iii) from the date payment was made by Interconnection 
Customer to the date Transmission Provider refunds such payment to 
Interconnection Customer, and
    (iii) with respect to any such taxes paid by Transmission 
Provider, any refund or credit Transmission Provider receives or to 
which it may be entitled from any Governmental Authority, interest 
(or that portion thereof attributable to the payment described in 
clause (i), above) owed to Transmission Provider for such 
overpayment of taxes (including any reduction in interest otherwise 
payable by Transmission Provider to any Governmental Authority 
resulting from an offset or credit); provided, however, that 
Transmission Provider will remit such amount promptly to 
Interconnection Customer only after and to the extent that 
Transmission Provider has received a tax refund, credit or offset 
from any Governmental Authority for any applicable overpayment of 
income tax related to Transmission Provider's Interconnection 
Facilities.
    The intent of this provision is to leave the Parties, to the 
extent practicable, in the event that no taxes are due with respect 
to any payment for Interconnection Facilities and Network Upgrades 
hereunder, in the same position they would have been in had no such 
tax payments been made.
    5.17.9 Taxes Other Than Income Taxes. Upon the timely request by 
Interconnection Customer, and at Interconnection Customer's sole 
expense, Transmission Provider may appeal, protest, seek abatement 
of, or otherwise contest any tax (other than federal or state income 
tax) asserted or assessed against Transmission Provider for which 
Interconnection Customer may be required to reimburse Transmission 
Provider under the terms of this LGIA. Interconnection Customer 
shall pay to Transmission Provider on a periodic basis, as invoiced 
by Transmission Provider, Transmission Provider's documented 
reasonable costs of prosecuting such appeal, protest, abatement, or 
other contest. Interconnection Customer and Transmission Provider 
shall cooperate in good faith with respect to any such contest. 
Unless the payment of such taxes is a prerequisite to an appeal or 
abatement or cannot be deferred, no amount shall be payable by 
Interconnection Customer to Transmission Provider for such taxes 
until they are assessed by a final, non-appealable order by any 
court or agency of competent

[[Page 61322]]

jurisdiction. In the event that a tax payment is withheld and 
ultimately due and payable after appeal, Interconnection Customer 
will be responsible for all taxes, interest and penalties, other 
than penalties attributable to any delay caused by Transmission 
Provider.
    5.17.10 Transmission Owners Who Are Not Transmission Providers. 
If Transmission Provider is not the same entity as the Transmission 
Owner, then (i) all references in this Article 5.17 to Transmission 
Provider shall be deemed also to refer to and to include the 
Transmission Owner, as appropriate, and (ii) this LGIA shall not 
become effective until such Transmission Owner shall have agreed in 
writing to assume all of the duties and obligations of Transmission 
Provider under this Article 5.17 of this LGIA.
    5.18 Tax Status. Each Party shall cooperate with the other to 
maintain the other Party's tax status. Nothing in this LGIA is 
intended to adversely affect any Transmission Provider's tax exempt 
status with respect to the issuance of bonds including, but not 
limited to, Local Furnishing Bonds.
    5.19 Modification.
    5.19.1 General. Either Party may undertake modifications to its 
facilities. If a Party plans to undertake a modification that 
reasonably may be expected to affect the other Party's facilities, 
that Party shall provide to the other Party sufficient information 
regarding such modification so that the other Party may evaluate the 
potential impact of such modification prior to commencement of the 
work. Such information shall be deemed to be confidential hereunder 
and shall include information concerning the timing of such 
modifications and whether such modifications are expected to 
interrupt the flow of electricity from the Large Generating 
Facility. The Party desiring to perform such work shall provide the 
relevant drawings, plans, and specifications to the other Party at 
least ninety (90) Calendar Days in advance of the commencement of 
the work or such shorter period upon which the Parties may agree, 
which agreement shall not unreasonably be withheld, conditioned or 
delayed.
    In the case of Large Generating Facility modifications that do 
not require Interconnection Customer to submit an Interconnection 
Request, Transmission Provider shall provide, within thirty (30) 
Calendar Days (or such other time as the Parties may agree), an 
estimate of any additional modifications to the Transmission System, 
Transmission Provider's Interconnection Facilities or Network 
Upgrades necessitated by such Interconnection Customer modification 
and a good faith estimate of the costs thereof.
    5.19.2 Standards. Any additions, modifications, or replacements 
made to a Party's facilities shall be designed, constructed and 
operated in accordance with this LGIA and Good Utility Practice.
    5.19.3 Modification Costs. Interconnection Customer shall not be 
directly assigned for the costs of any additions, modifications, or 
replacements that Transmission Provider makes to Transmission 
Provider's Interconnection Facilities or the Transmission System to 
facilitate the interconnection of a third party to Transmission 
Provider's Interconnection Facilities or the Transmission System, or 
to provide transmission service to a third party under Transmission 
Provider's Tariff. Interconnection Customer shall be responsible for 
the costs of any additions, modifications, or replacements to 
Interconnection Customer's Interconnection Facilities that may be 
necessary to maintain or upgrade such Interconnection Customer's 
Interconnection Facilities consistent with Applicable Laws and 
Regulations, Applicable Reliability Standards or Good Utility 
Practice.

Article 6. Testing and Inspection

    6.1 Pre-Commercial Operation Date Testing and Modifications. 
Prior to the Commercial Operation Date, Transmission Provider shall 
test Transmission Provider's Interconnection Facilities and Network 
Upgrades and Interconnection Customer shall test the Large 
Generating Facility and Interconnection Customer's Interconnection 
Facilities to ensure their safe and reliable operation. Similar 
testing may be required after initial operation. Each Party shall 
make any modifications to its facilities that are found to be 
necessary as a result of such testing. Interconnection Customer 
shall bear the cost of all such testing and modifications. 
Interconnection Customer shall generate test energy at the Large 
Generating Facility only if it has arranged for the delivery of such 
test energy.
    6.2 Post-Commercial Operation Date Testing and Modifications. 
Each Party shall at its own expense perform routine inspection and 
testing of its facilities and equipment in accordance with Good 
Utility Practice as may be necessary to ensure the continued 
interconnection of the Large Generating Facility with the 
Transmission System in a safe and reliable manner. Each Party shall 
have the right, upon advance written notice, to require reasonable 
additional testing of the other Party's facilities, at the 
requesting Party's expense, as may be in accordance with Good 
Utility Practice.
    6.3 Right to Observe Testing. Each Party shall notify the other 
Party in advance of its performance of tests of its Interconnection 
Facilities. The other Party has the right, at its own expense, to 
observe such testing.
    6.4 Right to Inspect. Each Party shall have the right, but shall 
have no obligation to: (i) observe the other Party's tests and/or 
inspection of any of its System Protection Facilities and other 
protective equipment, including Power System Stabilizers; (ii) 
review the settings of the other Party's System Protection 
Facilities and other protective equipment; and (iii) review the 
other Party's maintenance records relative to the Interconnection 
Facilities, the System Protection Facilities and other protective 
equipment. A Party may exercise these rights from time to time as it 
deems necessary upon reasonable notice to the other Party. The 
exercise or non-exercise by a Party of any such rights shall not be 
construed as an endorsement or confirmation of any element or 
condition of the Interconnection Facilities or the System Protection 
Facilities or other protective equipment or the operation thereof, 
or as a warranty as to the fitness, safety, desirability, or 
reliability of same. Any information that a Party obtains through 
the exercise of any of its rights under this Article 6.4 shall be 
deemed to be Confidential Information and treated pursuant to 
Article 22 of this LGIA.

Article 7. Metering

    7.1 General. Each Party shall comply with the [Applicable 
Reliability Council] Electric Reliability Organization requirements. 
Unless otherwise agreed by the Parties, Transmission Provider shall 
install Metering Equipment at the Point of Interconnection prior to 
any operation of the Large Generating Facility and shall own, 
operate, test and maintain such Metering Equipment. Power flows to 
and from the Large Generating Facility shall be measured at or, at 
Transmission Provider's option, compensated to, the Point of 
Interconnection. Transmission Provider shall provide metering 
quantities, in analog and/or digital form, to Interconnection 
Customer upon request. Interconnection Customer shall bear all 
reasonable documented costs associated with the purchase, 
installation, operation, testing and maintenance of the Metering 
Equipment.
    7.2 Check Meters. Interconnection Customer, at its option and 
expense, may install and operate, on its premises and on its side of 
the Point of Interconnection, one or more check meters to check 
Transmission Provider's meters. Such check meters shall be for check 
purposes only and shall not be used for the measurement of power 
flows for purposes of this LGIA, except as provided in Article 7.4 
below. The check meters shall be subject at all reasonable times to 
inspection and examination by Transmission Provider or its designee. 
The installation, operation and maintenance thereof shall be 
performed entirely by Interconnection Customer in accordance with 
Good Utility Practice.
    7.3 Standards. Transmission Provider shall install, calibrate, 
and test revenue quality Metering Equipment in accordance with 
applicable ANSI standards.
    7.4 Testing of Metering Equipment. Transmission Provider shall 
inspect and test all Transmission Provider-owned Metering Equipment 
upon installation and at least once every two (2) years thereafter. 
If requested to do so by Interconnection Customer, Transmission 
Provider shall, at Interconnection Customer's expense, inspect or 
test Metering Equipment more frequently than every two (2) years. 
Transmission Provider shall give reasonable notice of the time when 
any inspection or test shall take place, and Interconnection 
Customer may have representatives present at the test or inspection. 
If at any time Metering Equipment is found to be inaccurate or 
defective, it shall be adjusted, repaired or replaced at 
Interconnection Customer's expense, in order to provide accurate 
metering, unless the inaccuracy or defect is due to Transmission 
Provider's failure to maintain, then Transmission Provider shall 
pay. If Metering Equipment fails to register,

[[Page 61323]]

or if the measurement made by Metering Equipment during a test 
varies by more than two percent from the measurement made by the 
standard meter used in the test, Transmission Provider shall adjust 
the measurements by correcting all measurements for the period 
during which Metering Equipment was in error by using 
Interconnection Customer's check meters, if installed. If no such 
check meters are installed or if the period cannot be reasonably 
ascertained, the adjustment shall be for the period immediately 
preceding the test of the Metering Equipment equal to one-half the 
time from the date of the last previous test of the Metering 
Equipment.
    7.5 Metering Data. At Interconnection Customer's expense, the 
metered data shall be telemetered to one or more locations 
designated by Transmission Provider and one or more locations 
designated by Interconnection Customer. Such telemetered data shall 
be used, under normal operating conditions, as the official 
measurement of the amount of energy delivered from the Large 
Generating Facility to the Point of Interconnection.

Article 8. Communications

    8.1 Interconnection Customer Obligations. Interconnection 
Customer shall maintain satisfactory operating communications with 
Transmission Provider's Transmission System dispatcher or 
representative designated by Transmission Provider. Interconnection 
Customer shall provide standard voice line, dedicated voice line and 
facsimile communications at its Large Generating Facility control 
room or central dispatch facility through use of either the public 
telephone system, or a voice communications system that does not 
rely on the public telephone system. Interconnection Customer shall 
also provide the dedicated data circuit(s) necessary to provide 
Interconnection Customer data to Transmission Provider as set forth 
in Appendix D, Security Arrangements Details. The data circuit(s) 
shall extend from the Large Generating Facility to the location(s) 
specified by Transmission Provider. Any required maintenance of such 
communications equipment shall be performed by Interconnection 
Customer. Operational communications shall be activated and 
maintained under, but not be limited to, the following events: 
system paralleling or separation, scheduled and unscheduled 
shutdowns, equipment clearances, and hourly and daily load data.
    8.2 Remote Terminal Unit. Prior to the Initial Synchronization 
Date of the Large Generating Facility, a Remote Terminal Unit, or 
equivalent data collection and transfer equipment acceptable to the 
Parties, shall be installed by Interconnection Customer, or by 
Transmission Provider at Interconnection Customer's expense, to 
gather accumulated and instantaneous data to be telemetered to the 
location(s) designated by Transmission Provider through use of a 
dedicated point-to-point data circuit(s) as indicated in Article 
8.1. The communication protocol for the data circuit(s) shall be 
specified by Transmission Provider. Instantaneous bi-directional 
analog real power and reactive power flow information must be 
telemetered directly to the location(s) specified by Transmission 
Provider.
    Each Party will promptly advise the other Party if it detects or 
otherwise learns of any metering, telemetry or communications 
equipment errors or malfunctions that require the attention and/or 
correction by the other Party. The Party owning such equipment shall 
correct such error or malfunction as soon as reasonably feasible.
    8.3 No Annexation. Any and all equipment placed on the premises 
of a Party shall be and remain the property of the Party providing 
such equipment regardless of the mode and manner of annexation or 
attachment to real property, unless otherwise mutually agreed by the 
Parties.
    8.4 Provision of Data from a Variable Energy Resource. The 
Interconnection Customer whose Generating Facility contains at least 
one[is] Variable Energy Resource shall provide meteorological and 
forced outage data to the Transmission Provider to the extent 
necessary for the Transmission Provider's development and deployment 
of power production forecasts for that class of Variable Energy 
Resources. The Interconnection Customer with a Variable Energy 
Resource having wind as the energy source, at a minimum, will be 
required to provide the Transmission Provider with site-specific 
meteorological data including: temperature, wind speed, wind 
direction, and atmospheric pressure. The Interconnection Customer 
with a Variable Energy Resource having solar as the energy source, 
at a minimum, will be required to provide the Transmission Provider 
with site-specific meteorological data including: temperature, 
atmospheric pressure, and irradiance. The Transmission Provider and 
Interconnection Customer whose Generating Facility contains [is] a 
Variable Energy Resource shall mutually agree to any additional 
meteorological data that are required for the development and 
deployment of a power production forecast. The Interconnection 
Customer whose Generating Facility contains [is] a Variable Energy 
Resource also shall submit data to the Transmission Provider 
regarding all forced outages to the extent necessary for the 
Transmission Provider's development and deployment of power 
production forecasts for that class of Variable Energy Resources. 
The exact specifications of the meteorological and forced outage 
data to be provided by the Interconnection Customer to the 
Transmission Provider, including the frequency and timing of data 
submittals, shall be made taking into account the size and 
configuration of the Variable Energy Resource, its characteristics, 
location, and its importance in maintaining generation resource 
adequacy and transmission system reliability in its area. All 
requirements for meteorological and forced outage data must be 
commensurate with the power production forecasting employed by the 
Transmission Provider. Such requirements for meteorological and 
forced outage data are set forth in Appendix C, Interconnection 
Details, of this LGIA, as they may change from time to time.

Article 9. Operations

    9.1 General. Each Party shall comply with the[Applicable 
Reliability Council] Electric Reliability Organization requirements. 
Each Party shall provide to the other Party all information that may 
reasonably be required by the other Party to comply with Applicable 
Laws and Regulations and Applicable Reliability Standards.
    9.2 [Control Area]Balancing Authority Area Notification. At 
least three months before Initial Synchronization Date, 
Interconnection Customer shall notify Transmission Provider in 
writing of the [Control Area]Balancing Authority Area in which the 
Large Generating Facility will be located. If Interconnection 
Customer elects to locate the Large Generating Facility in a[Control 
Area] Balancing Authority Area other than the [Control 
Area]Balancing Authority Area in which the Large Generating Facility 
is physically located, and if permitted to do so by the relevant 
transmission tariffs, all necessary arrangements, including but not 
limited to those set forth in Article 7 and Article 8 of this LGIA, 
and remote [Control Area]Balancing Authority Area generator 
interchange agreements, if applicable, and the appropriate measures 
under such agreements, shall be executed and implemented prior to 
the placement of the Large Generating Facility in the other [Control 
Area]Balancing Authority Area.
    9.3 Transmission Provider Obligations. Transmission Provider 
shall cause the Transmission System and Transmission Provider's 
Interconnection Facilities to be operated, maintained and controlled 
in a safe and reliable manner and in accordance with this LGIA. 
Transmission Provider may provide operating instructions to 
Interconnection Customer consistent with this LGIA and Transmission 
Provider's operating protocols and procedures as they may change 
from time to time. Transmission Provider will consider changes to 
its operating protocols and procedures proposed by Interconnection 
Customer.
    9.4 Interconnection Customer Obligations. Interconnection 
Customer shall at its own expense operate, maintain and control the 
Large Generating Facility and Interconnection Customer's 
Interconnection Facilities in a safe and reliable manner and in 
accordance with this LGIA. Interconnection Customer shall operate 
the Large Generating Facility and Interconnection Customer's 
Interconnection Facilities in accordance with all applicable 
requirements of the [Control Area]Balancing Authority Area of which 
it is part, as such requirements are set forth in Appendix C, 
Interconnection Details, of this LGIA. Appendix C, Interconnection 
Details, will be modified to reflect changes to the requirements as 
they may change from time to time. Either Party may request that the 
other Party provide copies of the requirements set forth in Appendix 
C, Interconnection Details, of this LGIA.
    9.5 Start-Up and Synchronization. Consistent with the Parties' 
mutually acceptable procedures, Interconnection Customer is 
responsible for the proper synchronization of the Large Generating

[[Page 61324]]

Facility to Transmission Provider's Transmission System.
    9.6 Reactive Power and Primary Frequency Response.
    9.6.1 Power Factor Design Criteria.
    9.6.1.1 Synchronous Generation. Interconnection Customer shall 
design the Large Generating Facility to maintain a composite power 
delivery at continuous rated power output at the Point of 
Interconnection at a power factor within the range of 0.95 leading 
to 0.95 lagging, unless [the]Transmission Provider has established 
different requirements that apply to all synchronous generators in 
the [Control Area]Balancing Authority Area on a comparable basis.
    9.6.1.2 Non-Synchronous Generation. Interconnection Customer 
shall design the Large Generating Facility to maintain a composite 
power delivery at continuous rated power output at the high-side of 
the generator substation at a power factor within the range of 0.95 
leading to 0.95 lagging, unless[the] Transmission Provider has 
established a different power factor range that applies to all non-
synchronous generators in the [Control Area]Balancing Authority Area 
on a comparable basis. This power factor range standard shall be 
dynamic and can be met using, for example, power electronics 
designed to supply this level of reactive capability (taking into 
account any limitations due to voltage level, real power output, 
etc.) or fixed and switched capacitors, or a combination of the two. 
This requirement shall only apply to newly interconnecting non-
synchronous generators that have not yet executed a Facilities Study 
Agreement as of the effective date of the Final rule establishing 
this requirement (Order No. 827).
    9.6.2 Voltage Schedules. Once Interconnection Customer has 
synchronized the Large Generating Facility with the Transmission 
System, Transmission Provider shall require Interconnection Customer 
to operate the Large Generating Facility to produce or absorb 
reactive power within the design limitations of the Large Generating 
Facility set forth in Article 9.6.1 (Power Factor Design Criteria). 
Transmission Provider's voltage schedules shall treat all sources of 
reactive power in the [Control Area]Balancing Authority Area in an 
equitable and not unduly discriminatory manner. Transmission 
Provider shall exercise Reasonable Efforts to provide 
Interconnection Customer with such schedules at least one (1) day in 
advance, and may make changes to such schedules as necessary to 
maintain the reliability of the Transmission System. Interconnection 
Customer shall operate the Large Generating Facility to maintain the 
specified output voltage or power factor at the Point of 
Interconnection within the design limitations of the Large 
Generating Facility set forth in Article 9.6.1 (Power Factor Design 
Criteria). If Interconnection Customer is unable to maintain the 
specified voltage or power factor, it shall promptly notify the 
System Operator.
    9.6.2.1 Voltage Regulators. Whenever the Large Generating 
Facility is operated in parallel with the Transmission System and 
voltage regulators are capable of operation, Interconnection 
Customer shall operate the Large Generating Facility with its 
voltage regulators in automatic operation. If the Large Generating 
Facility's voltage regulators are not capable of such automatic 
operation, Interconnection Customer shall immediately notify 
Transmission Provider's system operator, or its designated 
representative, and ensure that such Large Generating Facility's 
reactive power production or absorption (measured in MVARs) are 
within the design capability of the Large Generating Facility's 
generating unit(s) and steady state stability limits. 
Interconnection Customer shall not cause its Large Generating 
Facility to disconnect automatically or instantaneously from the 
Transmission System or trip any generating unit comprising the Large 
Generating Facility for an under or over frequency condition unless 
the abnormal frequency condition persists for a time period beyond 
the limits set forth in ANSI/IEEE Standard C37.106, or such other 
standard as applied to other generators in the [Control 
Area]Balancing Authority Area on a comparable basis.
    9.6.3 Payment for Reactive Power. Transmission Provider is 
required to pay Interconnection Customer for reactive power that 
Interconnection Customer provides or absorbs from the Large 
Generating Facility when Transmission Provider requests 
Interconnection Customer to operate its Large Generating Facility 
outside the range specified in Article 9.6.1, provided that if 
Transmission Provider pays its own or affiliated generators for 
reactive power service within the specified range, it must also pay 
Interconnection Customer. Payments shall be pursuant to Article 11.6 
or such other agreement to which the Parties have otherwise agreed.
    9.6.4 Primary Frequency Response. Interconnection Customer shall 
ensure the primary frequency response capability of its Large 
Generating Facility by installing, maintaining, and operating a 
functioning governor or equivalent controls. The term ``functioning 
governor or equivalent controls'' as used herein shall mean the 
required hardware and/or software that provides frequency responsive 
real power control with the ability to sense changes in system 
frequency and autonomously adjust the Large Generating Facility's 
real power output in accordance with the droop and deadband 
parameters and in the direction needed to correct frequency 
deviations. Interconnection Customer is required to install a 
governor or equivalent controls with the capability of operating: 
(1) with a maximum 5 percent droop and 0.036 Hz 
deadband; or (2) in accordance with the relevant droop, deadband, 
and timely and sustained response settings from an approved [NERC] 
Electric Reliability Organization [R]reliability [S]standard 
providing for equivalent or more stringent parameters. The droop 
characteristic shall be: (1) based on the nameplate capacity of the 
Large Generating Facility, and shall be linear in the range of 
frequencies between 59 to 61 Hz that are outside of the deadband 
parameter; or (2) based an approved [NERC] Electric Reliability 
Organization [R]reliability [S]standard providing for an equivalent 
or more stringent parameter. The deadband parameter shall be: the 
range of frequencies above and below nominal (60 Hz) in which the 
governor or equivalent controls is not expected to adjust the Large 
Generating Facility's real power output in response to frequency 
deviations. The deadband shall be implemented: (1) without a step to 
the droop curve, that is, once the frequency deviation exceeds the 
deadband parameter, the expected change in the Large Generating 
Facility's real power output in response to frequency deviations 
shall start from zero and then increase (for under-frequency 
deviations) or decrease (for over-frequency deviations) linearly in 
proportion to the magnitude of the frequency deviation; or (2) in 
accordance with an approved [NERC] Electric Reliability Organization 
[R]reliability [S]standard providing for an equivalent or more 
stringent parameter. Interconnection Customer shall notify 
Transmission Provider that the primary frequency response capability 
of the Large Generating Facility has been tested and confirmed 
during commissioning. Once Interconnection Customer has synchronized 
the Large Generating Facility with the Transmission System, 
Interconnection Customer shall operate the Large Generating Facility 
consistent with the provisions specified in Sections 9.6.4.1 and 
9.6.4.2 of this Agreement. The primary frequency response 
requirements contained herein shall apply to both synchronous and 
non-synchronous Large Generating Facilities.
    9.6.4.1 Governor or Equivalent Controls. Whenever the Large 
Generating Facility is operated in parallel with the Transmission 
System, Interconnection Customer shall operate the Large Generating 
Facility with its governor or equivalent controls in service and 
responsive to frequency. Interconnection Customer shall: (1) in 
coordination with Transmission Provider and/or the relevant 
balancing authority, set the deadband parameter to: (1) a maximum of 
0.036 Hz and set the droop parameter to a maximum of 5 
percent; or (2) implement the relevant droop and deadband settings 
from an approved [NERC] Electric Reliability Organization 
[R]reliability [S]standard that provides for equivalent or more 
stringent parameters. Interconnection Customer shall be required to 
provide the status and settings of the governor or equivalent 
controls to Transmission Provider and/or the relevant balancing 
authority upon request. If Interconnection Customer needs to operate 
the Large Generating Facility with its governor or equivalent 
controls not in service, Interconnection Customer shall immediately 
notify Transmission Provider and the relevant balancing authority, 
and provide both with the following information: (1) the operating 
status of the governor or equivalent controls (i.e., whether it is 
currently out of service or when it will be taken out of service); 
(2) the reasons for removing the governor or equivalent controls 
from service; and (3) a reasonable estimate of when the governor or 
equivalent controls will be returned to service. Interconnection 
Customer shall make Reasonable Efforts to return its governor or 
equivalent controls into service as soon as practicable. 
Interconnection Customer shall make

[[Page 61325]]

