Document ID: FERC-2018-0582-0001
Agency: ferc
Document Type: Rule
Title: Reform of Generator Interconnection Procedures and Agreements
Posted Date: 2018-05-09T04:00Z

[Federal Register Volume 83, Number 90 (Wednesday, May 9, 2018)]
[Rules and Regulations]
[Pages 21342-21414]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-08659]

[[Page 21341]]

Vol. 83

Wednesday,

No. 90

May 9, 2018

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 37

Reform of Generator Interconnection Procedures and Agreements; Final 
Rule

  Federal Register / Vol. 83 , No. 90 / Wednesday, May 9, 2018 / Rules 
and Regulations  

[[Page 21342]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 37

[Docket No. RM17-8-000; Order No. 845]

Reform of Generator Interconnection Procedures and Agreements

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final action.

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SUMMARY: In this final action, the Federal Energy Regulatory Commission 
(Commission) is amending the pro forma Large Generator Interconnection 
Procedures and the pro forma Large Generator Interconnection Agreement 
to improve certainty, promote more informed interconnection, and 
enhance interconnection processes. The reforms are intended to ensure 
that the generator interconnection process is just and reasonable and 
not unduly discriminatory or preferential.

DATES: This action is effective July 23, 2018.

FOR FURTHER INFORMATION CONTACT:

Tony Dobbins (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-6630, [email protected].
Kathleen Ratcliff (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-8018, [email protected].
Adam Pan (Legal Information), Office of the General Counsel, Federal 
Energy Regulatory Commission, 888 First Street NE, Washington, DC 
20426, (202) 502-6023, [email protected].

SUPPLEMENTARY INFORMATION:
Before Commissioners: Kevin J. McIntyre, Chairman; Cheryl A. LaFleur, 
Neil Chatterjee, Robert F. Powelson, and Richard Glick.

Table of Contents

 
                                                               Paragraph
                                                                 Nos.
 
I. Introduction.............................................           1
II. Background..............................................           9
    A. Order No. 2003.......................................           9
    B. 2008 Order on Interconnection Queuing Practices......          12
    C. 2015 American Wind Energy Association Petition and             15
     2016 Technical Conference..............................
    D. Notice of Proposed Rulemaking........................          18
III. Overview and Need for Reform...........................          23
    A. Comments on Overall Approach.........................          26
    B. Commission Determination.............................          36
IV. Proposed Reforms........................................          45
    A. Improving Certainty for Interconnection Customers....          45
        1. Scheduled Periodic Restudies.....................          46
        2. The Interconnection Customer's Option To Build...          73
        3. Self-Funding by the Transmission Owner...........         114
        4. Dispute Resolution...............................         123
        5. Capping Costs for Network Upgrades...............         172
    B. Promoting More Informed Interconnection..............         191
        1. Identification and Definition of Contingent               192
         Facilities.........................................
        2. Transparency Regarding Study Models and                   221
         Assumptions........................................
        3. Congestion and Curtailment Information...........         247
        4. Definition of Generating Facility in the Pro              273
         Forma LGIP and Pro Forma LGIA......................
        5. Interconnection Study Deadlines..................         290
        6. Improving Coordination With Affected Systems.....         335
    C. Enhancing Interconnection Processes..................         342
        1. Requesting Interconnection Service Below                  343
         Generating Facility Capacity.......................
        2. Provisional Interconnection Service..............         424
        3. Utilization of Surplus Interconnection Service...         453
        4. Material Modification and Incorporation of                510
         Advanced Technologies..............................
        5. Modeling of Electric Storage Resources for                537
         Interconnection Studies............................
    D. Other Issues.........................................         545
        1. Whether Proposed Reforms Should Be Applied to             545
         Small Generation...................................
        2. Issues Not Raised in the NOPR....................         550
        3. Process Considerations...........................         552
        4. Compliance and Implementation....................         554
V. Information Collection Statement.........................         557
VI. Environmental Analysis..................................         563
VII. Regulatory Flexibility Act.............................         564
VIII. Document Availability.................................         566
IX. Effective Date and Congressional Notification...........         569
 

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I. Introduction

    1. In this final action, the Commission revises its pro forma Large 
Generator Interconnection Procedures (LGIP) and the pro forma Large 
Generator Interconnection Agreement (LGIA) to implement ten specific 
reforms.
    2. This final action adopts reforms that are designed to improve 
certainty for interconnection customers, promote more informed 
interconnection decisions, and enhance the interconnection process. We 
believe the reforms adopted in this final action will benefit both 
interconnection customers and transmission providers.\1\ Specifically, 
we expect these reforms to provide interconnection customers with 
better information and more options for obtaining interconnection 
service such that there are fewer interconnection requests overall and 
fewer interconnection requests that are unlikely to reach commercial 
operation. As a result, we expect transmission providers will be able 
to focus on those requests that are most likely to reach commercial 
operation.
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    \1\ 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.
    Pro forma LGIP Section 1 (Definitions); pro forma LGIA Art. 1 
(Definitions).
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    3. First, in order to improve certainty for interconnection 
customers, this final action: (1) Removes the limitation that 
interconnection customers may only exercise the option to build a 
transmission provider's interconnection facilities and stand alone 
network upgrades in instances when the transmission provider cannot 
meet the dates proposed by the interconnection customer; and (2) 
requires that transmission providers establish interconnection dispute 
resolution procedures that allow a disputing party to unilaterally seek 
non-binding dispute resolution.
    4. Second, to promote more informed interconnection decisions, this 
final action: (1) Requires transmission providers to outline and make 
public a method for determining contingent facilities; (2) requires 
transmission providers to list the specific study processes and 
assumptions for forming the network models used for interconnection 
studies; (3) revises the definition of ``Generating Facility'' to 
explicitly include electric storage resources; and (4) establishes 
reporting requirements for aggregate interconnection study performance.
    5. The third area of reforms aims to enhance the interconnection 
process. To effectuate this goal, this final action: (1) Allows 
interconnection customers to request a level of interconnection service 
that is lower than their generating facility capacity; (2) requires 
transmission providers to allow for provisional interconnection 
agreements that provide for limited operation of a generating facility 
prior to completion of the full interconnection process; (3) requires 
transmission providers to create a process for interconnection 
customers to use surplus interconnection service at existing points of 
interconnection; and (4) requires transmission providers to set forth a 
procedure to allow transmission providers to assess and, if necessary, 
study an interconnection customer's technology changes without 
affecting the interconnection customer's queued position.
    6. The pro forma LGIP and pro forma LGIA establish the terms and 
conditions under which public utilities that own, control, or operate 
facilities for transmitting electric energy in interstate commerce \2\ 
must provide interconnection service to large generating facilities.\3\ 
Based on the record in this proceeding, we find it necessary under 
section 206 of the Federal Power Act (FPA) \4\ to revise the pro forma 
LGIP and the pro forma LGIA to ensure that the rates, terms, and 
conditions pursuant to which public utilities provide interconnection 
service to large generating facilities are just and reasonable and not 
unduly discriminatory or preferential.
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    \2\ A public utility is a utility that owns, controls, or 
operates facilities used for transmitting electric energy in 
interstate commerce, as defined by the Federal Power Act (FPA). See 
16 U.S.C. 824(e) (2012). A non-public utility that seeks voluntary 
compliance with the reciprocity condition of an Open Access 
Transmission Tariff (OATT) may satisfy that condition by filing an 
OATT, which includes the pro forma LGIP and the pro forma LGIA. See 
Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003) 
(Order No. 2003), order on reh'g, Order No. 2003-A, FERC Stats. & 
Regs. ] 31,160, at P 774 (Order No. 2003-A), order on reh'g, Order 
No. 2003-B, FERC Stats. & Regs. ] 31,171 (2004) (Order No. 2003-B), 
order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ] 31,190 
(2005) (Order No. 2003-C), aff'd sub nom. Nat'l Ass'n of Regulatory 
Util. Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007), cert. denied, 
552 U.S. 1230 (2008).
    \3\ A large generating facility is ``a Generating Facility 
having a Generating Facility Capacity of more than 20 [megawatts].'' 
Pro forma LGIA Art. 1.
    \4\ 16 U.S.C. 824e (2012).
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    7. Although the implementation of Order No. 2003 reduced undue 
discrimination in the generator interconnection process, some 
interconnection customers argue that they have continued to observe 
systemic inefficiencies and discriminatory practices.\5\ In addition, 
there have been a number of developments that affect generator 
interconnection, including a changing resource mix driven by market 
forces and state and federal policies, and by the emergence of new 
technologies. At the same time, transmission providers have expressed 
concern that the interconnection study process can be difficult to 
manage because some interconnection customers submit requests for 
interconnection service associated with new generating facilities that 
the transmission providers maintain have little chance of reaching 
commercial operation. Consequently, we conclude that it is appropriate 
to adopt the revisions to the pro forma LGIP and the pro forma LGIA 
described in this final action to mitigate existing concerns and to 
ensure that the pro forma LGIP and pro forma LGIA are just and 
reasonable and not unduly discriminatory or preferential.
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    \5\ See, e.g., AWEA June 19, 2015 Petition at 2 (Petition).
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    8. The reforms we adopt track many of the proposals set forth in 
the Notice of Proposed Rulemaking (NOPR) issued in this proceeding on 
December 15, 2016,\6\ with certain modifications. Among other things, 
we have revised aspects of the reforms pertaining to dispute 
resolution, contingent facilities, model and assumption transparency, 
study deadline metrics, provisional interconnection service, 
utilization of surplus interconnection service, and material 
modification.\7\ Additionally, in this final action, as discussed more 
fully below, we withdraw or decline to move forward with the NOPR 
proposals pertaining to scheduled periodic restudies, self-funding by 
the transmission owner, congestion and curtailment information, and 
modeling electric storage resources. The Commission also held a 
technical conference on April 3 and 4, 2018 to gather additional 
information regarding transmission providers' and interconnection 
customers' coordination with affected systems.\8\ We conclude

[[Page 21344]]

that the reforms adopted in this final action will help improve the 
efficiency of processing interconnection requests for both transmission 
providers and interconnection customers, maintain reliability, balance 
the needs of interconnection customers and transmission owners, and 
remove barriers to resource development.
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    \6\ Reform of Generator Interconnection Procedures and 
Agreements, 82 FR 4464 (Jan. 13, 2017), FERC Stats. & Regs. ] 32,719 
(2017) (NOPR).
    \7\ The pro forma LGIP defines Material Modification as ``those 
modifications that have a material impact on the cost or timing of 
any Interconnection Request with a later queue priority date.'' See 
pro forma LGIP Section 1.
    \8\ Reform of Affected System Coordination in the Generator 
Interconnection Process, Docket No. AD18-8-000 and EDF Renewable 
Energy, Inc. v. Midcontinent Independent System Operator, Inc., 
Southwest Power Pool, Inc., and PJM Interconnection, L.L.C., Docket 
No. EL18-26-000, Notice of Technical Conference (Feb. 2, 2018).
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II. Background

A. Order No. 2003

    9. In Order No. 2003, the Commission recognized a ``pressing need 
for a single set of procedures for jurisdictional Transmission 
Providers and a single, uniformly applicable interconnection agreement 
for Large Generators.'' \9\ Prior to the issuance of Order No. 2003, 
the Commission addressed interconnection issues on a case-by-case basis 
through, for example, filings under section 205 of the FPA.\10\
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    \9\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 11.
    \10\ See Id. P 10.
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    10. In Order No. 2003, the Commission noted that it had previously 
found that interconnection is a ``critical component of open access 
transmission service and thus is subject to the requirement that 
utilities offer comparable service under the OATT.'' \11\ The 
Commission found that a standard set of procedures ``will minimize 
opportunities for undue discrimination and expedite the development of 
new generation, while protecting reliability and ensuring that rates 
are just and reasonable.'' \12\
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    \11\ Id. P 9 (citing Tennessee Power Co., 90 FERC ] 61,238 
(2000)).
    \12\ Id. P 11.
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    11. Consequently, in Order No. 2003, the Commission required public 
utilities that own, control, or operate transmission facilities to file 
standard generator interconnection procedures and a standard agreement 
to provide interconnection service to generating facilities with a 
capacity greater than 20 megawatts (MW). To this end, the Commission 
adopted the pro forma LGIP and pro forma LGIA and required all public 
utilities subject to Order No. 2003 to modify their OATTs to 
incorporate the pro forma LGIP and pro forma LGIA.

B. 2008 Order on Interconnection Queuing Practices

    12. Although the issuance of Order No. 2003 was a significant step 
in minimizing undue discrimination in the generator interconnection 
process, some concerns with the process persisted, while some new 
concerns came to light. In response to concerns voiced to the 
Commission about interconnection queue management by regional 
transmission organizations and independent system operators (RTOs/ISOs) 
as well as other entities, the Commission held a technical conference 
on December 17, 2007, and issued a notice inviting further comments in 
response to such concerns.\13\
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    \13\ Interconnection Queuing Practices, Docket No. AD08-2-000, 
Notice of Technical Conference (Nov. 2, 2007).
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    13. The Commission issued an order on March 20, 2008 addressing 
interconnection queue issues based on the December 2007 technical 
conference and subsequent comments.\14\ The Commission acknowledged 
that delays in processing interconnection queues were more pronounced 
in RTOs/ISOs that were attracting significant new entry.
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    \14\ Interconnection Queuing Practices, 122 FERC ] 61,252, at PP 
16-18 (2008) (2008 Order).
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    14. The Commission declined to impose generally applicable 
solutions, given the regional nature of some interconnection queue 
issues. However, the Commission provided guidance to assist RTOs/ISOs 
and their stakeholders in their efforts to improve the processing of 
interconnection queues.\15\ The Commission further stated that, 
although it ``may need to [impose solutions] if the RTOs and ISOs do 
not act themselves,'' each region would have an opportunity to work 
with stakeholders to develop its own solutions through ``consensus 
proposals.'' \16\ Following the 2008 Order, RTOs/ISOs submitted 
multiple queue reform proposals to the Commission, some of which were 
intended to move away from a ``first-come, first-served'' approach to a 
``first-ready, first-served'' approach.
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    \15\ 2008 Order, 122 FERC ] 61,252 at PP 16-18.
    \16\ Id. P 8.
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C. 2015 American Wind Energy Association Petition and 2016 Technical 
Conference

    15. On June 19, 2015, AWEA filed a petition in Docket No. RM15-21-
000 requesting that the Commission revise the pro forma LGIP and pro 
forma LGIA. On July 7, 2015, the Commission issued a Notice of Petition 
for Rulemaking in that docket to seek public comment on the petition. 
The Commission received thirty-five comments and three answers and 
reply comments.
    16. On May 13, 2016, Commission staff convened a technical 
conference (2016 Technical Conference). The 2016 Technical Conference 
featured five panels on ``The Current State of Generator 
Interconnection Queues,'' ``Transparency and Timing in the 
Interconnection Study Process,'' ``Certainty in Cost Estimates and 
Construction Time,'' ``Other Queue Coordination and Management 
Issues,'' and ``Interconnection of Electric Storage Resources.'' The 
panels featured representatives from RTOs/ISOs, transmission owners 
from both RTO/ISO and non-RTO/ISO regions, renewable generation 
developers, electric storage resource developers, and other 
stakeholders.
    17. On June 3, 2016, the Commission issued a Notice Inviting Post-
Technical Conference Comments. The Commission received twenty-four 
post-technical conference comments.

D. Notice of Proposed Rulemaking

    18. On December 15, 2016, the Commission issued the NOPR, proposing 
fourteen reforms focused on improving aspects of the pro forma LGIP and 
pro forma LGIA, the pro forma OATT, and the Commission's regulations. 
The Commission also sought comment on, but did not propose, tariff or 
regulatory revisions on other issues.
    19. First, the Commission proposed four reforms to improve 
certainty by affording interconnection customers more predictability in 
the interconnection process. To accomplish this goal, the Commission 
proposed to: (1) Revise the pro forma LGIP to require transmission 
providers that conduct cluster studies to move toward a scheduled, 
periodic restudy process; (2) remove from the pro forma LGIA the 
limitation that interconnection customers may only exercise the option 
to build transmission provider's interconnection facilities and stand 
alone network upgrades if the transmission provider cannot meet the 
dates proposed by the interconnection customer; (3) modify the pro 
forma LGIA to require mutual agreement between the transmission owner 
and interconnection customer for the transmission owner to opt to 
initially self-fund the costs of the construction of network upgrades; 
and (4) require that RTOs/ISOs establish dispute resolution procedures 
for interconnection disputes. The Commission also sought comment on the 
extent to which a cap on the network upgrade costs for which 
interconnection customers are responsible can mitigate the potential 
for serial restudies without inappropriately shifting cost 
responsibility.
    20. Second, the Commission proposed five reforms to improve 
transparency by

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providing more detailed information for the benefit of all participants 
in the interconnection process. The Commission proposed to: (1) Require 
transmission providers to outline and make public a method for 
determining contingent facilities in their LGIPs and LGIAs based upon 
guiding principles in the NOPR; (2) require transmission providers to 
list in their LGIPs and on their Open Access Same-Time Information 
System (OASIS) sites the specific study processes and assumptions for 
forming the networking models used for interconnection studies; (3) 
require congestion and curtailment information to be posted in one 
location on each transmission provider's OASIS site; (4) revise the 
definition of ``Generating Facility'' in the pro forma LGIP and pro 
forma LGIA to explicitly include electric storage resources; and (5) 
create a system of reporting requirements for aggregate interconnection 
study performance. The Commission also sought comment on proposals or 
additional steps that the Commission could take to improve the 
resolution of issues that arise when a proposed interconnection impacts 
affected systems.\17\
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    \17\ Affected system ``shall mean an electric system other than 
the Transmission Provider's Transmission System that may be affected 
by the proposed interconnect.'' Pro forma LGIP Section 1 
(Definitions); pro forma LGIA Art. 1 (Definitions).
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    21. Third, the Commission proposed five reforms to enhance 
interconnection processes by making use of underutilized existing 
interconnections, providing interconnection service earlier, or 
accommodating changes in the development process. In this area, the 
Commission proposed to: (1) Allow interconnection customers to limit 
their requested level of interconnection service below their generating 
facility capacity; (2) require transmission providers to allow for 
provisional agreements so that interconnection customers can operate on 
a limited basis prior to completion of the full interconnection 
process; (3) require transmission providers to create a process for 
interconnection customers to utilize surplus interconnection service at 
existing interconnection points; (4) require transmission providers to 
set forth a separate procedure to allow transmission providers to 
assess and, if necessary, study an interconnection customer's 
technology changes (e.g., incorporation of a newer turbine model) 
without a change to the interconnection customer's queue position; and 
(5) require transmission providers to evaluate their methods for 
modeling electric storage resources for interconnection studies and 
report to the Commission why and how their existing practices are or 
are not sufficient.
    22. In response to the NOPR, sixty-three comments were filed.\18\ 
These comments have informed our determinations in this final action.
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    \18\ Appendix A to Order No. 845 lists the entities that 
submitted comments on the NOPR and the shortened names used through 
this final action to describe those entities. Order No. 845 is 
available on the Commission's eLibrary and website.
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III. Overview and Need for Reform

    23. In the NOPR, the Commission noted that the electric power 
industry has undergone numerous changes since Order No. 2003's 
issuance. These changes are due to a variety of factors, such as the 
economics of new power generation being driven by sustained low natural 
gas prices, technological advances, and federal and state policies. In 
the NOPR, the Commission found that such changes have implications for 
the interconnection process, for both interconnection customers and 
transmission providers.\19\
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    \19\ NOPR, FERC Stats. & Regs. ] 32,719 at PP 24-25.
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    24. As a result of such changes and despite Commission efforts to 
improve the interconnection process, aspects of the generator 
interconnection process still provide cause for concern.\20\ For 
example, the Commission noted that many interconnection customers 
experience delays, and some interconnection queues have significant 
backlogs and long timelines.\21\ The Commission also recognized the 
recurring problem of late-stage interconnection request withdrawals 
that lead to interconnection restudies and consequent delays for lower-
queued interconnection customers.\22\ The Commission further recognized 
that interconnection request withdrawals can lead to increased network 
upgrade cost responsibility for lower-queued interconnection customers, 
which, in turn, could result in cascading withdrawals. Moreover, the 
Commission stated that the lack of cost and timing certainty can hinder 
interconnection customers from obtaining financing, and that cost 
uncertainty is a significant obstacle, as some interconnection 
customers are less able to absorb unexpected and potentially higher 
costs.
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    \20\ Id. P 26.
    \21\ Id. (citing, e.g., 2016 Technical Conference Tr. 210: 1-10 
(discussion of delays up to a year)).
    \22\ Id. (citing, e.g., 2016 Technical Conference Tr. 20:15-23 
(discussion regarding MISO experiencing 50 percent withdrawal rates 
in many parts of the queue)).
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    25. In light of the changing industry and the aforementioned 
concerns, the Commission preliminarily found that the current 
interconnection process may hinder the timely development of new 
generation and, thereby, stifle competition in the wholesale markets, 
resulting in rates, terms, and conditions that are not just and 
reasonable or are unduly discriminatory or preferential. Additionally, 
the Commission preliminarily found that the interconnection study 
process may result in uncertainty and inaccurate information. Finally, 
the Commission preliminarily found that the potential for 
discriminatory interconnection processes exists as new technologies 
enter the power generation sphere.

A. Comments on Overall Approach

    26. A number of parties express support for the proposals in the 
NOPR.\23\ For example, TAPS ``generally support[s] the proposed 
reforms'' and states that the NOPR proposals ``reasonably balance the 
needs of interconnection customers with the needs of load and 
transmission providers.'' \24\ Generation Developers agree with the 
Commission's preliminary findings and argue that the NOPR ``addresses 
critical items that directly impact: (i) The development of new 
generation; (ii) the rates; terms and conditions of interconnection 
service; and (iii) the rates to customers for wholesale electric 
products.'' \25\ Joint Renewable Parties and ESA ask the Commission to 
quickly proceed with a final rulemaking.\26\ ESA states that Order No. 
2003's issuances predate the deployment of electric storage resources 
on the transmission system and that existing interconnection agreements 
and processes do not consider electric storage resources' 
attributes.\27\ ESA also states that the resulting undue uncertainty 
limits grid access for electric storage resources and prevents them 
from providing low cost reliability services.\28\ ESA asserts, however, 
that the Commission's NOPR proposals strike an effective balance 
between transmission provider flexibility and interconnection customer 
certainty.\29\
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    \23\ See e.g., Community Renewable Energy Association 2017 
Comments at 1-2; Joint Renewable Commenters 2017 Comments at 1; 
Generation Developers 2017 Comments at 2; Renewable Energy Coalition 
2017 Comments at 2; Renewable and Storage Associations 2017 Comments 
at 1-2; TAPS 2017 Comments at 1; TDU Systems 2017 Comments at 3-13, 
16-30.
    \24\ TAPS 2017 Comments at 1.
    \25\ Generation Developers 2017 Comments at 2.
    \26\ Joint Renewable Commenters 2017 Comments at 1; ESA 2017 
Comments at 19.
    \27\ Id. at 5-6.
    \28\ Id. at 6.
    \29\ Id. at 19.

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[[Page 21346]]

    27. IECA supports the majority of the Commission's proposed 
reforms.\30\ Invenergy supports many of the Commission's proposed 
reforms but states that the NOPR ``leaves fundamental causes of these 
[interconnection] delays unaddressed.'' \31\ NEPOOL states that the 
proposed reforms could: (1) Address the time ISO-NE takes to evaluate, 
study, and approve new interconnections; and (2) facilitate market 
entry through more transparent and useful information regarding 
capacity and energy deliverability of potential new ISO-NE 
resources.\32\ Joint Renewable Parties contend that, despite existing 
rules, abusive interconnection practices impede the development of 
competitively supplied generation from renewable resources--
particularly where the transmission provider is a vertically integrated 
utility.\33\ CAISO recognizes the need to nationalize many of the 
practices proposed in the NOPR.\34\
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    \30\ IECA 2017 Comments at 2.
    \31\ Invenergy 2017 Comments at 1.
    \32\ NEPOOL 2017 Comments at 5.
    \33\ Joint Renewable Parties 2017 Comments at 1-2.
    \34\ CAISO 2017 Comments at 37.
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    28. Other parties express some support for the NOPR proposals but 
object to specific reforms. For example, the Non-Public Utility Trade 
Associations ``believe that certain of the NOPR's proposed changes . . 
. hold the potential for improving transparency and process in a manner 
that may enhance cost certainty and predictability.'' \35\ They object, 
however, to any changes that would impose cost caps for network 
upgrades and certain of the NOPR's proposed reforms.\36\ Additionally, 
California Energy Storage Alliance commends CAISO for the reforms 
already implemented in that region and suggests that other RTOs/ISOs 
should adopt these reforms.\37\ However, California Energy Storage 
Alliance also suggests that each RTO/ISO should decide upon the 
proposed solutions for themselves rather than through the establishment 
of new national policy.\38\
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    \35\ Non-Profit Utility Trade Associations 2017 Comments at 4.
    \36\ Non-Profit Utility Trade Associations 2017 Comments at 4. 
These include the proposal for transparency regarding study models 
and assumptions, the proposal to allow interconnection customers to 
request interconnection service below generating facility capacity, 
and the proposal regarding the utilization of surplus 
interconnection service.
    \37\ California Energy Storage Alliance 2017 Comments at 1-2.
    \38\ Id. at 13.
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    29. Other parties oppose some or all aspects of the NOPR. EEI 
argues that improving certainty is a responsibility shared by 
interconnection customers and transmission providers.\39\ It states 
that the volume of interconnection requests and the inherently 
speculative nature of generation development lead to queue delays, 
suspensions, and withdrawals.\40\ Imperial states that the NOPR could 
alter transmission owners' rights and raises concerns regarding the 
feasibility of processing interconnection requests.\41\ ISO-NE states 
that several of the proposed reforms may be overly prescriptive and may 
have unintended negative consequences.\42\ Southern argues that the 
NOPR fails to address problems or delays caused or exacerbated by 
interconnection customers.\43\
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    \39\ EEI 2017 Comments at 9. AEP and Duke support the comments 
being filed by EEI in this proceeding. AEP 2017 Comments at 1; Duke 
2017 Comments at 2.
    \40\ EEI 2017 Comments at 9.
    \41\ Imperial 2017 Comments at 1.
    \42\ ISO-NE 2017 Comments at 2.
    \43\ Southern 2017 Comments at 4-5.
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    30. A number of parties object to proposals that they contend could 
compromise system reliability or shift risk and costs to transmission 
providers for factors beyond the transmission providers' control.\44\ 
EEI requests that the Commission not deviate from its longstanding 
policy ``that risks and costs associated with an interconnection 
request be borne by the interconnection customer.'' \45\ Similarly, 
Salt River states that the NOPR could undermine the Commission's non-
discrimination policy as well as the cost causation principle.\46\ 
Southern asks the Commission to reconsider those proposals that ``lack 
balance and would shift risks and add bureaucratic responsibilities 
to'' transmission providers.\47\
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    \44\ Non-Profit Utility Trade Associations 2017 Comments at 3; 
EEI 2017 Comments at 9-10; Salt River 2017 Comments at 1-2; Southern 
2017 Comments at 4; Xcel 2017 Comments at 3-4; APS 2017 Comments at 
5.
    \45\ EEI 2017 Comments at 9.
    \46\ Salt River 2017 Comments at 1-2.
    \47\ Southern 2017 Comments at 4.
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    31. APS states that it reviewed the NOPR against its current LGIP 
and LGIA and identified various revisions, in addition to those 
proposed in the NOPR, that would need to be made to comply with the 
proposals in the NOPR.\48\ APS suggests that the Commission re-evaluate 
its revisions and additions to ensure that there are not potentially 
conflicting or otherwise limiting provisions elsewhere in the pro forma 
LGIP and pro forma LGIA.\49\
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    \48\ APS 2017 Comments at 5-6.
    \49\ Id. at 7.
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    32. Duke, ISO-NE, and Southern support the NOPR to the extent that 
it allows procedures to vary according to differing regional needs.\50\ 
Similarly, MISO TOs state that each RTO/ISO's LGIP or LGIA is not 
simply a set of procedures tied to a pro forma agreement that is 
amenable to generic modifications but is instead a complex series of 
arrangements, accepted by the Commission, developed in consultation 
with stakeholders, and designed to meet the RTO/ISO's particular needs 
and circumstances.\51\
---------------------------------------------------------------------------

    \50\ Duke 2017 Comments at 29; ISO-NE 2017 Comments at 3; 
Southern 2017 Comments at 3.
    \51\ MISO TOs 2017 Comments at 4.
---------------------------------------------------------------------------

    33. NEPOOL states that a final action should allow for significant 
regional flexibility, especially for regions such as ISO-NE that have 
continued to improve their interconnection processes and incorporated 
region-specific features into interconnection rules, such as ISO-NE's 
Forward Capacity Market (FCM) and Elective Transmission Upgrade 
provisions. NEPOOL notes that, especially where interconnection 
provisions intersect with the FCM qualification process, the Commission 
should allow maximum flexibility to deviate from pro forma rules to 
avoid unintended disruptions to market participants. NEPOOL states 
that, to the extent that the proposals would disrupt the integrated 
interconnection and FCM process in New England, they would not support 
the adoption of the NOPR in New England.\52\ Similarly, because of the 
unique interconnection issues in each region and significant regional 
variations, NYISO asks the Commission to allow parties to tailor 
appropriate tariff revisions and demonstrate how they are addressing, 
or plan to address, the Commission's concerns in a manner consistent 
with or superior to the NOPR's proposed revisions.\53\
---------------------------------------------------------------------------

    \52\ NEPOOL 2017 Comments at 6.
    \53\ NYISO 2017 Comments at 1.
---------------------------------------------------------------------------

    34. Southern recommends that the Commission issue a revised notice 
of proposed rulemaking to allow for another round of notice and 
comment.\54\ EEI asks the Commission to convene technical conferences 
to seek feedback on the portions of the LGIA and LGIP that require 
review and revision to ensure consistency, completeness, and 
applicability.\55\
---------------------------------------------------------------------------

    \54\ Southern 2017 Comments a 6.
    \55\ EEI 2017 Comments at 76.
---------------------------------------------------------------------------

    35. Duke states that, to fulfill their obligations to ensure 
reliability service, ``transmission providers must be afforded the time 
needed to: (i) Carefully evaluate the potential reliability impact on 
[their] system[s] of

[[Page 21347]]

proposed interconnections; and (ii) provide generators with reasonable 
estimates within the time needed to effectuate interconnection and 
necessary supporting upgrades.'' \56\
---------------------------------------------------------------------------

    \56\ Duke 2017 Comments at 3.
---------------------------------------------------------------------------

B. Commission Determination

    36. After consideration of the NOPR comments, we conclude that 
certain revisions to interconnection processes are necessary and that 
the record supports the need for reform. Therefore, with the exception 
of the withdrawal of some reforms proposed in the NOPR and the 
modification of others, which are discussed in further detail below, we 
adopt the majority of the proposed revisions to the pro forma LGIP and 
the pro forma LGIA.\57\
---------------------------------------------------------------------------

    \57\ The final action revises the pro forma LGIP and pro forma 
LGIA in accordance with Sec.  35.28(f)(1) of the Commission's 
regulations, which provides that every public utility that is 
required to have on file a non-discriminatory open access 
transmission tariff under the section must amend such tariff by 
adding the standard interconnection procedures and agreement and the 
standard small generator interconnection procedures and agreement 
required by Commission rulemaking proceedings promulgating and 
amending such interconnection procedures and agreements, or such 
other interconnection procedures and agreements as may be required 
by Commission rulemaking proceedings promulgating and amending the 
standard interconnection procedures and agreement and the standard 
small generator interconnection procedures and agreement. 18 CFR 
35.28(f)(1) (2017). See Reactive Power Requirements for Non-
Synchronous Generation, Order No. 827, FERC Stats. & Regs. ] 31,385 
(cross-referenced at 155 FERC ] 61,277), order on clarification and 
reh'g, 157 FERC ] 61,003 (2016) (Order No. 827).
---------------------------------------------------------------------------

    37. Based on our analysis of the record, we adopt the NOPR's 
preliminary findings.\58\ We find that the record in this proceeding 
provides support for our findings that, without the reforms adopted 
here, the current interconnection process may hinder timely development 
of new generation,\59\ stifle competition,\60\ result in uncertainty 
\61\ and inaccurate information,\62\ or potentially unduly discriminate 
against new technologies.\63\ Further, we find that, absent the reforms 
adopted in this final action, the existing defects and inefficiencies 
in generator interconnection processes that we have described could 
become exacerbated, resulting in longer delays in generation 
development, higher costs to customers, more uncertainty in the 
process, and less competition in the market. For these reasons, we 
conclude that these reforms are necessary to ensure that rates, terms, 
and conditions of service are just and reasonable and are not unduly 
discriminatory or preferential.
---------------------------------------------------------------------------

    \58\ See supra P 26.
    \59\ See, e.g., Invenergy 2017 Comments at 1 (stating that 
``many of the Commission's proposed reforms. . . . are small steps 
in the right direction toward reducing the current chronic queue 
delays); FTC 2017 Comments at 2 (stating that it supports the 
Commission's proposals ``to facilitate generation interconnections 
to the grid).
    \60\ See, e.g., FTC 2017 Comments at 2, 5 (stating that the NOPR 
``is a logical next step in [a] procompetitive process'' and citing 
existing concerns about ``anticompetitive behavior'' in the 
interconnection process);
    \61\ See, e.g., AFPA 2017 Comments at 6 (stating that the option 
to build proposal ``should increase cost certainty'').
    \62\ See, e.g., id. at 4 (stating that the provisional 
interconnection service, utilization of surplus interconnection 
service, and material modification reforms ``have the potential to . 
. . improve the accuracy and reliability of interconnection 
studies'').
    \63\ See, e.g. AWEA 2017 Comments at 4 (stating that ``the 
current process . . . creates the potential for discriminatory 
interconnection processes as new technologies enter the generation 
sphere''); Public Interest Organizations 2017 Comments at 17 
(stating that they agree that ``[i]nterconnection customers 
involving `new technologies may be affected more by process and 
information uncertainty than incumbents' '').
---------------------------------------------------------------------------

    38. We disagree with commenters that take issue with the proposals 
to impose new requirements and responsibilities on transmission 
providers. For example, although EEI is correct that interconnection 
customers and transmission providers share responsibility to improve 
certainty and that generator interconnection, by its nature, involves 
some uncertainty, we find that current interconnection processes and 
agreements can create unnecessary levels of uncertainty as discussed in 
more detail below.
    39. Additionally, in response to Imperial's concerns that the NOPR 
could alter transmission owners' rights, we note that, although the 
final action creates new obligations and responsibilities for 
transmission providers and transmission owners, these changes are 
likely to improve the generator interconnection process for all 
involved parties. Also, we emphasize that the final action does not 
relieve interconnection customers of their existing responsibilities. 
Nor does it alter the ownership structure established in Order No. 2003 
for interconnection facilities or network upgrades. Although some 
commenters argue that the NOPR's proposed reforms do not increase the 
responsibilities of, or directly address delays created by, 
interconnection customers, we believe that the reforms adopted in this 
final action should help improve the efficiency of processing 
interconnection requests for both transmission providers and 
interconnection customers.
    40. We also disagree with arguments that the NOPR will compromise 
system reliability. We find that, for those reforms for which 
commenters have expressed reliability concerns, the Commission has 
either maintained existing safeguards or provided transmission 
providers with sufficient discretion to ensure that the reforms will 
not interfere with system reliability. For example, as discussed more 
fully below, the option to build, as modified by this final action, 
does not relax any of the safeguards that the Commission first 
established in Order No. 2003. Additionally with regard to the reforms 
that allow interconnection customers to request interconnection service 
below generating facility capacity and to utilize surplus 
interconnection service, transmission providers have the ability to 
require control technologies or to establish conditions necessary for 
interconnection customers to exercise these options without 
compromising reliability.
    41. In response to comments by EEI and Salt River, among others, 
that the NOPR will shift costs traditionally borne by the 
interconnection customer, we note that this final action makes no 
changes with regard to interconnection customers' cost responsibilities 
for network upgrades and that the Commission is taking no further 
action on the issue of cost caps. Additionally, in response to 
Southern's concerns that the NOPR proposals lack balance, it is our 
belief that improved generator interconnection processes will benefit 
both transmission providers and interconnection customers.
    42. Although APS argues that the NOPR necessitates additional pro 
forma LGIP and pro forma LGIA revisions, it neglects to further 
describe or explain the particulars of such revisions. The revisions to 
the pro forma LGIP and the pro forma LGIA adopted here are intended to 
effectuate the reforms discussed in this final action and to integrate 
the adopted reforms so that they do not unintentionally conflict with 
other portions of the pro forma LGIP and the pro forma LGIA. 
Nonetheless, to the extent that a particular transmission provider 
believes that additional revisions to its LGIP or LGIA are necessary, 
it may propose such revisions in a filing pursuant to section 205 of 
the FPA.
    43. Finally, we note that a number of commenters seek regional 
flexibility in complying with the rule to accommodate regional needs. 
In Order No. 2003, the Commission stated that if, on compliance, a non-
RTO/ISO transmission provider ``offers a variation from the Final Rule 
LGIP and Final Rule LGIA and the variation is in response to 
established . . . reliability requirements, then it may seek to justify 
its variation using the regional

[[Page 21348]]

difference rationale.'' \64\ However, if a non-RTO/ISO seeks a 
variation ``for any other reason,'' it must present its justification 
for the variation as ``consistent with or superior to'' the pro forma 
LGIA or pro forma LGIP.\65\ The Commission went on to say that, for 
RTOs/ISOs, it would allow independent entity variations for pricing and 
non-pricing provisions, and that RTOs/ISOs ``shall have greater 
flexibility to customize [their] interconnection procedures and 
agreements to fit regional needs.'' \66\ In this final action, we make 
no changes to the variations allowed by Order No. 2003. Therefore, on 
compliance, transmission providers may argue that they qualify for the 
above-mentioned variations from the requirements of this final action.
---------------------------------------------------------------------------

    \64\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 826.
    \65\ Id.
    \66\ Id.
---------------------------------------------------------------------------

    44. We decline to adopt Southern's recommendation that we issue a 
revised notice of proposed rulemaking, as well as EEI's proposal to 
convene general generator interconnection technical conferences, apart 
from the technical conference concerning affected systems discussed 
further below. We note that the process used in this proceeding has 
included a number of opportunities to narrow the issues for discussion 
and to provide comments. As stated, the Commission noticed AWEA's 
original 2015 petition for comment, held a technical conference in May 
2016, and issued subsequent questions for which it requested comment, 
and sought comments on the NOPR. Therefore, we do not think additional 
steps are necessary in this proceeding at this time. In response to 
Duke's requests that transmission providers need to have adequate time 
to evaluate reliability impacts and to provide generators ``with 
reasonable estimates within the time needed to effectuate 
interconnection and necessary supporting upgrades,'' we point out that 
this final action neither changes the deadlines for interconnection 
studies nor eliminates the reasonable efforts standard or the deadlines 
for construction of facilities necessary to interconnect a particular 
large generating facility.\67\
---------------------------------------------------------------------------

    \67\ Duke 2017 Comments at 3.
---------------------------------------------------------------------------

IV. Proposed Reforms

A. Improving Certainty for Interconnection Customers

    45. The Commission proposed reforms intended to improve certainty 
by providing interconnection customers more predictability in the 
interconnection process, including more predictability regarding the 
costs and the timing of interconnecting to the transmission system. In 
addition to the proposed reforms, the Commission sought comment on the 
extent to which capping interconnection customer cost responsibility 
for actual network upgrade costs to some margin above estimated network 
upgrade costs could mitigate the potential for serial restudies without 
inappropriately shifting cost responsibility.
1. Scheduled Periodic Restudies
a. NOPR Proposal
    46. The Commission proposed to revise the pro forma LGIP to require 
transmission providers that conduct cluster studies \68\ to conduct 
restudies on a scheduled, periodic basis (e.g., annually, semi-
annually, quarterly, or a set number of days after the completion of 
the cluster study).\69\ Specifically, the Commission proposed to 
require each transmission provider that conducts cluster studies to 
revise Sections 6.4, 7.6, and 8.5 of the pro forma LGIP with time 
frames for periodic restudies.\70\ The Commission also sought comment 
on: (1) If the Commission's proposal were adopted, whether transmission 
providers that conduct cluster studies should be allowed to retain some 
discretion to conduct a restudy outside of the established schedule at 
the request of interconnection customers or under specific 
circumstances that make such schedule deviations necessary; and (2) 
when this discretion should be restricted and the circumstances under 
which such schedule deviations should be allowed.\71\ The Commission 
also sought comment on whether there are improvements to the pro forma 
LGIP necessary to clarify events that would trigger a restudy (restudy 
triggers).\72\
---------------------------------------------------------------------------

    \68\ Clustering allows transmission providers to simultaneously 
study all interconnection requests received during a specified 
period. See Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 149-
156.
    \69\ NOPR, FERC Stats. & Regs. ] 32,719 at P 46.
    \70\ Id. PP 48-49.
    \71\ Id. P 50.
    \72\ Id. P 51.
---------------------------------------------------------------------------

b. Comments
    47. Several commenters argue that, although restudies are often 
necessary, repeated restudies conducted at irregular intervals create 
cost and timing uncertainty for interconnection customers, impose 
delays on the process, and put development of new generation at risk, 
despite reductions in some RTOs/ISOs' interconnection requests and the 
use of cluster studies.\73\ Some of these commenters assert that, 
because the withdrawal of higher-queued interconnection requests can 
create cascading restudies of lower-queued interconnection requests, 
regularly scheduled restudies would help alleviate the need for 
multiple ad hoc restudies, thereby helping to reduce uncertainty and 
delays.\74\
---------------------------------------------------------------------------

    \73\ AFPA 2017 Comments at 5; AVANGRID 2017 Comments at 5-6; 
AWEA 2017 Comments at 8-9; Generation Developers 2017 Comments at 6; 
NextEra 2017 Comments at 6; IECA 2017 Comments at 2.
    \74\ AFPA 2017 Comments at 5; AVANGRID 2017 Comments at 5-6; 
AWEA 2017 Comments at 8-9; Generation Developers 2017 Comments at 6; 
NextEra 2017 Comments at 6.
---------------------------------------------------------------------------

    48. Some commenters note that the unpredictable start and stop of 
the generation interconnection study process has caused project 
cancellations because delays in obtaining an LGIA or small generator 
interconnection agreement (SGIA) can affect project financing.\75\ 
NextEra explains that, in some cases, restudies have taken years to 
complete due to projects withdrawing from the queue, transmission 
project changes, inadequate transmission provider resources, and other 
factors.\76\ NextEra further notes that transmission providers then 
have to restart the study with the remaining members of the 
interconnection customer study group. NextEra contends that this 
occurrence can delay the interconnection customer's receipt of its 
study results and finalized GIA, which could prevent it from accurately 
evaluating the timing and costs of necessary network upgrades.\77\ 
NextEra suggests that a regularly scheduled restudy process will allow 
transmission providers to consider relevant changes on a set timetable 
and reduce the need for ad hoc restudies. NextEra also argues that, by 
ensuring that studies are completed, an interconnection customer will 
receive some network upgrade information that it would not receive if 
studies are restarted or delayed.\78\
---------------------------------------------------------------------------

    \75\ Generation Developers 2017 Comments at 6; NextEra 2017 
Comments at 6.
    \76\ NextEra 2017 Comments at 6.
    \77\ Id.
    \78\ Id. at 6-7.
---------------------------------------------------------------------------

    49. AWEA states that requiring transmission providers to identify 
the frequency of restudies of a cluster study and post the dates of 
these scheduled restudies on OASIS will increase certainty and give 
transmission providers flexibility.\79\ NextEra suggests that periodic 
restudies should be conducted every six months, noting that, with that 
frequency, there should be little need for intervening studies, and 
yearly studies would be frequent enough.\80\
---------------------------------------------------------------------------

    \79\ AWEA 2017 Comments at 9-10.
    \80\ NextEra 2017 Comments at 7.

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

[[Page 21349]]

    50. Xcel supports the Commission's proposal but requests that the 
Commission clarify that restudies will commence within a specified time 
period (e.g., ninety days) of a triggering event, instead of after the 
completion of the cluster study. Xcel suggests that explicitly defining 
triggering events is not necessary and notes that determination of 
triggering events tends to vary between regions.\81\
---------------------------------------------------------------------------

    \81\ Xcel 2017 Comments at 7.
---------------------------------------------------------------------------

    51. AVANGRID recommends that transmission providers provide cost 
estimates for the proposed scheduled periodic restudies for 
interconnection customers with interconnection requests included in a 
group or cluster, instead of providing interconnection customers 
estimates for the initial study only.\82\ AFPA supports regular cluster 
studies but believes that RTOs/ISOs should have the ability to avoid 
restudies and the associated costs where they can demonstrate no 
material change in relevant assumptions or inputs.\83\
---------------------------------------------------------------------------

    \82\ AVANGRID 2017 comments at 5-6.
    \83\ AFPA 2017 Comments at 3.
---------------------------------------------------------------------------

    52. APPA/LPPC states that a schedule detailing periodic restudies 
may provide added predictability that could be valuable to project 
developers.\84\ However, it argues that, where interconnection queues 
are short, there may be no need to await specified dates to perform 
restudies, and in those circumstances, a fixed schedule may hamper the 
interconnection process.\85\
---------------------------------------------------------------------------

    \84\ APPA/LPPC 2017 Comments at 5.
    \85\ Id.
---------------------------------------------------------------------------

    53. Duke states that it does not regularly conduct cluster studies, 
but it supports the proposal and the flexibility provided for 
transmission providers that do conduct cluster studies.\86\ Southern 
agrees with the Commission that transmission providers that do not 
conduct interconnection studies in clusters should not have to perform 
periodic restudies.\87\
---------------------------------------------------------------------------

    \86\ Duke 2017 Comments at 4.
    \87\ Southern 2017 Comments at 9.
---------------------------------------------------------------------------

    54. CAISO cautions that periodic restudies are effective in CAISO 
because it uses a cluster study approach with firm cost caps, and 
transmission owners finance network upgrade costs beyond these cost 
caps.\88\ CAISO asserts that only with both of these mechanisms is it 
reasonable for interconnection customers to wait for an annual restudy 
to find out how their projects may have been affected by project 
withdrawals over the course of the prior year.\89\ CAISO states that, 
with the transmission owners picking up any costs above the cost cap, 
withdrawals can decrease or increase interconnection customers' network 
upgrade costs depending upon whether the upgrade is still necessary for 
other interconnection customers.\90\ CAISO states that costs decrease 
when sufficient interconnection customers withdraw and obviate the need 
for a network upgrade. However, CAISO states that costs may increase if 
the network upgrade is still necessary but fewer interconnection 
customers remain to finance it.\91\
---------------------------------------------------------------------------

    \88\ CAISO 2017 Comments at 7.
    \89\ Id.
    \90\ Id. at 7-8.
    \91\ Id. at 8.
---------------------------------------------------------------------------

    55. CAISO asserts that imposing scheduled periodic restudies in 
other RTOs/ISOs that do not share CAISO's market features may be 
problematic.\92\ CAISO states that, as ISO-NE and others pointed out in 
response to the AWEA petition, an interconnection customer must wait 
for a periodic restudy to find out that its project costs have 
increased dramatically.\93\
---------------------------------------------------------------------------

    \92\ Id.
    \93\ Id.
---------------------------------------------------------------------------

    56. CAISO cautions that the Commission should consider the various 
proposed reforms in concert with each other, including changes to 
schedules in periodic studies, because cost caps and the definition of 
contingent facilities also have a significant impact on the efficacy of 
periodic restudies.\94\
---------------------------------------------------------------------------

    \94\ Id.
---------------------------------------------------------------------------

    57. SoCal Edison and PG&E state that scheduled periodic annual 
restudies are the standard practice for CAISO and that they appreciate 
the predictability of CAISO's restudy process.\95\
---------------------------------------------------------------------------

    \95\ PG&E 2017 Comments at 3 (citing CAISO, eTariff, FERC 
Electric Tariff, OATT, app. DD Section 7.4 (6.0.0)).
---------------------------------------------------------------------------

    58. Generation Developers support the Commission's proposal, but 
they assert that semi-annual or quarterly restudies could be 
problematic and unpredictable, especially if the RTO/ISO has missed the 
study completion deadline listed in its tariff.\96\ Similarly, EDP 
indicates that, although each transmission provider should be able to 
establish its own unique schedule, a pro forma restudy schedule should 
be developed that serves as the default schedule unless a transmission 
provider demonstrates the need for an alternative schedule.\97\
---------------------------------------------------------------------------

    \96\ Generation Developers 2017 Comments at 6-7.
    \97\ EDP 2017 Comments at 3.
---------------------------------------------------------------------------

    59. Invenergy states that restudies can be useful but should not 
add unnecessary time and expense, citing the substantial time 
differences for restudies within several RTOs/ISOs.\98\ According to 
Invenergy, an important missing element in the restudy process is 
transparency for the interconnection customer. Invenergy suggests a 
requirement that RTOs/ISOs inform the customer of the restudy prior to 
its initiation. Invenergy suggests that the transmission provider 
should provide information in sufficient detail so that the customer 
can understand the need for restudy, including whether there is an 
addition or change to the necessary network upgrades.\99\
---------------------------------------------------------------------------

    \98\ Invenergy 2017 Comments at 5.
    \99\ Id.
---------------------------------------------------------------------------

    60. Several commenters oppose the Commission's proposed revisions 
to require transmission providers that conduct cluster studies to 
conduct restudies on a scheduled, periodic basis. As discussed further 
below, commenters state that the Commission's proposal may cause 
unnecessary delays, may not be appropriate in each region, and may 
unduly burden smaller transmission providers.
    61. PJM contends that the NOPR may have the opposite effect from 
what is intended by causing unnecessary delays.\100\ PJM argues that, 
in a situation where a project withdraws during the system impact 
study, or prior to the completion of the facilities study, and restudy 
is necessary, the NOPR proposal would harm all subsequently queued 
projects. PJM explains that these projects would remain in a ``holding 
pattern'' until the scheduled, periodic restudy is complete.\101\ PJM 
states that improvements in transparency can achieve the intended goals 
of the NOPR proposal without the drawbacks.\102\
---------------------------------------------------------------------------

    \100\ PJM 2017 Comments at 5.
    \101\ Id. at 4-5.
    \102\ Id. at 5.
---------------------------------------------------------------------------

    62. PJM explains that although it performs cluster studies at the 
feasibility and system impact study stages, it does not conduct 
restudies at the feasibility study stage because of the broad scope of 
the feasibility study and because the system impact study can account 
for withdrawals.\103\ However, PJM states that it does not oppose 
conducting periodic restudies within a cluster after the issuance of a 
system impact study report and receipt of an executed facilities study 
agreement from the projects that need to be restudied.\104\ PJM states 
that it could commit to post such restudy dates on its website.\105\
---------------------------------------------------------------------------

    \103\ Id. at 3-4.
    \104\ Id. at 4.
    \105\ Id.
---------------------------------------------------------------------------

    63. PJM asserts that the pro forma LGIP appropriately requires 
restudied interconnection customers to bear the cost of restudy.\106\ 
PJM also states that, at the facilities study stage, interconnection 
customers should bear all costs, including any impacts caused

[[Page 21350]]

to lower-queued projects by changes made to a higher-queued 
project.\107\
---------------------------------------------------------------------------

    \106\ Id. at 6 (citing pro forma LGIP Sections 6.4, 7.6, and 
8.5).
    \107\ Id.
---------------------------------------------------------------------------

    64. PJM opposes the NOPR's 45/60 day restudy timeframe because 
restudies ``come in all sizes and complexities.'' \108\ PJM states that 
committing to a strict timeframe would then necessitate granting the 
transmission provider the flexibility to extend the timeframe beyond 
the study period found in the tariff, regardless of whether a 
transmission provider is serially processing a restudy or restudying a 
cluster.\109\ PJM maintains that reporting and sharing of status 
information with the affected parties is more effective than inflexible 
restudy deadlines.\110\
---------------------------------------------------------------------------

    \108\ Id. at 5.
    \109\ Id.
    \110\ Id. at 5-6.
---------------------------------------------------------------------------

    65. NYISO and Indicated NYTOs state that NYISO does not perform 
restudies in its Standard Large Facility Interconnection Procedures to 
modify the upgrades required for projects or their cost estimates based 
on changes to higher-queued projects or system conditions.\111\
---------------------------------------------------------------------------

    \111\ NYISO 2017 Comments at 13; Indicated NYTOs 2017 Comments 
at 4-5.
---------------------------------------------------------------------------

    66. ISO-NE and NEPOOL state that the Commission should not adopt 
the NOPR proposal because it may not be appropriate in each 
region.\112\ As an example, ISO-NE states that the recent revisions to 
its interconnection procedures incorporate a clustering approach that 
does not include scheduled restudies.\113\ ISO-NE argues that a 
scheduled restudy would result in less certainty for interconnection 
customers because it would delay the study outcome. On the other hand, 
ISO-NE states that its clustering approach would still meet the 
objectives of the NOPR by establishing milestones that can serve as 
decision points for interconnection customers.\114\
---------------------------------------------------------------------------

    \112\ ISO-NE 2017 Comments at 15-16.
    \113\ Id. at 16.
    \114\ Id. at 16-17.
---------------------------------------------------------------------------

    67. Specifically, ISO-NE states that its proposed two-phased 
cluster study structure is designed to provide interconnection 
customers with information regarding the likely outcome of the cluster 
study in the first phase. ISO-NE states that interconnection customers 
could then determine whether they would like to proceed to the second-
phase, move to the end of the interconnection queue, or withdraw from 
the interconnection queue.\115\ ISO-NE states that its cluster study 
approach minimizes the need for restudy through provisions that allow 
for the participation of lower-queued requests in the event of 
withdrawals.\116\
---------------------------------------------------------------------------

    \115\ Id.
    \116\ Id. at 17.
---------------------------------------------------------------------------

    68. MISO, MISO TOs, ITC, and MidAmerican state that MISO's 2016 
queue reform proposal addressed unstructured and repeated restudies. 
MISO asserts that, consistent with the independent entity variation 
standard, its revised procedures are now in effect and should be 
implemented.\117\ MISO states that the Commission should not deviate 
from its current requirement that allows transmission providers to use 
reasonable efforts. It also contends that the Commission should not 
impose inflexible timeframes on restudies, and asserts that a one-size-
fits-all approach would not be appropriate here. MISO notes that in 
RTOs/ISOs, the interconnection process involves many parties, and 
imposing inflexible restudy deadlines would be counter-productive, 
particularly where delays are caused by third parties or by factors 
outside of the RTO/ISO's control.\118\ ITC urges the Commission to 
accept MISO's Definitive Planning Phase \119\ process, which addresses 
restudies, as consistent with or superior to the revisions made to the 
pro forma LGIP in this proceeding.\120\
---------------------------------------------------------------------------

    \117\ MISO 2017 Comments at 12-13.
    \118\ Id. at 13-14.
    \119\ Under MISO's Definitive Planning Phase process, MISO 
performs three sequential system impact studies after successive 
milestone payments to account for queue withdrawals.
    \120\ ITC 2017 Comments at 6.
---------------------------------------------------------------------------