Reasonable Efforts to keep outages of the Large Generating 
Facility's governor or equivalent controls to a minimum whenever the 
Large Generating Facility is operated in parallel with the 
Transmission System.
    9.6.4.2 Timely and Sustained Response. Interconnection Customer 
shall ensure that the Large Generating Facility's real power 
response to sustained frequency deviations outside of the deadband 
setting is automatically provided and shall begin immediately after 
frequency deviates outside of the deadband, and to the extent the 
Large Generating Facility has operating capability in the direction 
needed to correct the frequency deviation. Interconnection Customer 
shall not block or otherwise inhibit the ability of the governor or 
equivalent controls to respond and shall ensure that the response is 
not inhibited, except under certain operational constraints 
including, but not limited to, ambient temperature limitations, 
physical energy limitations, outages of mechanical equipment, or 
regulatory requirements. The Large Generating Facility shall sustain 
the real power response at least until system frequency returns to a 
value within the deadband setting of the governor or equivalent 
controls. A Commission-approved [R]reliability [S]standard with 
equivalent or more stringent requirements shall supersede the above 
requirements.
    9.6.4.3 Exemptions. Large Generating Facilities that are 
regulated by the United States Nuclear Regulatory Commission shall 
be exempt from Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this 
Agreement. Large Generating Facilities that are behind the meter 
generation that is sized-to-load (i.e., the thermal load and the 
generation are near-balanced in real-time operation and the 
generation is primarily controlled to maintain the unique thermal, 
chemical, or mechanical output necessary for the operating 
requirements of its host facility) shall be required to install 
primary frequency response capability in accordance with the droop 
and deadband capability requirements specified in Section 9.6.4, but 
shall be otherwise exempt from the operating requirements in 
Sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.4 of this Agreement.
    9.6.4.4 Electric Storage Resources. Interconnection Customer 
interconnecting a Generating Facility that contains an electric 
storage resource shall establish an operating range in Appendix C of 
its LGIA that specifies a minimum state of charge and a maximum 
state of charge between which the electric storage resource will be 
required to provide primary frequency response consistent with the 
conditions set forth in Sections 9.6.4, 9.6.4.1, 9.6.4.2 and 9.6.4.3 
of this Agreement. Appendix C shall specify whether the operating 
range is static or dynamic, and shall consider (1) the expected 
magnitude of frequency deviations in the interconnection; (2) the 
expected duration that system frequency will remain outside of the 
deadband parameter in the interconnection; (3) the expected 
incidence of frequency deviations outside of the deadband parameter 
in the interconnection; (4) the physical capabilities of the 
electric storage resource; (5) operational limitations of the 
electric storage resource due to manufacturer specifications; and 
(6) any other relevant factors agreed to by Transmission Provider 
and Interconnection Customer, and in consultation with the relevant 
transmission owner or balancing authority as appropriate. If the 
operating range is dynamic, then Appendix C must establish how 
frequently the operating range will be reevaluated and the factors 
that may be considered during its reevaluation.
    Interconnection Customer's electric storage resource is required 
to provide timely and sustained primary frequency response 
consistent with Section 9.6.4.2 of this Agreement when it is online 
and dispatched to inject electricity to the Transmission System and/
or receive electricity from the Transmission System. This excludes 
circumstances when the electric storage resource is not dispatched 
to inject electricity to the Transmission System and/or dispatched 
to receive electricity from the Transmission System. If 
Interconnection Customer's electric storage resource is charging at 
the time of a frequency deviation outside of its deadband parameter, 
it is to increase (for over-frequency deviations) or decrease (for 
under-frequency deviations) the rate at which it is charging in 
accordance with its droop parameter. Interconnection Customer's 
electric storage resource is not required to change from charging to 
discharging, or vice versa, unless the response necessitated by the 
droop and deadband settings requires it to do so and it is 
technically capable of making such a transition.
    9.7 Outages and Interruptions.
    9.7.1 Outages.
    9.7.1.1 Outage Authority and Coordination. Each Party may in 
accordance with Good Utility Practice in coordination with the other 
Party remove from service any of its respective Interconnection 
Facilities or Network Upgrades that may impact the other Party's 
facilities as necessary to perform maintenance or testing or to 
install or replace equipment. Absent an Emergency Condition, the 
Party scheduling a removal of such facility(ies) from service will 
use Reasonable Efforts to schedule such removal on a date and time 
mutually acceptable to the Parties. In all circumstances, any Party 
planning to remove such facility(ies) from service shall use 
Reasonable Efforts to minimize the effect on the other Party of such 
removal.
    9.7.1.2 Outage Schedules. Transmission Provider shall post 
scheduled outages of its transmission facilities on the OASIS. 
Interconnection Customer shall submit its planned maintenance 
schedules for the Large Generating Facility to Transmission Provider 
for a minimum of a rolling twenty-four month period. Interconnection 
Customer shall update its planned maintenance schedules as 
necessary. Transmission Provider may request Interconnection 
Customer to reschedule its maintenance as necessary to maintain the 
reliability of the Transmission System; provided, however, adequacy 
of generation supply shall not be a criterion in determining 
Transmission System reliability. Transmission Provider shall 
compensate Interconnection Customer for any additional direct costs 
that Interconnection Customer incurs as a result of having to 
reschedule maintenance, including any additional overtime, breaking 
of maintenance contracts or other costs above and beyond the cost 
Interconnection Customer would have incurred absent Transmission 
Provider's request to reschedule maintenance. Interconnection 
Customer will not be eligible to receive compensation, if during the 
twelve (12) months prior to the date of the scheduled maintenance, 
Interconnection Customer had modified its schedule of maintenance 
activities.
    9.7.1.3 Outage Restoration. If an outage on a Party's 
Interconnection Facilities or Network Upgrades adversely affects the 
other Party's operations or facilities, the Party that owns or 
controls the facility that is out of service shall use Reasonable 
Efforts to promptly restore such facility(ies) to a normal operating 
condition consistent with the nature of the outage. The Party that 
owns or controls the facility that is out of service shall provide 
the other Party, to the extent such information is known, 
information on the nature of the Emergency Condition, an estimated 
time of restoration, and any corrective actions required. Initial 
verbal notice shall be followed up as soon as practicable with 
written notice explaining the nature of the outage.
    9.7.2 Interruption of Service. If required by Good Utility 
Practice to do so, Transmission Provider may require Interconnection 
Customer to interrupt or reduce deliveries of electricity if such 
delivery of electricity could adversely affect Transmission 
Provider's ability to perform such activities as are necessary to 
safely and reliably operate and maintain the Transmission System. 
The following provisions shall apply to any interruption or 
reduction permitted under this Article 9.7.2:
    9.7.2.1 The interruption or reduction shall continue only for so 
long as reasonably necessary under Good Utility Practice;
    9.7.2.2 Any such interruption or reduction shall be made on an 
equitable, non-discriminatory basis with respect to all generating 
facilities directly connected to the Transmission System;
    9.7.2.3 When the interruption or reduction must be made under 
circumstances which do not allow for advance notice, Transmission 
Provider shall notify Interconnection Customer by telephone as soon 
as practicable of the reasons for the curtailment, interruption, or 
reduction, and, if known, its expected duration. Telephone 
notification shall be followed by written notification as soon as 
practicable;
    9.7.2.4 Except during the existence of an Emergency Condition, 
when the interruption or reduction can be scheduled without advance 
notice, Transmission Provider shall notify Interconnection Customer 
in advance regarding the timing of such scheduling and further 
notify Interconnection Customer of the expected duration. 
Transmission Provider shall coordinate with Interconnection Customer 
using Good Utility Practice to schedule the interruption or 
reduction during periods of least impact to Interconnection Customer 
and Transmission Provider;

[[Page 61326]]

    9.7.2.5 The Parties shall cooperate and coordinate with each 
other to the extent necessary in order to restore the Large 
Generating Facility, Interconnection Facilities, and the 
Transmission System to their normal operating state, consistent with 
system conditions and Good Utility Practice.
    9.7.3 [Under-Frequency and Over Frequency Conditions]Ride 
Through Capability and Performance. The Transmission System is 
designed to automatically activate a load-shed program as required 
by the[Applicable Reliability Council]Electric Reliability 
Organization in the event of an underfrequency system disturbance. 
Interconnection Customer shall implement under-frequency and over-
frequency relay set points for the Large Generating Facility as 
required by the [Applicable Reliability Council] Electric 
Reliability Organization to ensure frequency ``ride through'' 
capability of the Transmission System. Large Generating Facility 
response to frequency deviations of pre-determined magnitudes, both 
under-frequency and over-frequency deviations, shall be studied and 
coordinated with Transmission Provider in accordance with Good 
Utility Practice. Interconnection Customer shall also implement 
under-voltage and over-voltage relay set points, or equivalent 
electronic controls, as required by the Electric Reliability 
Organization to ensure voltage ``ride through'' capability of the 
Transmission System. The term ``ride through'' as used herein shall 
mean the ability of a Large Generating Facility to stay connected to 
and synchronized with the Transmission System during system 
disturbances within a range of under-frequency, [and]over-frequency, 
under-voltage, and over-voltage conditions, in accordance with Good 
Utility Practice and consistent with any standards and guidelines 
that are applied to other Generating Facilities in the Balancing 
Authority Area on a comparable basis. For abnormal frequency 
conditions and voltage conditions within the ``no trip zone'' 
defined by Reliability Standard PRC-024-3 or successor mandatory 
ride through reliability standards, the non-synchronous Large 
Generating Facility must ensure that, within any physical 
limitations of the Large Generating Facility, its control and 
protection settings are configured or set to (1) continue active 
power production during disturbance and post disturbance periods at 
pre-disturbance levels, unless providing primary frequency response 
or fast frequency response; (2) minimize reductions in active power 
and remain within dynamic voltage and current limits, if reactive 
power priority mode is enabled, unless providing primary frequency 
response or fast frequency response; (3) not artificially limit 
dynamic reactive power capability during disturbances; and (4) 
return to pre-disturbance active power levels without artificial 
ramp rate limits if active power is reduced, unless providing 
primary frequency response or fast frequency response.
    9.7.4 System Protection and Other Control Requirements.
    9.7.4.1 System Protection Facilities. Interconnection Customer 
shall, at its expense, install, operate and maintain System 
Protection Facilities as a part of the Large Generating Facility or 
Interconnection Customer's Interconnection Facilities. Transmission 
Provider shall install at Interconnection Customer's expense any 
System Protection Facilities that may be required on Transmission 
Provider's Interconnection Facilities or the Transmission System as 
a result of the interconnection of the Large Generating Facility and 
Interconnection Customer's Interconnection Facilities.
    9.7.4.2 Each Party's protection facilities shall be designed and 
coordinated with other systems in accordance with Good Utility 
Practice.
    9.7.4.3 Each Party shall be responsible for protection of its 
facilities consistent with Good Utility Practice.
    9.7.4.4 Each Party's protective relay design shall incorporate 
the necessary test switches to perform the tests required in Article 
6. The required test switches will be placed such that they allow 
operation of lockout relays while preventing breaker failure schemes 
from operating and causing unnecessary breaker operations and/or the 
tripping of Interconnection Customer's units.
    9.7.4.5 Each Party will test, operate and maintain System 
Protection Facilities in accordance with Good Utility Practice.
    9.7.4.6 Prior to the In-Service Date, and again prior to the 
Commercial Operation Date, each Party or its agent shall perform a 
complete calibration test and functional trip test of the System 
Protection Facilities. At intervals suggested by Good Utility 
Practice and following any apparent malfunction of the System 
Protection Facilities, each Party shall perform both calibration and 
functional trip tests of its System Protection Facilities. These 
tests do not require the tripping of any in-service generation unit. 
These tests do, however, require that all protective relays and 
lockout contacts be activated.
    9.7.5 Requirements for Protection. In compliance with Good 
Utility Practice, Interconnection Customer shall provide, install, 
own, and maintain relays, circuit breakers and all other devices 
necessary to remove any fault contribution of the Large Generating 
Facility to any short circuit occurring on the Transmission System 
not otherwise isolated by Transmission Provider's equipment, such 
that the removal of the fault contribution shall be coordinated with 
the protective requirements of the Transmission System. Such 
protective equipment shall include, without limitation, a 
disconnecting device or switch with load-interrupting capability 
located between the Large Generating Facility and the Transmission 
System at a site selected upon mutual agreement (not to be 
unreasonably withheld, conditioned or delayed) of the Parties. 
Interconnection Customer shall be responsible for protection of the 
Large Generating Facility and Interconnection Customer's other 
equipment from such conditions as negative sequence currents, over- 
or under-frequency, sudden load rejection, over- or under-voltage, 
and generator loss-of-field. Interconnection Customer shall be 
solely responsible to disconnect the Large Generating Facility and 
Interconnection Customer's other equipment if conditions on the 
Transmission System could adversely affect the Large Generating 
Facility.
    9.7.6 Power Quality. Neither Party's facilities shall cause 
excessive voltage flicker nor introduce excessive distortion to the 
sinusoidal voltage or current waves as defined by ANSI Standard 
C84.1-1989, in accordance with IEEE Standard 519, or any applicable 
superseding electric industry standard. In the event of a conflict 
between ANSI Standard C84.1-1989, or any applicable superseding 
electric industry standard, ANSI Standard C84.1-1989, or the 
applicable superseding electric industry standard, shall control.
    9.8 Switching and Tagging Rules. Each Party shall provide the 
other Party a copy of its switching and tagging rules that are 
applicable to the other Party's activities. Such switching and 
tagging rules shall be developed on a non-discriminatory basis. The 
Parties shall comply with applicable switching and tagging rules, as 
amended from time to time, in obtaining clearances for work or for 
switching operations on equipment.
    9.9 Use of Interconnection Facilities by Third Parties.
    9.9.1 Purpose of Interconnection Facilities. Except as may be 
required by Applicable Laws and Regulations, or as otherwise agreed 
to among the Parties, the Interconnection Facilities shall be 
constructed for the sole purpose of interconnecting the Large 
Generating Facility to the Transmission System and shall be used for 
no other purpose.
    9.9.2 Third Party Users. If required by Applicable Laws and 
Regulations or if the Parties mutually agree, such agreement not to 
be unreasonably withheld, to allow one or more third parties to use 
Transmission Provider's Interconnection Facilities, or any part 
thereof, Interconnection Customer will be entitled to compensation 
for the capital expenses it incurred in connection with the 
Interconnection Facilities based upon the pro rata use of the 
Interconnection Facilities by Transmission Provider, all third party 
users, and Interconnection Customer, in accordance with Applicable 
Laws and Regulations or upon some other mutually agreed upon 
methodology. In addition, cost responsibility for ongoing costs, 
including operation and maintenance costs associated with the 
Interconnection Facilities, will be allocated between 
Interconnection Customer and any third party users based upon the 
pro rata use of the Interconnection Facilities by Transmission 
Provider, all third party users, and Interconnection Customer, in 
accordance with Applicable Laws and Regulations or upon some other 
mutually agreed upon methodology. If the issue of such compensation 
or allocation cannot be resolved through such negotiations, it shall 
be submitted to FERC for resolution.
    9.10 Disturbance Analysis Data Exchange. The Parties will 
cooperate with one another in the analysis of disturbances to either 
the Large Generating Facility or Transmission Provider's 
Transmission System by gathering and providing access to any 
information relating to any disturbance, including information from 
oscillography, protective

[[Page 61327]]

relay targets, breaker operations and sequence of events records, 
and any disturbance information required by Good Utility Practice.

Article 10. Maintenance

    10.1 Transmission Provider Obligations. Transmission Provider 
shall maintain the Transmission System and Transmission Provider's 
Interconnection Facilities in a safe and reliable manner and in 
accordance with this LGIA.
    10.2 Interconnection Customer Obligations. Interconnection 
Customer shall maintain the Large Generating Facility and 
Interconnection Customer's Interconnection Facilities in a safe and 
reliable manner and in accordance with this LGIA.
    10.3 Coordination. The Parties shall confer regularly to 
coordinate the planning, scheduling and performance of preventive 
and corrective maintenance on the Large Generating Facility and the 
Interconnection Facilities.
    10.4 Secondary Systems. Each Party shall cooperate with the 
other in the inspection, maintenance, and testing of control or 
power circuits that operate below 600 volts, AC or DC, including, 
but not limited to, any hardware, control or protective devices, 
cables, conductors, electric raceways, secondary equipment panels, 
transducers, batteries, chargers, and voltage and current 
transformers that directly affect the operation of a Party's 
facilities and equipment which may reasonably be expected to impact 
the other Party. Each Party shall provide advance notice to the 
other Party before undertaking any work on such circuits, especially 
on electrical circuits involving circuit breaker trip and close 
contacts, current transformers, or potential transformers.
    10.5 Operating and Maintenance Expenses. Subject to the 
provisions herein addressing the use of facilities by others, and 
except for operations and maintenance expenses associated with 
modifications made for providing interconnection or transmission 
service to a third party and such third party pays for such 
expenses, Interconnection Customer shall be responsible for all 
reasonable expenses including overheads, associated with: (1) 
owning, operating, maintaining, repairing, and replacing 
Interconnection Customer's Interconnection Facilities; and (2) 
operation, maintenance, repair and replacement of Transmission 
Provider's Interconnection Facilities.

Article 11. Performance Obligation

    11.1 Interconnection Customer Interconnection Facilities. 
Interconnection Customer shall design, procure, construct, install, 
own and/or control Interconnection Customer Interconnection 
Facilities described in Appendix A, Interconnection Facilities, 
Network Upgrades and Distribution Upgrades, at its sole expense.
    11.2 Transmission Provider's Interconnection Facilities. 
Transmission Provider or Transmission Owner shall design, procure, 
construct, install, own and/or control the Transmission Provider's 
Interconnection Facilities described in Appendix A, Interconnection 
Facilities, Network Upgrades and Distribution Upgrades, at the sole 
expense of the Interconnection Customer.
    11.3 Network Upgrades and Distribution Upgrades. Transmission 
Provider or Transmission Owner shall design, procure, construct, 
install, and own the Network Upgrades and Distribution Upgrades 
described in Appendix A, Interconnection Facilities, Network 
Upgrades and Distribution Upgrades. [The]Interconnection Customer 
shall be responsible for all costs related to Distribution Upgrades. 
Unless Transmission Provider or Transmission Owner elects to fund 
the capital for the Network Upgrades, they shall be solely funded by 
Interconnection Customer.
    11.4 Transmission Credits.
    11.4.1 Repayment of Amounts Advanced for Network Upgrades. 
Interconnection Customer shall be entitled to a cash repayment, 
equal to the total amount paid to Transmission Provider and Affected 
System Operator, if any, for the Network Upgrades, including any tax 
gross-up or other tax-related payments associated with Network 
Upgrades, and not refunded to Interconnection Customer pursuant to 
Article 5.17.8 or otherwise, to be paid to Interconnection Customer 
on a dollar-for-dollar basis for the non-usage sensitive portion of 
transmission charges, as payments are made under Transmission 
Provider's Tariff and Affected System's Tariff for transmission 
services with respect to the Large Generating Facility. Any 
repayment shall include interest calculated in accordance with the 
methodology set forth in FERC's regulations at 18 CFR 
35.19a(a)(2)(iii) from the date of any payment for Network Upgrades 
through the date on which the Interconnection Customer receives a 
repayment of such payment pursuant to this subparagraph. 
Interconnection Customer may assign such repayment rights to any 
person.
    Notwithstanding the foregoing, Interconnection Customer, 
Transmission Provider, and Affected System Operator may adopt any 
alternative payment schedule that is mutually agreeable so long as 
Transmission Provider and Affected System Operator take one of the 
following actions no later than five years from the Commercial 
Operation Date: (1) return to Interconnection Customer any amounts 
advanced for Network Upgrades not previously repaid, or (2) declare 
in writing that Transmission Provider or Affected System Operator 
will continue to provide payments to Interconnection Customer on a 
dollar-for-dollar basis for the non-usage sensitive portion of 
transmission charges, or develop an alternative schedule that is 
mutually agreeable and provides for the return of all amounts 
advanced for Network Upgrades not previously repaid; however, full 
reimbursement shall not extend beyond twenty (20) years from the 
Commercial Operation Date.
    If the Large Generating Facility fails to achieve commercial 
operation, but it or another Generating Facility is later 
constructed and makes use of the Network Upgrades, Transmission 
Provider and Affected System Operator shall at that time reimburse 
Interconnection Customer for the amounts advanced for the Network 
Upgrades. Before any such reimbursement can occur, the 
Interconnection Customer, or the entity that ultimately constructs 
the Generating Facility, if different, is responsible for 
identifying the entity to which reimbursement must be made.
    11.4.2 Special Provisions for Affected Systems. Unless 
Transmission Provider provides, under the LGIA, for the repayment of 
amounts advanced to Affected System Operator for Network Upgrades, 
Interconnection Customer and Affected System Operator shall enter 
into an agreement that provides for such repayment. The agreement 
shall specify the terms governing payments to be made by 
Interconnection Customer to the Affected System Operator as well as 
the repayment by the Affected System Operator.
    11.4.3 Notwithstanding any other provision of this LGIA, nothing 
herein shall be construed as relinquishing or foreclosing any 
rights, including but not limited to firm transmission rights, 
capacity rights, transmission congestion rights, or transmission 
credits, that Interconnection Customer, shall be entitled to, now or 
in the future under any other agreement or tariff as a result of, or 
otherwise associated with, the transmission capacity, if any, 
created by the Network Upgrades, including the right to obtain cash 
reimbursements or transmission credits for transmission service that 
is not associated with the Large Generating Facility.
    11.5 Provision of Security. At least thirty (30) Calendar Days 
prior to the commencement of the procurement, installation, or 
construction of a discrete portion of a Transmission Provider's 
Interconnection Facilities, Network Upgrades, or Distribution 
Upgrades, Interconnection Customer shall provide Transmission 
Provider, at Interconnection Customer's option, a guarantee, a 
surety bond, letter of credit or other form of security that is 
reasonably acceptable to Transmission Provider and is consistent 
with the Uniform Commercial Code of the jurisdiction identified in 
Article 14.2.1. Such security for payment, as specified in Appendix 
B of this LGIA, shall be in an amount sufficient to cover the costs 
for constructing, procuring and installing the applicable portion of 
Transmission Provider's Interconnection Facilities, Network 
Upgrades, or Distribution Upgrades and shall be reduced on a dollar-
for-dollar basis for payments made to Transmission Provider for 
these purposes. Transmission Provider must use the LGIA Deposit 
required in Section 11.3 of the LGIP before requiring 
Interconnection Customer to submit security in addition to that LGIA 
Deposit. Transmission Provider must specify, in Appendix B of this 
LGIA, the dates for which Interconnection Customer must provide 
additional security for construction of each discrete portion of 
Transmission Provider's Interconnection Facilities, Network 
Upgrades, or Distribution Upgrades and Interconnection Customer must 
provide such additional security.
    In addition:
    11.5.1 The guarantee must be made by an entity that meets the 
creditworthiness requirements of Transmission Provider, and contain 
terms and conditions that guarantee payment of any amount that may 
be due from

[[Page 61328]]

Interconnection Customer, up to an agreed-to maximum amount.
    11.5.2 The letter of credit must be issued by a financial 
institution reasonably acceptable to Transmission Provider and must 
specify a reasonable expiration date.
    11.5.3 The surety bond must be issued by an insurer reasonably 
acceptable to Transmission Provider and must specify a reasonable 
expiration date.
    11.6 Interconnection Customer Compensation. If Transmission 
Provider requests or directs Interconnection Customer to provide a 
service pursuant to Articles 9.6.3 (Payment for Reactive Power), or 
13.5.1 of this LGIA, Transmission Provider shall compensate 
Interconnection Customer in accordance with Interconnection 
Customer's applicable rate schedule then in effect unless the 
provision of such service(s) is subject to an RTO or ISO FERC-
approved rate schedule. Interconnection Customer shall serve 
Transmission Provider or RTO or ISO with any filing of a proposed 
rate schedule at the time of such filing with FERC. To the extent 
that no rate schedule is in effect at the time the Interconnection 
Customer is required to provide or absorb any Reactive Power under 
this LGIA, Transmission Provider agrees to compensate 
Interconnection Customer in such amount as would have been due 
Interconnection Customer had the rate schedule been in effect at the 
time service commenced; provided, however, that such rate schedule 
must be filed at FERC or other appropriate Governmental Authority 
within sixty (60) Calendar Days of the commencement of service.
    11.6.1 Interconnection Customer Compensation for Actions During 
Emergency Condition. Transmission Provider or RTO or ISO shall 
compensate Interconnection Customer for its provision of real and 
reactive power and other Emergency Condition services that 
Interconnection Customer provides to support the Transmission System 
during an Emergency Condition in accordance with Article 11.6.

Article 12. Invoice

    12.1 General. Each Party shall submit to the other Party, on a 
monthly basis, invoices of amounts due for the preceding month. Each 
invoice shall state the month to which the invoice applies and fully 
describe the services and equipment provided. The Parties may 
discharge mutual debts and payment obligations due and owing to each 
other on the same date through netting, in which case all amounts a 
Party owes to the other Party under this LGIA, including interest 
payments or credits, shall be netted so that only the net amount 
remaining due shall be paid by the owing Party.
    12.2 Final Invoice. Within six months after completion of the 
construction of Transmission Provider's Interconnection Facilities 
and the Network Upgrades, Transmission Provider shall provide an 
invoice of the final cost of the construction of Transmission 
Provider's Interconnection Facilities and the Network Upgrades and 
shall set forth such costs in sufficient detail to enable 
Interconnection Customer to compare the actual costs with the 
estimates and to ascertain deviations, if any, from the cost 
estimates. Transmission Provider shall refund to Interconnection 
Customer any amount by which the actual payment by Interconnection 
Customer for estimated costs exceeds the actual costs of 
construction within thirty (30) Calendar Days of the issuance of 
such final construction invoice.
    12.3 Payment. Invoices shall be rendered to the paying Party at 
the address specified in Appendix F. The Party receiving the invoice 
shall pay the invoice within thirty (30) Calendar Days of receipt. 
All payments shall be made in immediately available funds payable to 
the other Party, or by wire transfer to a bank named and account 
designated by the invoicing Party. Payment of invoices by either 
Party will not constitute a waiver of any rights or claims either 
Party may have under this LGIA.
    12.4 Disputes. In the event of a billing dispute between 
Transmission Provider and Interconnection Customer, Transmission 
Provider shall continue to provide Interconnection Service under 
this LGIA as long as Interconnection Customer: (i) continues to make 
all payments not in dispute; and (ii) pays to Transmission Provider 
or into an independent escrow account the portion of the invoice in 
dispute, pending resolution of such dispute. If Interconnection 
Customer fails to meet these two requirements for continuation of 
service, then Transmission Provider may provide notice to 
Interconnection Customer of a Default pursuant to Article 17. Within 
thirty (30) Calendar Days after the resolution of the dispute, the 
Party that owes money to the other Party shall pay the amount due 
with interest calculated in accord with the methodology set forth in 
FERC's regulations at 18 CFR 35.19a(a)(2)(iii).

Article 13. Emergencies

    13.1 Definition. ``Emergency Condition'' shall mean a condition 
or situation: (i) that in the judgment of the Party making the claim 
is imminently likely to endanger life or property; or (ii) that, in 
the case of Transmission Provider, is imminently likely (as 
determined in a non-discriminatory manner) to cause a material 
adverse effect on the security of, or damage to the Transmission 
System, Transmission Provider's Interconnection Facilities or the 
Transmission Systems of others to which the Transmission System is 
directly connected; or (iii) that, in the case of Interconnection 
Customer, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the 
security of, or damage to, the Large Generating Facility or 
Interconnection Customer's Interconnection Facilities' System 
restoration and black start shall be considered Emergency 
Conditions; provided, that Interconnection Customer is not obligated 
by this LGIA to possess black start capability.
    13.2 Obligations. Each Party shall comply with the Emergency 
Condition procedures of the applicable ISO/RTO, [NERC,] the 
[Applicable Reliability Council]Electric Reliability Organization, 
Applicable Laws and Regulations, and any emergency procedures agreed 
to by the Joint Operating Committee.
    13.3 Notice. Transmission Provider shall notify Interconnection 
Customer promptly when it becomes aware of an Emergency Condition 
that affects Transmission Provider's Interconnection Facilities or 
the Transmission System that may reasonably be expected to affect 
Interconnection Customer's operation of the Large Generating 
Facility or Interconnection Customer's Interconnection Facilities. 
Interconnection Customer shall notify Transmission Provider promptly 
when it becomes aware of an Emergency Condition that affects the 
Large Generating Facility or Interconnection Customer's 
Interconnection Facilities that may reasonably be expected to affect 
the Transmission System or Transmission Provider's Interconnection 
Facilities. To the extent information is known, the notification 
shall describe the Emergency Condition, the extent of the damage or 
deficiency, the expected effect on the operation of Interconnection 
Customer's or Transmission Provider's facilities and operations, its 
anticipated duration and the corrective action taken and/or to be 
taken. The initial notice shall be followed as soon as practicable 
with written notice.
    13.4 Immediate Action. Unless, in Interconnection Customer's 
reasonable judgment, immediate action is required, Interconnection 
Customer shall obtain the consent of Transmission Provider, such 
consent to not be unreasonably withheld, prior to performing any 
manual switching operations at the Large Generating Facility or 
Interconnection Customer's Interconnection Facilities in response to 
an Emergency Condition either declared by Transmission Provider or 
otherwise regarding the Transmission System.
    13.5 Transmission Provider Authority.
    13.5.1 General. Transmission Provider may take whatever actions 
or inactions with regard to the Transmission System or Transmission 
Provider's Interconnection Facilities it deems necessary during an 
Emergency Condition in order to (i) preserve public health and 
safety, (ii) preserve the reliability of the Transmission System or 
Transmission Provider's Interconnection Facilities, (iii) limit or 
prevent damage, and (iv) expedite restoration of service.
    Transmission Provider shall use Reasonable Efforts to minimize 
the effect of such actions or inactions on the Large Generating 
Facility or Interconnection Customer's Interconnection Facilities. 
Transmission Provider may, on the basis of technical considerations, 
require the Large Generating Facility to mitigate an Emergency 
Condition by taking actions necessary and limited in scope to remedy 
the Emergency Condition, including, but not limited to, directing 
Interconnection Customer to shut-down, start-up, increase or 
decrease the real or reactive power output of the Large Generating 
Facility; implementing a reduction or disconnection pursuant to 
Article 13.5.2; directing Interconnection Customer to assist with 
blackstart (if available) or restoration efforts; or altering the 
outage schedules of the Large Generating Facility and 
Interconnection Customer's Interconnection Facilities. 
Interconnection Customer shall comply with all of Transmission 
Provider's operating

[[Page 61329]]

instructions concerning Large Generating Facility real power and 
reactive power output within the manufacturer's design limitations 
of the Large Generating Facility's equipment that is in service and 
physically available for operation at the time, in compliance with 
Applicable Laws and Regulations.
    13.5.2 Reduction and Disconnection. Transmission Provider may 
reduce Interconnection Service or disconnect the Large Generating 
Facility or Interconnection Customer's Interconnection Facilities, 
when such, reduction or disconnection is necessary under Good 
Utility Practice due to Emergency Conditions. These rights are 
separate and distinct from any right of curtailment of Transmission 
Provider pursuant to Transmission Provider's Tariff. When 
Transmission Provider can schedule the reduction or disconnection in 
advance, Transmission Provider shall notify Interconnection Customer 
of the reasons, timing and expected duration of the reduction or 
disconnection. Transmission Provider shall coordinate with 
Interconnection Customer using Good Utility Practice to schedule the 
reduction or disconnection during periods of least impact to 
Interconnection Customer and Transmission Provider. Any reduction or 
disconnection shall continue only for so long as reasonably 
necessary under Good Utility Practice. The Parties shall cooperate 
with each other to restore the Large Generating Facility, the 
Interconnection Facilities, and the Transmission System to their 
normal operating state as soon as practicable consistent with Good 
Utility Practice.
    13.6 Interconnection Customer Authority. Consistent with Good 
Utility Practice and the LGIA and the LGIP, Interconnection Customer 
may take actions or inactions with regard to the Large Generating 
Facility or Interconnection Customer's Interconnection Facilities 
during an Emergency Condition in order to (i) preserve public health 
and safety, (ii) preserve the reliability of the Large Generating 
Facility or Interconnection Customer's Interconnection Facilities, 
(iii) limit or prevent damage, and (iv) expedite restoration of 
service. Interconnection Customer shall use Reasonable Efforts to 
minimize the effect of such actions or inactions on the Transmission 
System and Transmission Provider's Interconnection Facilities. 
Transmission Provider shall use Reasonable Efforts to assist 
Interconnection Customer in such actions.
    13.7 Limited Liability. Except as otherwise provided in Article 
11.6.1 of this LGIA, neither Party shall be liable to the other for 
any action it takes in responding to an Emergency Condition so long 
as such action is made in good faith and is consistent with Good 
Utility Practice.