    69. Imperial states that the Commission's proposal to require 
scheduled, periodic restudies for cluster studies would unduly burden 
smaller transmission providers.\121\ Imperial states that transmission 
providers may not be willing to memorialize an aggressive restudy 
commitment if they expect to experience variations in the number of 
interconnection requests that would be appropriate for cluster studies 
or restudies over a period of time.\122\ Additionally, for smaller 
transmission providers that conduct few restudies, such a proposal may 
be less efficient than studying each project individually as the need 
to restudy arises.\123\ Therefore, Imperial requests that the 
Commission allow transmission providers, particularly smaller 
transmission providers, the discretion to conduct periodic cluster 
restudies within their selected timeframes.\124\
---------------------------------------------------------------------------

    \121\ Imperial 2017 Comments at 15.
    \122\ Id. at 16.
    \123\ Id.
    \124\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    70. We decline to adopt the proposal in the NOPR to require 
transmission providers that conduct cluster studies to conduct 
scheduled periodic restudies. We find that the record does not support 
a finding that cascading restudies are an issue that the final action 
should address by adopting the proposal on scheduled periodic 
restudies. We recognize that scheduled periodic restudies may provide 
timing certainty for interconnection queues that experience cascading 
restudies, but the record does not suggest that this is a significant 
problem in all or many regions' interconnection queues where cluster 
studies are used. We agree with the commenters' concern that requiring 
scheduled periodic restudies would unnecessarily constrain the restudy 
process for transmission providers that are not experiencing cascading 
restudies. As explained in the RTO/ISO comments on this issue, existing 
variations in interconnection processes suggest that a one-size-fits-
all approach is not appropriate at this time. For example, CAISO's firm 
cost caps allow customers to know in advance that network upgrade costs 
will not exceed the cost cap, even if a restudy occurs. In other RTOs/
ISOs, however, adopting CAISO's annual restudy approach would require 
interconnection customers to wait for a scheduled periodic restudy to 
learn of cost changes.
    71. We note that restudies are sometimes necessary due to a number 
of factors, including project withdrawals, modifications of higher-
queued projects subject to section 4.4 of the LGIP, and/or a change to 
a project's point of interconnection.\125\ We agree with the comments 
that, regardless of the restudy schedule, restudies that result from 
such actions by a higher-queued interconnection customer may not be 
foreseeable or preventable. Implementing a scheduled periodic restudy 
process may reduce timing uncertainty by creating decision points, but 
it would not eliminate the cost uncertainty created by the withdrawal 
or modification of a higher-queued project. In that case, restudy would 
be necessary to recalculate network upgrade cost distribution among the 
remaining customers, and restricting the timing of these restudies may 
cause, rather than prevent, unnecessary delays.
---------------------------------------------------------------------------

    \125\ Pro forma LGIP Sections 6.4, 7.6, and 8.5.
---------------------------------------------------------------------------

    72. Accordingly, we decline to adopt revisions to the pro forma 
LGIP that would require transmission providers that conduct cluster 
studies to establish a schedule for conducting periodic restudies. We 
also decline to adopt revisions to the pro forma LGIP to address the 
transmission provider's

[[Page 21351]]

discretion to conduct restudies outside of an established schedule, and 
decline to propose revisions to the restudy triggers in the pro forma 
LGIP.
2. The Interconnection Customer's Option To Build
a. NOPR Proposal
    73. In the NOPR, the Commission proposed modifications to the pro 
forma LGIA to allow interconnection customers to exercise the option to 
build regardless of whether the transmission provider can meet the 
interconnection customer's proposed dates.\126\
---------------------------------------------------------------------------

    \126\ NOPR, FERC Stats. & Regs. ] 32,719 at P 52.
---------------------------------------------------------------------------

    74. Generally, in the interconnection process, the transmission 
provider is responsible for the construction of all network upgrades 
and the transmission provider's interconnection facilities. Under 
article 5.1.3 of the current pro forma LGIA, however, the 
interconnection customer has the option to build the transmission 
provider's interconnection facilities \127\ and stand alone network 
upgrades,\128\ but only if the transmission provider notifies the 
interconnection customer that the transmission provider cannot complete 
construction of such facilities by the interconnection customer's 
proposed in-service date, initial synchronization date, or commercial 
operation date; this is termed the ``option to build.'' To expand the 
opportunity for interconnection customers to exercise the option to 
build to reduce costs or complete construction more quickly, the 
Commission proposed in the NOPR to allow the interconnection customer 
to exercise the option to build regardless of whether the transmission 
provider finds the interconnection customer's selected in-service date, 
initial synchronization date, and commercial operation date acceptable.
---------------------------------------------------------------------------

    \127\ According to the pro forma LGIA:
    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.
    Pro forma LGIA Art. 1.
    \128\ Stand alone network upgrades:
    Shall mean Network Upgrades that an Interconnection Customer may 
construct without affecting day-to-day operations of the 
Transmission System during their construction. 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.
    Id.
---------------------------------------------------------------------------

    75. Under the current pro forma LGIA, unless otherwise mutually 
agreed to by the parties, the interconnection customer selects the 
``In-Service Date, Initial Synchronization Date, and Commercial Date'' 
\129\ and ``either the Standard Option or Alternative Option.'' \130\ 
Under both of these options, the transmission provider is responsible 
for construction of the transmission provider's interconnection 
facilities and all network upgrades.
---------------------------------------------------------------------------

    \129\ The In-Service Date is ``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.'' Id. The Initial Synchronization Date is 
``the date upon which the Generating Facility is initially 
synchronized and upon which Trial Operation begins.'' Id. The 
Commercial Operation Date is ``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.'' Id.
    \130\ Pro forma LGIA Art. 5.1.
---------------------------------------------------------------------------

    76. Under the ``standard option,'' the transmission provider 
``shall construct the Transmission Provider's Interconnection 
Facilities and Network Upgrades using Reasonable Efforts to complete 
the construction by the dates designated by the Interconnection 
Customer.'' \131\ Under the ``alternate option,'' the transmission 
provider may be liable for liquidated damages if it does not construct 
the transmission provider's interconnection facilities and ``Network 
Upgrades according to the construction completion dates established by 
the Interconnection Customer.'' \132\
---------------------------------------------------------------------------

    \131\ Pro forma LGIA Art. 5.1.1.
    \132\ The transmission provider has the ability to decline this 
option within 30 days of the LGIA's execution.
---------------------------------------------------------------------------

    77. Under the current pro forma LGIA, there are two additional 
options for assuming responsibility for constructing certain 
facilities, which are available if the transmission provider informs 
the interconnection customer that it cannot meet proposed construction 
completion dates: The option to build, described above, and the 
``negotiated option.'' \133\ The negotiated option, described in 
article 5.1.4 of the pro forma LGIA, applies if the transmission 
provider cannot meet the interconnection customer's proposed dates but 
the interconnection customer does not want to assume responsibility for 
construction of the transmission provider's interconnection facilities 
and stand alone network upgrades. In this case, the transmission 
provider would construct the transmission provider's interconnection 
facilities and all network upgrades.
---------------------------------------------------------------------------

    \133\ Pro forma LGIA Art. 5.1.4.
---------------------------------------------------------------------------

    78. In the NOPR, the Commission proposed modifications to articles 
5.1, 5.1.3, and 5.1.4 of the pro forma LGIA to allow interconnection 
customers to exercise the option to build with respect to the 
transmission provider's interconnection facilities and stand alone 
network upgrades regardless of whether the transmission provider can 
meet the interconnection customer's proposed dates. Specifically, the 
Commission proposed to modify the language in article 5.1 of the pro 
forma LGIA as follows (with proposed deletions in brackets and proposed 
additions in italics):
    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 [for completion of 
Transmission Provider's Interconnection Facilities and Network 
Upgrades, as set forth in Appendix A, Interconnection Facilities and 
Network Upgrades,] 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 the 
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.\134\
---------------------------------------------------------------------------

    \134\ In this final action, the adopted language differs 
slightly from the NOPR language because we remove the word ``the'' 
before ``Transmission Provider'' in the final sentence of this 
article.
---------------------------------------------------------------------------

    79. The Commission also proposed to modify the language in article 
5.1.3 of the pro forma LGIA as follows (with proposed deletions in 
brackets):

    Option to Build. [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 and unless the Parties agree otherwise,] 
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

[[Page 21352]]

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.

    80. The Commission stated that, given the changes proposed above, 
revisions to the negotiated option were necessary because the 
negotiated option references the current limitations on the option to 
build.\135\ For this reason, it proposed to revise the negotiated 
option to remove references to limitations on the option to build, to 
address scenarios in which an interconnection customer exercises the 
option to build and still wishes to negotiate completion times for 
network upgrades that are not stand alone network upgrades, and to 
address circumstances in which the interconnection customer does not 
wish to exercise the option to build. The Commission asserted that such 
revisions are necessary because the ability to exercise the option to 
build would no longer be contingent upon a transmission provider's 
inability to meet the interconnection customer's proposed dates. 
However, the Commission noted that the negotiated option must also 
contemplate the possibility that the transmission provider does not 
agree to the interconnection customer's proposed dates as to network 
upgrades that are not stand alone. That is, even if the interconnection 
customer elects to exercise the option to build, the transmission 
provider would still be responsible for the design, procurement, and 
construction of network upgrades that are not stand alone network 
upgrades.
---------------------------------------------------------------------------

    \135\ NOPR, FERC Stats. & Regs. ] 32,719 at P 62.
---------------------------------------------------------------------------

    81. Therefore, the Commission also proposed to modify the language 
in article 5.1.4 of the pro forma LGIA as follows (with proposed 
deletions in brackets and proposed additions in italics):

    Negotiated Option. [If Interconnection Customer elects not to 
exercise its option under Article 5.1.3, Option to Build, 
Interconnection Customer shall so notify Transmission Provider 
within thirty (30) Calendar Days, and] 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 [a portion of Transmission Provider's 
Interconnection Facilities and Stand Alone Network Upgrades by 
Interconnection Customer] 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) [pursuant to which Transmission 
Provider is responsible for the design, procurement and construction 
of Transmission Provider's Interconnection Facilities and Network 
Upgrades]. 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 [Transmission Provider's 
Interconnection Facilities and Network Upgrades] 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 [pursuant to article 5.1.1, Standard 
Option].

    82. Consistent with article 5.2 of the current pro forma LGIA, the 
interconnection customer and transmission provider (and transmission 
owner, if applicable) would continue to reach agreement on the design 
and construction of the transmission provider's interconnection 
facilities and stand alone network upgrades; the Commission proposed no 
changes to article 5.2 in the NOPR.
b. General
i. Comments
    83. Many commenters support this proposal.\136\ AWEA states that 
the current restriction on when the option to build can be exercised is 
unnecessary, unjust, and unreasonable because it restricts an 
interconnection customer's ability to build interconnection facilities 
and stand alone network upgrades cost-effectively.\137\ Several 
commenters contend that the proposal will reduce costs and improve 
construction timelines.\138\ NextEra states that, in late 2016, one of 
its subsidiaries in SPP exercised the option to build and completed 
construction of facilities for a cost of approximately $12 million, 
even though the relevant transmission owner asserted that it could not 
complete such facilities until late 2017 for an estimated cost of $18 
million. NextEra argues that if the Commission expanded interconnection 
customers' ability to exercise the option to build, there would be more 
instances where an interconnection customer constructs more efficiently 
than the transmission owner.\139\ AFPA asserts that the proposal will 
provide competitive and commercial discipline to utility cost 
estimates, construction timelines, and negotiating strategies.\140\ 
Competitive Suppliers and NEPOOL state that the proposal provides more 
flexibility to market participants and has the potential to increase 
efficiency.\141\ AFPA argues that the market for engineering and 
construction contractors is sufficiently robust that interconnection 
customers can often find cheaper and more efficient alternatives to 
utility construction.\142\ CAISO and PJM comment that they each 
currently allow this option to some degree.\143\ MISO and NYISO take no 
position on the proposal.\144\
---------------------------------------------------------------------------

    \136\ AFPA; AVANGRID; AWEA; Bonneville; CAISO; Joint Renewable 
Parties; Duke; Generation Developers; EDP; ELCON; Competitive 
Suppliers; FTC; IECA; NEPOOL; NextEra; PJM; Public Interest 
Organizations; SEIA; TDU Systems; TVA.
    \137\ AWEA 2017 Comments at 12-13.
    \138\ Id. at 13; EDP 2017 Comments at 3-4; ELCON 2017 Comments 
at 3; Public Interest Organizations 2017 Comments at 5-8; 
Competitive Suppliers 2017 Comments at 4.
    \139\ NextEra 2017 Comments at 9.
    \140\ AFPA 2017 Comments at 4.
    \141\ Competitive Suppliers 2017 Comments at 4; NEPOOL 2017 
Comments at 7.
    \142\ AFPA 2017 Comments at 6.
    \143\ CAISO 2017 Comments at 9; PJM 2017 Comments at 7 (citing 
PJM, Intra-PJM Tariffs, OATT, Attachment P, app. 2, Section 3.2.3 
(3.0.0)).
    \144\ MISO 2017 Comments at 15; NYISO 2017 Comments at 14.
---------------------------------------------------------------------------

    84. A number of commenters also oppose the proposal.\145\ EEI, and 
MISO TOs argue that there has been no demonstration that the options 
under the existing pro forma LGIA result in unjust and unreasonable 
rates, undue discrimination, or preferential treatment.\146\ Both 
Imperial and MISO TOs question whether exercising the option to build 
would result in significant decreases in cost or construction 
time.\147\ AEP, Xcel, and National Grid argue that only transmission 
owners have the required knowledge, processes, and access to suppliers 
and contractors to properly construct network upgrades.\148\ Several 
commenters state that the additional coordination needed between 
transmission owners and interconnection customers may undercut the 
interconnection customer's ability to achieve lower costs or quicker 
construction.\149\ AEP contends that the

[[Page 21353]]

Commission has ``appropriately recognized [that] the expansion of an 
existing station should be treated differently than a green field 
construction project, and this is precisely why the Commission should 
not broaden the Option-to-Build.'' \150\
---------------------------------------------------------------------------

    \145\ AEP; AES; APPA/LPPC; EEI; Eversource; Imperial; Indicated 
NYTOs; ITC; MidAmerican; MISO TOs; National Grid; PG&E 
NorthWestern; SoCal Edison; Southern; Xcel; Sunflower.
    \146\ EEI 2017 Comments at 17; MISO TOs 2017 Comments at 13.
    \147\ Imperial 2017 Comments at 17; MISO TOs 2017 Comments at 
13.
    \148\ AEP 2017 Comments at 6; Xcel 2017 Comments at 8-10; 
National Grid 2017 Comments at 6-7.
    \149\ Duke 2017 Comments at 6; TVA 2017 Comments at 4; ITC 2017 
Comments at 7; MidAmerican 2017 Comments at 9-10; NorthWestern 2017 
Comments at 3; Southern 2017 Comments at 10-11; Xcel 2017 Comments 
at 8-9.
    \150\ AEP 2017 Comments at 6.
---------------------------------------------------------------------------

ii. Commission Determination
    85. In this final action, we adopt the NOPR proposal to modify 
articles 5.1, 5.1.3, and 5.1.4 of the pro forma LGIA to allow 
interconnection customers to exercise the option to build with respect 
to the transmission provider's interconnection facilities and stand 
alone network upgrades regardless of whether the transmission provider 
can meet the interconnection customer's proposed dates. We conclude 
that this reform will benefit the interconnection process by providing 
interconnection customers more control and certainty during the design 
and construction phases of the interconnection process.\151\ Further, 
we find that limiting exercise of the option to build to circumstances 
where the transmission provider cannot meet the interconnection 
customer's requested dates is not just and reasonable. The limitation 
restricts an interconnection customer's ability to efficiently build 
the transmission provider's interconnection facilities and stand alone 
network upgrades in a cost-effective manner, which could result in 
higher costs for interconnection customers.
---------------------------------------------------------------------------

    \151\ NOPR, FERC Stats. & Regs. ] 32,719 at P 58.
---------------------------------------------------------------------------

    86. In response to EEI's and MISO TOs' contention that there has 
been no demonstration that the options under the existing pro forma 
LGIA result in unjust and unreasonable rates, undue discrimination, or 
preferential treatment, we find that in circumstances where an 
interconnection customer cannot exercise the option to build, it may 
pay more and/or wait longer for the construction of the transmission 
provider's interconnection facilities and stand alone network upgrades. 
With regard to Imperial and MISO TOs' skepticism regarding the 
potential cost and construction efficiencies gained by exercising the 
option to build, the record suggests that such savings can occur and 
have already occurred. For example, NextEra states that its subsidiary 
exercised the option to build in SPP in 2016 and was able to complete 
the project one year sooner and for $6 million less than estimated by 
the transmission provider. NextEra also notes that its subsidiary used 
approved subcontractors, built to the transmission owner's 
specifications, and purchased components from vendors approved by the 
transmission owner.\152\
---------------------------------------------------------------------------

    \152\ See, e.g., NextEra 2017 Comments at 9.
---------------------------------------------------------------------------

    87. Although AEP, Xcel, and National Grid question interconnection 
customers' abilities to properly construct stand alone network 
upgrades, we note that the NOPR proposal makes no changes to the 
transmission provider's right to approve the engineering design, the 
equipment tests, and the construction of its interconnection facilities 
and stand alone network upgrades. In response to AEP, we note that the 
final action does not change the type of facilities for which the 
option to build is available, and neither the final action nor the NOPR 
discuss the applicability of the option to build to an ``existing 
station'' versus a ``green field construction project.''
c. Reliability Concerns
i. Comments
    88. APPA/LPPC, MidAmerican, EEI, ITC, National Grid, and Southern 
contend that this proposal could compromise grid reliability.\153\ EEI, 
ITC, MidAmerican, National Grid, and Southern argue that the proposal 
favors granting interconnection customers the potential for quicker or 
less costly construction over potential degradation of safety and 
reliability.\154\ APPA/LPPC state that the existing option to build 
provision sufficiently balances the needs of interconnection customers 
with best utility practice and reliability concerns.\155\ They argue 
that the NOPR proposal, however, will ``alter dramatically'' the risk 
to long-term reliability of transmission providers' systems and that 
the safeguards in article 5.2 of the pro forma LGIA lack a grasp of the 
``short- and long-term reliability implications associated with 
construction, interconnection and operation of interconnection 
facilities and network upgrades.'' \156\
---------------------------------------------------------------------------

    \153\ APPA/LPPC 2017 Comments at 4; MidAmerican 2017 Comments at 
9-10; EEI 2017 Comments at 17; ITC 2017 Comments at 7; National Grid 
2017 Comments at 6-7; Southern 2017 Comments at 10.
    \154\ EEI 2017 Comments at 17; ITC 2017 Comments at 7; 
MidAmerican 2017 Comments at 9-10; National Grid 2017 Comments at 6-
7; Southern 2017 Comments at 10.
    \155\ APPA/LPPC 2017 Comments at 2.
    \156\ Id. at 3.
---------------------------------------------------------------------------

    89. Three commenters state that article 5.2 of the pro forma LGIA 
does not fully cover the ongoing system operations, planning, and 
reliability requirements that are inherent in interconnection and 
network upgrades.\157\ CAISO asserts that interconnection customers 
must follow the transmission owners' existing standards as well as meet 
grid engineering and reliability standards.\158\ EEI requests that the 
Commission ensure that any facilities constructed by the 
interconnection customer that are transferred to the transmission 
provider comply with any applicable North American Electric Reliability 
Corporation (NERC) reliability standards.\159\
---------------------------------------------------------------------------

    \157\ Id. at 4; MISO TOs 2017 Comments at 15; National Grid 2017 
Comments at 6-7.
    \158\ CAISO 2017 Comments at 10.
    \159\ EEI 2017 Comments at 20.
---------------------------------------------------------------------------

    90. Other commenters disagree and argue that the expanded option to 
build would not affect system reliability.\160\ NextEra, for example, 
states that there is little evidence that the NOPR proposal would 
compromise grid reliability, and any contrary arguments ignore the fact 
that this proposal only loosens the conditions for exercising this 
right with regard to the option to build.\161\ AWEA asserts that 
expanding the option to build should not increase reliability concerns 
because it does not change existing approval requirements.\162\
---------------------------------------------------------------------------

    \160\ AWEA 2017 Comments at 14; Generation Developers 2017 
Comments at 12; NextEra 2017 Comments at 10.
    \161\ Id.
    \162\ AWEA 2017 Comments at 14.
---------------------------------------------------------------------------

ii. Commission Determination
    91. Concerns that the option to build, as revised by the final 
action, will compromise system reliability are misplaced because they 
ignore the safeguards for reliability already in place for the existing 
option to build. We note that a number of commenters expressed similar 
concerns in the Order No. 2003 proceeding.\163\ There, in response to 
such concerns, the Commission established several safeguards.\164\ 
These safeguards, embodied in article 5.2 of the pro forma LGIA, 
require, among other things, that the interconnection customer exercise 
good utility practice and adhere to the standards and specifications 
provided in advance by the transmission providers. Further, these 
safeguards give the transmission provider the right to approve the 
engineering design, equipment acceptance tests, and the construction 
itself. In Order No. 2003-A, the Commission stated that vague 
reliability concerns about the option to build are misplaced, and that 
articles 5.2.1, 5.2.3, 5.2.5, and 5.2.6 of the pro

[[Page 21354]]

forma LGIA are sufficient to guarantee the reliability of the 
facilities in question.\165\ In this final action, we make no changes 
to the requirements in article 5.2. Furthermore, we note that because 
article 5.2 already gives the transmission provider a significant role 
with regard to the option to build and provides sufficient safeguards 
to ensure reliable operations, we see no reason why the expanded option 
to build should cause a new reliability concern.
---------------------------------------------------------------------------

    \163\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 341.
    \164\ Id. PP 356-357.
    \165\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 232.
---------------------------------------------------------------------------

    92. In response to EEI's and CAISO's concerns about whether any 
facilities constructed pursuant to the option to build comply with 
applicable NERC reliability standards, we note that article 5.2 already 
addresses this concern. For example, article 5.2(2) states that the 
interconnection customer ``shall comply with all requirements of law to 
which Transmission Provider would be subject.''
d. Liability and Cost Responsibility Concerns
i. Comments
    93. EEI, Xcel, and National Grid ask the Commission to ensure that 
interconnection customers indemnify the transmission owner or provider 
from any damages that result from facilities built pursuant to the 
option to build, including damages to adjacent facilities.\166\ Six 
commenters maintain that interconnection customers should assume all 
additional costs that may result from this proposal without cash, 
transmission credit, or congestion revenue right reimbursement.\167\ 
CAISO, NextEra, PG&E, and SoCal Edison also argue that the Commission 
should require that interconnection customers not receive such 
reimbursements to the extent that stand alone network upgrade costs 
exceed a specified cap.\168\
---------------------------------------------------------------------------

    \166\ EEI 2017 Comments at 23; Xcel 2017 Comments at 10; 
National Grid 2017 Comments at 8-11.
    \167\ CAISO 2017 Comments at 10; Bonneville 2017 Comments at 2-
3; EEI 2017 Comments at 23-24; MISO TOs 2017 Comments at 16; 
Southern 2017 Comments at 12; SoCal Edison 2017 Comments at 5.
    \168\ CAISO 2017 Comments at 10; NextEra 2017 Comments at 11; 
PG&E 2017 Comments at 4; SoCal Edison 2017 Comments at 5.
---------------------------------------------------------------------------

ii. Commission Determination
    94. In response to EEI's, Xcel's, and National Grid's comments, we 
note that article 5.2(7) of the pro forma LGIA requires the 
interconnection customer to ``indemnify the Transmission Provider for 
claims arising from Interconnection Customer's construction of 
Transmission Provider's Interconnection Facilities and Stand Alone 
Upgrades.'' We consider this provision sufficiently broad to address 
EEI's, Xcel's, and National Grid's concerns.\169\
---------------------------------------------------------------------------

    \169\ We note that the pro forma LGIA states that the term 
transmission provider ``should be read to include the Transmission 
Owner when the Transmission Owner is separate from the Transmission 
Provider.'' Pro forma LGIA Art.1 (Definitions).
---------------------------------------------------------------------------

    95. In response to arguments that interconnection customers should 
assume all additional costs that result from exercise of the option to 
build, we note that the final action makes no changes with regard to 
cost assignment for transmission provider's interconnection facilities 
and stand alone network upgrades. Additionally, apart from the 
modifications to articles 5.1, 5.1.3, and 5.1.4 of the pro forma LGIA 
to allow interconnection customers to exercise the option to build 
regardless of whether the transmission provider can meet the 
interconnection customer's proposed dates, this final action makes no 
changes to the option to build process. In response to CAISO, NextEra, 
PG&E, and SoCal Edison, we note that the issue of cost caps is 
currently unique to CAISO; therefore, issues regarding the interaction 
of the option to build and the CAISO network upgrade cost cap would be 
better addressed when CAISO submits its compliance filing to this final 
action.
e. Other
i. Comments
    96. AES claims that the proposal increases the transmission 
provider's risk regarding security compliance and project 
management.\170\ APPA/LPPC, MISO TOs, and National Grid express concern 
that transmission owners will have to expend significant resources to 
perform the oversight functions in article 5.2 of the pro forma 
LGIA.\171\
---------------------------------------------------------------------------

    \170\ AES 2017 Comments at 7.
    \171\ ITC 2017 Comments at 7; MISO TOs 2017 Comments at 14; AES 
2017 Comments at 7.
---------------------------------------------------------------------------

    97. Multiple commenters also identify barriers that will continue 
to exist under the current proposal. AWEA worries that requirements to 
adhere to jurisdictional transmission owner guidelines may remain a 
barrier to exercising the option to build under existing tariffs.\172\ 
APPA/LPPC note that interconnection customers may be constrained by 
state laws affecting the ability of non-utilities to exercise eminent 
domain to construct facilities and upgrades.\173\ CAISO states that 
later-queued projects may rely on network upgrades being built by 
interconnection customers and could be adversely affected if the 
customer withdraws from the queue or delays construction.\174\
---------------------------------------------------------------------------

    \172\ AWEA 2017 Comments at 15.
    \173\ APPA/LPPC 2017 Comments at 4.
    \174\ CAISO 2017 Comments at 9.
---------------------------------------------------------------------------

    98. Some commenters recommend that additional, specific options and 
regulatory language be added to the proposal. AVANGRID and AWEA 
recommend that the Commission ensure the expanded option to build would 
apply to identified transmission provider interconnection facilities 
and stand alone network upgrades identified through cluster 
studies.\175\ To ensure that transmission providers cannot refuse to 
build facilities and force interconnection customers to do so, EDP 
recommends that the Commission clarify that a transmission provider 
retains the obligation to build unless and until an interconnection 
customer exercises its option to build.\176\
---------------------------------------------------------------------------

    \175\ AVANGRID 2017 Comments at 14-15; AWEA 2017 Comments at 14.
    \176\ EDP 2017 Comments at 4.
---------------------------------------------------------------------------

    99. AVANGRID also recommends that the Commission provide two 
additional options for interconnection customers. Under the first, the 
transmission provider would construct, and the interconnection customer 
would pay the costs of, the transmission provider's interconnection 
facilities and stand alone network upgrades upfront, including an 
opportunity cost capped at 10 percent. Second, for all other network 
upgrades, the transmission provider, with the agreement of the 
interconnection customer, would construct and fund network upgrades, 
with charges to the interconnection customer made over time or the 
interconnection customer paying the costs up front, which would not 
include any margin.\177\ Bonneville recommends the option to build only 
be available if the customer can demonstrate it can build the 
facilities more cost-effectively than the transmission provider or 
improve the timeline for construction.\178\
---------------------------------------------------------------------------

    \177\ AVANGRID 2017 Comments at 14-15.
    \178\ Bonneville 2017 Comments at 2-3.
---------------------------------------------------------------------------

    100. Duke and EEI recommend that the Commission revise article 
9.7.1 of the LGIA to require that parties coordinate actions regarding 
stand alone network upgrades that may impact other parties' facilities 
during outages needed for maintenance, testing, or installation.\179\ 
Duke recommends revising article 11.5 of the pro forma LGIA (Provision 
of Security) to include stand alone network upgrades, as well as 
article 26.1 of the pro forma LGIA to clarify that the transmission 
provider is

[[Page 21355]]

not prevented from using subcontractors to perform its obligations 
under the LGIA. Duke also recommends adding language to require the 
transmission provider's approval of subcontractors.\180\ EEI requests 
that articles 5.1, 5.1.3, and 5.1.4 of the pro forma LGIA be revised to 
note that, if during the study process it is determined that upgrades 
and facilities need to be expedited, the option to build will be 
superseded.
---------------------------------------------------------------------------

    \179\ Duke 2017 Comments at 5; EEI 2017 Comments at 22.
    \180\ Duke 2017 Comments at 6.
---------------------------------------------------------------------------

    101. National Grid recommends that the Commission revise article 
5.2 of the pro forma LGIA to require: (1) Transmission owner's prior 
written approval of all contractors and any information requested to 
evaluate the creditworthiness and technical capabilities of proposed 
contractors; (2) prior written transmission owner approval of 
agreements between interconnection customers and contractors and 
provisions that allow transmission owners to directly enforce the 
agreement against the contractor; and (3) that the interconnection 
customer and transmission owner enter into a written transfer agreement 
regarding the transfer of ownership of facilities built by the 
interconnection customer.\181\ Similarly, Eversource suggests that the 
Commission grant blanket authorization for the transfer of these 
facilities.\182\
---------------------------------------------------------------------------

    \181\ National Grid 2017 Comments at 8-11.
    \182\ Eversource 2017 Comments at 17.
---------------------------------------------------------------------------

    102. TVA and EEI suggest that interconnection customers should meet 
standards similar to those required under Order No. 1000 for 
transmission construction qualification.\183\ Generation Developers, 
NextEra, and EEI support transmission owners maintaining a list of pre-
approved contractors.\184\ Some commenters suggest that the Commission 
require the transmission provider to post the standards and 
specifications used for the transmission provider's interconnection 
facilities and stand alone network upgrades on the transmission 
provider's website.\185\ Generation Developers state that there is a 
need for the transmission provider or interconnecting transmission 
owner to agree as to what constitutes a stand alone network 
upgrade.\186\ Generation Developers also request that transmission 
providers be required to provide written documentation and post on 
their website the reasons why they disagree that a facility is 
considered a stand alone network upgrade, in order to prevent undue 
discrimination.\187\ Eversource asks the Commission to require the 
interconnection customer to obtain transmission owner approval before 
ordering electrical material and equipment.\188\ Eversource and MISO 
recommend requiring that interconnection customers provide sufficient 
land rights for the transmission owners to access, operate, and 
maintain the transmission facilities and that the Commission terminate 
the interconnection customer's authority to construct during emergency 
situations.\189\
---------------------------------------------------------------------------

    \183\ TVA 2017 Comments at 4; EEI 2017 Comments at 18.
    \184\ Generation Developers 2017 Comments at 11; NextEra 2017 
Comments at 11; EEI 2017 Comments at 21.
    \185\ Generation Developers 2017 Comments at 11; EDP 2017 
Comments at 4; SEIA 2017 Comments at 14.
    \186\ Generation Developers 2017 Comments at 9-10.
    \187\ Id. at 10.
    \188\ Eversource 2017 Comments at 9-11.
    \189\ Id. at 1; MISO TOs 2017 Comments at 15-16.
---------------------------------------------------------------------------

ii. Commission Determination
    103. In response to AES's concern that the proposal increases 
transmission providers' risk regarding security compliance and project 
management, we again note that the final action does not relax the 
established safeguards in article 5.2 of the pro forma LGIA. In 
response to concerns raised by APPA/LPPC, MISO TOs, and National Grid 
that transmission owners will have to expend significant resources to 
perform oversight functions, we note that the final action does not 
alter the role that the transmission provider would play in overseeing 
the option to build process. However, it may result in more 
interconnection customers exercising the expanded option to build.
    104. In response to AWEA's and APPA/LPPC's assertions about 
jurisdictional barriers, states laws, and eminent domain, we note that 
the specific purpose of this proposal is only to eliminate the pro 
forma LGIP's existing limitation on the option to build. It is not to 
ensure that there are no jurisdictional or other legal barriers to 
construction by interconnection customers. Although more 
interconnection customers are likely to exercise the option to build as 
a result of the final action, there are still situations where an 
interconnection customer may not be able to do so due to jurisdictional 
or legal constraints. In those situations, we would not expect the 
interconnection customer to exercise its option to build if it could 
not do so effectively due to jurisdictional or legal constraints, such 
as limitations imposed by state law. Additionally, an interconnection 
customer might find that that there may be interconnection requests for 
which the option to build is unlikely to result in cost or time 
savings. Consequently, we believe that interconnection customers are in 
the best position to determine whether they will realize any cost or 
time savings from exercising the option to build for a particular 
interconnection request. Finally, the fact that this reform will not 
necessarily be useful to all interconnection requests does not mean 
that this reform will not afford an opportunity to some interconnection 
customers.
    105. In response to CAISO's comment that later-queued projects may 
be adversely affected if a higher-queued customer withdraws from the 
queue or delays construction, we see no reason to believe that an 
interconnection customer that exercises the option to build is more 
likely to adversely affect a later-queued project than would a delay 
caused by a transmission provider. In fact, it is our expectation that 
customers that exercise the option to build are likely only to do so if 
they believe they can construct the facilities faster than the 
transmission provider. Additionally, we agree with AVANGRID and AWEA 
that the expanded option to build would apply to identified 
transmission provider interconnection facilities and stand alone 
network upgrades regardless of whether those facilities were identified 
through clustering, serial, or another study method. This is consistent 
with the current option to build, which does not restrict the study 
method.
    106. In response to EDP, we note that the pro forma LGIA, as 
modified by the final action, makes clear that the interconnection 
customer may exercise the option to build at its discretion with regard 
to transmission provider's interconnection facilities and stand alone 
network upgrades. If the interconnection customer does not exercise 
this discretion, pursuant to articles 5.1.1, 5.1.2, and 5.1.4, the 
transmission provider would be responsible for the construction of 
transmission provider's interconnection facilities and stand alone 
network upgrades.
    107. We choose not to adopt AVANGRID's two additional proposals and 
find that the revisions adopted by the final action strike the 
appropriate balance. Additionally, we disagree with Bonneville's 
recommendation that we allow the interconnection customer to exercise 
the option to build only if it can demonstrate its ability to construct 
the subject facilities cost-effectively. It is unnecessary to impose 
such a requirement for interconnection customers because they will 
ultimately

[[Page 21356]]

bear the costs of the transmission provider's interconnection 
facilities and the stand alone network upgrades; thus, they have more 
incentive than transmission providers to select the most cost effective 
option.
    108. We disagree with Duke and EEI regarding the need to revise 
article 9.7.1 of the pro forma LGIA to require parties to coordinate 
maintenance, testing, or installation actions for stand alone upgrades. 
Article 5.2 provides sufficient safeguards to ensure coordination of 
maintenance, testing, and installation by providing for transmission 
provider access and requiring the ultimate transfer of ownership. We 
also disagree with National Grid's and Eversource's proposals regarding 
the transfer of ownership because articles 5.2(8) and (9) already 
require the transfer of control and ownership to the transmission 
provider.
    109. Furthermore, we disagree with Duke's proposal to revise 
article 11.5 of the pro forma LGIA to include stand alone upgrades. 
Duke provides no reason why such revision is necessary. Additionally, 
we read the phrase ``applicable portion'' in article 11.5 to exclude 
facilities that an interconnection customer would construct pursuant to 
the option to build. Since the purpose of article 11.5 is for the 
interconnection customer to provide funds to the transmission provider 
for construction costs, there would be no need for the interconnection 
customer to provide security to the transmission provider for 
facilities the transmission provider will not construct (because the 
interconnection customer is exercising the option to build).
    110. We also see no need to revise article 26.1 of the pro forma 
LGIA, as Duke proposed, to limit the interconnection customer's ability 
to use subcontractors. Similarly, while we agree with Generation 
Developers, NextEra, and EEI that it could be helpful for transmission 
owners to maintain a list of contractors available to interconnection 
customers for the option to build, given the adequacy of the safeguards 
in article 5.2, we find that it is not necessary to require 
transmission owners to do so. We find the safeguards in article 5.2 to 
be sufficient because they give the transmission provider significant 
oversight authority to review and approve the design, equipment 
testing, and construction, ``unrestricted access'' to inspect the 
construction, and the ability to require the interconnection customer 
to remedy deficiencies that may arise at ``any time during 
construction.'' \190\ Similarly, we do not agree with Duke's and 
National Grid's suggestion that the transmission provider should have 
the right to approve subcontractors because of the multiple preexisting 
protections in article 5.2. Further, we are not persuaded by EEI's 
contention that revisions are necessary to supersede the option to 
build if facilities need to be expedited. First, article 5.2 already 
obligates the interconnection customer to ``remedy deficiencies'' 
should ``any phase of the engineering, equipment procurement, or 
construction . . . not meet the standards and specifications provided 
by Transmission Provider.'' \191\ Second, the option to build is 
limited to the construction of transmission provider's interconnection 
facilities and stand alone network upgrades, the latter of which the 
pro forma LGIA defines as those network upgrades that the 
interconnection customer ``may construct without affecting day-to-day 
operations of the Transmission System during their construction.'' 
\192\ Together, these provisions minimize the likelihood that any 
delays in construction will adversely affect reliability.
---------------------------------------------------------------------------

    \190\ Pro forma LGIA Articles 5.2 (3), (5), & (6).
    \191\ Pro forma LGIA Art. 5.2(6).
    \192\ Pro forma LGIA Art. 1 (Definitions).
---------------------------------------------------------------------------

    111. In response to TVA and EEI, we find that article 5.2 already 
provides sufficient safeguards regarding transmission construction 
qualifications because it requires, for example, that interconnection 
customers use good utility practice and follow the standards and 
specifications outlined by the transmission provider. Additionally, 
while Generation Developers, EDP, and SEIA advocate that transmission 
providers post the standards and specifications for interconnection 
facilities and stand alone network upgrades on their websites, we will 
not require them to do so. Although posting such standards and 
specifications on a website could be useful, we do not think it 
appropriate to impose this requirement on transmission providers in 
this final action given the questionable usefulness of this 
information.
    112. In response to Generation Developers' request that 
transmission providers be required to provide an explanation when they 
disagree that a facility is a stand alone network upgrade, we find that 
it would be difficult for a transmission provider to determine whether 
or not a facility would be considered a stand alone network upgrade 
until it is presented with the results of a system impact study. While 
we recognize that questions regarding what constitutes a stand alone 
network upgrade could lead to disputes, interconnection customers are 
free to seek dispute resolution on such questions and/or pursue a 
complaint under section 206 of the FPA.
    113. We disagree with Eversource's request to require that 
interconnection customers receive transmission owner approval before 
ordering electrical materials and equipment. Article 5.2 already 
provides sufficient responsibilities to interconnection customers to 
mitigate the concerns Eversource raised through, for example, the 
requirements that the interconnection customer use good utility 
practice and abide by the transmission provider's standards and 
specifications, and the requirement that the transmission provider 
approve the design, equipment acceptance tests, and construction. We 
also disagree with Eversource's and MISO's recommendations to require 
that interconnection customers provide sufficient land rights to allow 
transmission provider access to transmission facilities and to 
terminate interconnection customers' authority to construct during 
emergency situations. We do not see the need to impose a further 
requirement on the interconnection customer, especially because the 
revisions adopted in this final action do not relax the existing 
requirements.
3. Self-Funding by the Transmission Owner
a. NOPR Proposal
    114. In the NOPR, the Commission proposed to require agreement 
between a transmission owner or provider and interconnection customer 
before the transmission owner or provider may elect to initially fund 
network upgrades.\193\
---------------------------------------------------------------------------

    \193\ NOPR, FERC Stats. & Regs. ] 32,719 at P 64.
---------------------------------------------------------------------------

    115. Prior to the revisions proposed in the NOPR, article 11.3 in 
the pro forma LGIA stated that ``[u]nless Transmission Provider or 
Transmission Owner elects to fund the capital for the Network Upgrades, 
they shall be solely funded by Interconnection Customer.'' This 
provision allowed the transmission provider or owner to unilaterally 
elect to ``self-fund'' network upgrades.
    116. In 2013, MISO proposed allowing a transmission owner to elect 
to directly assign costs associated with self-funded network upgrades 
to the interconnection customer.\194\ In that proceeding, the 
Commission accepted

[[Page 21357]]

MISO's proposal for a transmission owner that elects to initially fund 
network upgrades under MISO's pro forma GIA to recover the capital 
costs for network upgrades through a network upgrade charge assessed to 
the interconnection customer.\195\
---------------------------------------------------------------------------

    \194\ Midcontinent Indep. Sys. Operator, Inc., 145 FERC ] 61,111 
(2013) (Hoopeston).
    \195\ Hoopeston, 145 FERC ] 61,111 at P 41.
---------------------------------------------------------------------------

    117. The Commission revisited that approach in the Otter Tail 
proceedings.\196\ In those proceedings, the Commission found that 
article 11.3 in MISO's pro forma GIA, which allows a transmission owner 
to self-fund network upgrades, to be unjust, unreasonable, and unduly 
discriminatory or preferential. Consequently, the Commission directed 
MISO to revise article 11.3 to require mutual agreement with the 
interconnection customer for the transmission owner to elect to 
initially fund network upgrades. Ameren Services Company, a 
transmission owner in MISO, challenged this order in the United States 
Court of Appeals for the District of Columbia Circuit (D.C. Circuit).
---------------------------------------------------------------------------

    \196\ Midcontinent Indep. Sys. Operator, Inc., 151 FERC ] 61,220 
(2015); Otter Tail Power Co. v. Midcontinent Indep. Sys. Operator, 
Inc., 153 FERC ] 61,352, at P 14 (2015); Otter Tail Power Co. v. 
Midcontinent Indep. Sys. Operator, Inc., 156 FERC ] 61,099 (2016) 
(collectively, the Otter Tail proceedings).
---------------------------------------------------------------------------

    118. In the NOPR in this proceeding, the Commission proposed to 
revise article 11.3 of the pro forma LGIA to require mutual agreement 
between the interconnection customer and the transmission owner for the 
transmission owner to initially fund the cost of network upgrades. 
Specifically, the Commission proposed in the NOPR to modify the 
language in article 11.3 of the pro forma LGIA as follows (with 
proposed additions in italics):

    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, which election shall only be available upon mutual 
agreement of Interconnection Customer and Transmission Owner or 
Transmission Provider, they shall be solely funded by 
Interconnection Customer.

    119. The Commission also sought comment on whether to limit the 
proposal to RTOs/ISOs or to apply it to all transmission providers.
b. Comments
    120. A number of commenters support the proposal.\197\ A group of 
five commenters, predominantly from MISO, oppose the proposal and state 
that any action would be premature, given that, at the time that they 
filed their comments, the D.C. Circuit had not issued a decision in the 
Otter Tail proceedings. They ask the Commission to refrain from 
implementing this reform until the appellate decision is issued.\198\
---------------------------------------------------------------------------

    \197\ Non-Profit Utility Trade Associations; AFPA; AWEA; CAISO; 
Joint Renewable parties; Generation Developers; EDP; ELCON; FTC; 
IECA; NEPOOL; NextEra; PG&E SEIA; TDU Systems.
    \198\ Duke 2017 Comments at 6-7; EEI 2017 Comments at n.20; ITC 
2017 Comments at 8; MidAmerican 2017 Comments at 11; MISO TOs 2017 
Comments at 17.
---------------------------------------------------------------------------

    121. Regarding whether the Commission should extend the requirement 
for mutual agreement beyond RTOs/ISOs, AWEA, Joint Renewable Parties, 
TDU Systems, and AFPA all argue that the proposal should apply 
generically.\199\ On the other hand, Southern, TVA, Generation 
Developers, and Xcel state that self-funding by the transmission owner 
is not applicable to the pro forma OATT.\200\
---------------------------------------------------------------------------

    \199\ AWEA 2017 Comments at 19; Joint Renewable Parties 2017 
Comments at 9-10; TDU Systems 2017 Comments at 7; AFPA Comments at 
7.
    \200\ Southern 2017 Comments at 13-14; TVA 2017 Comments at 5; 
Generation Developers 2017 Comments at 15; Xcel 2017 Comments at 10-
11.
---------------------------------------------------------------------------

c. Commission Determination
    122. We withdraw the NOPR's proposal to extend the approach to 
self-funding that the Commission approved in MISO to all regions. On 
January 26, 2018, the D.C. Circuit issued a decision vacating the 
Commission's orders in the Otter Tail proceedings.\201\ In this 
decision, the court noted, among other things, that the Commission did 
not adequately respond to the argument that ``involuntary generator 
funding compels [transmission owners] to . . . accept additional risk 
without corresponding return.'' \202\ The court further stated that the 
Commission's approved changes to the MISO tariff ``open[ ] the 
floodgates to involuntary generator-funded interconnection projects.'' 
\203\ The court also referenced this proceeding, stating that the fact 
that the Commission ``plans a rulemaking to consider interconnection 
problems and costs . . . suggests that it should approach those issues 
on a clean slate.'' \204\ In light of the D.C. Circuit's decision, we 
will not move forward with the proposal pertaining to self-funding at 
this time. We will, however, continue to evaluate the issue.
---------------------------------------------------------------------------

    \201\ Ameren Servs. Co. v. FERC, 880 F.3d 571 (D.C. Cir. 2018).
    \202\ Id. at 573-74.
    \203\ Id. at 584.
    \204\ Id. at 585.
---------------------------------------------------------------------------

4. Dispute Resolution
a. NOPR Proposal
    123. In the NOPR, the Commission proposed that RTOs/ISOs establish 
interconnection dispute resolution procedures that allow a disputing 
party to unilaterally seek dispute resolution in RTO/ISO regions.\205\
---------------------------------------------------------------------------

    \205\ NOPR, FERC Stats. & Regs. ] 32,719 at P 78.
---------------------------------------------------------------------------

    124. Order No. 2003 created an arbitration process through the 
adoption of section 13.5 of the pro forma LGIP, which allows disputing 
parties to agree to arbitration ``upon mutual agreement of the 
Parties'' to the dispute.\206\ Pursuant to this process, arbitrators 
may interpret and apply the provisions of the LGIA and LGIP but have no 
power to modify those provisions.\207\ At the completion of this 
process, the arbitrator's decision is ``final and binding upon the 
Parties, and judgment on the award may be entered in any court having 
jurisdiction.'' Additionally, the decision may only ``be appealed . . . 
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.'' \208\ While the 
arbitrator's decision is binding, ``the final decision must still be 
filed with [the Commission] if it affects jurisdictional rates, terms 
and conditions of service, Interconnection Facilities, or Network 
Upgrades,'' \209\ and the Commission ``retains the authority to review 
the arbitrator's decision.'' \210\ Participation in the section 13.5 
arbitration process does not limit the ability of either party to bring 
a complaint about the same issues.\211\
---------------------------------------------------------------------------

    \206\ Pro forma LGIP Section 13.5.1.
    \207\ Pro forma LGIP Section 13.5.
    \208\ Pro forma LGIP Section 13.5.3.
    \209\ Id.
    \210\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 290.
    \211\ Specifically, it states that section 13.5 arbitration does 
not ``circumscribe[ ] the Parties' right to avail themselves of the 
Commission's complaint process because under section 13.5.1, a party 
that does not agree to arbitration may exercise its rights, 
including its right to bring a complaint to the Commission.'' Order 
No. 2003, FERC Stats. & Regs. ] 31,146 at P 290.
---------------------------------------------------------------------------

    125. In the NOPR, the Commission proposed to revise the Code of 
Federal Regulations to require RTOs/ISOs to establish interconnection 
dispute resolution procedures that would allow a disputing party to 
unilaterally seek dispute resolution. In particular, the Commission 
proposed to revise Sec.  35.28 of the Commission's regulations to add

[[Page 21358]]

a new paragraph (g)(9), providing that every Commission-approved 
independent system operator or regional transmission organization 
tariff must contain provisions governing generator interconnection 
dispute resolution procedures to allow a disputing party to 
unilaterally initiate dispute resolution procedures under the 
respective tariff. Such provisions must provide for independent system 
operator or regional transmission organization staff member(s) or 
utilize subcontractor(s) to serve as the neutral decision-maker(s) or 
presiding staff member(s) or subcontractor(s) to the dispute resolution 
procedures. Such staff participating in dispute resolution procedures 
shall not have any current or past substantial business or financial 
relationships with any party. Additionally, such dispute resolution 
procedures must account for the time sensitivity of the generator 
interconnection process.
    126. The Commission limited the proposed requirements in this draft 
text to RTOs/ISOs because the Commission had only received comments 
regarding the need for dispute resolution reform in RTOs/ISOs. However, 
given the lack of a record on this issue, the Commission also sought 
comment on the need for reform outside the RTOs/ISOs.\212\ The 
Commission also sought comment on the appropriateness of adopting 
procedures similar to section 4.2 of the pro forma SGIP, which allows 
parties to contact the Commission's Dispute Resolution Service (DRS) 
for assistance in resolving an interconnection dispute.\213\
---------------------------------------------------------------------------

    \212\ NOPR, FERC Stats. & Regs. ] 32,719 at P 86.
    \213\ Section 4.2.4 of the pro forma SGIP states that DRS will 
assist in resolving a dispute or in selecting an appropriate dispute 
resolution venue. Additionally, section 4.2.6 states that if neither 
party elects to contact DRS or if the attempted dispute resolution 
fails, ``either Party may exercise whatever rights and remedies it 
may have in equity or law consistent with the terms of these 
procedures.''
---------------------------------------------------------------------------

    127. The NOPR proposal represented a potential alternative to, and 
not a replacement of, section 13.5 of the pro forma LGIP.\214\ The 
Commission crafted its proposal in response to its observation that the 
arbitration process embodied in section 13.5 is effectively unavailable 
to an interconnection customer if a transmission owner opposes this 
arbitration process.\215\
---------------------------------------------------------------------------

    \214\ Id.
    \215\ Id. P 85.
---------------------------------------------------------------------------

b. General
i. Comments
    128. Multiple commenters support the proposal.\216\ The Non-Profit 
Utility Trade Associations state that they do not object to this 
proposal.\217\ Salt River states that the proposal is reasonable with 
regard to disputes between interconnection customers and RTOs/ISOs, 
RTO/ISO transmission owners, or affected system operators that are also 
RTO/ISO transmission owners.\218\ However, Salt River argues that if 
the dispute is with an autonomous neighboring affected system operator 
that is a non-RTO/ISO member, then the dispute resolution procedures in 
the affected system operator's OATT should apply.\219\
---------------------------------------------------------------------------

    \216\ AWEA 2017 Comments at 21; Joint Renewable Parties 2017 
Comments at 2-3; IECA 2017 Comments at 3; Invenergy 2017 Comments at 
15-16; AFPA 2017 Comments at 8; CAISO 2017 Comments at 11-12; SEIA 
2017 Comments at 14-15; TDU Systems 2017 Comments at 11; AVANGRID 
2017 Comments at 18.
    \217\ Non-Profit Utility Trade Associations 2017 Comments at 6.
    \218\ Salt River 2017 Comments at 8.
    \219\ Id.
---------------------------------------------------------------------------

    129. AES asserts that RTOs/ISOs, not the Commission, should 
reexamine their existing dispute resolution procedures.\220\ Indicated 
NYTOs oppose the dispute resolution proposal, arguing that NYISO's 
existing dispute resolution provisions are adequate.\221\ NYISO also 
opposes the proposed revisions, stating that they would duplicate 
existing dispute resolution opportunities.\222\ ISO-NE and CAISO 
similarly argue that their current dispute resolution procedures are 
adequate.\223\ CAISO also notes that its tariff includes a dedicated 
dispute committee for generator interconnection issues.\224\ 
MidAmerican argues that the existing MISO tariff addresses the 
Commission's concerns about the ability of a party to unilaterally 
request dispute resolution.\225\
---------------------------------------------------------------------------

    \220\ AES 2017 Comments at 7-8.
    \221\ Indicated NYTOs 2017 Comments at 12-14.
    \222\ NYISO 2017 Comments at 17.
    \223\ ISO-NE 2017 Comments at 18; CAISO 2017 Comments at 12.
    \224\ Id. (citing CAISO, eTariff, FERC Electric Tariff, OATT, 
Section 13 (0.0.0) & app. DD, Section 15.5 (1.0.0)).
    \225\ MidAmerican 2017 Comments at 7; see also MISO TOs 2017 
Comments at 24.
---------------------------------------------------------------------------

    130. MISO requests a clarification that RTOs/ISOs do not need to 
create separate dispute resolution procedures for generator 
interconnection disputes and may continue to rely on their general 
dispute resolution procedures as long as they permit parties to 
unilaterally initiate the resolution process.\226\ MISO TOs ask the 
Commission to clarify that the dispute resolution procedures are for 
genuine disputes only and should not be used to gain additional time to 
meet LGIP or LGIA obligations.\227\ PJM agrees with the dispute 
resolution proposal and believes that its dispute resolution procedures 
generally conform to it.\228\
---------------------------------------------------------------------------

    \226\ MISO 2017 Comments at 17-18.
    \227\ MISO TOs 2017 Comments at 24.
    \228\ PJM 2017 Comments at 8.
---------------------------------------------------------------------------

    131. Generation Developers request that the final action state that 
the dispute resolution mechanism that an RTO/ISO adopts should trump 
the existing provisions in section 13.5 of the LGIP. Generation 
Developers state that, unless this is made clear, the parties will 
argue about which dispute resolution provision applies.\229\
---------------------------------------------------------------------------

    \229\ General Developers 2017 Comments at 19.
---------------------------------------------------------------------------

ii. Commission Determination
    132. In this final action, we revise the pro forma LGIP to add new 
section 13.5.5, as discussed further below. We are taking this step 
because the record in this proceeding indicates that existing dispute 
resolution procedures may not be just and reasonable and may be unduly 
discriminatory or preferential because one disputing party may 
effectively prevent the other disputing party from pursuing dispute 
resolution.\230\ We thus disagree with those commenters that argue that 
transmission providers should simply reexamine their dispute resolution 
procedures. The reason is that, if the status quo provides little 
recourse for interconnection customers when a transmission provider 
does not agree to dispute resolution, then it would not be sufficient 
for transmission providers to merely reexamine their dispute resolution 
procedures with no guarantee that they would address this concern. 
Additionally, as discussed further below, we find that the record 
developed here demonstrates the need for generic dispute resolution 
reform, both inside and outside RTOs/ISOs. To avoid having dispute 
resolution requirements in multiple places, we are effectuating this 
reform through revisions to the pro forma LGIP as part of the existing 
dispute resolution provisions, rather than through changes to the Code 
of Federal Regulations.
---------------------------------------------------------------------------

    \230\ NOPR, FERC Stats. & Regs. ] 32,719 at P 84.
---------------------------------------------------------------------------

    133. Therefore, this final action revises the pro forma LGIP by 
adding new section 13.5.5, which will read as follows:

    Non-binding dispute resolution procedures. If a Party has 
submitted a Notice of Dispute pursuant to section 13.5.1, and the

[[Page 21359]]

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 section 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 section 13.5 arbitration 
process. The process in section 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 section 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.