Article 14. Regulatory Requirements and Governing Law

    14.1 Regulatory Requirements. Each Party's obligations under 
this LGIA shall be subject to its receipt of any required approval 
or certificate from one or more Governmental Authorities in the form 
and substance satisfactory to the applying Party, or the Party 
making any required filings with, or providing notice to, such 
Governmental Authorities, and the expiration of any time period 
associated therewith. Each Party shall in good faith seek and use 
its Reasonable Efforts to obtain such other approvals. Nothing in 
this LGIA shall require Interconnection Customer to take any action 
that could result in its inability to obtain, or its loss of, status 
or exemption under the Federal Power Act, the Public Utility Holding 
Company Act of 1935, as amended, or the Public Utility Regulatory 
Policies Act of 1978.
    14.2 Governing Law.
    14.2.1 The validity, interpretation and performance of this LGIA 
and each of its provisions shall be governed by the laws of the 
state where the Point of Interconnection is located, without regard 
to its conflicts of law principles.
    14.2.2 This LGIA is subject to all Applicable Laws and 
Regulations.
    14.2.3 Each Party expressly reserves the right to seek changes 
in, appeal, or otherwise contest any laws, orders, rules, or 
regulations of a Governmental Authority.

Article 15. Notices

    15.1 General. Unless otherwise provided in this LGIA, any 
notice, demand or request required or permitted to be given by 
either Party to the other and any instrument required or permitted 
to be tendered or delivered by either Party in writing to the other 
shall be effective when delivered and may be so given, tendered or 
delivered, by recognized national courier, or by depositing the same 
with the United States Postal Service with postage prepaid, for 
delivery by certified or registered mail, addressed to the Party, or 
personally delivered to the Party, at the address set out in 
Appendix F, Addresses for Delivery of Notices and Billings.
    Either Party may change the notice information in this LGIA by 
giving five (5) Business Days written notice prior to the effective 
date of the change.
    15.2 Billings and Payments. Billings and payments shall be sent 
to the addresses set out in Appendix F.
    15.3 Alternative Forms of Notice. Any notice or request required 
or permitted to be given by a Party to the other and not required by 
this Agreement to be given in writing may be so given by telephone, 
facsimile or email to the telephone numbers and email addresses set 
out in Appendix F.
    15.4 Operations and Maintenance Notice. Each Party shall notify 
the other Party in writing of the identity of the person(s) that it 
designates as the point(s) of contact with respect to the 
implementation of Articles 9 and 10.

Article 16. Force Majeure

    16.1 Force Majeure.
    16.1.1 Economic hardship is not considered a Force Majeure 
event.
    16.1.2 Neither Party shall be considered to be in Default with 
respect to any obligation hereunder, (including obligations under 
Article 4), other than the obligation to pay money when due, if 
prevented from fulfilling such obligation by Force Majeure. A Party 
unable to fulfill any obligation hereunder (other than an obligation 
to pay money when due) by reason of Force Majeure shall give notice 
and the full particulars of such Force Majeure to the other Party in 
writing or by telephone as soon as reasonably possible after the 
occurrence of the cause relied upon. Telephone notices given 
pursuant to this article shall be confirmed in writing as soon as 
reasonably possible and shall specifically state full particulars of 
the Force Majeure, the time and date when the Force Majeure occurred 
and when the Force Majeure is reasonably expected to cease. The 
Party affected shall exercise due diligence to remove such 
disability with reasonable dispatch, but shall not be required to 
accede or agree to any provision not satisfactory to it in order to 
settle and terminate a strike or other labor disturbance.

Article 17. Default

    17.1 Default.
    17.1.1 General. No Default shall exist where such failure to 
discharge an obligation (other than the payment of money) is the 
result of Force Majeure as defined in this LGIA or the result of an 
act of omission of the other Party. Upon a Breach, the non-breaching 
Party shall give written notice of such Breach to the breaching 
Party. Except as provided in Article 17.1.2, the breaching Party 
shall have thirty (30) Calendar Days from receipt of the Default 
notice within which to cure such Breach; provided however, if such 
Breach is not capable of cure within thirty (30) Calendar Days, the 
breaching Party shall commence such cure within thirty (30) Calendar 
Days after notice and continuously and diligently complete such cure 
within ninety (90) Calendar Days from receipt of the Default notice; 
and, if cured within such time, the Breach specified in such notice 
shall cease to exist.
    17.1.2 Right to Terminate. If a Breach is not cured as provided 
in this article, or if a Breach is not capable of being cured within 
the period provided for herein, the non-breaching Party shall have 
the right to declare a Default and terminate this LGIA by written 
notice at any time until cure occurs, and be relieved of any further 
obligation hereunder and, whether or not that Party terminates this 
LGIA, to recover from the breaching Party all amounts due hereunder, 
plus all other damages and remedies to which it is entitled at law 
or in equity. The provisions of this article will survive 
termination of this LGIA.
    17.2 Violation of Operating Assumptions for Generating 
Facilities. If Transmission Provider requires Interconnection 
Customer to memorialize the operating assumptions for the charging 
behavior of a Generating Facility that includes at least one 
electric storage resource in Appendix H of this LGIA, Transmission 
Provider may consider Interconnection Customer to be in Breach of 
the LGIA if Interconnection Customer fails to operate the Generating 
Facility in accordance with those operating assumptions for charging 
behavior. However, if Interconnection Customer operates contrary to 
the operating assumptions for charging behavior specified in 
Appendix H of this LGIA at the direction of Transmission Provider, 
Transmission Provider shall not consider Interconnection Customer in 
Breach of this LGIA.

[[Page 61330]]

Article 18. Indemnity, Consequential Damages and Insurance

    18.1 Indemnity. The Parties shall at all times indemnify, 
defend, and hold the other Party harmless from, any and all damages, 
losses, claims, including claims and actions relating to injury to 
or death of any person or damage to property, demand, suits, 
recoveries, costs and expenses, court costs, attorney fees, and all 
other obligations by or to third parties, arising out of or 
resulting from the other Party's action or inactions of its 
obligations under this LGIA on behalf of the Indemnifying Party, 
except in cases of gross negligence or intentional wrongdoing by the 
indemnified Party.
    18.1.1 Indemnified Person. If an Indemnified Person is entitled 
to indemnification under this Article 18 as a result of a claim by a 
third party, and the Indemnifying Party fails, after notice and 
reasonable opportunity to proceed under Article 18.1, to assume the 
defense of such claim, such Indemnified Person may at the expense of 
the Indemnifying Party contest, settle or consent to the entry of 
any judgment with respect to, or pay in full, such claim.
    18.1.2 Indemnifying Party. If an Indemnifying Party is obligated 
to indemnify and hold any Indemnified Person harmless under this 
Article 18, the amount owing to the Indemnified Person shall be the 
amount of such Indemnified Person's actual Loss, net of any 
insurance or other recovery.
    18.1.3 Indemnity Procedures. Promptly after receipt by an 
Indemnified Person of any claim or notice of the commencement of any 
action or administrative or legal proceeding or investigation as to 
which the indemnity provided for in Article 18.1 may apply, the 
Indemnified Person shall notify the Indemnifying Party of such fact. 
Any failure of or delay in such notification shall not affect a 
Party's indemnification obligation unless such failure or delay is 
materially prejudicial to the Indemnifying Party.
    The Indemnifying Party shall have the right to assume the 
defense thereof with counsel designated by such Indemnifying Party 
and reasonably satisfactory to the Indemnified Person. If the 
defendants in any such action include one or more Indemnified 
Persons and the Indemnifying Party and if the Indemnified Person 
reasonably concludes that there may be legal defenses available to 
it and/or other Indemnified Persons which are different from or 
additional to those available to the Indemnifying Party, the 
Indemnified Person shall have the right to select separate counsel 
to assert such legal defenses and to otherwise participate in the 
defense of such action on its own behalf. In such instances, the 
Indemnifying Party shall only be required to pay the fees and 
expenses of one additional attorney to represent an Indemnified 
Person or Indemnified Persons having such differing or additional 
legal defenses.
    The Indemnified Person shall be entitled, at its expense, to 
participate in any such action, suit or proceeding, the defense of 
which has been assumed by the Indemnifying Party. Notwithstanding 
the foregoing, the Indemnifying Party (i) shall not be entitled to 
assume and control the defense of any such action, suit or 
proceedings if and to the extent that, in the opinion of the 
Indemnified Person and its counsel, such action, suit or proceeding 
involves the potential imposition of criminal liability on the 
Indemnified Person, or there exists a conflict or adversity of 
interest between the Indemnified Person and the Indemnifying Party, 
in such event the Indemnifying Party shall pay the reasonable 
expenses of the Indemnified Person, and (ii) shall not settle or 
consent to the entry of any judgment in any action, suit or 
proceeding without the consent of the Indemnified Person, which 
shall not be reasonably withheld, conditioned or delayed.
    18.2 Consequential Damages. Other than the Liquidated Damages 
heretofore described, in no event shall either Party be liable under 
any provision of this LGIA for any losses, damages, costs or 
expenses for any special, indirect, incidental, consequential, or 
punitive damages, including but not limited to loss of profit or 
revenue, loss of the use of equipment, cost of capital, cost of 
temporary equipment or services, whether based in whole or in part 
in contract, in tort, including negligence, strict liability, or any 
other theory of liability; provided, however, that damages for which 
a Party may be liable to the other Party under another agreement 
will not be considered to be special, indirect, incidental, or 
consequential damages hereunder.
    18.3 Insurance. Each party shall, at its own expense, maintain 
in force throughout the period of this LGIA, and until released by 
the other Party, the following minimum insurance coverages, with 
insurers authorized to do business in the state where the Point of 
Interconnection is located:
    18.3.1 Employers' Liability and Workers' Compensation Insurance 
providing statutory benefits in accordance with the laws and 
regulations of the state in which the Point of Interconnection is 
located.
    18.3.2 Commercial General Liability Insurance including premises 
and operations, personal injury, broad form property damage, broad 
form blanket contractual liability coverage (including coverage for 
the contractual indemnification) products and completed operations 
coverage, coverage for explosion, collapse and underground hazards, 
independent contractors coverage, coverage for pollution to the 
extent normally available and punitive damages to the extent 
normally available and a cross liability endorsement, with minimum 
limits of One Million Dollars ($1,000,000) per occurrence/One 
Million Dollars ($1,000,000) aggregate combined single limit for 
personal injury, bodily injury, including death and property damage.
    18.3.3 Comprehensive Automobile Liability Insurance for coverage 
of owned and non-owned and hired vehicles, trailers or semi-trailers 
designed for travel on public roads, with a minimum, combined single 
limit of One Million Dollars ($1,000,000) per occurrence for bodily 
injury, including death, and property damage.
    18.3.4 Excess Public Liability Insurance over and above the 
Employers' Liability Commercial General Liability and Comprehensive 
Automobile Liability Insurance coverage, with a minimum combined 
single limit of Twenty Million Dollars ($20,000,000) per occurrence/
Twenty Million Dollars ($20,000,000) aggregate.
    18.3.5 The Commercial General Liability Insurance, Comprehensive 
Automobile Insurance and Excess Public Liability Insurance policies 
shall name the other Party, its parent, associated and Affiliate 
companies and their respective directors, officers, agents, servants 
and employees (``Other Party Group'') as additional insured. All 
policies shall contain provisions whereby the insurers waive all 
rights of subrogation in accordance with the provisions of this LGIA 
against the Other Party Group and provide thirty (30) Calendar Days 
advance written notice to the Other Party Group prior to anniversary 
date of cancellation or any material change in coverage or 
condition.
    18.3.6 The Commercial General Liability Insurance, Comprehensive 
Automobile Liability Insurance and Excess Public Liability Insurance 
policies shall contain provisions that specify that the policies are 
primary and shall apply to such extent without consideration for 
other policies separately carried and shall state that each insured 
is provided coverage as though a separate policy had been issued to 
each, except the insurer's liability shall not be increased beyond 
the amount for which the insurer would have been liable had only one 
insured been covered. Each Party shall be responsible for its 
respective deductibles or retentions.
    18.3.7 The Commercial General Liability Insurance, Comprehensive 
Automobile Liability Insurance and Excess Public Liability Insurance 
policies, if written on a Claims First Made Basis, shall be 
maintained in full force and effect for two (2) years after 
termination of this LGIA, which coverage may be in the form of tail 
coverage or extended reporting period coverage if agreed by the 
Parties.
    18.3.8 The requirements contained herein as to the types and 
limits of all insurance to be maintained by the Parties are not 
intended to and shall not in any manner, limit or qualify the 
liabilities and obligations assumed by the Parties under this LGIA.
    18.3.9 Within ten (10) days following execution of this LGIA, 
and as soon as practicable after the end of each fiscal year or at 
the renewal of the insurance policy and in any event within ninety 
(90) days thereafter, each Party shall provide certification of all 
insurance required in this LGIA, executed by each insurer or by an 
authorized representative of each insurer.
    18.3.10 Notwithstanding the foregoing, each Party may self-
insure to meet the minimum insurance requirements of Articles 18.3.2 
through 18.3.8 to the extent it maintains a self-insurance program; 
provided that, such Party's senior secured debt is rated at 
investment grade or better by Standard & Poor's and that its self-
insurance program meets the minimum insurance requirements of 
Articles 18.3.2 through 18.3.8. For any period of time that a 
Party's senior secured debt is unrated by Standard & Poor's or is 
rated at less than investment grade by Standard & Poor's, such Party 
shall comply with the insurance requirements applicable to it under 
Articles 18.3.2 through 18.3.9. In

[[Page 61331]]

the event that a Party is permitted to self-insure pursuant to this 
article, it shall notify the other Party that it meets the 
requirements to self-insure and that its self-insurance program 
meets the minimum insurance requirements in a manner consistent with 
that specified in Article 18.3.9.
    18.3.11 The Parties agree to report to each other in writing as 
soon as practical all accidents or occurrences resulting in injuries 
to any person, including death, and any property damage arising out 
of this LGIA.

Article 19. Assignment

    19.1 Assignment. This LGIA may be assigned by either Party only 
with the written consent of the other; provided that either Party 
may assign this LGIA without the consent of the other Party to any 
Affiliate of the assigning Party with an equal or greater credit 
rating and with the legal authority and operational ability to 
satisfy the obligations of the assigning Party under this LGIA; and 
provided further that Interconnection Customer shall have the right 
to assign this LGIA, without the consent of Transmission Provider, 
for collateral security purposes to aid in providing financing for 
the Large Generating Facility, provided that Interconnection 
Customer will promptly notify Transmission Provider of any such 
assignment. Any financing arrangement entered into by 
Interconnection Customer pursuant to this article will provide that 
prior to or upon the exercise of the secured party's, trustee's or 
mortgagee's assignment rights pursuant to said arrangement, the 
secured creditor, the trustee or mortgagee will notify Transmission 
Provider of the date and particulars of any such exercise of 
assignment right(s), including providing the Transmission Provider 
with proof that it meets the requirements of Articles 11.5 and 18.3. 
Any attempted assignment that violates this article is void and 
ineffective. Any assignment under this LGIA shall not relieve a 
Party of its obligations, nor shall a Party's obligations be 
enlarged, in whole or in part, by reason thereof. Where required, 
consent to assignment will not be unreasonably withheld, conditioned 
or delayed.

Article 20. Severability

    20.1 Severability. If any provision in this LGIA is finally 
determined to be invalid, void or unenforceable by any court or 
other Governmental Authority having jurisdiction, such determination 
shall not invalidate, void or make unenforceable any other 
provision, agreement or covenant of this LGIA; provided that if 
Interconnection Customer (or any third party, but only if such third 
party is not acting at the direction of Transmission Provider) seeks 
and obtains such a final determination with respect to any provision 
of the Alternate Option (Article 5.1.2), or the Negotiated Option 
(Article 5.1.4), then none of these provisions shall thereafter have 
any force or effect and the Parties' rights and obligations shall be 
governed solely by the Standard Option (Article 5.1.1).

Article 21. Comparability

    21.1 Comparability. The Parties will comply with all applicable 
comparability and code of conduct laws, rules and regulations, as 
amended from time to time.

Article 22. Confidentiality

    22.1 Confidentiality. Confidential Information shall include, 
without limitation, all information relating to a Party's 
technology, research and development, business affairs, and pricing, 
and any information supplied by either of the Parties to the other 
prior to the execution of this LGIA.
    Information is Confidential Information only if it is clearly 
designated or marked in writing as confidential on the face of the 
document, or, if the information is conveyed orally or by 
inspection, if the Party providing the information orally informs 
the Party receiving the information that the information is 
confidential.
    If requested by either Party, the other Party shall provide in 
writing, the basis for asserting that the information referred to in 
this Article 22 warrants confidential treatment, and the requesting 
Party may disclose such writing to the appropriate Governmental 
Authority. Each Party shall be responsible for the costs associated 
with affording confidential treatment to its information.
    22.1.1 Term. During the term of this LGIA, and for a period of 
three (3) years after the expiration or termination of this LGIA, 
except as otherwise provided in this Article 22, each Party shall 
hold in confidence and shall not disclose to any person Confidential 
Information.
    22.1.2 Scope. Confidential Information shall not include 
information that the receiving Party can demonstrate: (1) is 
generally available to the public other than as a result of a 
disclosure by the receiving Party; (2) was in the lawful possession 
of the receiving Party on a non-confidential basis before receiving 
it from the disclosing Party; (3) was supplied to the receiving 
Party without restriction by a third party, who, to the knowledge of 
the receiving Party after due inquiry, was under no obligation to 
the disclosing Party to keep such information confidential; (4) was 
independently developed by the receiving Party without reference to 
Confidential Information of the disclosing Party; (5) is, or 
becomes, publicly known, through no wrongful act or omission of the 
receiving Party or Breach of this LGIA; or (6) is required, in 
accordance with Article 22.1.7 of the LGIA, Order of Disclosure, to 
be disclosed by any Governmental Authority or is otherwise required 
to be disclosed by law or subpoena, or is necessary in any legal 
proceeding establishing rights and obligations under this LGIA. 
Information designated as Confidential Information will no longer be 
deemed confidential if the Party that designated the information as 
confidential notifies the other Party that it no longer is 
confidential.
    22.1.3 Release of Confidential Information. Neither Party shall 
release or disclose Confidential Information to any other person, 
except to its Affiliates (limited by the Standards of Conduct 
requirements), subcontractors, employees, consultants, or to parties 
who may be or considering providing financing to or equity 
participation with Interconnection Customer, or to potential 
purchasers or assignees of Interconnection Customer, on a need-to-
know basis in connection with this LGIA, unless such person has 
first been advised of the confidentiality provisions of this Article 
22 and has agreed to comply with such provisions. Notwithstanding 
the foregoing, a Party providing Confidential Information to any 
person shall remain primarily responsible for any release of 
Confidential Information in contravention of this Article 22.
    22.1.4 Rights. Each Party retains all rights, title, and 
interest in the Confidential Information that each Party discloses 
to the other Party. The disclosure by each Party to the other Party 
of Confidential Information shall not be deemed a waiver by either 
Party or any other person or entity of the right to protect the 
Confidential Information from public disclosure.
    22.1.5 No Warranties. By providing Confidential Information, 
neither Party makes any warranties or representations as to its 
accuracy or completeness. In addition, by supplying Confidential 
Information, neither Party obligates itself to provide any 
particular information or Confidential Information to the other 
Party nor to enter into any further agreements or proceed with any 
other relationship or joint venture.
    22.1.6 Standard of Care. Each Party shall use at least the same 
standard of care to protect Confidential Information it receives as 
it uses to protect its own Confidential Information from 
unauthorized disclosure, publication or dissemination. Each Party 
may use Confidential Information solely to fulfill its obligations 
to the other Party under this LGIA or its regulatory requirements.
    22.1.7 Order of Disclosure. If a court or a Government Authority 
or entity with the right, power, and apparent authority to do so 
requests or requires either Party, by subpoena, oral deposition, 
interrogatories, requests for production of documents, 
administrative order, or otherwise, to disclose Confidential 
Information, that Party shall provide the other Party with prompt 
notice of such request(s) or requirement(s) so that the other Party 
may seek an appropriate protective order or waive compliance with 
the terms of this LGIA. Notwithstanding the absence of a protective 
order or waiver, the Party may disclose such Confidential 
Information which, in the opinion of its counsel, the Party is 
legally compelled to disclose. Each Party will use Reasonable 
Efforts to obtain reliable assurance that confidential treatment 
will be accorded any Confidential Information so furnished.
    22.1.8 Termination of Agreement. Upon termination of this LGIA 
for any reason, each Party shall, within ten (10) Calendar Days of 
receipt of a written request from the other Party, use Reasonable 
Efforts to destroy, erase, or delete (with such destruction, 
erasure, and deletion certified in writing to the other Party) or 
return to the other Party, without retaining copies thereof, any and 
all written or electronic Confidential Information received from the 
other Party.
    22.1.9 Remedies. The Parties agree that monetary damages would 
be inadequate to compensate a Party for the other Party's Breach of 
its obligations under this Article 22. Each Party accordingly agrees 
that the other Party shall be entitled to equitable

[[Page 61332]]

relief, by way of injunction or otherwise, if the first Party 
Breaches or threatens to Breach its obligations under this Article 
22, which equitable relief shall be granted without bond or proof of 
damages, and the receiving Party shall not plead in defense that 
there would be an adequate remedy at law. Such remedy shall not be 
deemed an exclusive remedy for the Breach of this Article 22, but 
shall be in addition to all other remedies available at law or in 
equity. The Parties further acknowledge and agree that the covenants 
contained herein are necessary for the protection of legitimate 
business interests and are reasonable in scope. No Party, however, 
shall be liable for indirect, incidental, or consequential or 
punitive damages of any nature or kind resulting from or arising in 
connection with this Article 22.
    22.1.10 Disclosure to FERC, its Staff, or a State. 
Notwithstanding anything in this Article 22 to the contrary, and 
pursuant to 18 CFR 1b.20, if FERC or its staff, during the course of 
an investigation or otherwise, requests information from one of the 
Parties that is otherwise required to be maintained in confidence 
pursuant to this LGIA, the Party shall provide the requested 
information to FERC or its staff, within the time provided for in 
the request for information. In providing the information to FERC or 
its staff, the Party must, consistent with 18 CFR 388.112, request 
that the information be treated as confidential and non-public by 
FERC and its staff and that the information be withheld from public 
disclosure. Parties are prohibited from notifying the other Party to 
this LGIA prior to the release of the Confidential Information to 
FERC or its staff. The Party shall notify the other Party to the 
LGIA when it is notified by FERC or its staff that a request to 
release Confidential Information has been received by FERC, at which 
time either of the Parties may respond before such information would 
be made public, pursuant to 18 CFR 388.112. Requests from a state 
regulatory body conducting a confidential investigation shall be 
treated in a similar manner if consistent with the applicable state 
rules and regulations.
    22.1.11 Subject to the exception in Article 22.1.10, any 
information that a Party claims is competitively sensitive, 
commercial or financial information under this LGIA (``Confidential 
Information'') shall not be disclosed by the other Party to any 
person not employed or retained by the other Party, except to the 
extent disclosure is (i) required by law; (ii) reasonably deemed by 
the disclosing Party to be required to be disclosed in connection 
with a dispute between or among the Parties, or the defense of 
litigation or dispute; (iii) otherwise permitted by consent of the 
other Party, such consent not to be unreasonably withheld; or (iv) 
necessary to fulfill its obligations under this LGIA or as a 
transmission service provider or a [Control Area]Balancing Authority 
Area operator including disclosing the Confidential Information to 
an RTO or ISO or to a regional or national reliability organization. 
The Party asserting confidentiality shall notify the other Party in 
writing of the information it claims is confidential. Prior to any 
disclosures of the other Party's Confidential Information under this 
subparagraph, or if any third party or Governmental Authority makes 
any request or demand for any of the information described in this 
subparagraph, the disclosing Party agrees to promptly notify the 
other Party in writing and agrees to assert confidentiality and 
cooperate with the other Party in seeking to protect the 
Confidential Information from public disclosure by confidentiality 
agreement, protective order or other reasonable measures.

Article 23. Environmental Releases

    23.1 Each Party shall notify the other Party, first orally and 
then in writing, of the release of any Hazardous Substances, any 
asbestos or lead abatement activities, or any type of remediation 
activities related to the Large Generating Facility or the 
Interconnection Facilities, each of which may reasonably be expected 
to affect the other Party. The notifying Party shall: (i) provide 
the notice as soon as practicable, provided such Party makes a good 
faith effort to provide the notice no later than twenty-four hours 
after such Party becomes aware of the occurrence; and (ii) promptly 
furnish to the other Party copies of any publicly available reports 
filed with any Governmental Authorities addressing such events.