    134. The provision retains the central principles of the NOPR 
proposal but extends its application to all transmission providers, 
including non-RTOs/ISOs. We have revised the provision to also provide 
necessary clarification in response to the comments received in this 
proceeding, as discussed further below.
    135. We note that numerous parties have expressed a need for 
dispute resolution reform and support for the principles embodied in 
the NOPR proposal. While this final action establishes the core 
requirement that transmission providers adopt a new non-binding dispute 
resolution process, each transmission provider must develop and 
establish the additional specifics of a just and reasonable process 
that allows disputing parties to unilaterally seek non-binding dispute 
resolution.
    136. In response to Salt River's argument regarding the 
applicability of the proposed revisions to an autonomous neighboring 
affected system operator, as explained more fully below, on April 3-4, 
2018, the Commission convened a technical conference in Docket No. 
AD18-8-000 for industry representatives and others to discuss issues 
related to affected systems. Given that the discussion here pertains to 
disputes within a transmission provider's region (such as a dispute 
between an interconnection customer and a transmission provider) and 
not to disputes with a party external to the region of the 
interconnection request, we find that Salt River's concerns are better 
addressed in a proceeding dedicated to issues involving affected 
systems, such as the aforementioned technical conference.\231\
---------------------------------------------------------------------------

    \231\ Initial and reply comments on the technical conference in 
Docket No. AD18-8-000 are due within 30 days and 45 days, 
respectively, from the date of the issuance of the Notice Inviting 
Post-Technical Conference Comments in that proceeding, which issued 
concurrently with this final action.
---------------------------------------------------------------------------

    137. In response to Indicated NYTOs', ISO-NE's, NYISO's, PJM's, 
MISO's, MidAmerican's, and CAISO's contentions about the existing 
dispute resolution procedures in their specific regions, we remind 
these parties that we will not evaluate a particular transmission 
provider's tariff provisions until it submits its compliance filing. We 
note, however, that a transmission provider that has only adopted the 
generator interconnection dispute resolution procedures imposed by 
Order No. 2003, namely the section 13.5 arbitration process, would not 
comply with the non-binding dispute resolution requirements of this 
final action, as set forth in the new section 13.5.5 above.
    138. In response to MISO's request for clarifications, we find that 
a transmission provider does not need to create dispute resolution 
procedures that only apply to generator interconnection disputes, so 
long as the transmission provider provides a dispute resolution process 
that a party, including the interconnection customer, may seek 
unilaterally. In response to the MISO TOs' request for clarification, 
we find that their concern that a party will use the dispute resolution 
process to gain additional time to meet LGIP or LGIA obligations to be 
speculative, and, to the extent that this is a valid concern, it would 
apply equally to disputing interconnection customers and transmission 
providers or owners. In addition, both the dispute resolution process 
created here and the section 13.5 arbitration process impose costs on 
the disputing parties, which should mitigate concerns about potential 
misuse of the process.
    139. We find that the new dispute resolution provisions in section 
13.5.5 of the pro forma LGIP adopted by this final action do not trump 
the existing language in section 13.5 of the pro forma LGIP. We 
establish the new non-binding dispute resolution process here primarily 
to address the concern that dispute resolution is unavailable where 
there is no mutual agreement to pursue a section 13.5 arbitration. This 
final action thus provides a dispute resolution avenue that one party 
may seek unilaterally. Disputing parties are free to determine which 
process they prefer, and disputing parties may pursue the non-binding 
process even if they have not previously sought a section 13.5 
arbitration. Additionally, participation in the new section 13.5.5 
process does not preclude the parties from pursuing arbitration after 
the conclusion of another process if they seek a binding result. Also, 
pursuing either process does not prevent either party from availing 
itself of the complaint process pursuant to section 206 of the FPA. 
Furthermore, we note that we do not restrict a party's ability to cite 
the record developed in the arbitration process described in section 
13.5 of the pro forma LGIP in a complaint proceeding pursuant to 
section 206 of the FPA, and we see no reason to impose such a 
restriction for the non-binding dispute resolution provisions adopted 
in this final action. We note, however, that parties may mutually agree 
to restrict the use of the record created in a non-binding dispute 
resolution process.
c. Extending the Dispute Resolution Proposal beyond RTOs/ISOs
i. Comments
    140. Generation Developers, IECA, Competitive Suppliers, and TDU 
Systems argue that the Commission should also reform dispute resolution 
procedures outside of RTOs/ISOs.\232\ For example, Generation 
Developers state that problems that interconnection customers encounter 
pertaining to dispute resolution ``are also encountered with a 
Transmission Provider outside of [an RTO/ISO].'' \233\ TDU Systems 
state that they have ``found the current dispute resolution processes 
[outside of RTOs/ISOs] to be inadequate,'' because, for example, in 
regions that lack an RTO/ISO-like entity ``to assist in resolving 
disputes, the waiting period to access dispute

[[Page 21360]]

resolutions is too long, and parties to disputes should have options 
beyond mutually-agreed upon arbitration.'' \234\ In non-RTO/ISO 
regions, AFPA recommends the establishment of a separate Commission 
dispute resolution service with expertise on these matters.\235\ 
Competitive Suppliers believe that the rules and protocols in organized 
markets are superior to those outside organized markets and encourage 
the Commission to uphold consistency and comparability unless there is 
an adequate reason to allow regional variation.\236\ MISO asserts that 
there is no basis to conclude that the procedures currently used in 
RTOs/ISOs are inferior to the procedures used by other transmission 
providers.\237\
---------------------------------------------------------------------------

    \232\ Generation Developers 2017 Comments at 18-20; IECA 2017 
Comments at 3; Competitive Suppliers 2017 Comments at 6; TDU Systems 
2017 Comments at 11.
    \233\ Generation Developers 2017 Comment at 20.
    \234\ TDU Systems 2017 Comments at 12.
    \235\ AFPA 2017 Comments at 8.
    \236\ Competitive Suppliers 2017 Comments at 5.
    \237\ MISO 2017 Comments at 17.
---------------------------------------------------------------------------

    141. TVA believes that the current dispute resolution process for 
non-RTOs/ISOs is sufficient, under both the pro forma LGIP and the pro 
forma SGIP.\238\ If the Commission decides that any final action should 
align more closely to the parameters of the NOPR, Competitive Suppliers 
argue that the proposed revisions to the dispute resolution changes 
should apply to all transmission owners and providers offering 
interconnection service.\239\
---------------------------------------------------------------------------

    \238\ TVA 2017 Comments at 6.
    \239\ Competitive Suppliers 2017 Comments at 6.
---------------------------------------------------------------------------

ii. Commission Determination
    142. In this final action, we adopt the aforementioned pro forma 
LGIP language, which imposes the revised dispute resolution 
requirements on both RTOs/ISOs and non-RTOs/ISOs. As noted above, the 
Commission sought comment on the need for dispute resolution reform 
outside of RTOs/ISOs. We agree with commenters that there is a need for 
dispute resolution reform outside of RTO/ISOs.\240\ Outside of the 
RTOs/ISOs, the transmission provider and transmission owner are the 
same entity. Consequently, outside of RTOs/ISOs and without the 
presence of an independent RTO/ISO as a third party, it may be more 
difficult for the transmission provider and the interconnection 
customer to reach mutual agreement to seek dispute resolution. Under 
such circumstances, when a dispute arises, the process would benefit 
from a neutral decision-maker that can evaluate the dispute without an 
interest in the outcome. For this reason, the procedures adopted here 
apply generically, in both RTO/ISO regions and non-RTO/ISO regions. 
Finally, we have opted to include new pro forma LGIP section 13.5.5 in 
the pro forma LGIP instead of the Code of Federal Regulations, so that 
all generically applicable generator interconnection dispute resolution 
requirements are in the same place.
---------------------------------------------------------------------------

    \240\ Competitive Suppliers 2017 Comments at 5; MISO 2017 
Comments at 17.
---------------------------------------------------------------------------

d. RTO/ISO Neutrality
i. Comments
    143. Multiple commenters question the neutrality of RTO/ISO staff 
or oppose allowing RTO/ISO staff as dispute resolution neutral 
decision-makers.\241\ AWEA, for instance, notes that RTOs/ISOs rely 
upon transmission owner assistance (for modeling and design 
information) and transmission owner membership (for financial support) 
and that, on occasion, RTOs/ISOs have refused to participate in dispute 
resolution.\242\ Another option that AWEA and NextEra suggest is for 
RTOs/ISOs to contract for staff from a disinterested RTO/ISO to oversee 
their dispute resolution.\243\ NextEra suggests adding a draft tariff 
provision that would allow for this arrangement.\244\
---------------------------------------------------------------------------

    \241\ FTC 2017 Comments at 11; AWEA 2017 Comments at 23-24; 
Generation Developers 2017 Comments at 18; EDP 2017 Comments at 5; 
NextEra 2017 Comments at 15; AVANGRID 2017 Comments at 18.
    \242\ AWEA 2017 Comments at 22-23.
    \243\ Id. at 23; NextEra 2017 Comments at 20.
    \244\ Id. at 17.
---------------------------------------------------------------------------

    144. AWEA also states that market monitors have the necessary 
independence to oversee dispute resolution, but they already have 
significant responsibilities and may lack relevant interconnection 
process experience.\245\ EEI argues that having an RTO/ISO serve as a 
decision-maker in a dispute could potentially challenge its 
independence and neutrality.\246\ Similarly, Indicated NYTOs argue that 
entities like NYISO would be reluctant to resolve such disputes by 
making judgments in favor of either the developer or the transmission 
owner.\247\ ISO-NE and NEPOOL explain that ISO-NE fulfills the role of 
transmission provider for many functions but that participating 
transmission owners serve in this role when providing cost estimates 
for network upgrades.\248\ ISO-NE and NEPOOL also state that, given 
ISO-NE's transmission provider role, disputes can arise between ISO-NE 
and the interconnection customer or the transmission owner, and it 
would therefore be inappropriate to require ISO-NE to decide these 
disputes.\249\ NEPOOL also argues that having RTO/ISO staff resolve 
disputes could impair the RTO's/ISO's performance of its core 
duties.\250\ NextEra suggests that RTO/ISO staff serving in this role 
would need comparable status to the RTO's/ISO's independent market 
monitoring staff.\251\ TDU Systems state that RTO/ISO staff are likely 
adequately independent from all market participants and able to serve 
as a useful resource for resolving disputes.\252\ AVANGRID states that, 
while RTO/ISO staff are often ``very good'' at preventing and resolving 
disputes as they arise, they should not ``be put in the position of 
determining the outcome of formal dispute resolution processes.'' \253\
---------------------------------------------------------------------------

    \245\ AWEA 2017 Comments at 24.
    \246\ EEI 2017 Comments at 28.
    \247\ Indicated NYTOs 2017 Comments at 14.
    \248\ ISO-NE 2017 Comments at 18-19; NEPOOL 2017 Comments at 8.
    \249\ ISO-NE 2017 Comments at 19.
    \250\ NEPOOL 2017 Comments at 8.
    \251\ NextEra 2017 Comments at 15.
    \252\ TDU Systems 2017 Comments at 11.
    \253\ AVANGRID 2017 Comments at 18.
---------------------------------------------------------------------------

    145. Generation Developers and NextEra argue that subcontractors 
could serve as neutral parties.\254\ AWEA also argues that the NOPR's 
neutrality standard may be too vague and that subcontractor vetting may 
resolve this concern.\255\ Generation Developers state that the RTO/ISO 
should maintain a long-term contract for dispute services to ensure 
that the subcontractor is neutral and not beholden to the RTO/ISO. 
Generation Developers propose that the RTO/ISO should have a list of 
subcontractors with substantial experience in interconnection and 
modeling matters that are available to serve as neutral third-parties, 
and that all RTO/ISO members should be allowed to propose to use the 
listed subcontractors. Generation Developers propose that subcontractor 
fees should be borne by interconnection customers to ensure that there 
is no tendency for a subcontractor to be beholden to the RTO/ISO.
---------------------------------------------------------------------------

    \254\ Generation Developers 2017 Comments at 18; NextEra 2017 
Comments at 15-16; see also AVANGRID 2017 Comments at 18.
    \255\ AWEA 2017 Comments at 23.
---------------------------------------------------------------------------

    146. Conversely, MISO contends that there is no need for 
independent staff or subcontractors and that the proposed requirements 
could increase RTO/ISO bureaucratization and impose additional 
costs.\256\ MISO states that the proposed independence requirements are 
unnecessary, as RTOs/ISOs are already subject to stringent independence 
requirements. MISO asserts that there has been no showing that the 
existing conflict of interest requirements are inadequate for purposes 
of dispute resolution. MISO proposes that the Commission permit RTOs/
ISOs to rely

[[Page 21361]]

on their existing standards of conduct and similar requirements for 
their dispute resolution staff.\257\
---------------------------------------------------------------------------

    \256\ MISO 2017 Comments at 19.
    \257\ Id. at 18-19.
---------------------------------------------------------------------------

    147. MISO states that the requirement that RTO/ISO dispute 
resolution staff not have current or past substantial business or 
financial relationships with any disputing party is too broad and 
burdensome and that the pool of suitable candidates to perform these 
tasks is limited. If the Commission adopts this requirement, MISO asks 
the Commission to limit the prohibition to a reasonable time period 
(e.g., three years).\258\
---------------------------------------------------------------------------

    \258\ Id. at 19.
---------------------------------------------------------------------------

    148. NYISO is concerned about instituting a framework that would 
outsource responsibility to subcontractors.\259\ It states that section 
30.13.2 of its LGIP provides that, even when NYISO uses subcontractors, 
it must comply with the tariff's requirements. Therefore, NYISO objects 
to any process that would allow a subcontractor's determination--for 
example, regarding appropriate network upgrades--to override NYISO's 
judgment concerning tariff requirements and applicable reliability 
standards.\260\
---------------------------------------------------------------------------

    \259\ NYISO 2017 Comments at 18.
    \260\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    149. With few exceptions, the commenters voice strong opposition to 
having RTO/ISO staff serve as decision-makers in dispute resolution 
proceedings. Some commenters argue that RTO/ISO staff may be unable to 
demonstrate independence in such a process. Conversely, Indicated NYTOs 
argue that requiring RTO/ISO staff to act as decision-makers would 
compromise their independence. In response to these concerns, and to 
address the issue where the transmission owner is the transmission 
provider outside of RTOs/ISOs, the LGIP provision adopted in this final 
action requires transmission providers to appoint an independent third 
party to preside over dispute resolution proceedings.
    150. In response to Generation Developers' contention that 
interconnection customers should bear the fees for the decision-maker, 
we find that it makes little sense to have one disputing party bear all 
costs when there are multiple parties involved in the dispute. For this 
reason, the newly adopted provision in section 13.5.5 of the pro forma 
LGIP requires the same cost division as that established for the 
arbitration process described in section 13.5 of the pro forma LGIP. 
Thus, the cost of the decision-maker shall be divided equally among 
each party to the dispute. Each individual party to a dispute will be 
responsible for its own costs incurred during the process.
    151. The final action requires that the assigned decision-maker 
have no ``current or past substantial business or financial 
relationships with either party.'' We note that this standard is 
identical to the neutrality standard proposed in the NOPR and to the 
one established for arbitrators in section 13.5 of the pro forma LGIP. 
While MISO argues that this standard would limit the pool of eligible 
participants, we read MISO's comments to pertain to the NOPR proposal, 
which required RTOs/ISOs to have RTO/ISO staff serve as decision-
makers. For this reason, the neutrality standard adopted in this final 
action will not be too burdensome, in light of the changes from the 
NOPR.
    152. With regard to NYISO's concern about ``outsourcing'' 
responsibility to subcontractors, we note that the newly created 
process, like the arbitration process described in section 13.5 of the 
pro forma LGIP, limits a decision-maker's authority so that it may only 
``interpret and apply the provisions of the LGIA and LGIP.'' The 
subcontractor would therefore have no ability to alter NYISO's existing 
responsibilities.
e. Binding Nature of the Proposal
i. Comments
    153. AWEA indicates that, due to neutrality issues that are likely 
to remain, dispute resolution should be non-binding.\261\ Similarly, 
NextEra argues that it would not be appropriate for this ``expeditious 
input'' to be binding on the parties and cause them to lose rights 
under sections 205 or 206 of the FPA.\262\ NextEra also asserts that if 
the expedited dispute resolution were binding, there would be too much 
risk involved.\263\ NextEra views the process as similar to ``input 
from a subject matter expert'' rather than any form of litigation.\264\
---------------------------------------------------------------------------

    \261\ AWEA 2017 Comments at 24.
    \262\ NextEra 2017 Comments at 16.
    \263\ Id.
    \264\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    154. In this final action, we adopt a non-binding dispute 
resolution process. The pro forma LGIP provisions adopted in this final 
action will be an alternative to, and not a replacement of, the 
existing arbitration process described in section 13.5 of the pro forma 
LGIP, which is a binding process. Specifically, section 13.5.3 of the 
pro forma LGIP states that ``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.'' \265\ Because the new 
process adopted in this final action does not require mutual agreement, 
we agree with AWEA and NextEra that this new process should be non-
binding.\266\ Although the non-binding nature of the process could 
dampen its appeal, the process would still require disputing parties to 
participate in a process presided over by a neutral party. To this 
point, we agree with NextEra that the process would be beneficial 
because it would offer an opportunity for ``input from a subject matter 
expert.'' Additionally, we find that it would be inappropriate for the 
new, non-binding dispute resolution process to limit a party's ability 
to pursue a complaint pursuant to section 206 of the FPA.
---------------------------------------------------------------------------

    \265\ Pro forma LGIP Section 13.5.3 (emphasis added).
    \266\ No other commenters discussed this issue. Although we are 
adopting a non-binding process in the pro forma LGIP, transmission 
providers that have binding dispute resolution processes that, on 
compliance, are able to demonstrate that their processes otherwise 
satisfactorily adhere to the tenets of this final action (i.e., that 
they do not require mutual agreement) may qualify for a variation 
from the pro forma LGIP provision adopted in this final action.
---------------------------------------------------------------------------

f. Timing
i. Comments
    155. AWEA strongly supports the Commission's proposal to require 
the RTO/ISO-devised dispute resolution procedures to account for the 
interconnection process's time sensitivity.\267\ Generation Developers 
argue that the proposed regulation fails to meaningfully address time 
sensitivity and contends that the process could be resolved within 30 
days of initiation.\268\ FTC argues that the proposed requirement that 
RTOs/ISOs account for the time sensitivity of the generator 
interconnection process is likely to reduce a transmission provider's 
ability to delay interconnection dispute resolution.\269\ AVANGRID 
comments that any dispute resolution procedures must not result in 
``significant delay'' of the generator interconnection process.\270\
---------------------------------------------------------------------------

    \267\ AWEA 2017 Comments at 24-25.
    \268\ General Developers 2017 Comments at 19.
    \269\ FTC 2017 Comments at 10. See NOPR, FERC Stats. & Regs. ] 
32,719 at P 87.
    \270\ AVANGRID 2017 Comments at 18.
---------------------------------------------------------------------------

    156. TDU Systems state that, for non-RTO/ISO regions, it would be 
appropriate to reduce to two weeks the thirty-day period for parties to 
resolve disputes once a formal notice of the dispute has been provided. 
TDU Systems argue that nothing prevents the parties from continuing to 
attempt to

[[Page 21362]]

resolve the dispute informally once other procedures are initiated, and 
given the time sensitivity of these issues, a shorter timeframe would 
be less prejudicial to the interconnection customer.\271\
---------------------------------------------------------------------------

    \271\ TDU Systems 2017 Comments at 12.
---------------------------------------------------------------------------

    157. TDU Systems state that the rules in section 13.5 of the pro 
forma LGIP and article 27 of the pro forma LGIA provide for a thirty-
day period in which the parties will attempt to resolve a dispute, 
followed by the right for the parties to mutually agree to submit the 
dispute to arbitration; however, TDU Systems contend that the selection 
of the arbitrator can take up to thirty days, with the arbitration 
decision to be rendered within ninety days of appointment. TDU Systems 
note that, in contrast, article 10 of the SGIA and section 4.2 of the 
SGIP provide that if a dispute has not been resolved within two 
business days after receipt of a notice of the dispute, either party 
may contact FERC's Dispute Resolution Service for assistance in 
resolving the dispute.
    158. TDU Systems ask the Commission to adopt fast-track complaint 
procedures for complaints that parties cannot resolve or do not 
mutually agree to arbitrate. It recommends a fixed period of time (for 
example, sixty days) from complaint filing to Commission order 
issuance. TDU Systems recognizes that even fast-track procedures, which 
it estimates could result in order issuance twenty days from the filing 
of an answer, might still be too long for interconnection disputes and 
that there is no guarantee of fast-track procedures. TDU Systems ask 
the Commission to specify that interconnection complaints are entitled 
to fast-track complaint procedures if the Commission does not adopt a 
separate streamlined interconnection process.\272\
---------------------------------------------------------------------------

    \272\ Id. at 13.
---------------------------------------------------------------------------

ii. Commission Determination
    159. The pro forma LGIP provision adopted in this final action 
requires the appointment of a decision-maker within thirty days of the 
receipt of a request for non-binding dispute resolution and requires a 
decision within sixty days of the decision-maker's appointment. We note 
that this process would require a decision thirty days sooner than the 
arbitration process described in section 13.5 of the pro forma LGIP 
would require. While the Commission did not propose such a timeline in 
the NOPR, the Commission did express the view that any new dispute 
resolution process should ``account for the time sensitivity of the 
generator interconnection process.'' \273\ The timeline adopted here is 
consistent with this position.
---------------------------------------------------------------------------

    \273\ NOPR, FERC Stats. & Regs. ] 32,719 at P 84.
---------------------------------------------------------------------------

    160. We disagree with TDU Systems' position that we should adopt 
different timing requirements inside and outside RTOs/ISOs, and we 
instead apply this rule generically. Additionally, while TDU Systems 
point to the timing requirements in the pro forma SGIP dispute 
resolution process, we note that, as discussed more fully below, we 
decline to adopt the timing requirements in the pro forma SGIP dispute 
resolution process for the pro forma LGIP. Finally, we disagree with 
TDU Systems' request that we should require fast-track complaint 
procedures for generator interconnection disputes. Because of the fact-
specific nature of every complaint, we do not support the request to 
have fast-track complaint procedure for one category of disputes.
g. Mutual Agreement
i. Comments
    161. Multiple commenters support the elimination of the mutual 
agreement requirement.\274\ MISO states that, while it does not oppose 
this requirement, in MISO, parties to a generator interconnection 
dispute can already commence dispute resolution unilaterally. MISO 
further notes that, while a disputing party may exit its procedures at 
certain designated points to pursue the Commission complaint process or 
other remedies, no party can veto another party's ability to pursue 
dispute resolution under the procedures.\275\ Similarly, PG&E believes 
this reform is not applicable to CAISO because CAISO allows any 
disputing party to trigger dispute resolution and does not require 
agreement from a transmission owner or CAISO.\276\
---------------------------------------------------------------------------

    \274\ Generation Developers 2017 Comments at 16; EDP 2017 
Comments at 5; Invenergy 2017 Comments at 15-16; FTC 2017 Comments 
at 10; NEPOOL 2017 Comments at 8; NextEra 2017 Comments at 15; TDU 
Systems 2017 Comments at 11; AVANGRID 2017 Comments at 18.
    \275\ MISO 2017 Comments at 17-18.
    \276\ PG&E 2017 Comments at 5 (citing CAISO Tariff, eTariff, 
FERC Electric Tariff, OATT, app. DD, Section 15.5 (1.0.0)).
---------------------------------------------------------------------------

    162. EEI questions who should bear the costs for such unilateral 
activity or how such costs would be recovered.\277\ EEI states that the 
Commission has not explained how unilateral dispute resolution would 
work because it implies a non-consensual process, which is more akin to 
an adjudication.\278\ EEI is uncertain as to what authority an RTO/ISO 
would or should have in this process and whether this proposal is 
intended to limit a transmission provider's or interconnection 
customer's right to seek judicial relief.\279\
---------------------------------------------------------------------------

    \277\ EEI 2017 Comments at 28.
    \278\ Id. at 27.
    \279\ Id.
---------------------------------------------------------------------------

    163. ISO-NE and EEI contend that, if the requirement for mutual 
agreement for alternative resolution methods is removed, unnecessary 
delays and uncertainties may result.\280\ ISO-NE argues that its 
current dispute resolution process provides a disputing party with 
recourse and minimizes the potential for unnecessary delays and 
uncertainty by allowing for dispute resolution through a section 206 
complaint filed with the Commission.\281\ As a result, ISO-NE states 
that the current pro forma construct avoids disagreements being 
submitted to arbitration, which would consume significant ISO-NE 
resources.\282\
---------------------------------------------------------------------------

    \280\ ISO-NE 2017 Comments at 19; EEI 2017 Comments at 27.
    \281\ ISO-NE 2017 Comments at 19-20.
    \282\ Id. at 20-21.
---------------------------------------------------------------------------

ii. Commission Determination
    164. The provision adopted in this final action requires that 
transmission providers allow disputing parties to unilaterally seek 
dispute resolution procedures. In response to MISO and PG&E, we again 
note that, to the extent MISO and CAISO believe that they comply with 
the adopted pro forma LGIP provisions, they may explain their positions 
in their compliance filings.
    165. We also clarify for EEI that, although each party will bear 
its own costs to participate in the dispute resolution process, the 
cost of the decision-maker will be split equally among the disputing 
parties. Furthermore, we clarify for EEI that the process adopted by 
this final action, unlike the arbitration process described in section 
13.5 of the pro forma LGIP, is non-binding and thus does not limit a 
party's right to seek judicial relief.
    166. In response to ISO-NE, we note that its concerns about delays 
and uncertainty would still be present if disputing participants choose 
to participate in the existing arbitration process described in section 
13.5 of the pro forma LGIP. If transmission providers have agreed to 
participate in an arbitration process pursuant to section 13.5, other 
interconnection customers, including those in the same cluster as the 
disputing interconnection customer would experience a delay. 
Furthermore, as discussed above, multiple generation developers have 
alleged that the section 13.5 arbitration process is effectively 
unavailable to interconnection customers because

[[Page 21363]]

transmission providers are disinclined to participate. It will benefit 
the interconnection process for there to be an available avenue of 
dispute resolution to resolve a genuine matter of dispute.
    167. Additionally, in response to ISO-NE's argument that it avoids 
delay by ``allowing for'' a section 206 complaint, we answer that the 
pro forma LGIP already allows parties to file a complaint pursuant to 
section 206 of the FPA, and this option is still available even if the 
disputing parties mutually agree to the arbitration process described 
in section 13.5 of the pro forma LGIP.\283\ Thus, we disagree with ISO-
NE that ``allowing for'' the process pursuant to section 206 is 
sufficient to address our concerns with the status quo. The dispute 
resolution provisions adopted in this final action serve as an 
alternative to both the section 13.5 arbitration process and the FPA 
section 206 process. With regard to ISO-NE's suggestion that the NOPR 
proposal would consume significant ISO-NE resources, we note that the 
final action distributes the costs of the decision-maker overseeing the 
dispute resolution process equally among the parties to the dispute. 
Thus, even though transmission providers must allow for a dispute 
resolution process that a party may seek unilaterally, a transmission 
provider would only be responsible for costs if it is a party to the 
dispute. In such a scenario, the transmission provider would be 
responsible ``for its own costs incurred'' during the process (i.e., 
the cost to represent its position in the section 13.5.5 dispute 
resolution process) and the cost of the decision-maker ``divided 
equally among each Party to the dispute.'' Thus, if a transmission 
provider is not a party to a dispute, it would not be ultimately 
responsible for any costs related to the dispute resolution process. If 
the transmission provider is a party to a three party dispute, it would 
be responsible for ``its own costs incurred'' and one-third of the cost 
of the decision-maker.
---------------------------------------------------------------------------