Article 24. Information Requirements

    24.1 Information Acquisition. Transmission Provider and 
Interconnection Customer shall submit specific information regarding 
the electrical characteristics of their respective facilities to 
each other as described below and in accordance with Applicable 
Reliability Standards.
    24.2 Information Submission by Transmission Provider. The 
initial information submission by Transmission Provider shall occur 
no later than one hundred eighty (180) Calendar Days prior to Trial 
Operation and shall include Transmission System information 
necessary to allow Interconnection Customer to select equipment and 
meet any system protection and stability requirements, unless 
otherwise agreed to by the Parties. On a monthly basis Transmission 
Provider shall provide Interconnection Customer a status report on 
the construction and installation of Transmission Provider's 
Interconnection Facilities and Network Upgrades, including, but not 
limited to, the following information: (1) progress to date; (2) a 
description of the activities since the last report (3) a 
description of the action items for the next period; and (4) the 
delivery status of equipment ordered.
    24.3 Updated Information Submission by Interconnection Customer. 
The updated information submission by Interconnection Customer, 
including manufacturer information, shall occur no later than one 
hundred eighty (180) Calendar Days prior to the Trial Operation. 
Interconnection Customer shall submit a completed copy of the Large 
Generating Facility data requirements contained in Appendix 1 to the 
LGIP. It shall also include any additional information provided to 
Transmission Provider for the [Feasibility]Cluster Study and 
Facilities Study. Information in this submission shall be the most 
current Large Generating Facility design or expected performance 
data. Information submitted for stability models shall be compatible 
with Transmission Provider standard models. If there is no 
compatible model, Interconnection Customer will work with a 
consultant mutually agreed to by the Parties to develop and supply a 
standard model and associated information.
    If Interconnection Customer's data is materially different from 
what was originally provided to Transmission Provider pursuant to 
the Interconnection Study Agreement between Transmission Provider 
and Interconnection Customer, then Transmission Provider will 
conduct appropriate studies to determine the impact on Transmission 
Provider Transmission System based on the actual data submitted 
pursuant to this Article 24.3. [The]Interconnection Customer shall 
not begin Trial Operation until such studies are completed.
    24.4 Information Supplementation. Prior to the Operation Date, 
the Parties shall supplement their information submissions described 
above in this Article 24 with any and all ``as-built'' Large 
Generating Facility information or ``as-tested'' performance 
information that differs from the initial submissions or, 
alternatively, written confirmation that no such differences exist. 
The Interconnection Customer shall conduct tests on the Large 
Generating Facility as required by Good Utility Practice such as an 
open circuit ``step voltage'' test on the Large Generating Facility 
to verify proper operation of the Large Generating Facility's 
automatic voltage regulator.
    Unless otherwise agreed, the test conditions shall include: (1) 
Large Generating Facility at synchronous speed; (2) automatic 
voltage regulator on and in voltage control mode; and (3) a five 
percent change in Large Generating Facility terminal voltage 
initiated by a change in the voltage regulators reference voltage. 
Interconnection Customer shall provide validated test recordings 
showing the responses of Large Generating Facility terminal and 
field voltages. In the event that direct recordings of these 
voltages is impractical, recordings of other voltages or currents 
that mirror the response of the Large Generating Facility's terminal 
or field voltage are acceptable if information necessary to 
translate these alternate quantities to actual Large Generating 
Facility terminal or field voltages is provided. Large Generating 
Facility testing shall be conducted and results provided to 
Transmission Provider for each individual generating unit in a 
station.
    Subsequent to the Operation Date, Interconnection Customer shall 
provide Transmission Provider any information changes due to 
equipment replacement, repair, or adjustment. Transmission Provider 
shall provide Interconnection Customer any information changes due 
to equipment replacement, repair or adjustment in the directly 
connected substation or any adjacent Transmission Provider-owned 
substation that may affect Interconnection Customer's 
Interconnection Facilities equipment ratings, protection or 
operating requirements. The Parties shall provide such information 
no later than thirty (30) Calendar Days after the

[[Page 61333]]

date of the equipment replacement, repair or adjustment.

Article 25. Information Access and Audit Rights

    25.1 Information Access. Each Party (the ``disclosing Party'') 
shall make available to the other Party information that is in the 
possession of the disclosing Party and is necessary in order for the 
other Party to: (i) verify the costs incurred by the disclosing 
Party for which the other Party is responsible under this LGIA; and 
(ii) carry out its obligations and responsibilities under this LGIA. 
The Parties shall not use such information for purposes other than 
those set forth in this Article 25.1 and to enforce their rights 
under this LGIA.
    25.2 Reporting of Non-Force Majeure Events. Each Party (the 
``notifying Party'') shall notify the other Party when the notifying 
Party becomes aware of its inability to comply with the provisions 
of this LGIA for a reason other than a Force Majeure event. The 
Parties agree to cooperate with each other and provide necessary 
information regarding such inability to comply, including the date, 
duration, reason for the inability to comply, and corrective actions 
taken or planned to be taken with respect to such inability to 
comply. Notwithstanding the foregoing, notification, cooperation or 
information provided under this article shall not entitle the Party 
receiving such notification to allege a cause for anticipatory 
breach of this LGIA.
    25.3 Audit Rights. Subject to the requirements of 
confidentiality under Article 22 of this LGIA, each Party shall have 
the right, during normal business hours, and upon prior reasonable 
notice to the other Party, to audit at its own expense the other 
Party's accounts and records pertaining to either Party's 
performance or either Party's satisfaction of obligations under this 
LGIA. Such audit rights shall include audits of the other Party's 
costs, calculation of invoiced amounts, Transmission Provider's 
efforts to allocate responsibility for the provision of reactive 
support to the Transmission System, Transmission Provider's efforts 
to allocate responsibility for interruption or reduction of 
generation on the Transmission System, and each Party's actions in 
an Emergency Condition. Any audit authorized by this article shall 
be performed at the offices where such accounts and records are 
maintained and shall be limited to those portions of such accounts 
and records that relate to each Party's performance and satisfaction 
of obligations under this LGIA. Each Party shall keep such accounts 
and records for a period equivalent to the audit rights periods 
described in Article 25.4.

25.4 Audit Rights Periods.

    25.4.1 Audit Rights Period for Construction-Related Accounts and 
Records. Accounts and records related to the design, engineering, 
procurement, and construction of Transmission Provider's 
Interconnection Facilities and Network Upgrades shall be subject to 
audit for a period of twenty-four months following Transmission 
Provider's issuance of a final invoice in accordance with Article 
12.2.
    25.4.2 Audit Rights Period for All Other Accounts and Records. 
Accounts and records related to either Party's performance or 
satisfaction of all obligations under this LGIA other than those 
described in Article 25.4.1 shall be subject to audit as follows: 
(i) for an audit relating to cost obligations, the applicable audit 
rights period shall be twenty-four months after the auditing Party's 
receipt of an invoice giving rise to such cost obligations; and (ii) 
for an audit relating to all other obligations, the applicable audit 
rights period shall be twenty-four months after the event for which 
the audit is sought.
    25.5 Audit Results. If an audit by a Party determines that an 
overpayment or an underpayment has occurred, a notice of such 
overpayment or underpayment shall be given to the other Party 
together with those records from the audit which support such 
determination.

Article 26. Subcontractors

    26.1 General. Nothing in this LGIA shall prevent a Party from 
utilizing the services of any subcontractor as it deems appropriate 
to perform its obligations under this LGIA; provided, however, that 
each Party shall require its subcontractors to comply with all 
applicable terms and conditions of this LGIA in providing such 
services and each Party shall remain primarily liable to the other 
Party for the performance of such subcontractor.
    26.2 Responsibility of Principal. The creation of any 
subcontract relationship shall not relieve the hiring Party of any 
of its obligations under this LGIA. The hiring Party shall be fully 
responsible to the other Party for the acts or omissions of any 
subcontractor the hiring Party hires as if no subcontract had been 
made; provided, however, that in no event shall Transmission 
Provider be liable for the actions or inactions of Interconnection 
Customer or its subcontractors with respect to obligations of 
Interconnection Customer under Article 5 of this LGIA. Any 
applicable obligation imposed by this LGIA upon the hiring Party 
shall be equally binding upon, and shall be construed as having 
application to, any subcontractor of such Party.
    26.3 No Limitation by Insurance. The obligations under this 
Article 26 will not be limited in any way by any limitation of 
subcontractor's insurance.

Article 27. Disputes

    27.1 Submission. In the event either Party has a dispute, or 
asserts a claim, that arises out of or in connection with this LGIA 
or its performance, such Party (the ``disputing Party'') shall 
provide the other Party with written notice of the dispute or claim 
(``Notice of Dispute''). Such dispute or claim shall be referred to 
a designated senior representative of each Party for resolution on 
an informal basis as promptly as practicable after receipt of the 
Notice of Dispute by the other Party. In the event the designated 
representatives are unable to resolve the claim or dispute through 
unassisted or assisted negotiations within thirty (30) Calendar Days 
of the other Party's receipt of the Notice of Dispute, such claim or 
dispute may, upon mutual agreement of the Parties, be submitted to 
arbitration and resolved in accordance with the arbitration 
procedures set forth below. In the event the Parties do not agree to 
submit such claim or dispute to arbitration, each Party may exercise 
whatever rights and remedies it may have in equity or at law 
consistent with the terms of this LGIA.
    27.2 External Arbitration Procedures. Any arbitration initiated 
under this LGIA shall be conducted before a single neutral 
arbitrator appointed by the Parties. If the Parties fail to agree 
upon a single arbitrator within ten (10) Calendar Days of the 
submission of the dispute to arbitration, each Party shall choose 
one arbitrator who shall sit on a three-member arbitration panel. 
The two arbitrators so chosen shall within twenty (20) Calendar Days 
select a third arbitrator to chair the arbitration panel. In either 
case, the arbitrators shall be knowledgeable in electric utility 
matters, including electric transmission and bulk power issues, and 
shall not have any current or past substantial business or financial 
relationships with any party to the arbitration (except prior 
arbitration). The arbitrator(s) shall provide each of the Parties an 
opportunity to be heard and, except as otherwise provided herein, 
shall conduct the arbitration in accordance with the Commercial 
Arbitration Rules of the American Arbitration Association 
(``Arbitration Rules'') and any applicable FERC regulations or RTO 
rules; provided, however, in the event of a conflict between the 
Arbitration Rules and the terms of this Article 27, the terms of 
this Article 27 shall prevail.
    27.3 Arbitration Decisions. Unless otherwise agreed by the 
Parties, the arbitrator(s) shall render a decision within ninety 
(90) Calendar Days of appointment and shall notify the Parties in 
writing of such decision and the reasons therefor. The arbitrator(s) 
shall be authorized only to interpret and apply the provisions of 
this LGIA and shall have no power to modify or change any provision 
of this Agreement in any manner. The decision of the arbitrator(s) 
shall be final and binding upon the Parties, and judgment on the 
award may be entered in any court having jurisdiction. The decision 
of the arbitrator(s) may be appealed solely on the grounds that the 
conduct of the arbitrator(s), or the decision itself, violated the 
standards set forth in the Federal Arbitration Act or the 
Administrative Dispute Resolution Act. The final decision of the 
arbitrator must also be filed with FERC if it affects jurisdictional 
rates, terms and conditions of service, Interconnection Facilities, 
or Network Upgrades.
    27.4 Costs. Each Party shall be responsible for its own costs 
incurred during the arbitration process and for the following costs, 
if applicable: (1) the cost of the arbitrator chosen by the Party to 
sit on the three member panel and one half of the cost of the third 
arbitrator chosen; or (2) one half the cost of the single arbitrator 
jointly chosen by the Parties.

Article 28. Representations, Warranties, and Covenants

    28.1 General. Each Party makes the following representations, 
warranties and covenants:
    28.1.1 Good Standing. Such Party is duly organized, validly 
existing and in good

[[Page 61334]]

standing under the laws of the state in which it is organized, 
formed, or incorporated, as applicable; that it is qualified to do 
business in the state or states in which the Large Generating 
Facility, Interconnection Facilities and Network Upgrades owned by 
such Party, as applicable, are located; and that it has the 
corporate power and authority to own its properties, to carry on its 
business as now being conducted and to enter into this LGIA and 
carry out the transactions contemplated hereby and perform and carry 
out all covenants and obligations on its part to be performed under 
and pursuant to this LGIA.
    28.1.2 Authority. Such Party has the right, power and authority 
to enter into this LGIA, to become a Party hereto and to perform its 
obligations hereunder. This LGIA is a legal, valid and binding 
obligation of such Party, enforceable against such Party in 
accordance with its terms, except as the enforceability thereof may 
be limited by applicable bankruptcy, insolvency, reorganization or 
other similar laws affecting creditors' rights generally and by 
general equitable principles (regardless of whether enforceability 
is sought in a proceeding in equity or at law).
    28.1.3 No Conflict. The execution, delivery and performance of 
this LGIA does not violate or conflict with the organizational or 
formation documents, or bylaws or operating agreement, of such 
Party, or any judgment, license, permit, order, material agreement 
or instrument applicable to or binding upon such Party or any of its 
assets.
    28.1.4 Consent and Approval. Such Party has sought or obtained, 
or, in accordance with this LGIA will seek or obtain, each consent, 
approval, authorization, order, or acceptance by any Governmental 
Authority in connection with the execution, delivery and performance 
of this LGIA, and it will provide to any Governmental Authority 
notice of any actions under this LGIA that are required by 
Applicable Laws and Regulations.

Article 29. Joint Operating Committee

    29.1 Joint Operating Committee. Except in the case of ISOs and 
RTOs, Transmission Provider shall constitute a Joint Operating 
Committee to coordinate operating and technical considerations of 
Interconnection Service. At least six (6) months prior to the 
expected Initial Synchronization Date, Interconnection Customer and 
Transmission Provider shall each appoint one representative and one 
alternate to the Joint Operating Committee. Each Interconnection 
Customer shall notify Transmission Provider of its appointment in 
writing. Such appointments may be changed at any time by similar 
notice. The Joint Operating Committee shall meet as necessary, but 
not less than once each calendar year, to carry out the duties set 
forth herein. The Joint Operating Committee shall hold a meeting at 
the request of either Party, at a time and place agreed upon by the 
representatives. The Joint Operating Committee shall perform all of 
its duties consistent with the provisions of this LGIA. Each Party 
shall cooperate in providing to the Joint Operating Committee all 
information required in the performance of the Joint Operating 
Committee's duties. All decisions and agreements, if any, made by 
the Joint Operating Committee, shall be evidenced in writing. The 
duties of the Joint Operating Committee shall include the following:
    29.1.1 Establish data requirements and operating record 
requirements.
    29.1.2 Review the requirements, standards, and procedures for 
data acquisition equipment, protective equipment, and any other 
equipment or software.
    29.1.3 Annually review the one (1) year forecast of maintenance 
and planned outage schedules of Transmission Provider's and 
Interconnection Customer's facilities at the Point of 
Interconnection.
    29.1.4 Coordinate the scheduling of maintenance and planned 
outages on the Interconnection Facilities, the Large Generating 
Facility and other facilities that impact the normal operation of 
the interconnection of the Large Generating Facility to the 
Transmission System.
    29.1.5 Ensure that information is being provided by each Party 
regarding equipment availability.
    29.1.6 Perform such other duties as may be conferred upon it by 
mutual agreement of the Parties.

Article 30. Miscellaneous

    30.1 Binding Effect. This LGIA and the rights and obligations 
hereof, shall be binding upon and shall inure to the benefit of the 
successors and assigns of the Parties hereto.
    30.2 Conflicts. In the event of a conflict between the body of 
this LGIA and any attachment, appendices or exhibits hereto, the 
terms and provisions of the body of this LGIA shall prevail and be 
deemed the final intent of the Parties.
    30.3 Rules of Interpretation. This LGIA, unless a clear contrary 
intention appears, shall be construed and interpreted as follows: 
(1) the singular number includes the plural number and vice versa; 
(2) reference to any person includes such person's successors and 
assigns but, in the case of a Party, only if such successors and 
assigns are permitted by this LGIA, and reference to a person in a 
particular capacity excludes such person in any other capacity or 
individually; (3) reference to any agreement (including this LGIA), 
document, instrument or tariff means such agreement, document, 
instrument, or tariff as amended or modified and in effect from time 
to time in accordance with the terms thereof and, if applicable, the 
terms hereof; (4) reference to any Applicable Laws and Regulations 
means such Applicable Laws and Regulations as amended, modified, 
codified, or reenacted, in whole or in part, and in effect from time 
to time, including, if applicable, rules and regulations promulgated 
thereunder; (5) unless expressly stated otherwise, reference to any 
Article, Section or Appendix means such Article of this LGIA or such 
Appendix to this LGIA, or such Section to the LGIP or such Appendix 
to the LGIP, as the case may be; (6) ``hereunder'', ``hereof'', 
``herein'', ``hereto'' and words of similar import shall be deemed 
references to this LGIA as a whole and not to any particular Article 
or other provision hereof or thereof; (7) ``including'' (and with 
correlative meaning ``include'') means including without limiting 
the generality of any description preceding such term; and (8) 
relative to the determination of any period of time, ``from'' means 
``from and including'', ``to'' means ``to but excluding'' and 
``through'' means ``through and including''.
    30.4 Entire Agreement. This LGIA, including all Appendices and 
Schedules attached hereto, constitutes the entire agreement between 
the Parties with reference to the subject matter hereof, and 
supersedes all prior and contemporaneous understandings or 
agreements, oral or written, between the Parties with respect to the 
subject matter of this LGIA. There are no other agreements, 
representations, warranties, or covenants which constitute any part 
of the consideration for, or any condition to, either Party's 
compliance with its obligations under this LGIA.
    30.5 No Third Party Beneficiaries. This LGIA is not intended to 
and does not create rights, remedies, or benefits of any character 
whatsoever in favor of any persons, corporations, associations, or 
entities other than the Parties, and the obligations herein assumed 
are solely for the use and benefit of the Parties, their successors 
in interest and, where permitted, their assigns.
    30.6 Waiver. The failure of a Party to this LGIA to insist, on 
any occasion, upon strict performance of any provision of this LGIA 
will not be considered a waiver of any obligation, right, or duty 
of, or imposed upon, such Party.
    Any waiver at any time by either Party of its rights with 
respect to this LGIA shall not be deemed a continuing waiver or a 
waiver with respect to any other failure to comply with any other 
obligation, right, duty of this LGIA. Termination or Default of this 
LGIA for any reason by Interconnection Customer shall not constitute 
a waiver of Interconnection Customer's legal rights to obtain an 
interconnection from Transmission Provider. Any waiver of this LGIA 
shall, if requested, be provided in writing.
    30.7 Headings. The descriptive headings of the various Articles 
of this LGIA have been inserted for convenience of reference only 
and are of no significance in the interpretation or construction of 
this LGIA.
    30.8 Multiple Counterparts. This LGIA may be executed in two or 
more counterparts, each of which is deemed an original but all 
constitute one and the same instrument.
    30.9 Amendment. The Parties may by mutual agreement amend this 
LGIA by a written instrument duly executed by the Parties.
    30.10 Modification by the Parties. The Parties may by mutual 
agreement amend the Appendices to this LGIA by a written instrument 
duly executed by the Parties. Such amendment shall become effective 
and a part of this LGIA upon satisfaction of all Applicable Laws and 
Regulations.
    30.11 Reservation of Rights. Transmission Provider shall have 
the right to make a unilateral filing with FERC to modify this LGIA 
with respect to any rates, terms and conditions, charges, 
classifications of service, rule or regulation under section 205 or 
any

[[Page 61335]]

other applicable provision of the Federal Power Act and FERC's rules 
and regulations thereunder, and Interconnection Customer shall have 
the right to make a unilateral filing with FERC to modify this LGIA 
pursuant to section 206 or any other applicable provision of the 
Federal Power Act and FERC's rules and regulations thereunder; 
provided that each Party shall have the right to protest any such 
filing by the other Party and to participate fully in any proceeding 
before FERC in which such modifications may be considered. Nothing 
in this LGIA shall limit the rights of the Parties or of FERC under 
sections 205 or 206 of the Federal Power Act and FERC's rules and 
regulations thereunder, except to the extent that the Parties 
otherwise mutually agree as provided herein.
    30.12 No Partnership. This LGIA shall not be interpreted or 
construed to create an association, joint venture, agency 
relationship, or partnership between the Parties or to impose any 
partnership obligation or partnership liability upon either Party. 
Neither Party shall have any right, power or authority to enter into 
any agreement or undertaking for, or act on behalf of, or to act as 
or be an agent or representative of, or to otherwise bind, the other 
Party.
    IN WITNESS WHEREOF, the Parties have executed this LGIA in 
duplicate originals, each of which shall constitute and be an 
original effective Agreement between the Parties.

[Insert name of Transmission Provider or Transmission Owner, if 
applicable]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Appendix A to LGIA

Interconnection Facilities, Network Upgrades and Distribution Upgrades

    1. Interconnection Facilities:
    (a) {insert Interconnection Customer's Interconnection 
Facilities{time} :
    (b) {insert Transmission Provider's Interconnection 
Facilities{time} :
    2. Network Upgrades:
    (a) {insert Stand Alone Network Upgrades{time} :
    (b) {insert Substation Network Upgrades [Other Network 
Upgrades]{time} :
    (c) {insert System Network Upgrades{time} :
    3. Distribution Upgrades:

Appendix B to LGIA

Milestones

Site Control

Check box if applicable [ ]

    Interconnection Customer with qualifying regulatory limitations 
must demonstrate 100% Site Control by {Transmission Provider to 
insert date 180 days from the effective date of this LGIA{time}  or 
the LGIA may be terminated per Article 17 (Default) of this LGIA and 
the Interconnection Customer may be subject to Withdrawal Penalties 
per Section 3.7.1.1 of the Transmission Provider's LGIP (Calculation 
of the Withdrawal Penalty).

Appendix C to LGIA

Interconnection Details

Appendix D to LGIA

Security Arrangements Details

    Infrastructure security of Transmission System equipment and 
operations and control hardware and software is essential to ensure 
day-to-day Transmission System reliability and operational security. 
FERC will expect all Transmission Providers, market participants, 
and Interconnection Customers interconnected to the Transmission 
System to comply with the recommendations offered by the President's 
Critical Infrastructure Protection Board and, eventually, best 
practice recommendations from the electric reliability authority. 
All public utilities will be expected to meet basic standards for 
system infrastructure and operational security, including physical, 
operational, and cyber-security practices.

Appendix E to LGIA

Commercial Operation Date

    This Appendix E is a part of the LGIA between Transmission 
Provider and Interconnection Customer.
{Date{time} 

{Transmission Provider Address{time} 

Re: _____ Large Generating Facility
Dear: _____.
On {Date{time}  {Interconnection Customer{time}  has completed Trial 
Operation of Unit No. __ . This letter confirms that 
{Interconnection Customer{time}  commenced Commercial Operation of 
Unit No. __ at the Large Generating Facility, effective as of {Date 
plus one day{time} .
    Thank you.

{Signature{time} 
{Interconnection Customer Representative{time} 

Appendix F to LGIA

Addresses for Delivery of Notices and Billings

Notices:

Transmission Provider:

    {To be supplied.{time} 

Interconnection Customer:

    {To be supplied.{time} 

Billings and Payments:

Transmission Provider:

    {To be supplied.{time} 

Interconnection Customer:

    {To be supplied.{time} 

Alternative Forms of Delivery of Notices (telephone, facsimile or 
email):

Transmission Provider:

    {To be supplied.{time} 
Interconnection Customer:
    {To be supplied.{time} 

APPENDIX G

Interconnection Requirements for a Wind Generating Plant

    Appendix G sets forth requirements and provisions specific to a 
wind generating plant or a Generating Facility that contains a wind 
generating plant. All other requirements of this LGIA continue to 
apply to wind generating plant interconnections.

A. Technical Standards Applicable to a Wind Generating Plant

i. Low Voltage Ride-Through (LVRT) Capability

    A wind generating plant shall be able to remain online during 
voltage disturbances up to the time periods and associated voltage 
levels set forth in the standard below. The LVRT standard provides 
for a transition period standard and a post-transition period 
standard.

Transition Period LVRT Standard

    The transition period standard applies to wind generating plants 
subject to FERC Order 661 that have either: (i) interconnection 
agreements signed and filed with the Commission, filed with the 
Commission in unexecuted form, or filed with the Commission as non-
conforming agreements between January 1, 2006 and December 31, 2006, 
with a scheduled in-service date no later than December 31, 2007, or 
(ii) wind generating turbines subject to a wind turbine procurement 
contract executed prior to December 31, 2005, for delivery through 
2007.
    1. Wind generating plants are required to remain in-service 
during three-phase faults with normal clearing (which is a time 
period of approximately 4-9 cycles) and single line to ground faults 
with delayed clearing, and subsequent post-fault voltage recovery to 
prefault voltage unless clearing the fault effectively disconnects 
the generator from the system. The clearing time requirement for a 
three-phase fault will be specific to the wind generating plant 
substation location, as determined by and documented by the 
transmission provider. The maximum clearing time the wind generating 
plant shall be required to withstand for a three-phase fault shall 
be 9 cycles at a voltage as low as 0.15 p.u., as measured at the 
high side of the wind generating plant step-up transformer (i.e. the 
transformer that steps the voltage up to the transmission 
interconnection voltage or ``GSU''), after which, if the fault 
remains following the location-specific normal clearing time for 
three-phase faults, the wind generating plant may disconnect from 
the transmission system.
    2. This requirement does not apply to faults that would occur 
between the wind generator terminals and the high side of the GSU or 
to faults that would result in a voltage lower than 0.15 per unit on 
the high side of the GSU serving the facility.
    3. Wind generating plants may be tripped after the fault period 
if this action is intended as part of a special protection system.
    4. Wind generating plants may meet the LVRT requirements of this 
standard by the performance of the generators or by installing 
additional equipment (e.g., Static VAr

[[Page 61336]]

Compensator, etc.) within the wind generating plant or by a 
combination of generator performance and additional equipment.
    5. Existing individual generator units that are, or have been, 
interconnected to the network at the same location at the effective 
date of the Appendix G LVRT Standard are exempt from meeting the 
Appendix G LVRT Standard for the remaining life of the existing 
generation equipment. Existing individual generator units that are 
replaced are required to meet the Appendix G LVRT Standard.

Post-transition Period LVRT Standard

    All wind generating plants subject to FERC Order No. 661 and not 
covered by the transition period described above must meet the 
following requirements:
    1. Wind generating plants are required to remain in-service 
during three-phase faults with normal clearing (which is a time 
period of approximately 4-9 cycles) and single line to ground faults 
with delayed clearing, and subsequent post-fault voltage recovery to 
prefault voltage unless clearing the fault effectively disconnects 
the generator from the system. The clearing time requirement for a 
three-phase fault will be specific to the wind generating plant 
substation location, as determined by and documented by the 
transmission provider. The maximum clearing time the wind generating 
plant shall be required to withstand for a three-phase fault shall 
be 9 cycles after which, if the fault remains following the 
location-specific normal clearing time for three-phase faults, the 
wind generating plant may disconnect from the transmission system. A 
wind generating plant shall remain interconnected during such a 
fault on the transmission system for a voltage level as low as zero 
volts, as measured at the high voltage side of the wind GSU.
    2. This requirement does not apply to faults that would occur 
between the wind generator terminals and the high side of the GSU.
    3. Wind generating plants may be tripped after the fault period 
if this action is intended as part of a special protection system.
    4. Wind generating plants may meet the LVRT requirements of this 
standard by the performance of the generators or by installing 
additional equipment (e.g., Static VAr Compensator) within the wind 
generating plant or by a combination of generator performance and 
additional equipment.
    Existing individual generator units that are, or have been, 
interconnected to the network at the same location at the effective 
date of the Appendix G LVRT Standard are exempt from meeting the 
Appendix G LVRT Standard for the remaining life of the existing 
generation equipment. Existing individual generator units that are 
replaced are required to meet the Appendix G LVRT Standard.

ii. Power Factor Design Criteria (Reactive Power)

    The following reactive power requirements apply only to a newly 
interconnecting wind generating plant that has executed a Facilities 
Study Agreement as of the effective date of the Final rule 
establishing the reactive power requirements for non-synchronous 
generators in S[s]ection 9.6.1 of this LGIA (Order No. 827). A wind 
generating plant to which this provision applies shall maintain a 
power factor within the range of 0.95 leading to 0.95 lagging, 
measured at the Point of Interconnection as defined in this LGIA, if 
the Transmission Provider's [System Impact] Cluster Study shows that 
such a requirement is necessary to ensure safety or reliability. The 
power factor range standard can be met by using, for example, power 
electronics designed to supply this level of reactive capability 606 
(taking into account any limitations due to voltage level, real 
power output, etc.) or fixed and switched capacitors if agreed to by 
the Transmission Provider, or a combination of the two. The 
Interconnection Customer shall not disable power factor equipment 
while the wind plant is in operation. Wind plants shall also be able 
to provide sufficient dynamic voltage support in lieu of the power 
system stabilizer and automatic voltage regulation at the generator 
excitation system if the System Impact Study shows this to be 
required for system safety or reliability.

iii. Supervisory Control and Data Acquisition (SCADA) Capability

    The wind plant shall provide SCADA capability to transmit data 
and receive instructions from the Transmission Provider to protect 
system reliability. The Transmission Provider and the wind plant 
Interconnection Customer shall determine what SCADA information is 
essential for the proposed wind plant, taking into account the size 
of the plant and its characteristics, location, and importance in 
maintaining generation resource adequacy and transmission system 
reliability in its area.

Appendix H to LGIA

Operating Assumptions for Generating Facility

Check box if applicable [ ]

Operating Assumptions:

    {insert operating assumptions that reflect the charging behavior 
of the Generating Facility that includes at least one electric 
storage resource{time} 

Appendix E: Pro Forma SGIP

    Note: Deletions are in brackets and additions are in italics.

Section 1. Application

* * * * *
    1.4 Modification of the Interconnection Request
    Any modification to machine data or equipment configuration or 
to the interconnection site of the Small Generating Facility not 
agreed to in writing by the Transmission Provider and the 
Interconnection Customer may be deemed a withdrawal of the 
Interconnection Request and may require submission of a new 
Interconnection Request, unless proper notification of each Party by 
the other and a reasonable time to cure the problems created by the 
changes are undertaken. Any such modification of the Interconnection 
Request must be accompanied by any resulting updates to the models 
described in Attachment 2 of this SGIP.
* * * * *

Section 3. Study Process

* * * * *
    3.3 Feasibility Study
    3.3.1 The feasibility study shall identify any potential adverse 
system impacts that would result from the interconnection of the 
Small Generating Facility.
    3.3.2 A deposit of the lesser of 50 percent of the good faith 
estimated feasibility study costs or earnest money of $1,000 may be 
required from the Interconnection Customer.
    3.3.3 The scope of and cost responsibilities for the feasibility 
study are described in the attached feasibility study agreement 
(Attachment 6).
    3.3.4 If the feasibility study shows no potential for adverse 
system impacts, the Transmission Provider shall send the 
Interconnection Customer a facilities study agreement, including an 
outline of the scope of the study and a non-binding good faith 
estimate of the cost to perform the study. If no additional 
facilities are required, the Transmission Provider shall send the 
Interconnection Customer an executable interconnection agreement 
within five Business Days.
    3.3.5 If the feasibility study shows the potential for adverse 
system impacts, the review process shall proceed to the appropriate 
system impact study(s).
    3.3.6 The feasibility study shall evaluate static synchronous 
compensators, static VAR compensators, advanced power flow control 
devices, transmission switching, synchronous condensers, voltage 
source converters, advanced conductors, and tower lifting. 
Transmission Provider shall evaluate each identified alternative 
transmission technology and determine whether it should be used, 
consistent with Good Utility Practice and other applicable 
regulatory requirements. Transmission Provider shall include an 
explanation of the results of Transmission Provider's evaluation for 
each technology in the feasibility study report.
    3.4 System Impact Study
    3.4.1 A system impact study shall identify and detail the 
electric system impacts that would result if the proposed Small 
Generating Facility were interconnected without project 
modifications or electric system modifications, focusing on the 
adverse system impacts identified in the feasibility study, or to 
study potential impacts, including but not limited to those 
identified in the scoping meeting. A system impact study shall 
evaluate the impact of the proposed interconnection on the 
reliability of the electric system.
    3.4.2 If no transmission system impact study is required, but 
potential electric power Distribution System adverse system impacts 
are identified in the scoping meeting or shown in the feasibility 
study, a distribution system impact study must be performed. The 
Transmission Provider shall send the Interconnection Customer a 
distribution system impact study agreement within 15 Business Days 
of transmittal of the feasibility study report, including an outline 
of the scope of the study and a non-binding

[[Page 61337]]

good faith estimate of the cost to perform the study, or following 
the scoping meeting if no feasibility study is to be performed.
    3.4.3 In instances where the feasibility study or the 
distribution system impact study shows potential for transmission 
system adverse system impacts, within five Business Days following 
transmittal of the feasibility study report, the Transmission 
Provider shall send the Interconnection Customer a transmission 
system impact study agreement, including an outline of the scope of 
the study and a non-binding good faith estimate of the cost to 
perform the study, if such a study is required.
    3.4.4 If a transmission system impact study is not required, but 
electric power Distribution System adverse system impacts are shown 
by the feasibility study to be possible and no distribution system 
impact study has been conducted, [the]Transmission Provider shall 
send [the]Interconnection Customer a distribution system impact 
study agreement.
    3.4.5 If the feasibility study shows no potential for 
transmission system or Distribution System adverse system impacts, 
the Transmission Provider shall send the Interconnection Customer 
either a facilities study agreement (Attachment 8), including an 
outline of the scope of the study and a non-binding good faith 
estimate of the cost to perform the study, or an executable 
interconnection agreement, as applicable.
    3.4.6 In order to remain under consideration for 
interconnection, the Interconnection Customer must return executed 
system impact study agreements, if applicable, within 30 Business 
Days.
    3.4.7 A deposit of the good faith estimated costs for each 
system impact study may be required from the Interconnection 
Customer.
    3.4.8 The scope of and cost responsibilities for a system impact 
study are described in the attached system impact study agreement.
    3.4.9 Where transmission systems and Distribution Systems have 
separate owners, such as is the case with transmission-dependent 
utilities (``TDUs'')--whether investor-owned or not--the 
Interconnection Customer may apply to the nearest Transmission 
Provider (Transmission Owner, Regional Transmission Operator, or 
Independent Transmission Provider) providing transmission service to 
the TDU to request project coordination. Affected Systems shall 
participate in the study and provide all information necessary to 
prepare the study.
    3.4.10 The system impact study shall evaluate static synchronous 
compensators, static VAR compensators, advanced power flow control 
devices, transmission switching, synchronous condensers, voltage 
source converters, advanced conductors, and tower lifting. 
Transmission Provider shall evaluate each identified alternative 
transmission technology and determine whether it should be used, 
consistent with Good Utility Practice and other applicable 
regulatory requirements. Transmission Provider shall include an 
explanation of the results of Transmission Provider's evaluation for 
each technology in the system impact study report.
* * * * *

Attachment 2

Small Generator Interconnection Request

(Application Form)

* * * * *

Models for Non-synchronous Small Generating Facilities

    For a non-synchronous Small Generating Facility, Interconnection 
Customer shall provide (1) a validated user-defined root mean 
squared (RMS) positive sequence dynamics model; (2) an appropriately 
parameterized generic library RMS positive sequence dynamics model, 
including model block diagram of the inverter control and plant 
control systems, as defined by the selection in Table 1 or a model 
otherwise approved by the Western Electricity Coordinating Council, 
that corresponds to Interconnection Customer's Small Generating 
Facility; and (3) if applicable, a validated electromagnetic 
transient model if Transmission Provider performs an electromagnetic 
transient study as part of the interconnection study process. A 
user-defined model is a set of programming code created by equipment 
manufacturers or developers that captures the latest features of 
controllers that are mainly software based and represents the 
entities' control strategies but does not necessarily correspond to 
any generic library model. Interconnection Customer must also 
demonstrate that the model is validated by providing evidence that 
the equipment behavior is consistent with the model behavior (e.g., 
an attestation from Interconnection Customer that the model 
accurately represents the entire Small Generating Facility; 
attestations from each equipment manufacturer that the user defined 
model accurately represents the component of the Small Generating 
Facility; or test data).

                    Table 1--Acceptable Generic Library RMS Positive Sequence Dynamics Models
----------------------------------------------------------------------------------------------------------------
           GE PSLF                  Siemens PSS/E*         PowerWorld simulator             Description
----------------------------------------------------------------------------------------------------------------
pvd1........................  .........................  PVD1....................  Distributed PV system model.
der_a.......................  DERAU1...................  DER_A...................  Distributed energy resource
                                                                                    model.
regc_a......................  REGCAU1, REGCA1..........  REGC_A..................  Generator/converter model.
regc_b......................  REGCBU1..................  REGC_B..................  Generator/converter model.
wt1g........................  WT1G1....................  WT1G and WT1G1..........  Wind turbine model for Type-1
                                                                                    wind turbines (conventional
                                                                                    directly connected induction
                                                                                    generator).
wt2g........................  WT2G1....................  WT2G and WT2G1..........  Generator model for generic
                                                                                    Type-2 wind turbines.
wt2e........................  WT2E1....................  WT2E and WT2E1..........  Rotor resistance control
                                                                                    model for wound-rotor
                                                                                    induction wind-turbine
                                                                                    generator wt2g.
reec_a......................  REECAU1, REECA1..........  REEC_A..................  Renewable energy electrical
                                                                                    control model.
reec_c......................  REECCU1..................  REEC_C..................  Electrical control model for
                                                                                    battery energy storage
                                                                                    system.
reec_d......................  REECDU1..................  REEC_D..................  Renewable energy electrical
                                                                                    control model.
wt1t........................  WT12T1...................  WT1T and WT12T1.........  Wind turbine model for Type-1
                                                                                    wind turbines (conventional
                                                                                    directly connected induction
                                                                                    generator).
wt1p_b......................  wt1p_b...................  WT12A1U_B...............  Generic wind turbine pitch
                                                                                    controller for WTGs of Types
                                                                                    1 and 2.
wt2t........................  WT12T1...................  WT2T....................  Wind turbine model for Type-2
                                                                                    wind turbines (directly
                                                                                    connected induction
                                                                                    generator wind turbines with
                                                                                    an external rotor
                                                                                    resistance).
wtgt_a......................  WTDTAU1, WTDTA1..........  WTGT_A..................  Wind turbine drive train
                                                                                    model.
wtga_a......................  WTARAU1, WTARA1..........  WTGA_A..................  Simple aerodynamic model.
wtgp_a......................  WTPTAU1, WTPTA1..........  WTGPT_A.................  Wind Turbine Generator Pitch
                                                                                    controller.
wtgq_a......................  WTTQAU1, WTTQA1..........  WTGTRQ_A................  Wind Turbine Generator Torque
                                                                                    controller.
wtgwgo_a....................  WTGWGOAU.................  WTGWGO_A................  Supplementary control model
                                                                                    for Weak Grids.
wtgibffr_a..................  WTGIBFFRA................  WTGIBFFR_A..............  Inertial-base fast frequency
                                                                                    response control.
wtgp_b......................  WTPTBU1..................  WTGPT_B.................  Wind Turbine Generator Pitch
                                                                                    controller.
wtgt_b......................  WTDTBU1..................  WTGT_B..................  Drive train model.
repc_a......................  Type 4: REPCAU1 (v33),     REPC_A..................  Power Plant Controller.
                               REPCA1 (v34) Type 3:
                               REPCTAU1 (v33), REPCTA1
                               (v34).
repc_b......................  PLNTBU1..................  REPC_B..................  Power Plant Level Controller
                                                                                    for controlling several
                                                                                    plants/devices.
                                                                                   In regard to Siemens PSS/E*:
                                                                                   Names of other models for
                                                                                    interface with other
                                                                                    devices: REA3XBU1, REAX4BU1--
                                                                                    for interface with Type 3
                                                                                    and 4 renewable machines.
                                                                                   SWSAXBU1--for interface with
                                                                                    SVC (modeled as switched
                                                                                    shunt in powerflow).

[[Page 61338]]

 
                                                                                   SYNAXBU1--for interface with
                                                                                    synchronous condenser.
                                                                                   FCTAXBU1--for interface with
                                                                                    FACTS device.
repc_c......................  REPCCU...................  REPC_C..................  Power plant controller.
----------------------------------------------------------------------------------------------------------------

* * * * *

Appendix F: Pro Forma SGIA

    Note:  Deletions are in brackets and additions are in italics.

* * * * *

Article 1. Scope and Limitations of Agreement

* * * * *

1.5 Responsibilities of the Parties

    1.5.1 The Parties shall perform all obligations of this 
Agreement in accordance with all Applicable Laws and Regulations, 
Operating Requirements, and Good Utility Practice.
    1.5.2 The Interconnection Customer shall construct, 
interconnect, operate and maintain its Small Generating Facility and 
construct, operate, and maintain its Interconnection Facilities in 
accordance with the applicable manufacturer's recommended 
maintenance schedule, and in accordance with this Agreement, and 
with Good Utility Practice.
    1.5.3 The Transmission Provider shall construct, operate, and 
maintain its Transmission System and Interconnection Facilities in 
accordance with this Agreement, and with Good Utility Practice.
    1.5.4 The Interconnection Customer agrees to construct its 
facilities or systems in accordance with applicable specifications 
that meet or exceed those provided by the National Electrical Safety 
Code, the American National Standards Institute, IEEE, Underwriter's 
Laboratory, and Operating Requirements in effect at the time of 
construction and other applicable national and state codes and 
standards. The Interconnection Customer agrees to design, install, 
maintain, and operate its Small Generating Facility so as to 
reasonably minimize the likelihood of a disturbance adversely 
affecting or impairing the system or equipment of the Transmission 
Provider and any Affected Systems.
    1.5.5 Each Party shall operate, maintain, repair, and inspect, 
and shall be fully responsible for the facilities that it now or 
subsequently may own unless otherwise specified in the Attachments 
to this Agreement. Each Party shall be responsible for the safe 
installation, maintenance, repair and condition of their respective 
lines and appurtenances on their respective sides of the point of 
change of ownership. The Transmission Provider and the 
Interconnection Customer, as appropriate, shall provide 
Interconnection Facilities that adequately protect the Transmission 
Provider's Transmission System, personnel, and other persons from 
damage and injury. The allocation of responsibility for the design, 
installation, operation, maintenance and ownership of 
Interconnection Facilities shall be delineated in the Attachments to 
this Agreement.
    1.5.6 The Transmission Provider shall coordinate with all 
Affected Systems to support the interconnection.
    1.5.7 The Interconnection Customer shall ensure ``frequency ride 
through'' capability and ``voltage ride through'' capability of its 
Small Generating Facility. The Interconnection Customer shall enable 
these capabilities such that its Small Generating Facility shall not 
disconnect automatically or instantaneously from the system or 
equipment of the Transmission Provider and any Affected Systems for 
a defined under-frequency or over-frequency condition, or an under-
voltage or over-voltage condition, as tested pursuant to S[s]ection 
2.1 of this agreement. The defined conditions shall be in accordance 
with Good Utility Practice and consistent with any standards and 
guidelines that are applied to other generating facilities in the 
Balancing Authority Area on a comparable basis. The Small Generating 
Facility's protective equipment settings shall comply with the 
Transmission Provider's automatic load-shed program. The 
Transmission Provider shall review the protective equipment settings 
to confirm compliance with the automatic load-shed program. The term 
``ride through'' as used herein shall mean the ability of a Small 
Generating Facility to stay connected to and synchronized with the 
system or equipment of the Transmission Provider and any Affected 
Systems during system disturbances within a range of conditions, in 
accordance with Good Utility Practice and consistent with any 
standards and guidelines that are applied to other generating 
facilities in the Balancing Authority Area on a comparable basis. 
The term ``frequency ride through'' as used herein shall mean the 
ability of a Small Generating Facility to stay connected to and 
synchronized with the system or equipment of the Transmission 
Provider and any Affected Systems during system disturbances within 
a range of under-frequency and over-frequency conditions, in 
accordance with Good Utility Practice and consistent with any 
standards and guidelines that are applied to other generating 
facilities in the Balancing Authority Area on a comparable basis. 
The term ``voltage ride through'' as used herein shall mean the 
ability of a Small Generating Facility to stay connected to and 
synchronized with the system or equipment of the Transmission 
Provider and any Affected Systems during system disturbances within 
a range of under-voltage and over-voltage conditions, in accordance 
with Good Utility Practice and consistent with any standards and 
guidelines that are applied to other generating facilities in the 
Balancing Authority Area on a comparable basis. For abnormal 
frequency conditions and voltage conditions within the ``no trip 
zone'' defined by Reliability Standard PRC-024-3 or successor 
mandatory ride through Applicable Reliability Standards, the non-
synchronous Small Generating Facility must ensure that, within any 
physical limitations of the Small Generating Facility, its control 
and protection settings are configured or set to (1) continue active 
power production during disturbance and post disturbance periods at 
pre-disturbance levels unless providing primary frequency response 
or fast frequency response; (2) minimize reductions in active power 
and remain within dynamic voltage and current limits, if reactive 
power priority mode is enabled, unless providing primary frequency 
response or fast frequency response; (3) not artificially limit 
dynamic reactive power capability during disturbances; and (4) 
return to pre-disturbance active power levels without artificial 
ramp rate limits if active power is reduced, unless providing 
primary frequency response or fast frequency response.

1.6 Parallel Operation Obligations

    Once the Small Generating Facility has been authorized to 
commence parallel operation, the Interconnection Customer shall 
abide by all rules and procedures pertaining to the parallel 
operation of the Small Generating Facility in the applicable 
[control area]Balancing Authority Area, including, but not limited 
to; (1) the rules and procedures concerning the operation of 
generation set forth in the Tariff or by the applicable system 
operator(s) for the Transmission Provider's Transmission System and; 
(2) the Operating Requirements set forth in Attachment 5 of this 
Agreement.
* * * * *

1.8 Reactive Power and Primary Frequency Response

1.8.1 Power Factor Design Criteria

1.8.1.1 Synchronous Generation. The Interconnection Customer shall 
design its Small Generating Facility to maintain a composite power 
delivery at continuous rated power output at the Point of 
Interconnection at a power factor within the range of 0.95 leading to 
0.95 lagging, unless the Transmission Provider has established 
different requirements that apply to all similarly situated synchronous 
generators in the [control area] Balancing Authority Area on a 
comparable basis.

    1.8.1.2 Non-Synchronous Generation. The Interconnection Customer 
shall design its Small Generating Facility to maintain a composite 
power delivery at continuous rated power output at the high-side of 
the generator substation at a power factor within the range of 0.95 
leading to 0.95 lagging, unless the Transmission Provider has 
established a different power factor range that applies to all 
similarly situated non-

[[Page 61339]]

synchronous generators in the [control area] Balancing Authority 
Area on a comparable basis. This power factor range standard shall 
be dynamic and can be met using, for example, power electronics 
designed to supply this level of reactive capability (taking into 
account any limitations due to voltage level, real power output, 
etc.) or fixed and switched capacitors, or a combination of the two. 
This requirement shall only apply to newly interconnecting non-
synchronous generators that have not yet executed a Facilities Study 
Agreement as of the effective date of the Final rule establishing 
this requirement (Order No. 827).
    1.8.2 The Transmission Provider is required to pay the 
Interconnection Customer for reactive power that the Interconnection 
Customer provides or absorbs from the Small Generating Facility when 
the Transmission Provider requests the Interconnection Customer to 
operate its Small Generating Facility outside the range specified in 
A[a]rticle 1.8.1. In addition, if the Transmission Provider pays its 
own or affiliated generators for reactive power service within the 
specified range, it must also pay the Interconnection Customer.
    1.8.3 Payments shall be in accordance with the Interconnection 
Customer's applicable rate schedule then in effect unless the 
provision of such service(s) is subject to a regional transmission 
organization or independent system operator FERC-approved rate 
schedule. To the extent that no rate schedule is in effect at the 
time the Interconnection Customer is required to provide or absorb 
reactive power under this Agreement, the Parties agree to 
expeditiously file such rate schedule and agree to support any 
request for waiver of the Commission's prior notice requirement in 
order to compensate the Interconnection Customer from the time 
service commenced.
    1.8.4 Primary Frequency Response. Interconnection Customer shall 
ensure the primary frequency response capability of its Small 
Generating Facility by installing, maintaining, and operating a 
functioning governor or equivalent controls. The term ``functioning 
governor or equivalent controls'' as used herein shall mean the 
required hardware and/or software that provides frequency responsive 
real power control with the ability to sense changes in system 
frequency and autonomously adjust the Small Generating Facility's 
real power output in accordance with the droop and deadband 
parameters and in the direction needed to correct frequency 
deviations. Interconnection Customer is required to install a 
governor or equivalent controls with the capability of operating: 
(1) with a maximum 5 percent droop and 0.036 Hz 
deadband; or (2) in accordance with the relevant droop, deadband, 
and timely and sustained response settings from an approved [NERC] 
Electric Reliability Organization [R]reliability [S]standard 
providing for equivalent or more stringent parameters. The droop 
characteristic shall be: (1) based on the nameplate capacity of the 
Small Generating Facility, and shall be linear in the range of 
frequencies between 59 to 61 Hz that are outside of the deadband 
parameter; or (2) based an approved [NERC] Electric Reliability 
Organization [R]reliability [S]standard providing for an equivalent 
or more stringent parameter. The deadband parameter shall be: the 
range of frequencies above and below nominal (60 Hz) in which the 
governor or equivalent controls is not expected to adjust the Small 
Generating Facility's real power output in response to frequency 
deviations. The deadband shall be implemented: (1) without a step to 
the droop curve, that is, once the frequency deviation exceeds the 
deadband parameter, the expected change in the Small Generating 
Facility's real power output in response to frequency deviations 
shall start from zero and then increase (for under-frequency 
deviations) or decrease (for over-frequency deviations) linearly in 
proportion to the magnitude of the frequency deviation; or (2) in 
accordance with an approved [NERC] Electric Reliability Organization 
[R]reliability [S]standard providing for an equivalent or more 
stringent parameter. Interconnection Customer shall notify 
Transmission Provider that the primary frequency response capability 
of the Small Generating Facility has been tested and confirmed 
during commissioning. Once Interconnection Customer has synchronized 
the Small Generating Facility with the Transmission System, 
Interconnection Customer shall operate the Small Generating Facility 
consistent with the provisions specified in Sections 1.8.4.1 and 
1.8.4.2 of this Agreement. The primary frequency response 
requirements contained herein shall apply to both synchronous and 
non-synchronous Small Generating Facilities.
    1.8.4.1 Governor or Equivalent Controls. Whenever the Small 
Generating Facility is operated in parallel with the Transmission 
System, Interconnection Customer shall operate the Small Generating 
Facility with its governor or equivalent controls in service and 
responsive to frequency. Interconnection Customer shall: (1) in 
coordination with Transmission Provider and/or the relevant 
[b]Balancing [a]Authority, set the deadband parameter to: (1) a 
maximum of 0.036 Hz and set the droop parameter to a 
maximum of 5 percent; or (2) implement the relevant droop and 
deadband settings from an approved [NERC] Electric Reliability 
Organization [R]reliability [S]standard that provides for equivalent 
or more stringent parameters. Interconnection Customer shall be 
required to provide the status and settings of the governor or 
equivalent controls to Transmission Provider and/or the relevant 
[b]Balancing [a]Authority upon request. If Interconnection Customer 
needs to operate the Small Generating Facility with its governor or 
equivalent controls not in service, Interconnection Customer shall 
immediately notify Transmission Provider and the relevant 
[b]Balancing [a]Authority, and provide both with the following 
information: (1) the operating status of the governor or equivalent 
controls (i.e., whether it is currently out of service or when it 
will be taken out of service); (2) the reasons for removing the 
governor or equivalent controls from service; and (3) a reasonable 
estimate of when the governor or equivalent controls will be 
returned to service. Interconnection Customer shall make Reasonable 
Efforts to return its governor or equivalent controls into service 
as soon as practicable. Interconnection Customer shall make 
Reasonable Efforts to keep outages of the Small Generating 
Facility's governor or equivalent controls to a minimum whenever the 
Small Generating Facility is operated in parallel with the 
Transmission System.
    1.8.4.2 Timely and Sustained Response. Interconnection Customer 
shall ensure that the Small Generating Facility's real power 
response to sustained frequency deviations outside of the deadband 
setting is automatically provided and shall begin immediately after 
frequency deviates outside of the deadband, and to the extent the 
Small Generating Facility has operating capability in the direction 
needed to correct the frequency deviation. Interconnection Customer 
shall not block or otherwise inhibit the ability of the governor or 
equivalent controls to respond and shall ensure that the response is 
not inhibited, except under certain operational constraints 
including, but not limited to, ambient temperature limitations, 
physical energy limitations, outages of mechanical equipment, or 
regulatory requirements. The Small Generating Facility shall sustain 
the real power response at least until system frequency returns to a 
value within the deadband setting of the governor or equivalent 
controls. A Commission-approved Reliability Standard with equivalent 
or more stringent requirements shall supersede the above 
requirements.
    1.8.4.3 Exemptions. Small Generating Facilities that are 
regulated by the United States Nuclear Regulatory Commission shall 
be exempt from Sections 1.8.4, 1.8.4.1, and 1.8.4.2 of this 
Agreement. Small Generating Facilities that are behind the meter 
generation that is sized-to-load (i.e., the thermal load and the 
generation are near-balanced in real-time operation and the 
generation is primarily controlled to maintain the unique thermal, 
chemical, or mechanical output necessary for the operating 
requirements of its host facility) shall be required to install 
primary frequency response capability in accordance with the droop 
and deadband capability requirements specified in Section 1.8.4, but 
shall be otherwise exempt from the operating requirements in 
Sections 1.8.4, 1.8.4.1, 1.8.4.2, and 1.8.4.4 of this Agreement.
    1.8.4.4 Electric Storage Resources. Interconnection Customer 
interconnecting an electric storage resource shall establish an 
operating range in Attachment 5 of its SGIA that specifies a minimum 
state of charge and a maximum state of charge between which the 
electric storage resource will be required to provide primary 
frequency response consistent with the conditions set forth in 
Sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 of this Agreement. 
Attachment 5 shall specify whether the operating range is static or 
dynamic, and shall consider: (1) the expected magnitude of frequency 
deviations in the interconnection; (2) the expected duration that 
system frequency will remain outside of the deadband parameter in 
the interconnection; (3) the expected incidence of frequency 
deviations outside of the deadband parameter in the interconnection; 
(4) the physical capabilities of the electric

[[Page 61340]]

storage resource; (5) operational limitations of the electric 
storage resource due to manufacturer specifications; and (6) any 
other relevant factors agreed to by Transmission Provider and 
Interconnection Customer, and in consultation with the relevant 
transmission owner or [b]Balancing [a]Authority as appropriate. If 
the operating range is dynamic, then Attachment 5 must establish how 
frequently the operating range will be reevaluated and the factors 
that may be considered during its reevaluation.
    Interconnection Customer's electric storage resource is required 
to provide timely and sustained primary frequency response 
consistent with Section 1.8.4.2 of this Agreement when it is online 
and dispatched to inject electricity to the Transmission System and/
or receive electricity from the Transmission System. This excludes 
circumstances when the electric storage resource is not dispatched 
to inject electricity to the Transmission System and/or dispatched 
to receive electricity from the Transmission System. If 
Interconnection Customer's electric storage resource is charging at 
the time of a frequency deviation outside of its deadband parameter, 
it is to increase (for over-frequency deviations) or decrease (for 
under-frequency deviations) the rate at which it is charging in 
accordance with its droop parameter. Interconnection Customer's 
electric storage resource is not required to change from charging to 
discharging, or vice versa, unless the response necessitated by the 
droop and deadband settings requires it to do so and it is 
technically capable of making such a transition.
* * * * *