    \283\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 290 
(stating that invocation of the arbitration process does not 
``circumscribe[] the Parties' right to avail themselves of the 
Commission's complaint process'').
---------------------------------------------------------------------------

h. SGIP DRS Process
i. Comments
    168. Competitive Suppliers argue that the Commission should 
generically adopt the dispute resolution provisions of the pro forma 
SGIP, which allow disputing parties to contact DRS.\284\ Similarly, 
ISO-NE contends that, if the Commission determines that there is a need 
to revise the existing pro forma LGIP and pro forma LGIA dispute 
resolution provisions, then the Commission should adopt the same 
approach provided for in the pro forma SGIP.\285\ TDU Systems also 
contend that parties in non-RTO/ISO regions with disputes arising under 
the LGIP and LGIA, like parties to the pro forma SGIA and pro forma 
SGIP, should have the unilateral ability to seek DRS' assistance.\286\ 
For non-RTO/ISO regions, SEIA requests that the Commission clarify that 
DRS is available to resolve interconnection disputes and will abide by 
the same general structures as those proposed in the NOPR.\287\
---------------------------------------------------------------------------

    \284\ Competitive Suppliers 2017 Comments at 6.
    \285\ ISO-NE 2017 Comments at 19.
    \286\ TDU Systems 2017 Comments at 11-13.
    \287\ SEIA 2017 Comments at 14-15. We assume SEIA is referring 
to DRS.
---------------------------------------------------------------------------

ii. Commission Determination
    169. In the NOPR, the Commission sought comment on ``the 
appropriateness of adopting procedures similar to those outlined in the 
pro forma SGIP.'' \288\ The process described in section 4.2 of the pro 
forma SGIP allows parties to contact DRS for assistance in resolving an 
interconnection dispute. Section 4.2.4 of the pro forma SGIP states 
that DRS will assist in resolving a dispute or in selecting an 
appropriate dispute resolution venue. Additionally, section 4.2.6 of 
the pro forma SGIP states that if neither party elects to contact DRS 
or if the attempted dispute resolution fails, ``either Party may 
exercise whatever rights and remedies it may have in equity or law 
consistent with the terms of these procedures.''
---------------------------------------------------------------------------

    \288\ NOPR, FERC Stats. & Regs. ] 32,719 at P 86.
---------------------------------------------------------------------------

    170. In response to the Commission's request for comments, only 
Competitive Suppliers and ISO-NE commented favorably in response to 
this suggestion. For this reason, we decline to take action to adopt 
dispute resolution procedures similar to those in the pro forma SGIP. 
Nonetheless, nothing in this final action precludes disputing parties 
from contacting DRS if they wish to participate in dispute resolution 
through that avenue.
    171. In response to SEIA, we note that, consistent with Order No. 
2003, DRS is always available to assist parties in resolving generator 
interconnection disputes. We note, however, that the new requirements 
imposed by this final action apply only to the non-binding dispute 
resolution process established through new section 13.5.5 in the pro 
forma LGIP, which is a non-DRS process.
5. Capping Costs for Network Upgrades
a. NOPR Request for Comments
    172. As part of the interconnection feasibility study and system 
impact study, the pro forma LGIP requires that transmission providers 
provide a good faith estimate of the cost of interconnection facilities 
and network upgrades needed to accommodate an interconnection 
customer's requested level of interconnection service.\289\ The 
transmission provider includes this cost estimate with the facilities 
study results, typically with a stated accuracy margin within 10 to 20 
percent of the estimate.\290\ After completion of the construction of 
the transmission provider's interconnection facilities and network 
upgrades needed to interconnect a generating facility, the transmission 
provider conducts a true-up to assess the final cost of construction to 
the interconnection customer. The transmission provider provides a 
final invoice to the interconnection customer that details variations 
between actual and estimated costs. Overpayment by the interconnection 
customer results in a refund to the interconnection customer, or a 
surcharge in case of an underpayment.\291\
---------------------------------------------------------------------------

    \289\ See, e.g., pro forma LGIP Sections 6.2 and 7.3.
    \290\ Pro forma LGIP Section 8.3.
    \291\ Pro forma LGIA Art. 12.
---------------------------------------------------------------------------

    173. The Commission sought comment on whether it should revise the 
pro forma LGIP and pro forma LGIA to provide for a cost cap that would 
limit an interconnection customer's network upgrade costs at the higher 
bound of a transmission provider's cost estimate plus a stated accuracy 
margin following a certain stage in the interconnection study process. 
Such a cap could permit the interconnection customer to assume costs 
that exceed the cap under limited circumstances, such as where there is 
demonstrable proof that the cause of a cost increase is beyond the 
transmission provider's control.\292\ The cost cap could also specify 
which party or parties would assume network upgrade costs in excess of 
the cap. The Commission further sought comment on how to minimize 
potential cost shifts to other parties if such a cost cap is imposed. 
The Commission also sought comments on alternative proposals, or 
additional steps that the Commission could take, to provide more cost 
certainty to

[[Page 21364]]

interconnection customers during the interconnection study 
process.\293\
---------------------------------------------------------------------------

    \292\ NOPR, FERC Stats. & Regs. ] 32,719 at P 95.
    \293\ Id.
---------------------------------------------------------------------------

b. Comments
    174. A minority of commenters,\294\ primarily renewable generation 
developers and transmission owners in CAISO, support the idea of 
network upgrade cost caps. AWEA notes that interconnection customers 
often pay costs that exceed the upper bound of a transmission 
provider's estimates, and this can significantly disrupt an 
interconnection customer's business model.\295\ AWEA argues that a cost 
cap would protect interconnection customers from cost overruns, allow 
them to accurately assess risk, and reduce the number of late-stage 
withdrawals due to increased cost certainty, which in turn would 
produce more accurate cost estimates.\296\ AWEA, Generation Developers, 
and NextEra assert that the imposition of a cost cap should incentivize 
more accurate cost estimates, and AWEA contends that cost shifts should 
be minimal if the transmission provider estimates costs more 
accurately.\297\
---------------------------------------------------------------------------

    \294\ These commenters include: AWEA 2017 Comments at 26; CAISO 
2017 Comments at 13; First Solar 2017 Comments at 4; Joint Renewable 
Parties 2017 Comments at 3; Generation Developers 2017 Comments at 
22-23; EDP 2017 Comments at 5-6; NextEra 2017 Comments at 17' and 
PG&E 2017 Comments at 5.
    \295\ AWEA 2017 Comments at 25.
    \296\ Id. at 25-26.
    \297\ Id. at 27; Generation Developers 2017 Comments at 23-24; 
NextEra 2017 Comments at 17-19.
---------------------------------------------------------------------------

    175. Generation Developers argue that if there is an overage from 
the cost estimate, it is just and reasonable to socialize that overage. 
Generation Developers acknowledge that this is a variation from strict 
``but for'' interconnection policy but assert that the variation is 
justified because all users of the transmission network receive 
benefits from the interconnection customer's network upgrades.
    176. APS, AVANGRID, Bonneville, EDP, Generation Developers, 
Invenergy, MISO TOs, NextEra, NorthWestern, and Tri-State contend that 
cost caps could lead to inflated cost estimates for network 
upgrades.\298\ On the other hand, commenters that support cost caps 
argue that increased cost estimates can either be addressed or are a 
reasonable trade-off for implementing a cost cap.\299\
---------------------------------------------------------------------------

    \298\ APS 2017 Comments at 3; AVANGRID 2017 Comments at 20; 
Bonneville 2017 Comments at 3; EDP 2017 Comments at 5; Generation 
Developers 2017 Comments at 24; Invenergy 2017 Comments at 9; MISO 
TOs 2017 Comments at 10-11; NextEra 2017 Comments at 17; 
NorthWestern 2017 Comments at 4; Tri-State 2017 Comments at 5.
    \299\ Generation Developers 2017 Comments at 24, AWEA 2017 
Comments at 27, and NextEra 2017 Comments at 18.
---------------------------------------------------------------------------

    177. CAISO states that, while cost caps come with some risk, they 
allow generators to have clear demarcations for their financial 
responsibilities going forward, which CAISO believes mitigates risk and 
financial uncertainty when generators submit proposals to provide 
capacity and later seek financing for construction.\300\
---------------------------------------------------------------------------

    \300\ CAISO 2017 Comments at 13.
---------------------------------------------------------------------------

    178. Most responsive commenters \301\ oppose revising the pro forma 
LGIP and pro forma LGIA to impose network upgrade cost caps. Several 
opposing commenters argue that cost caps would unfairly shift network 
upgrade costs from interconnection customers to load, transmission 
customers, or other interconnection customers that neither benefit from 
the generation nor caused the need for the upgrades.\302\ Several 
commenters also assert that cost caps would violate the Commission's 
``but for'' and cost causation policies for the assignment of 
interconnection network upgrade costs.\303\ Duke, EEI, and NorthWestern 
contend that if the Commission establishes a cost cap and requires that 
transmission providers assume any excess costs, transmission providers 
could face challenges of whether such costs are prudent transmission 
investments.\304\ EEI, Non-Profit Utility Trade Associations, and TAPS 
argue that implementing cost caps will likely result in more frequent 
and contentious litigation.\305\
---------------------------------------------------------------------------

    \301\ Alliant 2017 Comments at 5; AEP 2017 Comments at 3; AFPA 
2017 Comments at 5; AVANGRID 2017 Comments at 19; Bonneville 2017 
Comments at 3; Competitive Suppliers 2017 Comments at 7; Duke 2017 
Comments at 7; EEI 2017 Comments at 28; ELCON 2017 Comments at 2; 
Eversource 2017 Comments at 12; Imperial 2017 Comments at 18; 
IECA2017 Comments at 2; ISO-NE 2017 Comments at 21; ITC 2017 
Comments at 12-13; MidAmerican 2017 Comments at 11-12; MISO 2017 
Comments at 21; MISO TOs 2017 Comments at 7; Modesto 2017 Comments 
at 18; NEPOOL 2017 Comments at 9; Non-Profit Utility Trade 
Associations 2017 Comments at 6; NorthWestern 2017 Comments at 4; 
NYISO 2017 Comments at 19; PJM 2017 Comments at 9; PSEG/PPL 2017 
Comments at 3; Salt River 2017 Comments at 9; Southern 2017 Comments 
at 15-16; TAPS 2017 Comments at 3; TDU Systems 2017 Comments at 14-
16; Tri-State 2017 Comments at 5; TVA 2017 Comments at 6-7; Xcel 
2017 Comments at 11.
    \302\ Alliant 2017 Comments at 6; AEP 2017 Comments at 3; Duke 
2017 Comments at 7; EEI 2017 Comments at 29; ELCON 2017 Comments at 
2,5; Idaho Power 2017 Comments at 2-3; Imperial 2017 Comments at 19; 
IECA 2017 Comments at 2; ISO-NE 2017 Comments at 22; MidAmerican 
2017 Comments at 11-12; MISO 2017 Comments at 21; MISO TOs 2017 
Comments at 7; Modesto 2017 Comments at 19; Non-Profit Utility Trade 
Associations 2017 Comments at 6; NorthWestern 2017 Comments at 4; 
PJM 2017 Comments at 10; PSEG/PPL 2017 Comments at 5; Salt River 
2017 Comments at 9; Southern 2017 Comments at 15-16; TAPS 2017 
Comments at 5; TDU Systems 2017 Comments at 14-16; TVA 2017 Comments 
at 6-7.
    \303\ AEP 2017 Comments at 5; AVANGRID 2017 Comments at 20; EEI 
2017 Comments at 28-29; ITC 2017 Comments at 12-13; MISO 2017 
Comments at 21; MISO TOs 2017 Comments at 7; PJM 2017 Comments at 9-
10; PSEG/PPL 2017 Comments at 5; Salt River 2017 Comments at 9; 
Southern 2017 Comments at 15-16; TAPS 2017 Comments at 6; TDU 
Systems 2017 Comments at 14-16; TVA 2017 Comments at 6-7.
    \304\ Duke 2017 Comments at 7-8; EEI 2017 Comments at 29-30; 
NorthWestern 2017 Comments at 4.
    \305\ EEI 2017 Comments at 33-34; Non-Profit Utility Trade 
Associations 2017 Comments at 11; TAPS 2017 Comments at 7.
---------------------------------------------------------------------------

    179. Modesto argues that because smaller entities do not frequently 
estimate interconnection facility and network upgrade costs, their cost 
estimates are likely susceptible to greater variability, which could 
lead to a greater inaccuracy. Modesto asserts that smaller entities 
essentially would be penalized through cost caps on network 
upgrades.\306\
---------------------------------------------------------------------------

    \306\ Modesto 2017 Comments at 19-20.
---------------------------------------------------------------------------

    180. Several commenters contend that cost caps are unwarranted 
because many of the variables that affect cost estimates are outside 
the transmission provider's control and are based on the best data 
available at the time.\307\ AFPA argues that cost caps remove risk from 
interconnection customers and may remove the incentive for 
interconnection customers to mitigate cost overruns in network 
upgrades.\308\ IECA expresses concern that industrial consumers will 
have to pay for cost overruns resulting from a cost cap and that cost 
caps would encourage developers and utilities to be equally complacent 
about cost overruns.\309\
---------------------------------------------------------------------------

    \307\ AEP 2017 Comments at 3; Duke 2017 Comments at 7; EEI 2017 
Comments at 30-32; ITC 2017 Comments at 14-15; MidAmerican 2017 
Comments at 12; MISO 2017 Comments at 21; MISO TOs 2017 Comments at 
10-11; PSEG/PPL 2017 Comments at 5; Salt River 2017 Comments at 9; 
Southern 2017 Comments at 16; Tri-State 2017 Comments at 5.
    \308\ AFPA 2017 Comments at 9.
    \309\ IECA 2017 Comments at 2.
---------------------------------------------------------------------------

    181. ITC, MISO, Non-Profit Utility Trade Associations, and Xcel 
state that well-defined milestones and milestone payments are 
preferable to a cost cap.\310\
---------------------------------------------------------------------------

    \310\ ITC 2017 Comments at 15; MISO 2017 Comments at 22-23; Non-
Profit Utility Trade Associations 2017 Comments at 1-2, 4, 10-11; 
Xcel 2017 Comments at 12.
---------------------------------------------------------------------------

    182. NYISO and Indicated NYTOs state that NYISO already has a 
process in place in its tariff to allocate actual costs that exceed 
cost estimates.\311\ Indicated NYTOs contend that NYISO's provisions 
encourage interconnection

[[Page 21365]]

customers to efficiently locate their generating facility and strike a 
reasonable balance between providing certainty to interconnection 
customers and minimizing the imposition of unnecessary costs to 
load.\312\ NYISO asserts that adoption of bright line cost caps would 
likely require more detailed studies, cost estimates, and increased 
cost and time, contrary to the stated principles of the NOPR.\313\ 
NEPOOL notes that New England resolved its disputes over cost 
allocation for interconnections and regional transmission upgrades well 
over a decade ago through the interconnection cost allocation method in 
the ISO-NE OATT.\314\
---------------------------------------------------------------------------

    \311\ NYISO 2017 Comments at 19; Indicated NYTOs 2017 Comments 
at 5.
    \312\ Indicated NYTOs 2017 Comments at 6.
    \313\ NYISO 2017 Comments at 19.
    \314\ NEPOOL 2017 Comments at 9.
---------------------------------------------------------------------------

    183. Salt River and TVA believe that it would be inappropriate for 
the Commission to attempt to impose a cap on the costs that can be 
collected by a not-for-profit governmental utility, via the reciprocity 
condition or otherwise.\315\
---------------------------------------------------------------------------

    \315\ Salt River 2017 Comments at 10; TVA 2017 Comments at 6-7.
---------------------------------------------------------------------------

    184. CAISO states that its system of cost caps may be more 
difficult to implement outside of regions where ratepayers ultimately 
pay for generator interconnection-driven network upgrades.\316\ CAISO 
notes that, in CAISO, the interconnection customer only provides the 
initial financing for its network upgrades.\317\ CAISO states that, 
upon reaching commercial operation, those costs are reimbursed by the 
transmission owner and included in that transmission owner's 
transmission revenue requirement paid by ratepayers.\318\
---------------------------------------------------------------------------

    \316\ CAISO 2017 Comments at 14.
    \317\ Id.
    \318\ Id.
---------------------------------------------------------------------------

    185. AFPA, ELCON, ITC, SEIA, and Invenergy assert that policies 
other than cost caps will provide greater downward pressure on network 
upgrade costs including improving cost transparency, transmission 
planning that anticipates future generation needs, and aligning 
interconnection procedures with resource procurement processes.\319\
---------------------------------------------------------------------------

    \319\ AFPA 2017 Comments at 5; ELCON 2017 Comments at 5; ELCON 
2017 Comments at 5; ITC 2017 Comments at 15; SEIA 2017 Comments at 
15; Invenergy 2017 Comments at 9-10.
---------------------------------------------------------------------------

    186. Eversource suggests that the Commission instead explore the 
transmission provider's cost estimation process.\320\ Eversource 
suggests that, to improve cost estimates, the Commission should require 
interconnection customers to use the currently optional facilities 
study in the LGIP.\321\
---------------------------------------------------------------------------

    \320\ Eversource 2017 Comments at 13-14.
    \321\ Id. at 15.
---------------------------------------------------------------------------

    187. Xcel recommends that, instead of imposing cost caps, the 
Commission should reevaluate its policy discussed in Order No. 2003 and 
implement regional variations that allow transmission costs to be 
assigned to the interconnection customer after the execution of an 
LGIA.\322\ Xcel further recommends limiting the interconnection 
customer's cost responsibility to the specific facilities identified in 
the signed LGIA, rather than allowing the RTO/ISO, as transmission 
provider, to later modify the list of required facilities. Xcel asserts 
that if facilities are identified after the interconnection customer 
and transmission provider sign an LGIA, the costs of those facilities 
should be recovered from transmission customers through the 
transmission expansion cost allocation processes in the RTO/ISO tariff. 
Xcel believes that the Commission should allow regions to determine if 
or when such costs are allocated either locally or regionally to 
transmission customers.\323\
---------------------------------------------------------------------------

    \322\ Xcel 2017 Comment at 12.
    \323\ Id. at 12-13.
---------------------------------------------------------------------------

    188. TAPS opposes a generic rule establishing a cost cap and also 
opposes a generic rule that bars all cost caps.\324\ Duke states that 
transmission providers should be able to voluntarily adopt cost caps if 
done so through stakeholder processes.\325\
---------------------------------------------------------------------------

    \324\ TAPS 2017 Comments at 8.
    \325\ Duke 2017 Comments at 8.
---------------------------------------------------------------------------

c. Commission Determination
    189. In this final action, we decline to take any action related to 
capping costs for network upgrades. We find that there is insufficient 
evidence in the record to support cost caps as a preferred solution to 
reducing variances from cost estimates and providing greater cost 
certainty to interconnection customers. Therefore, we decline to 
propose revisions to the pro forma LGIP and pro forma LGIA to institute 
a cap on the cost of network upgrades required for interconnection. 
However, as suggested by Duke, we will not bar a transmission provider 
from proposing to establish cost caps for network upgrade costs within 
its footprint by submitting a separate filing pursuant to section 205 
of the FPA.
    190. We recognize the value of providing more accurate cost 
estimates to interconnection customers of the network upgrades needed 
to interconnect their generating facilities. Smaller deviations between 
the cost estimate and the final costs of the network upgrades would 
reduce risk and uncertainty faced by the interconnection customer. We 
note that other actions in this final action, including the reforms on 
transparency regarding study models and assumptions and identification 
and definition of contingent facilities, could contribute to improved 
accuracy of cost estimates for network upgrades. Additionally, we 
understand that greater cost certainty, where reasonably achievable 
without creating overly onerous requirements, could reduce queue 
withdrawals and their cascading effects on other projects within the 
queue. We encourage transmission providers and stakeholders to continue 
to work together to improve the cost estimation process.

B. Promoting More Informed Interconnection

    191. In the NOPR, the Commission proposed reforms designed to 
improve interconnection process transparency and provide improved 
information to benefit all participants in the interconnection process. 
In addition to the proposed reforms, the Commission sought comment on 
proposals or additional steps that the Commission could take to improve 
the resolution of issues that arise when affected systems are impacted 
by a proposed interconnection.
1. Identification and Definition of Contingent Facilities
a. NOPR Proposal
    192. The Commission currently requires transmission providers to 
identify for interconnection customers contingencies affecting 
interconnection studies \326\ and list applicable contingent facilities 
in interconnection agreements.\327\ In the NOPR, the Commission 
proposed to revise the pro forma LGIP to require transmission providers 
to detail the methods they use to determine which facilities are 
contingent facilities. The Commission proposed that a method be 
transparent and sufficiently detailed to allow interconnection 
customers to determine why a specific contingent facility is included 
and how it impacts the interconnection request. The Commission also 
proposed that

[[Page 21366]]

transmission providers provide the contingent facility list at the 
conclusion of the system impact study. The Commission further proposed 
that the transmission provider should, upon request, provide the 
estimated network upgrade costs and in-service completion time 
associated with each identified contingent facility when this 
information is not commercially sensitive. In particular, the 
Commission proposed to add a new section 3.8 to the pro forma LGIP as 
follows (with proposed additions in italics):
---------------------------------------------------------------------------

    \326\ Pro forma LGIP Section 2.3.
    \327\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 409 
(``[i]f it is apparent to the Parties . . . that contingencies (such 
as other Interconnection Customers terminating their LGIAs) might 
affect the financial arrangements, the Parties should include such 
contingencies in their LGIA and address the effect of such 
contingencies on their financial obligations'').

    3.8 Identification of Contingent Facilities
    Transmission Provider shall post in this section a method for 
identifying the Contingent Facilities to be provided to 
Interconnection Customer at the conclusion of the System Impact 
Study and included in Interconnection Customer's GIA. 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 not commercially sensitive.

    193. In addition, the Commission proposed to add the following new 
definition to section 1 of the pro forma LGIP (with proposed additions 
in italics):

    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 
not built, could cause a need for interconnection restudies or 
reassessments of the network upgrades, costs, or timing.

    194. The Commission also sought further comment on how transmission 
providers currently identify contingent facilities, as well as 
additional recommendations to improve the existing approach. Finally, 
the Commission sought comment on whether the method for determining 
contingent facilities should be harmonized as much as possible. To this 
end, the Commission sought comment on the usefulness of requiring 
transmission providers to include a distribution factor analysis in 
their methodologies for identifying contingent facilities, and if so, 
whether a specific distribution factor should be implemented in the pro 
forma LGIP (e.g., a five percent distribution factor).
b. General
i. Comments
    195. Most responsive commenters support \328\ or do not oppose 
\329\ the proposal to require transmission providers to publish a 
method for identifying contingent facilities in the LGIP. Several 
commenters state that the proposal will better inform the 
interconnection process and may lead to lower costs and fewer 
withdrawals.\330\ AWEA, Invenergy, and EDP cite inconsistent or non-
transparent treatment of contingent facilities across regions.\331\ 
Several commenters assert that the proposal will reduce opportunities 
for undue discrimination and disputes.\332\
---------------------------------------------------------------------------

    \328\ Alevo 2017 Comments at 5-6; AFPA 2017 Comments at 10; Non-
Profit Utility Trade Associations 2017 Comments at 12-13; AWEA 2017 
Comments at 30; Bonneville 2017 Comments at 4; Joint Renewable 
Parties 2017 Comments at 10; Generation Developers at 25; SEIA 2017 
Comments at 7; Portland 2017 Comments at 2; NEPOOL 2017 Comments at 
9-10; NextEra 2017 Comments at 20; ITC 2017 Comments at 16; 
Invenergy 2017 Comments at 11.
    \329\ MISO TOs 2017 Comments at 26; Non-Profit Utility Trade 
Associations 2017 Comments at 12.
    \330\ AFPA 2017 Comments at 10; AWEA 2017 Comments at 30; NEPOOL 
2017 Comments at 10; NextEra 2017 Comments at 20; Invenergy 2017 
Comments at 12; EDP 2017 Comments at 6.
    \331\ EDP 2017 Comments at 6; AWEA 2017 Comments at 29; 
Invenergy 2017 Comments at 11.
    \332\ AFPA 2017 Comments at 10; EDP 2017 Comments at 6; AWEA 
2017 Comments at 31; Invenergy 2017 Comments at 11.
---------------------------------------------------------------------------

    196. AWEA and NextEra contend that the proposal will place a 
minimal burden on transmission providers.\333\ ISO-NE comments that the 
proposal appropriately balances the need for regional flexibility to 
maintain the existing methods with the need to improve transparency 
regarding the interconnection process.\334\ CAISO states that 
information on contingent facilities is important to inform an 
interconnection customer about potential delays that might necessitate 
renegotiation of the interconnection customer's power purchase 
agreement. NextEra supports the Commission's guidance that a 
transmission provider's method to determine contingent facilities be 
detailed and states that an unverified list of contingent facilities 
creates uncertainty regarding potential restudies and revised cost 
responsibility for the interconnection customer.\335\
---------------------------------------------------------------------------

    \333\ AWEA 2017 Comments at 31; NextEra 2017 Comments at 21.
    \334\ ISO-NE 2017 Comments at 25.
    \335\ NextEra 2017 Comments at 20.
---------------------------------------------------------------------------

    197. AWEA comments that the interconnection customer should not be 
financially responsible for any facilities that are not listed among 
the contingent facilities and that even contingent facilities omitted 
in error should not be the financial responsibility of the 
interconnection customer.\336\
---------------------------------------------------------------------------

    \336\ AWEA 2017 Comments at 34
---------------------------------------------------------------------------

    198. A minority of responsive commenters oppose the proposal.\337\ 
MISO and Southern request that the Commission permit transmission 
providers to post the proposed information in their business practice 
manuals or OASIS-posted business practices rather than in the LGIP, as 
this information is technical and more suitable for a business practice 
manual and may need frequent changes to address characteristics of new 
technologies.\338\ Several commenters state that no new procedures are 
necessary to identify and define contingent facilities.\339\
---------------------------------------------------------------------------

    \337\ Modesto 2017 Comments at 21; Southern 2017 Comments at 19; 
EEI 2017 Comments at 38.
    \338\ MISO 2017 Comments at 24-25; Southern 2017 Comments at 19.
    \339\ AES 2017 Comments at 8-9; Southern 2017 Comments at 19.
---------------------------------------------------------------------------

ii. Commission Determination
    199. We adopt the NOPR proposal to add a new section 3.8 to the pro 
forma LGIP requiring transmission providers to publish a method for 
identifying contingent facilities in their LGIPs subject to 
clarification as outlined below. Specifically, the Commission adds 
section 3.8 to the pro forma LGIP as follows (with clarifying additions 
to the language originally proposed in the NOPR in italics):

3.8 Identification of Contingent Facilities

    Transmission Provider shall post in this section a method for 
identifying the Contingent Facilities to be provided to 
Interconnection Customer at the conclusion of the System Impact 
Study and included in Interconnection Customer's GIA. 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.