Attachment 1

Glossary of Terms

    Affected System--An electric system other than the Transmission 
Provider's Transmission System that may be affected by the proposed 
interconnection.
    Applicable Laws and Regulations--All duly promulgated applicable 
federal, state and local laws, regulations, rules, ordinances, 
codes, decrees, judgments, directives, or judicial or administrative 
orders, permits and other duly authorized actions of any 
Governmental Authority.
    Balancing Authority shall mean an entity that integrates 
resource plans ahead of time, maintains demand and resource balance 
within a Balancing Authority Area, and supports interconnection 
frequency in real time.
    Balancing Authority Area shall mean the collection of 
generation, transmission, and loads within the metered boundaries of 
the Balancing Authority. The Balancing Authority maintains load-
resource balance within this area.
    Business Day--Monday through Friday, excluding Federal Holidays.
    Default--The failure of a breaching Party to cure its breach 
under the Small Generator Interconnection Agreement.
    Distribution System--The Transmission Provider's facilities and 
equipment used to transmit electricity to ultimate usage points such 
as homes and industries directly from nearby generators or from 
interchanges with higher voltage transmission networks which 
transport bulk power over longer distances. The voltage levels at 
which Distribution Systems operate differ among areas.
    Distribution Upgrades--The additions, modifications, and 
upgrades to the Transmission Provider's Distribution System at or 
beyond the Point of Interconnection to facilitate interconnection of 
the Small Generating Facility and render the transmission service 
necessary to effect the Interconnection Customer's wholesale sale of 
electricity in interstate commerce. Distribution Upgrades do not 
include Interconnection Facilities.
    Good Utility Practice--Any of the practices, methods and acts 
engaged in or approved by a significant portion of the electric 
industry during the relevant time period, or any of the practices, 
methods and acts which, in the exercise of reasonable judgment in 
light of the facts known at the time the decision was made, could 
have been expected to accomplish the desired result at a reasonable 
cost consistent with good business practices, reliability, safety 
and expedition. Good Utility Practice is not intended to be limited 
to the optimum practice, method, or act to the exclusion of all 
others, but rather to be acceptable practices, methods, or acts 
generally accepted in the region.
    Governmental Authority--Any federal, state, local or other 
governmental regulatory or administrative agency, court, commission, 
department, board, or other governmental subdivision, legislature, 
rulemaking board, tribunal, or other governmental authority having 
jurisdiction over the Parties, their respective facilities, or the 
respective services they provide, and exercising or entitled to 
exercise any administrative, executive, police, or taxing authority 
or power; provided, however, that such term does not include the 
Interconnection Customer, the Interconnection Provider, or any 
Affiliate thereof.
    Interconnection Customer--Any entity, including the Transmission 
Provider, the Transmission Owner or any of the affiliates or 
subsidiaries of either, that proposes to interconnect its Small 
Generating Facility with the Transmission Provider's Transmission 
System.
    Interconnection Facilities--The Transmission Provider's 
Interconnection Facilities and the Interconnection Customer's 
Interconnection Facilities. Collectively, Interconnection Facilities 
include all facilities and equipment between the Small Generating 
Facility and the Point of Interconnection, including any 
modification, additions or upgrades that are necessary to physically 
and electrically interconnect the Small Generating Facility to the 
Transmission Provider's Transmission System. Interconnection 
Facilities are sole use facilities and shall not include 
Distribution Upgrades or Network Upgrades.
    Interconnection Request--The Interconnection Customer's request, 
in accordance with the Tariff, to interconnect a new Small 
Generating Facility, or to increase the capacity of, or make a 
Material Modification to the operating characteristics of, an 
existing Small Generating Facility that is interconnected with the 
Transmission Provider's Transmission System.
    Material Modification--A modification that has a material impact 
on the cost or timing of any Interconnection Request with a later 
queue priority date.
    Network Upgrades--Additions, modifications, and upgrades to the 
Transmission Provider's Transmission System required at or beyond 
the point at which the Small Generating Facility interconnects with 
the Transmission Provider's Transmission System to accommodate the 
interconnection of the Small Generating Facility with the 
Transmission Provider's Transmission System. Network Upgrades do not 
include Distribution Upgrades.
    Operating Requirements--Any operating and technical requirements 
that may be applicable due to Regional Transmission Organization, 
Independent System Operator, [control area]Balancing Authority Area, 
or [the]Transmission Providers requirements, including those set 
forth in the Small Generator Interconnection Agreement.
    Party or Parties--The Transmission Provider, Transmission Owner, 
Interconnection Customer or any combination of the above.
    Point of Interconnection--The point where the Interconnection 
Facilities connect with the Transmission Provider's Transmission 
System.
    Reasonable Efforts--With respect to an action required to be 
attempted or taken by a Party under the Small Generator 
Interconnection Agreement, efforts that are timely and consistent 
with Good Utility Practice and are otherwise substantially 
equivalent to those a Party would use to protect its own interests.
    Small Generating Facility--The Interconnection Customer's device 
for the production and/or storage for later injection of electricity 
identified in the Interconnection Request, but shall not include the 
Interconnection Customer's Interconnection Facilities.
    Tariff--The Transmission Provider or Affected System's Tariff 
through which open access transmission service and Interconnection 
Service are offered, as filed with the FERC, and as amended or 
supplemented from time to time, or any successor tariff.
    Transmission Owner--The entity that owns, leases or otherwise 
possesses an interest in the portion of the Transmission System at 
the Point of Interconnection and may be a Party to the Small 
Generator Interconnection Agreement to the extent necessary.
    Transmission Provider--The public utility (or its designated 
agent) that owns, controls, or operates transmission or distribution 
facilities used for the transmission of electricity in interstate 
commerce and provides transmission service under the Tariff. The 
term Transmission Provider should be read to include the 
Transmission Owner when the Transmission Owner is separate from the 
Transmission Provider.
    Transmission System--The facilities owned, controlled or 
operated by the

[[Page 61341]]

Transmission Provider or the Transmission Owner that are used to 
provide transmission service under the Tariff.
    Upgrades--The required additions and modifications to the 
Transmission Provider's Transmission System at or beyond the Point 
of Interconnection. Upgrades may be Network Upgrades or Distribution 
Upgrades. Upgrades do not include Interconnection Facilities.
* * * * *

Improvements to Generator Interconnection--Docket No. RM22-14-000

Procedures and Agreements

DANLY, Commissioner, concurring:

    1. I concur in the issuance of today's final rule. I write 
separately to state that, while I continue to harbor misgivings 
about the Commission's power to implement far-reaching, uniform 
policies based on our authority under FPA section 206,\1\ I am 
satisfied on this record that existing interconnection procedures in 
both RTO and non-RTO regions have been shown to be unjust and 
unreasonable, and that we take today's action consistent with the 
standards articulated in precedent.\2\ Though I am not convinced 
that this precedent will ultimately be proven correct in declaring 
that ``the Commission may rely on `generic' or `general' findings of 
a systemic problem to support imposition of an industry-wide 
solution,'' the Commission is entitled to act under prevailing case 
law.\3\
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824e.
    \2\ Improvements to Generator Interconnection Procedures & 
Agreements, 184 FERC ] 61,054, at P 57 & n.149 (2023) 
(Interconnection Rule) (citing S.C. Pub. Serv. Auth. v. FERC, 762 
F.3d 41, 67 (D.C. Cir. 2014) (quoting Interstate Nat. Gas Ass'n v. 
FERC, 285 F.3d 18, 37 (D.C. Cir. 2002))).
    \3\ Id.
---------------------------------------------------------------------------

    2. I also agree that the relatively narrow reforms contemplated 
in this final rule appear, based on this record, to be a just and 
reasonable replacement rate. I am pleased that most of that which I 
considered to be the most problematic elements in the Notice of 
Proposed Rulemaking have been excluded from this rule.\4\ I also 
remind parties of the availability of ``the independent entity 
variation standard for regional transmission organizations (RTO) and 
independent system operators (ISO) and the consistent with or 
superior to standard for non-RTO/ISO transmission providers'' should 
they choose to seek variations from these rules.\5\
---------------------------------------------------------------------------

    \4\ Improvements to Generator Interconnection Procedures & 
Agreements, 179 FERC ] 61,194 (2022) (Danly, Comm'r, concurring at 
PP 6-10) (NOPR Concurrence).
    \5\ Interconnection Rule, 184 FERC ] 61,054 at P 10 (citation 
omitted).
---------------------------------------------------------------------------

    3. While I vote to approve today's order, I will also thoroughly 
review any requests for rehearing, particularly to the extent to 
which parties to the proceeding wish to advance arguments that we 
have exceeded our authority under FPA section 206, or that we have 
failed to carry our evidentiary burden, either generally, or in a 
sufficient number of specific cases that our order amounts to an 
unlawful exercise of our powers.
    4. I would have preferred to receive section 205 \6\ filings 
from utilities proposing interconnection reforms--and indeed we have 
received and ruled upon a number of such filings. Failing that, I 
would have preferred for the Commission or interested parties to 
have initiated FPA section 206 complaints against the RTOs or other 
entities with interconnection delays, rather than to have proceeded 
generically in an effort to establish uniformity.\7\ However, my 
preferences do not make this rule unlawful, and I am satisfied that 
today's rule is consistent with our legal obligations.
---------------------------------------------------------------------------

    \6\ 16 U.S.C. 824d.
    \7\ See NOPR Concurrence at PP 1, 4.
---------------------------------------------------------------------------

    For these reasons, I respectfully concur.

-----------------------------------------------------------------------

James P. Danly,
Commissioner.

Improvements to Generator Interconnection--Docket No. RM22-14-000

Procedures and Agreements

CLEMENTS, Commissioner, concurring:
    1. As the findings of this final rule illustrate, our nation is 
facing a grid infrastructure crisis. Five years ago, the Commission 
issued Order No. 845 in an effort to improve interconnection queue 
delays, noting that ``despite Commission efforts to improve the 
interconnection process . . . many interconnection customers 
experience delays, and some interconnection queues have significant 
backlogs and long timelines.'' \1\ Unfortunately, the same 
observation can be made today, only the problem has gotten far 
worse.\2\ As of the end of 2022, a staggering 10,000 projects 
representing over 2,000 GW of potential generation and storage 
capacity are stuck in line to connect to the grid.\3\ That is nearly 
double the 1,250 GW of total installed capacity in the United States 
today.\4\ Wait times have ``increased markedly,'' with Lawrence 
Berkeley National Lab reporting that ``[t]he typical project built 
in 2022 took 5 years from the interconnection request to commercial 
operations, compared to 3 years in 2015 and [less than] 2 years in 
2008.'' \5\ Meanwhile, interconnection costs have increased 
significantly.\6\ Project completion rates are very low,\7\ and 
late-stage withdrawal is becoming more common.\8\ In addition, the 
typical timespan between the execution of a project's 
interconnection agreement and its commercial operations date has 
also increased, from roughly 17 months for projects built between 
2007-2014 to around 22 months for projects built between 2015-
2022.\9\
---------------------------------------------------------------------------

    \1\ Reform of Generator Interconnection Procs. & Agreements, 
Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ] 61,043, at P 24 
(2018), order on reh'g, Order No. 845-A, 166 FERC ] 61,137, 84 FR 
8156 (Mar. 6, 2019), order on reh'g, Order No. 845-B, 168 FERC ] 
61,092 (2019).
    \2\ See Improvements to Generator Interconnection Procedures and 
Agreements, Order No. 2023, 184 FERC ] 61,054, at PP 37-40 (2023) 
[hereinafter Final Rule].
    \3\ Joseph Rand et al., Lawrence Berkeley Nat'l Lab'y, Queued 
Up: Characteristics of Power Plants Seeking Transmission 
Interconnection As of the End of 2022, at 7-8 (Apr. 2023), https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf 
[hereinafter Queued Up 2023].
    \4\ Id. at 10.
    \5\ Id. at 3.
    \6\ See Final rule at P 41 (detailing interconnection cost 
increases seen across different regions).
    \7\ See Queued Up 2023 at 18-20.
    \8\ Id. at 22.
    \9\ Id. at 30.
---------------------------------------------------------------------------

    2. Ultimately, the dysfunction of the interconnection process 
harms consumers. It prevents low-cost generation from coming online 
that could have reduced the cost of electricity,\10\ and it harms 
reliability. Several of the nation's largest grid operators have 
stated that they could face resource adequacy problems if new 
resource entry does not occur rapidly enough to match the pace of 
resource retirements.\11\ Given these challenges and their attendant 
impacts on consumers, I enthusiastically support this final rule, 
which includes a number of helpful reforms that will improve 
interconnection processes across the country. The bulk of these 
reforms will widely extend proven best practices to utilities around 
the country.
---------------------------------------------------------------------------

    \10\ See, e.g., T. Bruce Tsuchida et al., The Brattle Grp., 
Unlocking the Queue with Grid-Enhancing Technologies: Case Study of 
the Southwest Power Pool at 9 (Feb. 1, 2021), https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf (estimating that integrating 2,670 MW of new 
generation in the Southwest Power Pool would yield annual production 
cost savings of $175 million).
    \11\ See PJM Interconnection, LLC, Energy Transition in PJM: 
Resource Retirements, Replacements & Risks at 2 (Feb. 24, 2023), 
energy-transition-in-pjm-resource-retirements-replacements-and-
risks.ashx; Midcontinent Indep. Sys. Operator, 2022 Regional 
Resource Assessment at 4, 20 (Nov. 2022), https://cdn.misoenergy.org/2022%20Regional%20Resource%20Assessment%20Report627163.pdf; California Indep. Sys. Operator, Summer Loads and 
Resources Assessment at 20 (May 18, 2022), http://www.caiso.com/Documents/2022-Summer-Loads-and-Resources-Assessment.pdf.
---------------------------------------------------------------------------

    3. What we have learned through consideration of comments to and 
stakeholder engagement about the Commission's Notice of Proposed 
Rulemaking, however, is that while this rule can be expected to 
improve matters, more will be necessary to solve the problem. What 
was perhaps considered a straightforward kitchen renovation has 
become more complicated. After we have removed the cabinets and 
taken out the drywall, we have discovered outdated wires, rusted 
pipes and cracks in the foundation. None of these additional 
challenges are insurmountable, but they are in some ways more 
fundamental to getting that modern, working kitchen up and running.
    4. I therefore write separately to highlight some of the 
remaining issues and potential solutions parties have brought 
forward that may address the remainder of the full interconnection 
reform challenge, as well as to encourage stakeholders to remain 
focused on taking additional critical steps toward addressing these 
issues.
    5. I do not suggest that solving the remaining challenges 
related to interconnection will be easy. The record

[[Page 61342]]

reveals quite the opposite. A comprehensive solution set will 
require out-of-the-box thinking in some areas and continued 
incremental improvements in others.
    6. Fortunately, we have received many thoughtful suggestions for 
further reforms, which serve as the seeds for future solutions. 
Below, I discuss two categories of promising ideas meriting further 
discussion: (1) deeper reforms that get at some of the remaining 
fundamental challenges with interconnection processes; and (2) 
additional nuts and bolts changes that could enhance the 
effectiveness of a variety of interconnection processes, but which 
were not part of the proposal giving rise to this final rule.
    7. I urge stakeholders to examine these and related suggestions, 
and for transmission planners to adopt regionally appropriate 
solutions beyond those required by this final rule.

I. Deeper reforms

    8. In considering interconnection processes across the country, 
twin challenges emerge as the most fundamental problems. First, 
interconnection studies initially examine clusters of projects that 
often bear little resemblance to what ultimately interconnects to 
the system. They rely on a long and painful process of attrition to 
arrive at a final set of projects along with corresponding network 
upgrades.
    9. More specifically, processes that rely solely on 
interconnection applications to determine study scope, and which 
require substantial study work for each customer based on inputs 
that depend on other projects in the queue, have become overwhelmed. 
For example, S&P reports that the California Independent System 
Operator (CAISO) received more than 350 GW of projects in its latest 
application window, driving its total queue to over 500 GW.\12\ 
Meanwhile, the Midcontinent Independent System Operator's (MISO) 
queue has ballooned to 339 GW, while PJM Interconnection, LLC's 
(PJM) has risen to 298 GW, both comfortably greater than the present 
installed capacity of either region.\13\ According to a recent CAISO 
stakeholder presentation, ``[t]he massive increase in 
interconnection requests seeking to meet the accelerated cadence of 
resource development . . . has overwhelmed critical planning and 
engineering resources across the industry. . . . The current 
generator interconnection processes simply cannot efficiently 
accommodate the latest level of interconnection requests received.'' 
\14\ Other queues are similarly overwhelmed.\15\
---------------------------------------------------------------------------

    \12\ Garrett Hering, California ISO Tackles `Broken' 
Interconnection Process as Queue Tops 500 GW, S&P Global (July 19, 
2023); see also CAISO, Cluster 15 Interconnection Requests, http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx 
(last visited July 26, 2023).
    \13\ Queued Up 2023 at 9-10.
    \14\ CAISO, 2023 Interconnection Process Enhancements: Summary 
of June 20 & 21 Track 2 Working Group Meeting--Revised Principles 
and Problem Statements 1 and 2, at 4 (June 23, 2023), http://www.caiso.com/InitiativeDocuments/Revised-Principles-and-Problem-Statements-Interconnection-Process-Enhancements-2023-Track%202-Jun%2020-212023.pdf.
    \15\ See Queued Up 2023 at 9 (showing very large amounts of 
queue capacity across several regions).
---------------------------------------------------------------------------

    10. Second, project developers face enormous cost 
uncertainty.\16\ Initial study results may be far different from 
final costs because the number of projects reaching the facilities 
study stage (the final stage before the execution of a generator 
interconnection agreement) can be far fewer than those earlier 
examined in the cluster study stage. As CAISO observed in a recent 
stakeholder presentation, its ``[s]tudy results lose accuracy, 
meaning and utility when the level of cluster [Interconnection 
Resource] capacity [is] multiple times the existing or planned 
transmission capacity for an area.'' \17\
---------------------------------------------------------------------------

    \16\ See Final rule at P 43 (``Cost uncertainty poses an 
especially significant obstacle because interconnection customers 
may not be able to finance substantial increases in unexpected 
interconnection costs.''). For example, in one relatively recent 
interconnection cluster in MISO, the preliminary system impact study 
estimated $3.2 billion in network upgrades for 31 projects, but that 
estimate was cut to only $330 million by Decision Point I after more 
than half of the projects withdrew. See Midcontinent Indep. Sys. 
Operator, 169 FERC ] 61,173, at P 11 (2019).
    \17\ CAISO, 2023 Interconnection Process Enhancements Track 2 
Working Group at 10 (July 11, 2023), http://www.caiso.com/InitiativeDocuments/Presentation-Interconnection-Process-Enhancements-2023-Track-2-Working-Group-Jul112023.pdf.
---------------------------------------------------------------------------

    11. Today's final rule will help to ameliorate these problems. 
In particular, the rule's site control requirements,\18\ requirement 
for an interconnection customer to select a definitive point of 
interconnection,\19\ commercial readiness requirements,\20\ and 
withdrawal penalty framework \21\ will each contribute to more 
streamlined study clusters. As we have learned through this 
proceeding, however, they will likely be inadequate, on their own, 
to fully solve these deep challenges.\22\
---------------------------------------------------------------------------

    \18\ See Final rule at PP 583-612.
    \19\ Id. at PP 200-03.
    \20\ Id. at PP 690-707.
    \21\ Id. at PP 780-813].
    \22\ The Arizona Corporation Commission, for example, argues 
that ```first-ready' queue reforms that are not explicitly linked to 
an effective rationing process will likely fail to help resolve the 
growing backlog. Some mechanism to prioritize projects and allocate 
scarce interconnection access to the highest quality projects is 
likely needed.'' Arizona Commission Initial Comments at 1-2. 
Similarly, a coalition of consumer groups and the R Street Institute 
argues that the Commission's notice of proposed rulemaking in this 
proceeding ``leaves many critical reforms unresolved.'' R Street 
Institute et al. June 8, 2023 Comments in Support of Generator 
Interconnection Reform Under RM22-14, at 2. See also Cypress Creek 
Initial Comments at 12 (arguing that ``a cluster-based approach 
alone, without further changes, will not provide adequate reform'').
---------------------------------------------------------------------------

    12. In my estimation, the record of this proceeding, as well as 
recent stakeholder initiatives, suggest several options for further 
improvement. They are not necessarily exclusive of one another, and 
appropriate application may depend on the particular regional 
context. They include: (1) linking the interconnection process to 
proactive transmission system planning; (2) in applicable regions, 
aligning the interconnection process more closely with competitive 
resource solicitations; and (3) transitioning to a ``focused'' 
interconnection process or ``connect and manage'' approach for all 
energy-only resources.

A. Link The Interconnection Process to Proactive Transmission 
System Planning

    13. Foundationally, it should be acknowledged that for 
interconnection reform to succeed, holistic, forward-looking 
transmission planning, as included in the Commission's notice of 
proposed rulemaking on regional planning and cost allocation,\23\ 
must also succeed. Interconnection processes are overloaded in part 
because they are being relied on to build out core transmission 
system infrastructure that should be considered in regional planning 
processes. We know interconnection processes were not intended for, 
and are ill suited to perform, this task. As a coalition of consumer 
groups and the R Street Institute argues in a recent letter to the 
Commission, ``[t]he cost of network upgrades can be dramatically 
reduced through proactive regional transmission planning, which 
enables major reductions in [Generator Interconnection] requirements 
and delays.'' \24\ Even prior to the adoption of any final rule in 
the Commission's regional transmission planning proceeding, 
individual transmission providers can make significant strides 
toward the cost-effective construction of new transmission 
infrastructure via regionally tailored proposals and 
initiatives.\25\
---------------------------------------------------------------------------

    \23\ See Building for the Future Through Elec. Reg'l 
Transmission Planning & Cost Allocation & Generator Interconnection, 
179 FERC ] 61,028 (2022).
    \24\ R Street Institute et al. June 8, 2023 Comments in Support 
of Generator Interconnection Reform Under RM22-14, at 2.
    \25\ See, e.g., MISO, MTEP21 Report Addendum: Long Range 
Transmission Planning Tranche 1 Executive Summary at 1 (2022), 
https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary 625790.pdf 
(describing a proposed ``portfolio of 18 transmission projects 
located in the MISO Midwest Subregions with a total investment of 
$10.3 billion, and benefit-to-cost ratios average of 2.6'').
---------------------------------------------------------------------------

    14. There may also be opportunities to streamline the 
interconnection process by more closely linking it to the 
transmission system planning process,\26\ or to carry out forward-
looking interconnection studies driven by a more holistic assessment 
of interconnection needs.
---------------------------------------------------------------------------

    \26\ See, e.g., AEE Initial Comments at 10-13 (advocating for a 
closer linkage between transmission planning and generator 
interconnection).
---------------------------------------------------------------------------

    15. Southwest Power Pool (SPP) and its stakeholders have 
embarked on a potentially promising initiative along these lines, 
which proposes a ``Consolidated Planning Process'' that would 
connect SPP's interconnection

[[Page 61343]]

process to its regional transmission planning process.\27\ 
Similarly, CAISO is seeking to ``[p]rioritize interconnection in 
zones where transmission capacity exists or new transmission has 
been approved, while providing opportunities to identify and provide 
alternative points of interconnection or upgrades.'' \28\ Like SPP, 
CAISO aims to overhaul a bloated queue that requires initial studies 
that bear little relation to transmission system reality, and 
instead chart a course to a new process that produces ``meaningful 
study results that take into account system capability, resource 
planning and procurement.'' \29\
---------------------------------------------------------------------------

    \27\ See Southwest Power Pool, Consolidated Planning Process 
Task Force, https://www.spp.org/stakeholder-groups-list/organizational-groups/board-of-directorsmembers-committee/consolidated-planning-process-task-force/ (last visited July 26, 
2023); Southwest Power Pool, Consolidated Planning Process: Phase 1 
Recommendations (May 17, 2023), https://www.spp.org/spp-documents-filings/?id=297513 (when accessing ``CPPTF Meeting Materials 
20230621''). SPP proposes to calculate an ``entry fee,'' which would 
involve per-MW costs of any ``regional'' or ``sub-regional'' 
interconnection network infrastructure, along with a ``local'' 
component derived from a narrower reliability assessment examining 
any necessary facilities at the point of interconnection. See 
Southwest Power Pool, CPP Entry Fee Rate Structure, at 20 (July 14, 
2023), https://www.spp.org/spp-documents-filings/?id=297513 (when 
accessing ``CPPTF Meeting Materials 20230714'') (setting forth entry 
fee components). The key to SPP's proposal, as I understand it, is 
that the regional and sub-regional components of the entry fee would 
be identified by ``forward-casting,'' a ``longer-term assessment'' 
derived from estimated costs of interconnecting resources in a 
fashion that is integrated with SPP's long-term regional plan. Id. 
By assessing costs across a broader range of projects than any 
individual cluster, and by calculating it based on SPP's proactive 
planning vision rather than calculating costs for a hypothetical 
cluster of initial applicants that will not all reach commercial 
operation, SPP may be able to offer far greater cost certainty for 
project developers and thereby greatly streamline and accelerate the 
interconnection process. Id. at 11, 19 (illustrating a greatly 
simplified flow chart for the consolidated planning approach as 
compared to SPP's status quo).
    \28\ CAISO, 2023 Interconnection Process Enhancements Track 2 
Working Group at 9 (July 11, 2023), http://www.caiso.com/InitiativeDocuments/Presentation-Interconnection-Process-Enhancements-2023-Track-2-Working-Group-Jul112023.pdf.
    \29\ Id.
---------------------------------------------------------------------------

    16. The promise of a forward-looking approach is also becoming 
clear through the ongoing effort that MISO and SPP are pioneering in 
the affected systems context. That effort, known as the Joint 
Targeted Interconnection Queue (JTIQ), examines a larger portfolio 
of projects to identify solutions that more efficiently solve their 
collective needs.\30\ By assessing larger, long-term system needs 
across study clusters, this approach identifies efficiencies that 
could not be captured on a more project-specific basis.\31\
---------------------------------------------------------------------------

    \30\ See generally SPP & MISO, SPP-MISO Joint Targeted 
Interconnection Queue Cost Allocation and Affected System Study 
Process Changes White Paper (Dec. 20, 2022), https://www.spp.org/documents/68518/spp-miso%20jtiq%20study%20updated%20white%20paper%2020221220.pdf. 
Because this approach looks at projects that have reached the 
affected systems study stage, it does not provide a template for 
narrowing the initial pool of projects to facilitate meaningful 
study results. But the forward-looking nature of the initiative may 
nevertheless provide valuable insights to regional interconnection 
processes more broadly.
    \31\ See SPP & MISO, MISO-SPP Joint Targeted Interconnection 
Queue Update at 7 (March 27, 2023), https://cdn.misoenergy.org/20230337%20MISO%20SPP%20JTIQ% 20Update628357.pdf.
---------------------------------------------------------------------------

    17. As these regions' proposals are still in flux and have yet 
to be filed with the Commission, I do not prejudge them. But, at a 
high level, it appears that these types of approaches may hold the 
potential to provide developers more certainty; avoid a dynamic 
whereby large upgrades are assigned to individual projects that then 
drop from the queue, causing a cascading need for restudy; and 
deliver benefits to consumers by identifying more efficient 
infrastructure solutions than would be delivered on a piecemeal 
basis.
    18. Questions worth exploring as these types of processes 
develop include:
    a. How can the process ensure that fees charged to 
interconnection customers provide the funds needed for the relevant 
proactively-planned network upgrades, while providing developers 
with a reasonable degree of cost certainty?;
    b. Would a mechanism such as a competitive auction or open 
season administered by the transmission provider be an effective 
tool for allocating scarce interconnection capacity identified by 
the forward-looking plans, and/or are there other processes that can 
effectively streamline the study process?;
    c. How can such processes be designed in a manner that is not 
unduly discriminatory and is consistent with open access 
principles?; and
    d. What process is appropriate for interconnection applications 
that do not align with the transmission provider's forward-looking 
regional transmission plan?

B. Align Interconnection Processes With Competitive Resource 
Solicitations

    19. In some regions of the country, it may be appropriate to 
link aspects of the interconnection process to resource 
solicitation.\32\ The Colorado Public Utilities Commission (Colorado 
Commission), for example, characterizes the interconnection queue 
management processes of transmission providers in its state as 
``highly functional.'' \33\ The key, it says, is that its ``existing 
FERC-approved tariffs and bilateral market structure . . . ensures 
that projects selected in [its] competitive resource planning and 
acquisition process obtain scarce interconnection in a cost-
effective and timely manner.'' \34\
---------------------------------------------------------------------------

    \32\ See, e.g., Clean Energy Associations Initial Comments at 38 
(urging the acceptance of ``regionally specific proposals that would 
align the interconnection process with competitive procurements 
associated with resource planning, rather than placing them at 
odds''). Such alignment may not be appropriate or feasible, of 
course, in certain multi-state regions in which the bulk of resource 
development is driven by anticipated market revenues.
    \33\ Colorado Commission Initial Comments at 2.
    \34\ Id.
---------------------------------------------------------------------------

    20. The Colorado Commission and Arizona Corporation Commission 
(Arizona Commission) argue that a mechanism to allocate scarce 
interconnection capacity is needed.\35\ The Colorado Commission 
explains that if there is 400 MW of low-cost headroom on the system, 
for instance, several commercially viable projects that collectively 
exceed that amount may compete for that headroom yet be unviable on 
a collective basis if all proceed.\36\ It contends that, lacking a 
mechanism to allocate the headroom, a cluster study process may 
result in an inefficient cycle of study, re-study and delay, without 
necessarily ensuring that the 400 MW of headroom is used 
efficiently.\37\ It argues that facilitating a process where state-
jurisdictional competitive solicitation can be used to allocate 
scarce interconnection capacity is appropriate given ``state 
priorities involving reliability, customer, and environmental 
preferences.'' \38\
---------------------------------------------------------------------------

    \35\ Arizona Commission Initial Comments at 1-2; Colorado 
Commission Initial Comments at 21-27.
    \36\ Colorado Commission Initial Comments at 21-27.
    \37\ Id.
    \38\ Id. at 29.
---------------------------------------------------------------------------

    21. FERC proposed a similar ``optional resource solicitation'' 
study in this proceeding. Our proposed process differed in a 
critical respect: the resource solicitation was not granted a queue 
position,\39\ and being selected in the resource solicitation would 
not serve as a mechanism for allocating scarce interconnection 
capacity. The possibility of more comprehensively aligning the 
interconnection process with competitive resource solicitations 
(beyond the jurisdictions where such an approach is currently used) 
raises many questions, such as:
---------------------------------------------------------------------------

    \39\ Commenters argue that the Commission should have proposed 
to grant a queue position to the resource solicitation. See, e.g., 
Colorado Commission Reply Comments at 6; EEI Initial Comments at 5-
6; Xcel Initial Comments at 11-14; Clean Energy Associations Initial 
Comments at 51. Without a queue position for the resource 
solicitation, the costs identified in the study may not hold true 
for the various queue positions of underlying resources.
---------------------------------------------------------------------------

    a. How can competitive solicitations and interconnection 
processes be designed to effectively coordinate with one another, 
especially where the soliciting entity (e.g., a state) is different 
from the transmission provider (e.g., an RTO)?
    b. To be effective as a mechanism to allocate scarce 
interconnection capacity, must a competitive solicitation be paired 
with a mechanism such as further strengthened commercial readiness 
requirements to limit the pool of resources in the queue not 
responding to solicitations, or be designed in a fashion that limits 
the interactions in the study process between resources responding 
to the relevant solicitation(s) and those that do not? \40\ Can

[[Page 61344]]

such requirements be designed in a manner that is not unduly 
discriminatory, and if so, how?
---------------------------------------------------------------------------

    \40\ The Colorado Commission argues that if projects to be 
studied as part of a competitive solicitation request are 
``comingled with a much broader pool of speculative projects,'' the 
process could become ``unworkable.'' Colorado Commission Reply 
Comments at 5. It argues that, in the RTO context, commercial 
readiness requirements will be inadequate for this task, and 
suggests that the Commission allow transmission providers to 
prioritize native load, using solicitations as a mechanism to 
allocate scarce interconnection capacity. See Colorado Commission 
Initial Comments at 21-30. In contrast, the Interwest Energy 
Alliance argues that while competitive resource solicitations could 
be a useful tool to organize a portion of the interconnection 
process, they should not ``becom[e] the only pathway through the 
cluster study process,'' because ``alternative pathways with 
reasonable commercial readiness requirements may . . . reveal 
opportunities for independent transmission companies (potentially 
associated with independent generation developers) to discover cost-
effective ways to add much-needed transmission expansion through 
additional lines along with additional interconnection capacity.'' 
Interwest Initial Comments at 11-12. Alternatives may be available 
that allow for other development opportunities alongside resources 
solicitation clusters. For example, a resource solicitation might be 
granted its own cluster (so as to allow the soliciting entity to 
understand the interconnection costs for its combination of 
resources), while providing for serial processing of clusters 
composed of resources not participating in the resource 
solicitation. See Enel Initial Comments at 72 (arguing that if the 
Commission were to adopt an optional resource solicitation process 
that designated a queue position, it ``should be a separate queue 
cycle with an intermediate queue priority between the Transmission 
Provider's annual study clusters'').
---------------------------------------------------------------------------

    c. Are safeguards necessary to render not unduly discriminatory 
an interconnection process closely linked to a competitive 
solicitation process, and if so, what safeguards are necessary or 
appropriate? \41\
---------------------------------------------------------------------------

    \41\ Several entities highlighted the need for guardrails to 
prevent undue discrimination with regard to the Commission's 
proposal of an optional resource solicitation study. See, e.g., R 
Street Initial Comments at 15-16 (``Guardrails may be helpful to 
prevent inefficiencies, preference or undue discrimination''); NARUC 
Initial Comments at 26 (``NARUC strongly supports FERC's proposal to 
limit the applicability of the optional resource solicitation study 
to instances where the resource acquisition is overseen by a state 
regulatory authority and is competitive and open. Without this 
requirement, NARUC is concerned about the opportunity for load-
serving entities to potentially use the process in a way that would 
inappropriately favor the interconnection of company-owned 
resources.''); Pine Gate Initial Comments at 43 (advocating for 
``appropriate safeguards''). This concern is heightened in the 
context where the solicitation is granted a queue position, and/or 
where inclusion in the solicitation serves as a commercial readiness 
indicator.
---------------------------------------------------------------------------

    d. Is linking the interconnection process to competitive 
solicitations a viable option in RTO regions, in which state 
solicitation processes play a large role in supporting new market 
entrants but other paths to commercial viability may also exist?

C. Facilitate a ``Focused'' Interconnection Process

    22. Other promising ideas for improving cost certainty and 
reducing delays were put forward to the Commission in this 
proceeding. In particular, several commenters endorse a more 
``focused'' interconnection process that streamlines study scope and 
reduces the need for restudies for projects requesting energy-only 
service.\42\ As Enel observes, the dilemma of unwieldy studies and 
cascading restudy needs, and the delay and cost uncertainty that 
stems from these challenges, is ultimately caused by ``the 
interdependence amongst Interconnection Customers.'' \43\ Cypress 
Creek notes that ``[i]n one extreme example, a group of non-firm, 
energy-only resource interconnection service (`ERIS') requests 
triggered the need for upgrades up to 1,000 miles away on three 
different systems.'' \44\ Accordingly, another way to facilitate a 
more workable interconnection process could be to focus study of new 
projects on their immediate impact to the system. While the number 
of studies pursuant to such a process could still be large, their 
scope would be smaller and the potential for cascading restudies 
would be greatly reduced.
---------------------------------------------------------------------------

    \42\ See, e.g., R Street Institute et al. June 8, 2023 Comments 
in Support of Generator Interconnection Reform, at 2 (urging the 
Commission to ``[c]onsider a focused interconnection study 
approach''); Public Interest Organizations Initial Comments at 50-52 
(highlighting the potential for a narrow study process for ERIS 
resources to produce significantly faster interconnection 
timelines); ACORE Initial Comments at 2-3 (identifying potential 
benefits from an interconnection process ``focused on local 
transmission needs only''); R Street Initial Comments at 6-7 
(arguing that ERCOT's ``connect and manage'' approach is ``perhaps 
the most effective'' domestic interconnection process).
    \43\ Enel Initial Comments at 2.
    \44\ Cypress Creek Initial Comments at 3-4 (citing 
Pfeifenberger, Generation Interconnection and Transmission Planning 
(Aug. 9, 2022), https://www.esig.energy/download/generation-interconnection-and-transmission-planning-johannespfeifenberger/?wpdmdl=9241&refresh=62f38b6a0e44a1660128106).
---------------------------------------------------------------------------

    23. Johannes Pfeifenberger of The Brattle Group notes that, 
using a ``connect and manage'' approach, the Electric Reliability 
Council of Texas (ERCOT) has interconnected more generation more 
quickly than other regions.\45\ Under its system, which ``limits 
restudy needs,'' ``[p]rojects can be developed and interconnected 
within 2-3 years,'' while ``in other regions, the interconnection 
study process itself may take longer than that.'' \46\ Public 
Interest Organizations state that ``[t]he UK's `Connect and Manage' 
approach has reduced lead times by 5 years compared to its previous 
`Invest and Connect' approach.'' \47\
---------------------------------------------------------------------------

    \45\ See Pfeifenberger, Planning for Generation Interconnection 
2 (May 31, 2022), https://www.brattle.com/wp-content/uploads/2022/05/Planning-for-Generation-Interconnection.pdf (showing that ERCOT 
has interconnected more than 8 GW of capacity since 2021, 
significantly more than all other RTOs, even those with considerably 
greater peak load); see also Cypress Creek Initial Comments at 7.
    \46\ Pfeifenberger, Planning for Generation Interconnection at 
4.
    \47\ Public Interest Organizations Initial Comments at 51.
---------------------------------------------------------------------------

    24. While ERCOT's system, which treats all generators as energy-
only resources,\48\ may not provide a model for capacity resources, 
it could provide a template for ERIS interconnection. Enel argues 
that a ``focused'' approach to interconnection is appropriate for 
resources seeking ERIS because ``the Transmission Provider is not 
obligated to maintain the transmission system such that ERIS 
generators can maintain the same level of as available injection 
throughout the life of the generator,'' and accordingly, ``it would 
be unreasonable to expect an ERIS generator to mitigate every 
constraint identified'' in a more expansive study that uses a lower 
transfer distribution factor (TDF) threshold to identify more remote 
impacts of the project.\49\ Streamlining ERIS interconnection 
assessment could allow transmission providers to focus their study 
resources on a smaller number of requests seeking network resource 
interconnection service (NRIS).\50\
---------------------------------------------------------------------------

    \48\ See Cypress Creek Initial Comments at 7-8.
    \49\ Enel Initial Comments at 23.
    \50\ See Public Interest Organizations Initial Comments at 50-
52.
---------------------------------------------------------------------------

    25. Cypress Creek argues that a more focused study approach 
could be implemented across the many regions that provide an NRIS 
interconnection option through use of a ``two-step ERIS-NRIS'' 
process by which the transmission provider could by default study 
all resources for ERIS and provide a subsequent process by which an 
interconnection customer can add firm rights.\51\ Such a process 
might even feasibly provide a faster path to commercial operation 
while still facilitating deliverable resources in the long run if 
``NRIS requests [could] be connected more quickly on an ERIS basis 
while NRIS-related network upgrade study and construction work is 
still pending.'' \52\ While the final rule did not adopt the 
recommendation for a two-step study process because it was outside 
the scope of this proceeding,\53\ individual transmission providers 
could propose to implement such a process on their own initiative or 
the Commission could take up this suggestion in a subsequent 
rulemaking.
---------------------------------------------------------------------------

    \51\ Cypress Creek Initial Comments at 8-9.
    \52\ Public Interest Organizations Initial Comments at 52. 
Cypress Creek highlights that SPP currently allows for interim 
energy-only injection service, providing for a subsequent process by 
which a generator can add firm rights. Cypress Creek Initial 
Comments at 8-9. Such a process to add deliverability rights to ERIS 
resources may hold potential to facilitate immediate contributions 
to system reliability by these resources, even if such resources are 
not fully deliverable or compensated in capacity markets or 
accounted for in applicable resource adequacy analysis.
    \53\ Final rule at P 183.
---------------------------------------------------------------------------

    26. Key questions that this approach raises include:
    a. What is the appropriate mechanism to narrow the scope of ERIS 
studies to limit the interdependence of projects in the study 
process? For example, Enel argues that ERIS resources should be 
studied using a minimum TDF threshold of 20 percent,\54\ and that 
transmission providers should replace power flow models that assume 
extreme grid conditions with more realistic economic

[[Page 61345]]

dispatch models reflecting security constrained economic 
dispatch.\55\ How do these approaches interact and are they mutually 
exclusive? Are there other appropriate mechanisms?
---------------------------------------------------------------------------

    \54\ Enel Initial Comments at 21-25; see also AEE Reply Comments 
at 10 (supporting a minimum impact threshold); SEIA Initial Comments 
at 11 (same); Clean Energy Associations Initial Comments at 27 
(same); Pine Gate Initial Comments at 19 (supporting a minimum 
distribution factor impact threshold of 20 percent).
    \55\ Enel Initial Comments at 73-74.
---------------------------------------------------------------------------

    b. To the extent that ERIS studies are narrowed, are changes to 
market dispatch rules or other measures appropriate to account for 
the possibility that NRIS resources or resources with long-term firm 
transmission service may be curtailed before them? \56\
---------------------------------------------------------------------------

    \56\ Xcel objects to the treatment of ERIS resources in RTO 
markets because ``[t]hese resources do not bear the costs necessary 
to ensure that they are deliverable to load as NRIS resources or 
ERIS resources that have acquired long term firm transmission 
service do,'' and suggests that, as a consequence, it may be 
appropriate for ``ERIS-only service [to] receive a lower dispatch 
priority.'' Xcel Initial Comments at 15-16.
---------------------------------------------------------------------------

    c. If a two-step study process that considers ERIS analysis 
first is appropriate, how should it be designed? \57\ Would it be 
effective to provide for a process that allows ERIS resources to be 
converted to NRIS after they are constructed? \58\
---------------------------------------------------------------------------

    \57\ Some regions currently employ a similar two-step process 
that considers local project needs prior to considering 
deliverability analysis non-local upgrades based on project 
interactions. See, e.g., New York State Department Initial Comments 
at 5-6 (describing NYISO's Class Year study process).
    \58\ See Public Interest Organizations Initial Comments at 52 
(arguing that ``[i]deally, the interconnecting customer would 
receive an upfront estimate of typical curtailment levels to be 
expected under ERIS and would have the option to apply for NRIS at a 
later date if experienced curtailment levels rise above acceptable 
levels''). Might such a process be able to efficiently examine a 
large number of projects, while still requiring significantly fewer 
restudies than existing interconnection processes by examining only 
projects that have already secured ERIS?
---------------------------------------------------------------------------

    d. Could a focused interconnection approach for ERIS resources 
be combined with approaches above that may align the interconnection 
process more closely with long-term transmission planning, and/or 
use competitive selection processes to allocate scarce 
interconnection capacity? \59\
---------------------------------------------------------------------------

    \59\ For example, might a transmission provider efficiently 
assess ERIS upgrades by studying them using a distribution factor of 
20 percent, while simultaneously developing an ``entry fee'' or open 
season process aligned with its forward-looking transmission plan to 
fund upgrades to guarantee deliverability of NRIS resources?
---------------------------------------------------------------------------

II. General Interconnection Process Improvements

    27. In addition to these deeper reforms, commenters identified 
several potential incremental improvements to interconnection 
processes that were not proposed in the Commission's notice of 
proposed rulemaking. I discuss some of the most promising ideas 
below, which in some or most cases may be applicable on a generic 
basis.\60\
---------------------------------------------------------------------------

    \60\ The discussion herein is not intended to comprehensively 
capture all potential reforms, but rather to highlight some of the 
ideas that may be appropriate for further stakeholder discussion.
---------------------------------------------------------------------------

A. Further Refine Study Assumptions

    28. Commenters identified a number of ways that study 
assumptions could be further clarified, which may help to streamline 
and improve the accuracy of the interconnection process.

1. Clarify ERIS and NRIS Assumptions

    29. As Enel points out, the Commission has not to date clarified 
what ERIS studies should entail, and it has ``observed vastly 
different treatments of'' resources seeking ERIS by different 
transmission providers.\61\ As discussed above, a narrow approach to 
ERIS studies may facilitate a more streamlined interconnection 
process. In addition, some developers contend that grid operators 
deploy widely varying study assumptions on issues such as whether 
the models used allow for resource re-dispatch to mitigate any 
reliability issues that are identified.\62\ They argue that 
requiring ``a uniform set of minimum interconnection study 
requirements'' would ``facilitate effective, efficient 
interconnection queue processing.'' \63\
---------------------------------------------------------------------------

    \61\ Enel Initial Comments at 26-27.
    \62\ See, e.g., Cypress Creek Initial Comments at 6 n.11 (``Some 
RTOs conduct power flow analyses that consider redispatch 
opportunities (e.g., NYISO via a manual process, PJM via a 
simplified approach) but many do not check if generation redispatch 
can address an identified criteria violation.''); Pine Gate Initial 
Comments at 54 (``The primary issues identified relative to current 
study assumptions are extreme contingency scenarios and overly 
conservative operational characteristics and strategies (i.e., 
redispatch protocols).'').
    \63\ Pine Gate Initial Comments at 55; see also Cypress Creek 
Initial Comments at 6 (``re-dispatch should be a standard 
approach''); Clean Energy Associations Initial Comments at 28 
(``[T]he study approach to re-dispatching the system to account for 
proposed injections . . . is a crucial assumption that is not well 
understood or defined, but can trigger significant upgrades and 
increase complexity of interconnection process, even for energy-only 
(non-firm) interconnection requests. . . . Economic redispatch 
should be a standard approach to limit regional upgrades identified 
in the study process, particularly for energy-only interconnection 
requests.'').
---------------------------------------------------------------------------

    30. While the Commission declined to provide direction on how 
ERIS should be studied because such requests were outside the scope 
of this final rule,\64\ the Commission could take up this topic as 
part of a subsequent rulemaking. As an initial step, the Commission 
could solicit information from transmission providers documenting 
what assumptions and processes are used for ERIS and NRIS, 
respectively, to provide a starting point for dialogue around what 
study assumptions may be appropriate.\65\ Topics that may benefit 
from further clarification include: (1) the definition and scope of 
ERIS; (2) the study assumptions that should be implemented in 
examining ERIS requests; and (3) the proper scope of study results 
and other information that must be provided by transmission 
providers to interconnection customers so that they can understand 
the results.
---------------------------------------------------------------------------

    \64\ Final rule at P 1291.
    \65\ See Enel Initial Comments at 26-27.
---------------------------------------------------------------------------

2. Provide for More Accurate Assumptions Regarding Injection of Energy 
by Resources

    31. The final rule clarifies that its requirement to more 
accurately reflect the proposed charging behavior of electric 
storage resources extends only to ``the operating assumptions for 
withdrawals of energy.'' \66\ In part due to concerns regarding the 
administrative burden of extending the proposal to injections or 
other resource types, the final rule declines to extend the reform 
in these areas.\67\ But while the Commission determined that this 
record did not support adopting a structure where such assumptions 
would be studied at the request of individual generators, further 
examination of how to render operating assumptions more accurate is 
warranted.
---------------------------------------------------------------------------

    \66\ Final rule at PP 1509, 1524.
    \67\ Final rule at P 1529.
---------------------------------------------------------------------------

    32. Many commenters argued that the Commission should also 
require more accurate assumptions regarding injections of 
storage.\68\ And as the final rule acknowledges, many commenters 
``support eliminating unrealistic interconnection study assumptions 
for resource types other than electric storage resources, such as 
assuming that a solar facility will operate at night, or that a wind 
resource will produce maximum output during low-wind seasons.'' \69\ 
Further, several commenters highlighted the benefits of using 
realistic fuel-based dispatch assumptions in studies, as 
demonstrated by MISO.\70\ The final rule ``acknowledge[s] that fuel-
based dispatch assumptions may be able to address some of the 
identified challenges associated with inaccurate modeling 
assumptions for all resource types and encourage[s] transmission 
providers to

[[Page 61346]]

evaluate the merits of adopting it.'' \71\ Individual transmission 
providers remain free to advance such assumptions on an individual 
basis, and further examination of this concept could create a record 
adequate for the Commission to determine whether to require fuel-
based operating assumptions on a generic basis, and if so, how to 
precisely structure such a requirement.
---------------------------------------------------------------------------

    \68\ See, e.g., Clean Energy Associations Initial Comments at 53 
(``[T]he Clean Energy Associations recommend that the Commission 
specify that transmission providers should also not study electric 
storage resources as 100% injecting energy during low load periods 
by default.'') (emphasis in original); NextEra Initial Comments at 
37 (``Transmission providers should not study electric storage 
resources as . . . injecting energy during low load and shoulder 
periods, as [this does] not reasonably reflect typical operations of 
such units.''); Pine Gate Initial Comments at 51 (arguing that the 
Commission should prohibit transmission providers from using 
unrealistic operating assumptions, which includes ``assuming that 
electric storage resources will . . . discharge during light load 
periods'').
    \69\ Final rule at P 1480 (citing Enel Initial Comments at 74; 
AES Clean Energy Initial Comments at 24-25; Ameren Initial Comments 
at 29; CREA and NewSun Initial Comments at 92; Cypress Creek Initial 
Comments at 9-10; Invenergy Initial Comments at 59-61; Microgrid 
Resources Initial Comments at 7-8; Pine Gate Initial Comments at 54; 
Public Interest Organizations Initial Comments at 48-49; R Street 
Initial Comments at 16; rPlus Initial Comments at 6); see also id. 
(``Ameren, Cypress Creek, Microgrid Resources, NARUC, Pine Gate, and 
rPlus all request that the Commission extend this reform to allow 
any resource type, not just electric storage or co-located 
resources, to request that interconnection studies be based on their 
particular operating assumptions and characteristics.'').
    \70\ See Invenergy Initial Comments at 59-61 (highlighting 
MISO's practice, as well as ``recently approved more realistic fuel-
based dispatch'' assumptions in SPP); see also Enel Initial Comments 
at 77-78 (arguing that the Commission should require fuel-based 
dispatch of generators in modeling ``[i]f Power flow analyses are 
not replaced with SCED studies''); Interwest Reply Comment at 15 
(urging the adoption of ``realistic fuel-based dispatch 
assumptions'').
    \71\ Final rule at P 1529.
---------------------------------------------------------------------------

B. Use Automation To Facilitate More Efficient Interconnection

    33. Currently, the interconnection study and queue process is 
heavily labor-intensive, and market participants frequently suffer 
from shortages of qualified study staff, including transmission 
planners and engineers, in the face of a high volume of 
interconnection requests.\72\ Accordingly, numerous commenters noted 
the great potential of automation to conserve staffing resources and 
speed up this process.\73\ The broad term ``automation'' in this 
context can refer to a wide variety of time-saving steps to bring 
the queue process fully into the digital age, such as standardized 
data entry and collection; a web-based application process and data 
submission with automated validation; automated study model 
construction and study processes; and pre-population of manufacturer 
models for relevant equipment.\74\ Commenters requested steps, 
including the convening of a technical conference, to study how the 
interconnection process might become more robustly automated to save 
resources \75\ and facilitate other benefits, such as the more 
robust integration of grid enhancing technologies (referred to as 
``alternative transmission technologies'' in the final rule) into 
the bulk power system.\76\ Of course, continuing to support career 
path development in this area will remain critical. At the same 
time, as we have seen in many other industries, automation done 
right has the potential to save a great deal of unnecessary time, 
effort, and expense. I support more deeply exploring the range of 
options available in this domain.
---------------------------------------------------------------------------

    \72\ See, e.g., Cal. Indep. Sys. Operator Corp., 176 FERC ] 
61,207, at PP 7, 21 (2021) (noting CAISO's statement of its 
difficulty in finding sufficient expert staff and consultants to 
timely process a large cluster study); MISO, Informational Report, 
Docket No. ER19-1960, at 12 (filed Nov. 16, 2020) (noting similar 
delays); see also Akielly Hu, US Clean Energy Rollout Continues to 
Be Hamstrung by Grid Challenges, Canary Media (June 13, 2023), 
https://www.canarymedia.com/articles/transmission/us-clean-energy-rollout-continues-to-be-hamstrung-by-grid-challenges (noting that 
``interconnection studies rely on a workforce of engineers at grid 
operators, and experts say there are not enough to get the job 
done,'' and quoting the author of Lawrence Berkeley National 
Laboratory's Queued Up study as saying this staffing issue 
represents a ``fundamental constraint'' on queue processing); 
Avangrid Reply Comments at 12 (``Transmission providers are 
processing unprecedented numbers of interconnection requests at a 
time when these qualified transmission planners and engineers are 
scarce.''); APPA-LPPC Initial Comments at 13 (noting that 
``available industry system simulation tools'' can in some cases 
ameliorate ``labor-intensive study obligations'').
    \73\ See, e.g., California Energy Storage Alliance Initial 
Comments at 5; NextEra Initial Comments at 14, 40; MISO Initial 
Comments at 26 n.107; ACORE Initial Comments at 5; ACE-NY Initial 
Comments at 2-3; Pine Gate Reply Comments at 5.
    \74\ NextEra Initial Comments at 14, 40.
    \75\ See NextEra Initial Comments at 14; Pine Gate Reply 
Comments at 5.
    \76\ See, e.g., WATT Coalition Reply Comments at 2-3.
---------------------------------------------------------------------------

C. Reduce Delay and Cost Overruns in Network Upgrade Construction

    34. While there appears to be a lack of good data about the 
timing and cost of construction of network upgrades once an 
interconnection agreement is executed,\77\ developers have raised 
concerns that they have little recourse if such upgrades are delayed 
or subject to cost increases.\78\ As noted above, the Lawrence 
Berkeley National Laboratory's Queued Up report does not trace the 
cause of delays between execution of a project's interconnection 
agreement and commercial operation, but shows that the average 
timespan for this period has increased from roughly 17 months for 
projects built between 2007-2014 to around 22 months for projects 
built between 2015-2022, with projects in CAISO showing particularly 
heightened delays.\79\ Enel contends that ``upgrades for 
Interconnection Customers are only overseen by the Commission for 
adherence to good utility practice standards,'' and ``[t]he 
Commission does not review the timeliness or cost of upgrades unless 
an Interconnection Customer elects to file an LGIA in unexecuted 
form and challenge these specific assumptions,'' a choice that could 
result in ``costly delays in project timelines that often outweigh 
any benefit that might be gained from a favorable Commission 
decision.'' \80\
---------------------------------------------------------------------------

    \77\ See Queued Up 2023 at 30 (``[L]imited data were available 
to analyze typical durations from interconnection agreement to 
commercial operations.'').
    \78\ See, e.g., Enel Initial Comments at 50 (``Under the current 
standard[] of . . . good utility practice, there is a notable lack 
of incentive, and often a disincentive, for Transmission Owners to 
perform . . . EPC work in a timely and cost-conscious manner.''); 
Pine Gate Initial Comments at 64 (expressing concern that limiting 
the option for interconnection customers to self build will 
``further exacerbate construction delays and . . . ultimately harm 
consumers'').
    \79\ See Queued Up 2023 at 30. ``The typical solar project built 
in CAISO since 2018 took over 4 years to reach commercial operations 
after securing an interconnection agreement; those built in 2022 
averaged over 6 years.'' Id. (emphasis in original).
    \80\ Enel Initial Comments at 50-51.
---------------------------------------------------------------------------

    35. Accordingly, it may be appropriate for the Commission to 
take action to facilitate more timely and cost-conscious 
construction of such upgrades. One initial step could be for the 
Commission to gather more data concerning delays that may affect the 
commercial operation date of a generating facility, and to establish 
``metrics associated with the delayed construction of facilities.'' 
\81\ The Commission could also consider adopting penalties for 
delays or cost overruns, or an incentive structure for transmission 
providers that carry out construction on time and on budget.\82\
---------------------------------------------------------------------------