    200. We note that commenters widely support the adoption of this 
requirement. We agree with commenters that this requirement will 
increase transparency in the interconnection process, better inform 
interconnection customers, and, consequently, result in fewer 
interconnection disputes and withdrawals. The Commission notes that, 
while some transmission providers may provide information on contingent

[[Page 21367]]

facilities, the record indicates that this information may not be 
available from all transmission providers. We find that requiring 
transmission providers to publish a method for determining contingent 
facilities in the LGIP will ensure that there will be a transparent 
method applied on a non-discriminatory basis across all regions. We 
also disagree with MISO's and Southern's arguments that it would be 
more appropriate to publish methods for identifying contingent 
facilities in business practice manuals or on OASIS. The Commission's 
``rule of reason'' policy \340\ requires provisions that significantly 
affect rates, terms, and conditions should be in the filed tariff.\341\ 
The Commission finds, based on the record above, that information on 
contingent facilities materially affects rates, terms, and conditions, 
and therefore, needs to be part of the tariff. However, while 
transmission providers will have to publish their methods in the LGIP, 
certain technical implementation details relating to the methods that, 
consistent with the rule of reason, have less direct effect on rates, 
terms and conditions, may be published in a business practice manual.
---------------------------------------------------------------------------

    \340\ See Pacificorp, 127 FERC ] 61,144, at P 11 (2009); City of 
Cleveland, Ohio v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985) 
(finding that utilities must file ``only those practices that affect 
rates and service significantly, that are reasonably susceptible of 
specification, and that are not so generally understood in any 
contractual arrangement as to render recitation superfluous''); 
Public Serv. Comm'n of N.Y. v. FERC, 813 F.2d 448, 454 (D.C. Cir. 
1987) (holding that the Commission properly excused utilities from 
filing policies or practices that dealt with only matters of 
``practical insignificance'' to serving customers).
    \341\ Cal. Indep. Sys. Operator Corp. 119 FERC ] 61,076, at P 
656 (2007) (citing ANP Funding I, LLC v. ISO-NE, Inc., 110 FERC ] 
61,040, at P 22 (2005); Prior Notice and Filing Requirements Under 
Part II of the Federal Power Act, 64 FERC ] 61,139, at 61,986-89, 
order on reh'g, 65 FERC ] 61,081 (1993)).
---------------------------------------------------------------------------

    201. We disagree with AWEA's argument that the final action should 
exempt the interconnection customer from financial responsibility for 
any facilities that are not identified as contingent facilities, 
because changes in the interconnection queue may require changes to or 
subtractions from the list of contingent facilities. Thus, we find that 
the final action strikes the right balance to accomplish our goal of 
increasing transparency.
c. Timing
i. Comments
    202. Several commenters support the proposal that transmission 
providers provide the list of contingent facilities applicable to an 
interconnection request at the close of the system impact study 
phase.\342\ AWEA comments that the timing for the identification of 
contingent facilities has been a major issue for interconnection 
customers. It argues that, currently, interconnection customers only 
receive relevant contingent facility information after signing an LGIA. 
AWEA asserts that the timing requirements in this proposal remove risk 
for the interconnection customer.\343\
---------------------------------------------------------------------------

    \342\ AWEA 2017 Comments at 31; Duke 2017 Comments at 8; 
Generation Developers 2017 Comments at 25; MISO 2017 Comments at 25-
26; TDU Systems 2017 Comments at 26.
    \343\ AWEA 2017 Comments at 31.
---------------------------------------------------------------------------

    203. MISO requests that the Commission clarify that, in the context 
of MISO's phased system impact study process, the requirement would 
apply only after the final system impact study.\344\
---------------------------------------------------------------------------

    \344\ MISO 2017 Comments at 26.
---------------------------------------------------------------------------

ii. Commission Determination
    204. We adopt the NOPR proposal to require transmission providers 
to provide the list of contingent facilities applicable to an 
interconnection request at the close of the system impact study phase. 
The system impact study considers generating facilities and identified 
network upgrades associated with higher-queued interconnection 
requests, and an accompanying list of contingent facilities can 
contextualize these results. We find that this timing allows 
interconnection customers to access contingent facility information 
early enough to better understand their potential risk exposure and to 
expedite decisions on queue withdrawal, resulting in a more efficient 
interconnection process. We note that the majority of responsive 
commenters support the requirement to provide contingent facility 
information at the conclusion of the system impact study phase. In 
response to MISO's request that we address how the final action applies 
to its system impact study process, we will evaluate each transmission 
provider's tariff provisions at the time that it submits its compliance 
filing. In that filing, MISO can explain how its compliance proposal 
allows for the interconnection customer to use contingent facilities 
information to understand risk exposure and expedite decisions on queue 
withdrawal.
d. Requirements for Estimated Network Upgrade Costs and In-Service 
Completion Times
i. Comments
    205. A majority of responsive commenters support the proposed 
requirement to provide the costs and in-service completion time for 
each identified contingent facility.\345\ AWEA states that 
interconnection customers use information about potential cost 
increases, as well as timing of necessary upgrades, to make business 
decisions and assess risk.\346\ Generation Developers explain that 
there is little value in identifying a contingent facility if the 
interconnection customer still has no information about its associated 
costs and timing.\347\ AWEA contends that non-disclosure agreements can 
address commercial sensitivities related to contingent facilities.\348\ 
Invenergy states that PJM, MISO, and SPP already provide this 
information in some form and that it is unaware of any commercially 
sensitive information that would need to be revealed in this 
process.\349\ Other commenters state that the burden on transmission 
providers would be minimal.\350\
---------------------------------------------------------------------------

    \345\ AWEA 2017 Comments at 32; Alevo 2017 Comments at 5-6; 
Forecasting Coalition 2017 Comments at 4; Generation Developers 2017 
Comments at 26; TDU Systems 2017 Comments at 16-17; NEPOOL 2017 
Comments at 10; NextEra 2017 Comments at 20; SEIA 2017 Comments at 
7.
    \346\ AWEA 2017 Comments at 32.
    \347\ Generation Developers 2017 Comments at 26.
    \348\ AWEA 2017 Comments at 32.
    \349\ Invenergy 2017 Comments at 12.
    \350\ NextEra 2017 Comments at 20; AWEA 2017 Comments at 32.
---------------------------------------------------------------------------

    206. Duke, MidAmerican, and EEI oppose the proposed requirement to 
provide estimated network upgrade costs and in-service completion times 
for each identified contingent facility.\351\ EEI argues that the 
Commission should address concerns related to potential commercially-
sensitive information and Critical Energy/Electric Infrastructure 
Information (CEII). It asks the Commission to clarify that transmission 
providers need not disclose proprietary, commercially-sensitive, or 
CEII information without the appropriate consent and/or non-disclosure 
protections.\352\ EEI also has concerns about the proposal's costs and 
the appropriate recovery mechanisms.\353\ Duke states that schedules 
and cost estimates for milestones are available on OASIS via links to 
completed generator interconnection studies.\354\
---------------------------------------------------------------------------

    \351\ Duke 2017 Comments at 9-10; MidAmerican 2017 Comments at 
8; EEI 2017 Comments at 38.
    \352\ EEI 2017 Comments at 39.
    \353\ Id.
    \354\ Duke 2017 Comments at 8.
---------------------------------------------------------------------------

    207. A number of commenters state that some or all of the 
information referenced in the proposal is already made available in 
their region. ISO-NE states that estimated costs and in-service 
completion times associated with contingent facilities are available in 
the

[[Page 21368]]

interconnection study reports for the higher-queued projects that are 
primarily responsible for the cost of the contingent facility, and 
those reports are available to interconnection customers on the ISO-NE 
website.\355\ Bonneville states that it provides general estimates and 
schedules associated with contingent facilities in its study 
reports.\356\ MISO states that it already provides the estimated 
network upgrade costs and in-service completion time of each identified 
contingent facility via its MISO Transmission Expansion Plan process, 
updated quarterly and posted publicly.\357\ MidAmerican comments that 
it sees no value in providing this information and expresses concern 
about the potential administrative burden.\358\
---------------------------------------------------------------------------

    \355\ ISO-NE 2017 Comments at 24.
    \356\ Bonneville 2017 Comments at 4.
    \357\ MISO 2017 Comments at 25.
    \358\ MidAmerican 2017 Comments at 8.
---------------------------------------------------------------------------

    208. TVA comments that it is difficult to estimate the in-service 
timing of contingent facilities in the system impact study phase, as 
often the full scope of work is not known until the facilities 
study.\359\ TVA adds that to provide this information at the system 
impact study phase would increase the cost and duration of all system 
impact study efforts.\360\
---------------------------------------------------------------------------

    \359\ TVA 2017 Comments at 8.
    \360\ Id.
---------------------------------------------------------------------------

    209. Several commenters suggest that the Commission modify or 
clarify this aspect of the proposal. NextEra suggests clarifying the 
proposal to limit the information the transmission provider provides to 
the interconnection customer based on what the transmission provider 
could reasonably access so that transmission providers need not obtain 
information that they may not readily have available.\361\ Similarly, 
while Portland does not object to this aspect of the proposal, it 
argues that such information would be limited to the best information 
that the transmission provider has access to at the time.\362\
---------------------------------------------------------------------------

    \361\ NextEra 2017 Comments at 20.
    \362\ Portland 2017 Comments at 3.
---------------------------------------------------------------------------

    210. Forecasting Coalition and Alevo suggest that the transmission 
provider provide additional information to the interconnection 
customer. Alevo suggests that transmission providers also provide ``a 
detailed list of the symptoms that the transmission owner/operator is 
trying to cure.'' \363\ Alevo comments that this information may allow 
the interconnection customer to offer a more cost-effective solution 
(e.g., installing electric storage rather than building a new 
substation).\364\ Forecasting Coalition requests that the transmission 
provider identify the facility's limiting element along with the 
details on the electrical limiting element's rating.\365\
---------------------------------------------------------------------------

    \363\ Alevo 2017 Comments at 5-6.
    \364\ Id.
    \365\ Forecasting Coalition 2017 Comments at 4.
---------------------------------------------------------------------------

    211. AWEA and Generation Developers argue that the transmission 
provider should have to provide information on each identified 
contingent facility's estimated costs and timing even if the 
interconnection customer has not explicitly requested it.\366\
---------------------------------------------------------------------------

    \366\ AWEA 2017 Comments at 31-32; Generation Developers 2017 
Comments at 25-26.
---------------------------------------------------------------------------

ii. Commission Determination
    212. We adopt the NOPR proposal, subject to modification, and 
require the transmission provider to provide, upon request of the 
interconnection customer, the estimated network upgrade costs and 
estimated in-service completion time associated with each identified 
contingent facility when this information is readily available \367\ 
and not commercially sensitive. We are persuaded by comments that 
contend that this information helps interconnection customers to better 
assess the business risks associated with contingent facilities and may 
prevent instances of late-stage withdrawal. We find that these 
benefits, in turn, lead to a more efficient and informed 
interconnection process.
---------------------------------------------------------------------------

    \367\ In Order No. 792, the Commission defined ``readily 
available'' information as ``information that the [t]ransmission 
[p]rovider currently has on hand,'' which does not require that the 
transmission provider create new data. Small Generator 
Interconnection Agreements and Procedures, Order No. 792, 145 FERC ] 
61,159, at PP 63-64 (2013), clarified, Order No. 792-A, 146 FERC ] 
61,214 (2014) (Order No. 792-A).
---------------------------------------------------------------------------

    213. In response to comments on the administrative burden created 
by this proposal, we find NextEra's and Portland's comments persuasive. 
We therefore modify the proposal to clarify that transmission providers 
must provide information regarding costs and in-service completion 
times only if such information is ``readily available.'' This will also 
address TVA's concerns about increasing the costs of the system impact 
study phase. This clarification strikes a balance between providing 
more information for the interconnection customer and limiting the 
scope of what the transmission provider must do.
    214. In response to EEI's concern about commercially-sensitive 
information and CEII, we clarify that the final action does not require 
the transmission provider to disclose any such information without 
appropriate non-disclosure protections.
    215. In response to comments from AWEA and Generation Developers 
requesting that transmission providers provide information regarding 
costs and in-service completion times regardless of whether the 
interconnection customer requests it, we disagree. We note, consistent 
with comments from MidAmerican, that not all interconnection customers 
may need access to this information.\368\ The aim of the requirements 
adopted here is to improve transparency and better inform 
interconnection customer decision-making. Thus, if the interconnection 
customer does not request cost or in-service completion date 
information, we find it unnecessary to require the transmission 
provider to produce this information.
---------------------------------------------------------------------------

    \368\ MidAmerican 2017 Comments at 8.
---------------------------------------------------------------------------

    216. In response to comments from Alevo and Forecasting Coalition 
requesting that the transmission provider provide additional 
information related to line ratings and underlying symptoms, we find 
that such information is outside the scope of the NOPR proposal, which 
focuses on contingent facilities.
e. Definition of Contingent Facility
i. Comments
    217. AWEA and Generation Developers support the proposed definition 
of contingent facilities.\369\ MISO does not oppose the proposed 
definition.\370\ Southern suggests revising the definition to include a 
reference to the effect of delayed contingent facilities on an 
interconnection request.\371\
---------------------------------------------------------------------------

    \369\ AWEA 2017 Comments at 30; Generation Developers 2017 
Comments at 25.
    \370\ MISO 2017 Comments at 24.
    \371\ Southern 2017 Comments at 20.
---------------------------------------------------------------------------

ii. Commission Determination
    218. We adopt the proposed definition in the NOPR for contingent 
facilities, with a minor modification to reflect Southern's comments. 
Specifically, we adopt the following definition of contingent 
facilities (with clarifying additions to the language originally 
proposed in the NOPR in italics):

    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.

[[Page 21369]]

f. Harmonization
i. Comments
    219. Most responsive commenters oppose harmonization.\372\ AWEA 
supports a harmonized requirement but explains that it is more critical 
that each transmission provider detail the method it will use to 
determine contingent facilities.\373\ AWEA asserts that, if a three to 
five percent distribution factor test increases the availability of 
interconnection service, then it is a just and reasonable 
standard.\374\ Some commenters support a distribution factor test, 
similar to MISO's test.\375\ AFPA states that consistent standards 
across regions will reduce discrimination and disputes and supports a 
lower bound on the distribution factor where a facility would not be 
considered contingent (e.g., if a facility has a distribution factor 
below three percent, it will not be considered contingent).\376\ 
Portland supports the use of a standardized percentage power transfer 
distribution factor but comments that this measure is not typically 
used for this purpose. Portland opposes a specific percentage 
threshold, arguing that such a threshold could potentially be used to 
manipulate the interconnection process.\377\
---------------------------------------------------------------------------

    \372\ See, e.g., Bonneville 2017 Comments at 5; Duke 2017 
Comments at 10; Modesto 2017 Comments at 22; Non-Profit Utility 
Trade Associations 2017 Comments at 12-13; PJM 2017 Comments at 14.
    \373\ AWEA 2017 Comments at 32.
    \374\ Id. at 34-35.
    \375\ ITC 2017 Comments at 17; AFPA 2017 Comments at 10; AWEA 
2017 Comments at 33; Generation Developers 2017 Comments at 26; 
Portland 2017 Comments at 3.
    \376\ AFPA 2017 Comments at 10.
    \377\ Portland 2017 Comments at 3.
---------------------------------------------------------------------------

ii. Commission Determination
    220. Based on the comments submitted, it is clear that transmission 
providers have different approaches for identifying contingent 
facilities. We find that the present record does not support the use of 
a distribution factor test or another standard method for identifying 
contingent facilities across all regions because it is not clear a 
single method would apply across different queue types and footprints. 
Therefore, we find that harmonization is not appropriate at this time.
2. Transparency Regarding Study Models and Assumptions
a. NOPR Proposal
    221. To increase transparency and ensure consistency in the 
analysis of interconnection requests, the Commission proposed a 
requirement that transmission providers detail all the network models 
and underlying assumptions used for interconnection studies in their 
pro forma LGIPs and on OASIS.\378\ The Commission also proposed to 
require that transmission providers include a non-confidential network 
model supporting data on OASIS, including, but not limited to, shift 
factors, dispatch assumptions, load power factors, and power 
flows.\379\ To implement this, the Commission proposed to modify 
section 2.3 of the pro forma LGIP as follows (with proposed additions 
in italics):
---------------------------------------------------------------------------

    \378\ NOPR, FERC Stats. & Regs. ] 32,719 at P 118.
    \379\ Id. P 119.

    Base Case Data. Transmission Provider shall provide base power 
flow, short circuit and stability databases, including all 
underlying assumptions, and contingency list upon request subject to 
confidentiality provisions in LGIP Section 13.1. Additionally, 
Transmission Provider will maintain network models and underlying 
assumptions on its OASIS site for access by OASIS users. 
Transmission Provider is permitted to require that Interconnection 
Customer and OASIS site 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 (ii) 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.

    222. The Commission sought comment on whether transmission 
providers should post other specific network model details and 
underlying assumptions on OASIS and should describe in the pro forma 
LGIP.\380\ The Commission also sought comment on whether and how 
transmission providers should provide notice of any variation from 
posted network model assumptions for a specific study, including 
whether the Commission should require notice of any variation to be 
submitted to the Commission.\381\ In addition, the Commission sought 
comment on any confidentiality or security concerns regarding the 
posting of specific model assumptions on OASIS or describing them in 
the pro forma LGIP.\382\ While the Commission recognized transmission 
providers' confidentiality and data security concerns, the Commission 
stated that there are likely safeguards that can satisfactorily address 
these concerns. The Commission also requested that commenters specify 
any data elements that should be subject to confidentiality or non-
disclosure agreements.
---------------------------------------------------------------------------

    \380\ Id. P 120.
    \381\ Id.
    \382\ Id. P 121.
---------------------------------------------------------------------------

b. General
i. Comments
    223. Numerous commenters express support for the proposal to 
require transmission providers to list all the network models and 
underlying assumptions used for interconnection studies.\383\ Joint 
Renewable Parties, AFPA, and IECA believe that the proposal decreases 
opportunities for discrimination.\384\ AFPA also states that the 
proposal will provide important information and analytical tools for 
interconnection customers to identify potential risks and benefits of 
project technologies, size, timing, and interconnection points.\385\ 
EDP states that information access improves the interconnection process 
and that an interconnection customer should not have to make major 
decisions without understanding how the transmission provider will 
evaluate its interconnection request.\386\ EDP notes that tariffs and 
business practice manuals often do not contain evaluation and 
information production practices utilized by transmission 
providers.\387\
---------------------------------------------------------------------------

    \383\ Alevo 2017 Comments at 6; Alliant 2017 Comments at 11; 
AFPA 2017 Comments at 11; AWEA 2017 Comments 36-37; CAISO 2017 
Comments at 17; Joint Renewable Parties 2017 Comments at 10; 
Generation Developers 2017 Comments at 27; EDP 2017 Comments at 6; 
Forecasting Coalition 2017 Comments at 4; IECA 2017 Comments at 2; 
ITC 2017 Comments at 17; MidAmerican 2017 Comments at 13-14; NEPOOL 
2017 Comments at 10; NextEra 2017 Comments at 22; SEIA 2017 Comments 
at 18; TDU Systems 2017 Comments at 18; Xcel 2017 Comment at 13-14.
    \384\ Joint Renewable Parties 2017 Comments at 11; AFPA 2017 
Comments at 11; IECA 2017 Comments at 2.
    \385\ AFPA 2017 Comments at 11.
    \386\ EDP 2017 Comments at 6.
    \387\ Id.
---------------------------------------------------------------------------

    224. MidAmerican asserts that the proposed reforms would assist 
customers in helping to verify the accuracy of required interconnection 
facilities and network upgrades.\388\ NextEra also notes that receiving 
the models could help to verify study results with unexpectedly high 
upgrade costs. NextEra argues that better information about models will 
lead to a greater ability to determine whether a site is appropriate 
for interconnection and thus will help reduce the number of ``less 
favorable'' interconnection requests.\389\ SEIA states that providing 
the interconnection customer directly with data will significantly 
reduce the

[[Page 21370]]

need for study discussion and could eliminate several disputes.\390\
---------------------------------------------------------------------------

    \388\ MidAmerican 2017 Comments at 13-14.
    \389\ NextEra 2017 Comments at 22.
    \390\ SEIA 2017 Comments at 18.
---------------------------------------------------------------------------

    225. Xcel supports adding a description of the network model and 
assumptions in the pro forma attachments of the feasibility study 
agreement and the system impact study agreement. Xcel states that, if 
network model descriptions and assumptions and the study agreements are 
posted publicly, then interested interconnection customers can review 
those agreements to find how similarly situated generators were 
previously studied.\391\
---------------------------------------------------------------------------

    \391\ Xcel 2017 Comment at 13-14.
---------------------------------------------------------------------------

    226. Many commenters voice concerns regarding the proposed 
requirement that transmission providers post this information on 
OASIS.\392\ CAISO and NYISO state that they already provide network 
model and study assumptions on their respective websites.\393\
---------------------------------------------------------------------------

    \392\ CAISO 2017 Comments at 17; NYISO 2017 Comments at 22; TDU 
Systems 2017 Comments at 18-19; Xcel 2017 Comment at 14; Duke 2017 
Comments at 11-12; EEI 2017 Comments at 40; NEPOOL 2017 Comments at 
10; Non-Profit Utility Trade Associations 2017 Comments at 14-15; 
OATI 2017 Comments at 4; Salt River 2017 Comments at 12; Southern 
2017 Comments at 20; TVA 2017 Comments at 9.
    \393\ CAISO 2017 Comments at 17; NYISO 2017 Comments at 22.
---------------------------------------------------------------------------

    227. NYISO notes that, rather than posting such data on the non-
password protected portion of NYISO's OASIS, NYISO posts 
interconnection studies to the password-protected portion of its 
website because the studies contain CEII.\394\
---------------------------------------------------------------------------

    \394\ Id.
---------------------------------------------------------------------------

    228. MISO states that it posts its network models for all MISO 
market participants, members, and interconnection customers that have 
signed non-disclosure agreements. MISO requests clarification that, if 
the Commission adopts its proposal, it will not require OASIS posting 
if this information is available elsewhere.\395\
---------------------------------------------------------------------------

    \395\ MISO 2017 Comments at 27.
---------------------------------------------------------------------------

    229. EEI argues that transmission providers should have discretion 
as to where to post this information and that interconnection customers 
can already request certain information covered by this proposal under 
existing CEII processes; it asserts that other information, such as 
dispatch information, how transmission providers build their models, 
and how contingency files are developed, may include proprietary, 
confidential, and commercially sensitive information or intellectual 
property.\396\
---------------------------------------------------------------------------

    \396\ EEI 2017 Comments at 40-41.
---------------------------------------------------------------------------

    230. TDU Systems state that the Commission's pro forma CEII non-
disclosure agreement would be appropriate and sufficient to protect 
against disclosure of CEII.\397\ Duke suggests that transmission 
providers' power flow models that have been filed with the Commission 
and identified as CEII be obtained through the Commission's CEII 
processes.\398\
---------------------------------------------------------------------------

    \397\ TDU Systems 2017 Comments at 18-19.
    \398\ Duke 2017 Comments at 12.
---------------------------------------------------------------------------

    231. Several commenters oppose the proposal and argue that current 
posting procedures are sufficient.\399\ For example, Duke suggests that 
interconnection customers request a study review to discuss the 
underlying study assumptions with the transmission provider.\400\ In 
addition, ISO-NE states that its website provides base cases and study 
assumptions, subject to CEII protections.\401\ MISO TOs state that, to 
the extent that additional information is necessary, the best way to 
accomplish this is through improved communications between the 
transmission provider, the transmission owner, and the interconnection 
customer.\402\ PG&E states that, although an interconnection customer 
may need to execute a non-disclosure agreement prior to obtaining this 
information, it is already generally available to them.\403\
---------------------------------------------------------------------------

    \399\ AES 2017 Comments at 8-9; Duke 2017 Comments at 11; ISO-NE 
2017 Comments at 26; MISO TOs 2017 Comments at 27; PG&E 2017 
Comments at 5; PJM 2017 Comments at 14; Southern 2017 Comments at 
20; TVA 2017 Comments at 9.
    \400\ Duke 2017 Comments at11.
    \401\ ISO-NE 2017 Comments at 26.
    \402\ MISO TOs 2017 Comments at 27-28.
    \403\ PG&E 2017 Comments at 6.
---------------------------------------------------------------------------

    232. Commenters that oppose the proposal argue that it may be 
administratively burdensome.\404\ Duke argues, moreover, that the 
Commission should instead require transmission providers to review the 
information they already post on OASIS that provides a summary of the 
transmission planning processes. Then, if necessary, the Commission 
could augment that description with a high-level description of how 
transmission providers conduct interconnection studies.\405\ Similarly, 
EEI requests that the Commission only require transmission providers to 
furnish high-level descriptions on model development.\406\ EEI also 
argues that transmission providers should only have to post updates if 
there are material changes in the generally applied assumptions.\407\
---------------------------------------------------------------------------

    \404\ Duke 2017 Comments at 11; EEI 2017 Comments at 40; 
NorthWestern 2017 Comments at 4-6; NYISO 2017 Comments at 23; PG&E 
2017 Comments at 5; Salt River 2017 Comments at 12; Tri-State 2017 
Comments at 6-7.
    \405\ Duke 2017 Comments at 11.
    \406\ EEI 2017 Comments at 40.
    \407\ Id. at 43.
---------------------------------------------------------------------------

    233. NorthWestern expresses concern that the proposal would be 
unnecessary and cumbersome given base case changes and asserts that a 
complete list of models would not benefit an interconnection 
customer.\408\ Further, NorthWestern states that requiring a non-
disclosure agreement from each potential interconnection customer prior 
to the feasibility study would administratively burden transmission 
providers. It also argues that, in the West, interconnection customers 
seeking additional information about study benefits and assumptions 
currently have the ability to request model details from the Western 
Electricity Coordinating Council.\409\
---------------------------------------------------------------------------

    \408\ NorthWestern 2017 Comments at 5.
    \409\ Id. at 6.
---------------------------------------------------------------------------

    234. NYISO opposes the provision of shift factors, which, it 
argues, only pertain to power flow and thermal analyses, which are more 
applicable to interconnections in RTOs/ISOs that offer physical 
transmission rights.\410\ Tri-State argues that large-scale system 
planning is dynamic and often requires changes to in-service dates, 
identification of new delivery points, project cancellations, 
generation assumptions, and assumed demand levels.\411\
---------------------------------------------------------------------------

    \410\ NYISO 2017 Comments at 23.
    \411\ Tri-State 2017 Comments at 6.
---------------------------------------------------------------------------

    235. Xcel notes that, because each interconnection request is 
unique, the specific network model assumptions used are also usually 
distinctive. Xcel argues that the Commission should grant transmission 
providers flexibility to provide the detailed, unique specifics of the 
network models in individual study agreements.\412\ Xcel also proposes 
that interconnection customers review the general process, as described 
in the LGIP or a business practice manual, as well as published study 
agreements to gain insights into expectations for modeling. Xcel states 
that the customer can discuss the specific modeling process and 
assumptions for its request with the transmission provider, and the 
agreement to be modeled would be memorialized in the agreements posted 
on OASIS. Xcel asserts that this process would provide significant 
transparency while allowing the use of the most appropriate studies and 
up-to-date assumptions for interconnection requests.\413\
---------------------------------------------------------------------------

    \412\ Xcel 2017 Comments at 13.
    \413\ Id. at 14.

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

[[Page 21371]]

ii. Commission Determination
    236. We adopt the NOPR proposal, with modifications. Specifically, 
this final action revises section 2.3 of the pro forma LGIP to read as 
follows (the bracketed text reflects deletions from, and the italicized 
text reflects additions to, the language proposed in the NOPR):

    Base Case Data. Transmission Provider shall maintain [provide] 
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, [upon request] subject to 
confidentiality provisions in LGIP Section 13.1. [Additionally]In 
addition, Transmission Provider shall [will] maintain network models 
and underlying assumptions on either its OASIS site or a password-
protected website [for access by OASIS users]. 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 [and], 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 (2 [ii]) [414] 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.
---------------------------------------------------------------------------

    \414\ In this final action, we correct a typographical error in 
the pro forma LGIP.