    \81\ Pine Gate Initial Comments at 64.
    \82\ This issue has also arisen in the context of the 
Commission's docket on transmission planning and cost management. 
See, e.g., Advanced Energy Economy, Pre-Conference Comments, Docket 
No. AD22-8, at 2-3 (filed Oct. 4, 2022) (noting that a ``major 
driver[] of transmission cost increases in recent years [has] been . 
. . incremental network upgrades identified in generator 
interconnection studies''). In that docket, the Commission has 
considered, and some commenters have supported, among other 
measures, new independent entities to monitor transmission planning. 
See, e.g., Electricity Transmission Competition Coalition, Comments, 
Docket No. AD22-8, at 6 (filed Oct. 4, 2022); Harvard Electricity 
Law Initiative, Comment, Docket No. AD22-8, at 18-31 (filed Mar. 23, 
2023); R Street Institute, Comments, Docket No. AD22-8, at 6-7 
(filed Mar. 23, 2023). To the extent that such entities are 
established, the Commission could also consider tasking them with 
monitoring the timely and cost-conscious construction of network 
upgrades.
---------------------------------------------------------------------------

    36. Finally, it may be appropriate to reconsider the scope of 
``stand alone network upgrades'' to include facilities that may be 
needed for multiple interconnection customers, and to develop a 
process that either designates an interconnection customer to build 
such upgrades, or competitively solicits bids to award construction 
rights. While this final rule ``clarif[ies] that, for a network 
upgrade to be eligible for treatment as a stand alone network 
upgrade, the network upgrade must be required for only one 
interconnection customer,'' \83\ it does so in order to ``explicitly 
maintain[] the status quo.'' \84\ The Commission's Notice of 
Proposed Rulemaking examined changes to the definition of stand 
alone network upgrade necessary ``to implement a first-ready, first-
served cluster study process,'' \85\ and did not contemplate any 
mechanism to ``prevent lengthy conflict and negotiations in 
instances where multiple interconnection requests trigger the need 
for a network upgrade'' beyond restricting such upgrades to those 
that are required for only one interconnection customer.\86\
---------------------------------------------------------------------------

    \83\ Final rule at P 192.
    \84\ Id. at P 193.
    \85\ Improvements to Generator Interconnection Procedures and 
Agreements, Notice of Proposed Rulemaking, 179 FERC ] 61,194, at P 
65 (2022).
    \86\ Id.; see final rule at P 194 (requests to ``expand the 
definition of stand alone network upgrade . . . are outside the 
scope of this proceeding, which is not proposing to modify the scope 
of interconnection customers' option to build certain stand alone 
network upgrades but rather is only revising definitions insofar as 
is necessary to implement reforms adopted elsewhere in this final 
rule'').
---------------------------------------------------------------------------

    37. Ideas were put forth in this proceeding, however, that may 
hold potential to efficiently allocate construction rights and 
obligations. In particular, one idea is that ``the Commission should 
consider establishing a new third-party construction option'' 
pursuant to which stand alone network upgrades could ``be bid out 
and built by third parties, such as non-incumbent utilities, 
independent transmission developers or contractors.'' \87\ To 
develop

[[Page 61347]]

such an option, the Commission would need to consider ``details such 
as the posting of minimum design standards that must be met, the 
criteria for choosing a winning bidder, the incentives to hold the 
winning bidder to cost and schedule estimates, responsibility for 
cost overruns, rights to own, operate and maintain the Stand-Alone 
Network Upgrades, and the profit awarded to the winning bidder.'' 
\88\ Further process is warranted to examine this concept.\89\ I 
encourage transmission providers to work with interconnection 
customers and other stakeholders to explore structures such as this 
that may provide greater certainty surrounding the timing and cost 
of certain network upgrades.
---------------------------------------------------------------------------

    \87\ Enel Initial Comments at 52; see also Pine Gate Initial 
Comments at 63-64 (proposing that ``the Commission should grant the 
interconnection customer with the largest projected impact on a 
potential Stand Alone Network Upgrade facility the ability to elect 
the option to build with priority falling to each interconnection 
customer based on their interconnection request having the next 
largest impact on the Stand Alone Network Upgrade'').
    \88\ Enel Initial Comments at 52.
    \89\ Enel notes that ``[t]he Commission could establish 
workshops or other mechanisms to further explore and develop these 
details.'' Id.
---------------------------------------------------------------------------

D. Address Challenges Faced by Projects Serving Tribes and Tribal 
Communities

    38. Beyond these recommendations to further facilitate efficient 
interconnection of new resources, I encourage transmission providers 
to examine potential changes to address important considerations of 
equity and fairness related to interconnection of resources serving 
or developed by Tribes. In particular, I encourage transmission 
providers to examine whether any exceptions or waivers to the 
commercial readiness requirements or withdrawal penalties framework 
are appropriate for certain projects serving Tribal nations or their 
communities. While the commercial readiness deposit and withdrawal 
framework adopted in this final rule hold the potential to make 
interconnection processes more efficient, they may act as a barrier 
to projects serving or developed by Tribes in cases where such 
projects adopt unique ownership and financing structures.\90\ This 
may also be a concern with regard to projects developed by, or in 
partnership with, communities that have been historically 
marginalized or overburdened by pollution, and I encourage further 
dialogue examining whether that is the case.
---------------------------------------------------------------------------

    \90\ See OSPA Initial Comments at 8, 15-16 (arguing that SPP's 
current security deposit regime has been ``an insuperable barrier to 
renewable energy development on Tribal lands'').
---------------------------------------------------------------------------

    39. For example, the Commission recently granted a waiver to the 
SAGE Development Authority (SAGE), an entity developing a wind 
generation project on Tribal land, to allow it more time to post 
financial security as required by SPP.\91\ SAGE was created by the 
Standing Rock Sioux Tribe and is developing the project through ``a 
community-led process designed to, among other things, implement 
Tribal values and ensure that the financial benefits of the Project 
will in turn support further community projects intended to address 
disparities around public health and other issues.'' \92\ The 
Commission granted SAGE's requested waiver in part because ``due to 
its unique Tribal business structure, it [was] unable to secure 
credit in advance'' of the relevant security deposit deadline.\93\ 
Waiver ``provide[d] SAGE the time necessary to secure additional 
credit.'' \94\
---------------------------------------------------------------------------

    \91\ See SAGE Development Authority, 182 FERC ] 61,180 (2023).
    \92\ Id. at P 4.
    \93\ Id. at P 20.
    \94\ Id.
---------------------------------------------------------------------------

    40. To the extent this rule's deposit requirements subject 
Tribal projects to greater risk, the need for similar waivers could 
be heightened. Accordingly, I encourage further inquiry into whether 
certain projects developed to serve Tribal communities or 
disadvantaged communities may have other characteristics that 
uniquely demonstrate commercial readiness as alternatives to the new 
deposit requirements. The inquiry could also consider other measures 
that may allow such projects to overcome any unique barriers that 
they face.\95\
---------------------------------------------------------------------------

    \95\ See also Energy Keepers Initial Comments at 2-3 (arguing 
that it would not be ``unduly discriminatory or preferential for 
transmission providers to expedite the processing of Native American 
interconnection requests,'' considering ``prior environmental 
justice inequities.'').
---------------------------------------------------------------------------

    41. While challenges remain, the Commission's issuance of a 
final rule today is an important step forward in the effort to 
address interconnection backlogs around the country. The ideas for 
continuing reform that I describe in this concurrence represent best 
practices and innovative thinking by regions and stakeholders 
considering how to solve the challenges the final rule does not 
address. I encourage transmission providers, interconnection 
customers and other stakeholders to consider the rule's requirements 
a strong baseline and not a ceiling, and to continue to engage on 
the topics I have addressed herein.
    For these reasons, I respectfully concur.

-----------------------------------------------------------------------
Allison Clements,
Commissioner.

Improvements to Generator Interconnection Docket No. RM22-14-000

Procedures and Agreements--

CHRISTIE, Commissioner, concurring:

    1. I concur to this final rule,\1\ which represents major 
progress towards the primary goal we set out to accomplish last year 
when we issued the NOPR: To move from a system of ``first come, 
first served'' to a system of ``first ready, first served'' by 
identifying generation projects in the interconnection queues that 
are commercially more viable and then moving them ahead of requests 
that are speculative and which have been causing major backlogs. I 
write separately about four issues contained within:
---------------------------------------------------------------------------

    \1\ Improvements to Generator Interconnection Procedures and 
Agreements, 184 FERC ] 61,054 (2023) (Final Rule).
---------------------------------------------------------------------------

I. Evaluation of Alternative Transmission Technologies (Section 
III.C.2.iii)

    2. Alternative transmission technologies, or grid-enhancing 
technologies (GETs), is a short-hand categorical term that covers a 
sweeping array of very different technologies. A GET may hold the 
potential of squeezing more juice--literally--out of the existing 
transmission grid. By increasing the capacity of the existing grid, 
a GET could reduce or even eliminate the need for the future 
construction of new transmission assets. So the potential for cost-
savings from the use of GETs is too important to ignore.
    3. One of the most promising GETs--dynamic line ratings (DLRs)--
could potentially save billions of dollars in avoided costs for new 
transmission assets. DLRs are not covered by this final rule, but 
are the subject of a separate proceeding,\2\ and I hope we will use 
the record of that proceeding to move forward on a proposed rule to 
require implementation of DLRs when and where DLRs will be 
technologically sound and cost-effective.
---------------------------------------------------------------------------

    \2\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110 
(2022).
---------------------------------------------------------------------------

    4. While DLRs have tremendous potential and should be pursued, 
there is a problem with any categorical regulatory mandate to use 
GETs, which is this: Some GETs work somewhere but not everywhere; 
some work sometimes but not all the time; some only work under 
certain weather conditions; some don't work at all, or at least not 
as advertised; and some are only cost-effective where the congestion 
costs are greater than the cost of the GET itself.
    5. Given these engineering and economic realities, some 
knowledgeable transmission planning experts have argued that GETs 
categorically are not planning tools, but rather are operational 
applications that should be deployed when and where their efficacy 
is likely and can be appropriately proven. If they work in the real 
world as advertised, they could reduce or eliminate the need for 
future network upgrades or even backbone transmission assets, but 
they should not be mandated as planning tools or as potential 
substitutes for network upgrades caused by interconnection 
requests.\3\
---------------------------------------------------------------------------

    \3\ See PJM Initial Comments at 68 (``PJM therefore cautions the 
Commission not to conflate the operational benefits of alternative 
transmission technologies . . . with the need to address significant 
capacity enhancement needs (short and long-term) or long-range 
transmission needs under rapid growth or changing resource mix 
scenarios.''); MISO Initial Comments at 121-22 (``Further, although 
these technologies may be evaluated, the technologies identified by 
the Commission still may not provide the appropriate solution from a 
planning perspective. Many of the technologies identified are 
appropriately considered as operational tools or short-term 
solutions but are not necessarily appropriate for planning to 
support a particular generator interconnection.'') (emphases added, 
footnote omitted).
---------------------------------------------------------------------------

    6. Against this cautious view of GETs, I recognize the 
counterargument that transmission owners themselves have an economic 
incentive to favor the construction of costly new transmission 
assets rather than deploy GETs to squeeze out more capacity. New 
transmission assets can be rate-based, and the transmission owner 
can take advantage of the very generous formula rate treatment 
offered here at the Commission (another issue I have raised concerns 
about).\4\

[[Page 61348]]

So to overcome this incentive against GETs deployment, proponents 
argue that the Commission should require it.
---------------------------------------------------------------------------

    \4\ See, e.g., Sw. Power Pool, Inc., 183 FERC ] 61,151 (2023) 
(Clements, Comm'r, and Christie, Comm'r, concurring at P 4) 
(``Indeed, the Commission grants formula rate treatment, including a 
presumption of prudence, to filings from transmission owners seeking 
cost recovery for transmission projects without regard to whether 
such projects have been subject to a serious vetting in any 
proceeding in which both need and prudence of cost must be 
demonstrated by the transmission developer. We have expressed 
concerns about this lack of oversight previously, and this filing by 
SPP illustrates exactly why that is a major problem pertinent to the 
issue of rising consumer costs for transmission.''), https://www.ferc.gov/news-events/news/commissioner-clements-and-commissioner-christies-joint-concurrence-spp-project; Transmission 
Planning and Cost Management, Technical Conference, Docket No. AD22-
8-000, Tr. 16:4-20:11 (Comm'r Mark Christie) (Oct. 6, 2022).
---------------------------------------------------------------------------

    7. But--as usual--the economic incentives argument has more than 
one side. The companies that sell GETs (and the organizations they 
fund) stand to profit from any regulation mandating that their 
products must be used. And generation developers (and the 
organizations they fund) have every incentive to lobby for a 
regulation mandating the use of GETS as a way to avoid paying the 
costs of the traditional network upgrades made necessary by their 
interconnections. This incentive is particularly salient in RTOs/
ISOs that use participant funding to pay for the costs of network 
upgrades caused by the interconnecting customers (i.e., developers).
    8. So--again, as usual with sweeping Commission regulations--
there is plenty of rent-seeking to go around. Striking the 
appropriate balance--one that is in the public interest--is a 
challenge. I believe this final rule--unlike the NOPR--does strike 
the right balance, in terms of a requirement simply to evaluate GETs 
in determining the appropriate network upgrade.
    9. Importantly, the final rule makes it explicitly clear that 
while it is requiring the evaluation of certain listed GETs in the 
interconnection studies process, it is not requiring--nor even 
suggesting--that a GET must be deployed as an alternative to a 
necessary network upgrade. Indeed, the final rule explicitly says:

    This final rule does not create a presumption in favor of 
substituting alternative transmission technologies for necessary 
traditional network upgrades, either categorically or in specific 
cases. This final rule is agnostic as to whether, in a specific 
case, an alternative transmission technology is an acceptable 
alternative to a traditional network upgrade . . . .

    10. The final rule also makes it explicitly clear that the 
determination in each case is to be made at the sole discretion of 
the transmission provider (i.e., RTO/ISOs or non-RTO transmission 
providers), applying good utility practices, applicable reliability 
standards, and other applicable regulatory requirements. To avoid 
continual litigation aimed at the transmission provider's 
determination in specific cases when a generation developer does not 
want to pay the costs of a network upgrade, the final rule 
explicitly makes clear that it is requiring a process of evaluation, 
not mandating outcomes in specific cases. And it makes clear that if 
the transmission provider performs the evaluation as required in the 
final rule, it has complied with the final rule.
    11. This agnosticism as to outcomes in specific cases is 
critically important. Transmission providers must require the 
appropriate network upgrade necessary to fix the reliability issue 
caused by the interconnection request. If a GET is used instead, and 
it fails to fix the reliability issue caused by the interconnection, 
a later network upgrade will be required, one potentially more 
costly than the network upgrade originally required. And who will 
pay those costs? Certainly in RTOs/ISOs using participant funding, 
load (retail consumers) should not. Sticking those costs on 
consumers would raise a serious question of unjust and unreasonable 
rates.
    12. In summary though, I believe that this final rule strikes 
the appropriate balance between requiring the evaluation of GETs, 
but not mandating the use of a GET in specific cases unless the 
transmission provider--and only the transmission provider--
determines it would work from a real-world applicability standpoint. 
In all cases, the transmission provider should apply its engineering 
expertise to come to the right determination as to the necessary 
network upgrades. This final rule requires nothing less.

II. Repayment of Affected Systems Network Upgrade Costs (Section 
III.B.2.c.iii(c))

    13. The final rule essentially codifies existing precedent as to 
the repayment of affected systems network upgrade costs when a 
generation developer interconnects at or near a seam between an RTO 
(which uses participant funding to pay for interconnection costs) 
and a non-RTO, vertically integrated load-serving utility that uses 
a crediting mechanism.
    14. Three recent cases involving Duke Energy Progress, LLC 
(Duke) in North Carolina \5\ illustrate my concern about the 
Commission's repayment policy.\6\ In these cases, generation 
developers located within the PJM footprint, which extends into a 
corner of northeastern North Carolina due to Dominion Energy, Inc.'s 
PJM membership, chose to interconnect very close to the seam with 
Duke's North Carolina territory. Duke is a vertically integrated 
utility regulated by the North Carolina Utilities Commission (NCUC) 
on an Integrated Resource Plan (IRP) model. Duke builds transmission 
(and generation) subject to an IRP approved by the NCUC, and the 
costs of network upgrades caused by that new generation are paid by 
retail consumers. Since the NCUC approves new generation through its 
IRP process, which includes the costs to interconnect that new 
generation, the NCUC decides the generation and interconnection 
costs that are appropriately paid for by retail consumers.
---------------------------------------------------------------------------

    \5\ Duke Energy Progress, LLC, 181 FERC ] 61,229 (2022), reh'g 
deemed denied, 182 FERC ] 62,088 (2023); Duke Energy Progress, LLC, 
180 FERC ] 61,005, order on reh'g, 181 FERC ] 61,197 (2022) 
(Edgecombe Rehearing Order); Duke Energy Progress, LLC, 177 FERC ] 
61,001 (2021), order on reh'g, 179 FERC ] 61,007 (2022) (American 
Beech Rehearing Order). My concurrences to the Edgecombe Rehearing 
Order and American Beech Rehearing Order set forth my concerns as 
well. See Edgecombe Rehearing Order, 181 FERC ] 61,197 (Christie, 
Comm'r, concurring) (Edgecombe Concurrence), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-rehearing-duke-energy-progress; American Beech Rehearing Order, 179 
FERC ] 61,007 (Christie, Comm'r, concurring).
    \6\ See Standardization of Generator Interconnection Agreements 
& Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ] 
61,103, at PP 693-696, 720-739 (2003), order on reh'g, Order No. 
2003-A, 69 FR 15932, 106 FERC ] 61,220, at PP 584-586, order on 
reh'g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ] 
61,287 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (July 
18, 2005), 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of 
Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007). I note 
that this policy applies not just to affected systems network 
upgrades but also network upgrades on the host transmission 
provider's system.
---------------------------------------------------------------------------

    15. In these three cases, however, Duke was considered an 
``affected system'' for the interconnection costs caused by the 
generation developers located just across the seam in PJM's 
footprint. So the affected systems network upgrades were not paid by 
the developer (creating an incentive to locate close to the seam), 
but by Duke's retail consumers through crediting pursuant to 
Commission policy. And unlike the costs of transmission and network 
upgrades built with the prior approval of the NCUC, no state-
approved IRP controls the construction of generation in the PJM 
footprint in North Carolina. Not surprisingly, the NCUC and the NCUC 
Public Staff, which represents consumers in North Carolina, filed 
vigorous--and in my opinion, persuasive--comments in several 
proceedings on these issues.\7\
---------------------------------------------------------------------------

    \7\ See NCUC and NCUC Public Staff Initial Comments at 6; NCUC 
and NCUC Public Staff, Joint Comments, Docket No. RM21-17-000, at 12 
(filed Aug. 17, 2022); NCUC Public Staff, Comments, Docket No. RM21-
17-000, at 13-15 (filed Oct. 12, 2021); NCUC Public Staff Reply 
Comments, Docket No. RM21-17-000, at 6 (filed Nov. 30, 2021) 
(``[U]nder the crediting policy, ratepayers are left paying the bill 
regardless of the benefits, or lack thereof, they received from the 
network upgrades. Further, the [NCUC] Public Staff believes that 
[interconnection customers] are beginning to `game' the system by 
placing large merchant plants into the interconnection queue in 
congested areas to take advantage of the crediting policy and fill 
what excess capacity is then created with state jurisdictional 
projects that would normally have to fund the upgrades 
themselves.''); see also NCUC Public Staff, Motion to Intervene Out-
of-Time and Comment, Docket No. ER21-1955-003, at 1-9 (filed Nov. 9, 
2021) (generally arguing, inter alia, that Duke customers will not 
or will only minimally benefit from upgrading its system to 
accommodate power being interconnected and delivering to PJM; that 
Duke ratepayers are subsidizing costs that should be paid for by the 
developer, the party that is both causing the costs to be incurred 
and reaping the resulting benefits; that given the proliferation of 
merchant generation trying to locate in this area of North Carolina, 
the NCUC Public Staff is concerned that Duke ratepayers will be 
burdened with potentially hundreds of millions of dollars in 
affected systems network upgrade cost as a result of the 
Commission's actions; and that the project in American Beech had not 
yet received a CPCN from North Carolina so any decision put the 
``cart before the horse.'').

---------------------------------------------------------------------------

[[Page 61349]]

    16. While I recognize that the results in these cases were 
consistent with prior precedent and Order No. 2003,\8\ I think that 
precedent and, if necessary, Order No. 2003 itself, should be 
revisited as to the affected systems repayment policy. I concur to 
the issuance of this final rule because this final rule is not the 
appropriate place to revisit the issue and because the final rule by 
its own terms does not go beyond existing precedent.
---------------------------------------------------------------------------

    \8\ See, e.g., Edgecombe Concurrence.
---------------------------------------------------------------------------

III. Inappropriate Allocation of Certain Costs to Consumers

    17. As described below, while I support the final rule, I am 
concerned that study delay penalties on RTOs/ISOs and the costs of 
transmission provider heatmaps used as a tool for interconnection 
customers will be inappropriately allocated to consumers even though 
they both appear to provide much more of a benefit to generation 
developers than consumers. I address each in turn.

A. Study Delay Penalties on RTO/ISOs (Section III.B.1.c.x)

    18. The final rule adopts the NOPR proposal to eliminate the 
reasonable efforts standard from the pro forma LGIP, and it adds a 
new section to the pro forma LGIP that imposes penalties on 
transmission providers who miss study deadlines. I have no qualms 
about assessing penalties on non-RTO/ISO transmission providers and 
transmission-owning members of RTOs/ISOs. These are generally 
investor-owned companies and stockholders will bear such costs. On 
the other hand, I have concerns about assessing study penalties on 
RTOs/ISOs, as they are not-for-profit entities who do not have 
stockholders. In my concurrence to the NOPR, I explained:

    [T]he penalty provisions do not answer definitively the most 
important question of all: Who will pay these penalties in an RTO or 
ISO which has no stockholders? Consumers certainly should not pay, 
directly or indirectly.\9\
---------------------------------------------------------------------------

    \9\ Improvements to Generator Interconnection Procs. & 
Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ] 61,194 (2022) 
(Christie, Comm'r, concurring at P 3) (NOPR Concurrence), https://www.ferc.gov/news-events/news/e-1-commissioner-christies-concurrence-improvements-generator-interconnection.

The final rule does not fully address this question and does not 
provide complete assurance that consumers will be protected.
    19. However, the final rule does have some protections in place 
to protect against consumers ultimately having to pay for study 
delay penalties. First, the final rule modifies the NOPR proposal to 
prohibit non-RTO/ISO transmission providers and transmission-owning 
members of RTOs/ISOs from recovering study delay penalty amounts 
through transmission rates.\10\ Second, the final rule modifies the 
NOPR proposal to adopt a new provision in our regulations specifying 
that, for RTOs/ISOs in which the transmission-owning members perform 
certain interconnection studies, the study delay penalties will 
automatically be imposed directly on the transmission-owning 
member(s) that conducted the late study.
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    \10\ Final rule, Section III.B.1.c.ix.
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    20. But these provisions still leave open the question of how 
RTOs/ISOs will recover those study delay penalties that are not 
automatically imposed on a transmission-owning member. The final 
rule essentially punts on this question, explaining that RTOs/ISOs 
may submit an FPA section 205 filing to propose a default structure 
for recovering study delay penalties and/or make individual FPA 
section 205 filings to recover the costs of any specific study delay 
penalties. I urge that any such RTO/ISO filing make protections to 
consumers paramount.

B. Cost of Heatmap (Section III.A.1.c.iii)

    21. This final rule requires transmission providers to publicly 
post a ``heatmap'' with certain information after the completion of 
each cluster study and cluster restudy period. The final rule finds 
that the heatmap will benefit interconnection customers, including 
prospective interconnection customers, by providing them further 
transparency as to expected congestion and potential network 
upgrades and therefore will reduce the number of speculative 
interconnection requests. I agree that a requirement to post a 
heatmap will greatly benefit interconnection customers and support 
the requirement's addition to the pro forma LGIP.
    22. Where I am concerned, however, is how the heatmap should be 
funded. The final rule clarifies that transmission providers, not 
interconnection customers, are responsible for paying the costs 
associated with the heatmap requirement. Further, the final rule 
contemplates transmission providers recovering the costs of the 
heatmap from transmission customers and ex ante determines that such 
rate treatment is appropriate because interconnection queue 
efficiency benefits transmission customers. Commission policy may 
dictate that interconnection queue efficiency benefits transmission 
customers; \11\ however, that should not result in the costs of a 
requirement that best benefits interconnection customers, and really 
prospective interconnection customers that may ultimately not seek 
to interconnect, being recovered from consumers through transmission 
rates carte blanche. The Commission simply cannot ask retail 
consumers to foot the bill for every single ``efficiency,'' 
especially where many of these ``efficiencies'' largely benefit 
generation developers and then get folded into transmission rates 
and receive an ROE.\12\
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    \11\ Whether or not I agree with Commission policy is another 
matter entirely. See, e.g., supra PP 13-16.
    \12\ Joint Fed.-State Task Force on Elec. Transmission, 
Technical Conference, Docket No. AD21-15-000, Tr. 37:9-20 (Comm'r 
Mark Christie) (Nov. 15, 2022) (``Let's put this in context, and 
talk about what's really at stake here. Last year national 
transmission rate base went up over 9 percent. That's the third 
consecutive year it's gone up over 9 percent. What goes into rate 
base, goes into consumer's bills. Every nickel. And in the last 
decade, national transmission rate base has almost tripled, and . . 
. at 9 percent it's going to double again in the next eight years. 
This is all going into customer's bills. So this is a hugely 
important issue. This is a ton of money, this is big, big money.'').
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    23. I believe this issue merits further scrutiny, and I look 
forward to future comments on this issue.

IV. ``Hold Harmless'' Provisions (Sections I, III.A.6.c.iii, IV.C)

    24. In my concurrence to the NOPR, I wrote that while I 
supported the proposed queue reforms (subject, of course, to 
comment):

    I also caution strongly that we should avoid undermining through 
this NOPR what the RTOs/ISOs, working through their stakeholder 
processes, are already doing to fix their own queue problems. We 
should recognize that each RTO/ISO is different and faces unique 
local challenges and needs. The queue reforms proposed in today's 
NOPR should be seen more as guideposts or general standards rather 
than unyielding mandates that refuse to take local solutions into 
consideration. I would allow RTOs/ISOs the opportunity to 
demonstrate that if their own efforts to enact queue reforms achieve 
the same goals in a different, but equally effective manner, their 
individual reform may be acceptable in complying with any final 
rule. While this NOPR currently recognizes the potential for 
regional flexibility, I hope the need for such flexibility is 
explicitly memorialized in any final rule.\13\
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    \13\ NOPR Concurrence at P 4 (emphasis added, footnote omitted).

    25. This final rule contains language that is intended to 
recognize the earnest and good-faith efforts undertaken by the RTOs 
to enact queue reforms. Some RTOs, such as PJM, have already 
launched extensive queue reforms; others, such as CAISO, are hard at 
work on developing queue reforms.
    26. I concur because this final rule does contain language that 
is at least intended to recognize the efforts of RTOs to act on 
their own queue reforms without waiting on a Commission rulemaking. 
Whether the language of this final rule adequately recognizes or 
``holds harmless'' those efforts will be an issue for compliance 
filings.
    For these reasons, I concur.

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Mark C. Christie,
Commissioner.

[FR Doc. 2023-16628 Filed 9-5-23; 8:45 am]
BILLING CODE 6717-01-P