    237. Most responsive commenters note that the proposal could 
significantly increase transparency in the study process. We disagree 
with commenters that argue that current posting procedures are 
sufficient. The record before us demonstrates that transmission 
providers do not consistently make their network models and assumptions 
available, and access to information regarding the assumptions used is 
often inconsistent across regions.\415\ We believe the revisions to 
section 2.3 of the pro forma LGIP will reduce the possibility that some 
interconnection customers will have unduly discriminatory access to 
relevant information and will generally increase transparency for 
interconnection customers by requiring that network models and 
assumptions used by transmission providers be made available, subject 
to the appropriate confidentiality and information requirements. We 
expect that these revisions will allow interconnection customers to 
make more informed interconnection decisions while also holding 
transmission providers accountable as to which network models and 
assumptions they use to assess interconnection requests.
---------------------------------------------------------------------------

    \415\ NOPR, FERC Stats. & Regs. ] 32,719 at PP 111-112; see also 
NextEra 2017 Comments at 22; Alliant 2017 Comments at 11.
---------------------------------------------------------------------------

    238. However, we find persuasive concerns voiced by several 
commenters regarding the proposal's requirement to post the network 
model and assumption information on OASIS. Specifically, we recognize 
that a requirement to move information onto OASIS could burden 
transmission providers that currently make this information available 
to interconnection customers elsewhere. Therefore, we believe a 
transmission provider should be able to decide to maintain the required 
information on its website as long as it has a link to the location of 
the information on OASIS, as OASIS is the central location for all the 
information needed to request interconnection service. Accordingly, the 
revisions to section 2.3 of the pro forma LGIP require transmission 
providers to post network models and assumptions, subject to the 
appropriate confidentiality and information requirements, on OASIS and/
or on a password-protected website. These revisions strike an 
appropriate balance by increasing transparency while also limiting the 
burden on transmission providers.
    239. In response to those arguments alleging that maintaining 
network models and underlying assumptions on OASIS or a password-
protected website may be administratively burdensome, we find the 
benefits of increased transparency resulting from the revisions to 
section 2.3 of the pro forma LGIP will outweigh the burden placed on 
transmission providers to post and maintain up-to-date network models 
and underlying assumptions. Instead, we note that increasing 
transparency of network models and assumptions will allow 
interconnection customers to make informed interconnection decisions, 
which could potentially help interconnection customers avoid entering 
the queue with non-viable interconnection requests. Informed 
interconnection decisions will also allow transmission providers to 
improve queue management. Improved queue management, in turn, should 
aid in decreasing the administrative burden on transmission providers. 
In addition, increased transparency will also mitigate the potential 
for study disputes, re-studies and late-stage withdrawals, thus 
increasing the efficiency of the interconnection process.
    240. In response to confidentiality and data security concerns 
associated with providing certain information and system access, we 
reaffirm that there are safeguards that can be put in place to 
satisfactorily address these concerns. With the revisions in this final 
action, section 2.3 of the pro forma LGIP allows the transmission 
provider to require that the interconnection customer sign a 
confidentiality agreement before the release of commercially sensitive 
information. We agree with commenters that transmission providers 
should only provide commercially-sensitive information, such as 
contingency files and specific dispatch information, under a non-
disclosure agreement. We note that the information that this final 
action requires transmission providers to post will be available on a 
password-protected website or on the transmission provider's OASIS 
site.
    241. With regard to CEII, we note that the Commission's CEII 
regulations in 18 CFR 388.113 only govern ``the procedures for 
submitting, designating, handling, sharing, and disseminating [CEII] 
submitted to or generated by the Commission.'' \416\ However, to the 
extent that certain information that is currently designated by the 
Commission as CEII is implicated by this portion of the final action, 
this final action makes no changes to that information's CEII 
designation or to the Commission's existing CEII requirements. 
Additionally, even if the information has been designated as CEII, 
Sec.  388.113 of the Commission's regulations does not govern the 
transmission provider's handling, sharing, and disseminating of 
information that the transmission provider submitted for CEII 
designation, including how it disseminates that information on its 
OASIS site or password-protected website. We note, however, that 
nothing in Sec.  388.113 of the Commission's regulations precludes a 
transmission provider from taking necessary steps to protect 
information within its custody or control to ensure the safety and 
security of the electric grid. Specifically, we note that pro forma 
LGIP section 2.3 permits transmission providers to require a 
confidentiality agreement for anyone that wishes to access 
``commercially sensitive information or [information that has been 
designated as CEII]'' that may be posted in the base case data on the 
transmission provider's OASIS site or password-protected website.
---------------------------------------------------------------------------

    \416\ 18 CFR 388.113 (2017) (emphasis added).
---------------------------------------------------------------------------

    242. Upon consideration of the comments, we withdraw the NOPR

[[Page 21372]]

proposal to require transmission providers to post information 
``including, but not limited to, shift factors, dispatch assumptions, 
load power factors, and power flows.'' \417\ Such a requirement could 
result in transmission providers posting certain information that is 
not informative to interconnection customers and which could delay or 
otherwise burden the interconnection study process. For example, NYISO 
states that shift factors generally only pertain to power flow and 
thermal analyses, which are more applicable to interconnections in 
RTOs/ISOs that offer physical transmission rights.\418\
---------------------------------------------------------------------------

    \417\ NOPR, FERC Stats. & Regs. ] 32,719 at P 119.
    \418\ NYISO 2017 Comments at 23.
---------------------------------------------------------------------------

c. Suggested Modifications to Transparency Regarding Study Models and 
Assumptions Proposal
i. Comments
    243. Multiple commenters support the proposal but offer suggestions 
to increase transparency.\419\ For example, AWEA suggests that 
transmission providers should have to review interconnection study 
models and assumptions every two years and submit a filing pursuant to 
section 205 of the FPA justifying the model and assumptions to ensure 
that study models and assumptions are non-discriminatory, realistic, 
appropriate for generation or regional characteristics, and 
accountable.\420\
---------------------------------------------------------------------------

    \419\ AWEA 2017 Comments at 37; Generation Developers 2017 
Comments at 28; NEPOOL 2017 Comments at 10; NextEra 2017 Comments at 
22; TDU Systems 2017 Comments at 18; Xcel 2017 Comments at 13.
    \420\ AWEA 2017 Comments at 37; see also Generation Developers 
2017 Comments at 31.
---------------------------------------------------------------------------

    244. Generation Developers request that the modeling provision 
specify the minimum model assumptions that must be posted, including: 
(1) Shift factors used by region, sub-region, and even utility area; 
(2) generation dispatch assumptions by fuel-type of resource by region 
and sub-region for off-peak and peak hours; (3) load power factors; (4) 
power flows; (5) whether violations of NERC Category A (TPL-001), 
Category B (TPL-002), and Category C (TPL-003) require network upgrades 
and contingent facilities in all or some instances; (6) treatment of 
currently overloaded facilities; (7) the extent to which Network 
Resource Interconnection Service (NRIS) is hard-coded in the base 
model; and (8) contingency files.\421\
---------------------------------------------------------------------------

    \421\ Generation Developers 2017 Comments at 28.
---------------------------------------------------------------------------

    245. NextEra notes that, in addition to models, interconnection 
customers would benefit from two best practices: (1) Providing 
information about other interconnection requests ``in the same location 
by point on the transmission grid,'' instead of county-level data; 
\422\ and (2) providing information about lower voltage facilities 
(e.g., those below 100 kV) and higher voltage facilities.\423\
---------------------------------------------------------------------------

    \422\ NextEra 2017 Comments at 23.
    \423\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    246. While we appreciate the additional suggestions on what types 
of information transmission providers should post, the information 
requested by the commenters is outside of the scope of the proposal as 
set forth in the NOPR. In response to AWEA's requests, we note that 
when the Commission acts pursuant to FPA section 206, it ``must show 
that [a] utility's existing rate is unjust and unreasonable and . . . 
that [the Commission's] replacement rate is just and reasonable.'' 
Thus, the Commission would have to meet the requirements of FPA section 
206 to make changes to a currently effective tariff provision.\424\ We 
find that the current record does not support such a finding. With 
respect to Generation Developers', NextEra's, and TDU Systems' 
suggestions that transmission providers should have to post more 
information on OASIS, we clarify that the final action does not mandate 
an exhaustive list of minimum model assumptions. We find that the 
record before us does not support mandating that each region post the 
same set of information in the analysis of interconnection requests.
---------------------------------------------------------------------------

    \424\ Ark. Elec. Coop. Corp. v. ALLETE, Inc., 156 FERC ] 61,061, 
at P 18 (2016).
---------------------------------------------------------------------------

3. Congestion and Curtailment Information
a. NOPR Proposal
    247. In response to developer requests for increased transparency 
of congestion and curtailment information, the Commission proposed to 
require that transmission providers post congestion and curtailment 
information in one location on their OASIS sites so that 
interconnection customers can more easily access information that may 
aid in their decision-making.\425\ The Commission proposed to require 
that transmission providers post specific congestion and curtailment 
information that is disaggregated, or more granular (e.g., hourly and 
locational data) than the information that some transmission providers 
currently provide.\426\ To effectuate this requirement, the Commission 
proposed to add a new paragraph (l) to 18 CFR 37.6, which stated that 
the Transmission Provider must post on OASIS information as to 
congestion data representing (i) total hours of curtailment on all 
interfaces, (ii) total hours of Transmission Provider-ordered 
generation curtailment and transmission service curtailment due to 
congestion on that facility or interface, (iii) the cause of the 
congestion (e.g., a contingency or an outage), and (iv) total megawatt 
hours of curtailment due to lack of transmission for that month. This 
data shall be posted on a monthly basis by the 15th day of the 
following month and shall be posted in one location on the OASIS. The 
Transmission Provider should maintain this data for a minimum of three 
years.
---------------------------------------------------------------------------

    \425\ NOPR, FERC Stats. & Regs. ] 32,719 at P 128.
    \426\ Id. P 130.
---------------------------------------------------------------------------

    248. The Commission also sought comment on whether transmission 
providers should provide interconnection-request-specific congestion 
and curtailment information and whether transmission providers should 
be required to provide this information to interconnection customers 
during the interconnection study process (e.g., at the scoping 
meeting).\427\
---------------------------------------------------------------------------

    \427\ Id. P 128.
---------------------------------------------------------------------------

    249. The Commission also sought comment on the level of information 
to be provided, the frequency at which the information should be 
provided, and how many months/years the provided information should 
cover.\428\ The Commission sought further comment on the value of 
requiring transmission providers to post flow duration curves on the 
major transmission interfaces based on hourly flow data on OASIS.\429\ 
Finally, the Commission sought comment on changes to section 3.3.4 of 
the pro forma LGIP requiring transmission providers or transmission 
owners to provide curtailment and congestion information at the scoping 
meeting.\430\
---------------------------------------------------------------------------

    \428\ Id. P 131.
    \429\ Id.
    \430\ Id. P 133.
---------------------------------------------------------------------------

b. Comments
    250. Some responsive commenters support the proposed requirement 
for congestion and curtailment information to be posted in one location 
on each transmission provider's OASIS site.\431\ AFPA asserts that the 
proposal will allow interconnection customers to better use existing 
transmission

[[Page 21373]]

infrastructure.\432\ Public Interest Organizations and IECA contend 
that the proposal will help interconnection customers better understand 
investment risks, which could result in more efficient markets and 
lower costs.\433\ IECA, SEIA, and Joint Renewable Parties indicate that 
the added transparency will improve access to information, increase 
efficiency, and reduce discrimination.\434\
---------------------------------------------------------------------------

    \431\ AFPA 2017 Comments at 11; Public Interest Organizations 
2017 Comments at 5-8; IECA 2017 Comments at 2; SEIA 2017 Comments at 
19; Joint Renewable Parties 2017 Comments at 11; Alevo 2017 Comments 
at 6; NEPOOL 2017 Comments at 11; Alliant 2017 Comments at 12.
    \432\ AFPA 2017 Comments at 11.
    \433\ Public Interest Organizations 2017 Comments at 5-8; IECA 
2017 Comments at 2.
    \434\ Id.; SEIA 2017 Comments at 19; Joint Renewable Parties 
2017 Comments at 11.
---------------------------------------------------------------------------

    251. Joint Renewable Parties, Alliant, Generation Developers, and 
ITC state that access to the information will improve interconnection 
customers' ability to appropriately site projects and will reduce queue 
withdrawals, which occur due to high interconnection facility and 
network upgrade costs.\435\ AWEA asserts that it is crucial for 
interconnection customers to have access to historical local congestion 
information, noting that study results do not provide this information 
and that transmission providers frequently do not make it available. 
AWEA also states that there is a lack of uniformity in the type and 
location of information that transmission providers post.\436\ AWEA 
states that non-disclosure agreements can prevent disclosure of 
commercially sensitive information to the general public.\437\
---------------------------------------------------------------------------

    \435\ Id.; Alliant 2017 Comments at 12; Generation Developers 
2017 Comments at 31-32; ITC 2017 Comments at 17; see also AWEA 2017 
Comments at 40.
    \436\ Id. at 39.
    \437\ Id. at 41.
---------------------------------------------------------------------------

    252. In support of the proposal, NEPOOL and Alevo both argue that 
transmission owners, transmission providers, and system operators 
should post data that are as granular as possible. They argue that 
readily available transmission capacity data at the front end will 
enable market participants to size their projects appropriately and to 
anticipate network upgrade costs.\438\ AWEA contends that the burden on 
transmission providers to post this type of information is minimal, as 
the information is readily available and does not require significant 
additional studies.\439\ TDU Systems also supports the proposal and 
urges the Commission to clarify that transmission providers should 
report on congestion that is avoided by dispatching generation out of 
merit order.\440\
---------------------------------------------------------------------------

    \438\ Alevo 2017 Comments at 6; NEPOOL 2017 Comments at 11.
    \439\ AWEA 2017 Comments at 42.
    \440\ TDU Systems 2017 Comments at 19-20.
---------------------------------------------------------------------------

    253. Several commenters argue that sufficient procedures already 
exist for interconnection customers. TVA, EEI, and Xcel contend that 
the Commission should make existing data collection resources available 
to potential interconnection customers, rather than requiring 
transmission providers to create redundant new ones.\441\ TVA argues 
that the information that NERC stores via Transmission Loading Relief 
(TLR) logs provides enough information to allow the interconnection 
customer to evaluate its selected location.\442\ TVA also contends that 
the time and expense of analyzing potential interconnection locations 
should be the interconnection customer's responsibility.\443\ Xcel 
argues that, to the extent stakeholder needs are not met by posting the 
proposed information, RTO/ISO stakeholder processes should address 
these issues.\444\ Non-Profit Utility Trade Associations ask the 
Commission to convene a technical conference to determine what 
congestion and constraint information utilities should maintain, the 
format of that information, and what information would benefit 
interconnection customers.\445\
---------------------------------------------------------------------------

    \441\ EEI 2017 Comments at 45; TVA 2017 Comments at 10-11; Xcel 
2017 Comments at 15-16.
    \442\ TVA 2017 Comments at 10.
    \443\ Id. at 10-11.
    \444\ Xcel 2017 Comments at 15-16.
    \445\ Non-Profit Utility Trade Associations 2017 Comments at 17.
---------------------------------------------------------------------------

    254. CAISO and PG&E note that the requested information is largely 
already available on CAISO's website.\446\ CAISO explains that 
transmission providers publish dispatch reports, congestion data, and 
locational marginal price (LMP) data so that potential interconnection 
customers can understand where there is available capacity.\447\ CAISO 
also states that it already provides interconnection customers with as 
much information as can be predicted, bearing in mind that economic 
curtailment protects the grid from events that are difficult or 
impossible to predict, such as outages, overloads due to oversupply, 
and contingency events.\448\
---------------------------------------------------------------------------

    \446\ CAISO 2017 Comments at 20; PG&E 2017 Comments at 6 (citing 
http://www.caiso.com/market/Pages/OutageManagement/Curtailed-OperationalGeneratorReportGlossary.aspx).
    \447\ CAISO 2017 Comments at 19.
    \448\ Id.
---------------------------------------------------------------------------

    255. MISO argues that the sort of granular information the 
Commission has proposed to be posted will not significantly resolve 
issues with queue processing.\449\ MISO TOs state that MISO posts 
market reports that contain LMP data and the marginal congestion 
component for every commercial pricing node, which can be used to 
develop information on congestion. MISO TOs state that it would be 
redundant (and burdensome) to require MISO to publish this information 
on OASIS as well as on its website, where it currently resides.\450\
---------------------------------------------------------------------------

    \449\ MISO 2017 Comments at 28.
    \450\ MISO TOs 2017 Comments at 30.
---------------------------------------------------------------------------

    256. NextEra notes that operational snapshots of the transmission 
provider's system are more useful than statistics of total hours or MW 
of curtailment.\451\ NextEra notes that MISO and SPP already provide 
state estimator snapshots from the prior two weeks, which include 
generator dispatch, system congestion, and power flow information, 
among other things. NextEra recommends that all RTOs/ISOs adopt this 
practice and provide snapshots of their systems from different times of 
the day to show system conditions.\452\
---------------------------------------------------------------------------

    \451\ NextEra 2017 Comments at 25.
    \452\ Id.
---------------------------------------------------------------------------

    257. PJM agrees with the proposal to require transmission providers 
to post congestion data representing total hours of curtailment on all 
interfaces and asserts that it currently posts these data publicly on 
its website.\453\ PJM states that, along with LMP pricing information, 
these data are adequate to allow an interconnection customer to make 
informed business decisions relative to their interconnection 
project.\454\
---------------------------------------------------------------------------

    \453\ PJM 2017 Comments at 16.
    \454\ Id.
---------------------------------------------------------------------------

    258. However, PJM states that it opposes the NOPR's proposal to 
require transmission providers to post total hours of transmission 
provider-ordered generation curtailment and transmission service 
curtailment due to congestion on a facility or interface, the cause of 
the congestion, and total megawatt hours (MWh) of curtailment due to 
lack of transmission for that month.\455\ PJM states that posting 
information regarding unit-specific and constraint-specific generator 
curtailment information would allow other market participants to 
replicate market-sensitive data, such as unit offers, and would require 
significant effort.\456\ PJM contends that publicly posting the cause 
of congestion would improperly disclose commercially sensitive 
information and require difficult and time-consuming power flow 
analysis and market re-runs. PJM notes that it does not have the 
software capability to determine causes of congestion.\457\ PJM states 
that posting the total monthly MWh of curtailment

[[Page 21374]]

due to lack of transmission could result in misleading information, as 
curtailment may be caused by multiple factors.\458\
---------------------------------------------------------------------------

    \455\ Id.
    \456\ Id.
    \457\ Id. at 17.
    \458\ Id.
---------------------------------------------------------------------------

    259. EEI, Six Cities, MISO TOs, CAISO, and Xcel assert that 
historical congestion and curtailment information may have no bearing 
on future congestion or curtailment at any specific location, and the 
posting of this information should not be considered a commitment by 
the transmission provider to guarantee the availability of additional 
capacity or expose the transmission provider to damages or other 
remedies should interconnection customers' expectations regarding 
curtailment risk not materialize.\459\ Duke states that historic 
congestion and curtailment information might only be useful if the 
generating facility's location and the area of congestion 
coincided.\460\ Duke and MISO TOs further state that system changes 
including interconnection and transmission upgrades, large generators 
going on- or off-line, or a transmission system topology change could 
render historical congestion information meaningless.\461\ Xcel states 
that future generation impacts future congestion, and that knowledge of 
where other generation will locate is likely of more value to the 
interconnecting generators.\462\
---------------------------------------------------------------------------

    \459\ EEI 2017 Comments at 45; Six Cities 2017 Comments at 3-4; 
MISO TOs 2017 Comments at 29; CAISO 2017 Comments at 19; Xcel 2017 
Comments at 14-15.
    \460\ Duke 2017 Comments at 12.
    \461\ Id. at 13; MISO TOs 2017 Comments at 29.
    \462\ Xcel 2017 Comments at 14-15.
---------------------------------------------------------------------------

    260. Xcel notes that the impact of congestion and curtailment 
varies by region, mostly due to the existence of regional markets, 
different scheduling practices, and the treatment of firm transmission 
service.\463\ ISO-NE argues that regional flexibility is warranted to 
allow RTOs/ISOs to identify the relevant congestion and curtailment 
information in their region and the information that is already 
available to interconnection customers that meets the NOPR's 
objective.\464\ ISO-NE states that the congestion and curtailment 
information identified in the NOPR is not relevant in New England 
because this information relates to availability of pro forma 
transmission service and internal flow gates, neither of which is 
applicable in New England.\465\
---------------------------------------------------------------------------

    \463\ Id.
    \464\ ISO-NE 2017 Comments at 27-28.
    \465\ Id. n.65.
---------------------------------------------------------------------------

    261. NYISO states that it has historically published significant 
system information on its public website, including congestion and 
curtailment information.\466\ NYISO argues that additional operational 
data posted to NYISO's public website would not provide the information 
the NOPR anticipates would be useful to interconnection customers.\467\ 
NYISO further states that the curtailment data requested by AWEA and 
proposed in the NOPR would not be useful data to NYISO interconnection 
customers and explains that it may not even have the capability to 
provide certain data proposed by the NOPR.\468\ NYISO contends that it 
need not maintain and post the same OASIS-related information as RTOs/
ISOs with a physical reservation transmission system.\469\
---------------------------------------------------------------------------

    \466\ NYISO 2017 Comments at 24.
    \467\ Id. at 28.
    \468\ Id. at 26 (citing, e.g., N.Y. Indep. Sys. Operator, Inc., 
123 FERC ] 61,134, at PP 8-13 (2008); N.Y. Indep. Sys. Operator, 
Inc., Docket No. OA08-13-003 (Nov. 12, 2008) (delegated letter 
order)).
    \469\ Id. (citing, e.g., N.Y. Indep. Sys. Operator, Inc., Docket 
Nos. ER11-2048-003 & ER11-2048-004 (June 6, 2011) (delegated letter 
order); N.Y. Indep. Sys. Operator, Inc., 133 FERC ] 61,208, at PP 
12-13 (2010)).
---------------------------------------------------------------------------

    262. MISO asserts that queue congestion is a sub-region-wide issue 
and not an issue of locating around more granular points of congestion, 
which the proposed requirements would illuminate. MISO contends that 
for optimally locating around localized points of congestion, the 
initial scoping meetings are sufficient to advise customers regarding 
less congested points of interconnection within an interconnection 
customer's general preferred area.\470\
---------------------------------------------------------------------------

    \470\ MISO 2017 Comments at 28.
---------------------------------------------------------------------------

    263. PG&E questions whether this information should be posted on 
OASIS, instead of on CAISO's website, since an interconnection customer 
will not necessarily have access to OASIS until it becomes a 
transmission customer.\471\ PG&E expresses concern about making much of 
this information public, including but not limited to CEII, since CAISO 
has a process that provides much of this information to interconnection 
customers that have executed non-disclosure agreements.\472\ MISO TOs 
state that RTOs/ISOs should develop a method to ensure privileged and/
or confidential information is shared only with interconnection 
customers and is not available to market participants or others without 
authorization to receive CEII information, in order to prevent market 
manipulation and potential harm.\473\
---------------------------------------------------------------------------

    \471\ PG&E 2017 Comments at 6.
    \472\ Id.
    \473\ MISO TOs 2017 Comments at 30.
---------------------------------------------------------------------------

    264. Duke, NorthWestern, Southern, Xcel, and Non-Profit Utility 
Trade Associations argue that the proposal should not extend to 
transmission providers that operate outside of RTOs/ISOs because the 
information is neither available nor relevant.\474\ Duke states that 
the transmission system outside RTOs/ISOs is planned, designed, and 
operated so that generating resources with firm bilateral contracts to 
serve load are not constrained.\475\ Xcel notes that, in non-market 
areas, firm transmission service mitigates congestion and curtailment 
risk. Xcel and Southern contend that congestion and curtailment 
information is more relevant for RTOs/ISOs that have locational 
marginal pricing, and because regional markets usually dispatch 
generation according to price, curtailment is generally based on price 
and not a lack of transmission capacity.\476\ Southern points out that 
it provides congestion/curtailment screens specific to each 
interconnection request in each interconnection study report.\477\
---------------------------------------------------------------------------

    \474\ Duke 2017 Comments at 13; NorthWestern 2017 Comments at 6; 
Southern 2017 Comments at 21-22; Xcel 2017 Comments at 15; Non-
Profit Utility Trade Associations 2017 Comments at 15-16.
    \475\ Duke 2017 Comments at 13.
    \476\ Xcel 2017 Comments at 15; Southern 2017 Comments at 21.
    \477\ Id. at 21-22.
---------------------------------------------------------------------------

    265. NorthWestern and Non-Profit Utility Trade Associations state 
that the definition of ``congestion'' is unclear in non-RTOs/ISOs.\478\ 
NorthWestern argues that posting congestion could be duplicative 
because, in contract-path balancing authority areas that operate 
outside of organized markets, ``congestion'' is synonymous with 
``available transfer capability,'' which is already posted on OASIS in 
real time.\479\
---------------------------------------------------------------------------

    \478\ NorthWestern 2017 Comments at 6; Non-Profit Utility Trade 
Associations 2017 Comments at 15-16.
    \479\ NorthWestern 2017 Comments at 6.
---------------------------------------------------------------------------

    266. Duke, EEI, and OATI assert that the Commission should consult 
with NAESB regarding standards for making congestion and curtailment 
information accessible on OASIS.\480\ OATI states that it is critical 
that access to all of these postings require secure and controlled 
access through a registered OASIS user account per existing OASIS 
standards.\481\ Duke states that NAESB is already working on this 
issue, as evidenced by its 2017 Wholesale Electric Quadrant Annual Plan 
item 2.a.ii.1, and should consider designing queries for 
interconnection customers to use to obtain congestion and

[[Page 21375]]

curtailment information specific to their interconnection 
requests.\482\ TVA suggests that adding these data to data that NERC 
already tracks appears a more appropriate regulatory implementation 
path.\483\
---------------------------------------------------------------------------

    \480\ Duke 2017 Comments at 13; EEI 2017 Comments at 47-48; OATI 
2017 Comments at 2.
    \481\ Id.
    \482\ Duke 2017 Comments at 13.
    \483\ TVA 2017 Comments at 10-11.
---------------------------------------------------------------------------

    267. NYISO suggests that instead of the proposed OASIS postings, 
the Commission should consider adding the option of a pre-application 
report for large facilities, similar to that required to be offered for 
small facilities under Order No. 792 and the pro forma SGIP.\484\ NYISO 
urges the Commission to consider such an approach as an alternative to 
requiring cumbersome posting requirements that are not applicable in 
all regions and that can only provide historical data--data that are of 
little use to an interconnection customer and indeed may be misleading 
compared to data that could be provided through an interconnection 
study or in response to a pre-application report request.\485\
---------------------------------------------------------------------------

    \484\ NYISO 2017 Comments at 29.
    \485\ Id. at 29-30.
---------------------------------------------------------------------------

c. Commission Determination
    268. In this final action, we decline to adopt the proposal in the 
NOPR to require transmission providers to post certain specified 
congestion and curtailment information, as described further below.
    269. We agree with commenters that access to congestion and 
curtailment data could better inform the decision-making of 
interconnection customers and allow them to more appropriately size and 
site projects, resulting in more efficient use of the transmission 
system and fewer late stage queue withdrawals. Accordingly, we 
encourage all transmission providers that already make such information 
available to continue to do so.
    270. However, upon consideration of the comments in this 
proceeding, we decline to require transmission providers to post the 
specific information that the Commission originally proposed in the 
NOPR. We find persuasive those comments that assert that, in some 
instances, generating information on the causes of congestion or on 
unit-specific or constraint-specific curtailment information is 
technically infeasible or would require significant additional 
effort.\486\
---------------------------------------------------------------------------

    \486\ PJM 2017 Comments at 16-17; NYISO 2017 Comments at 29-30.
---------------------------------------------------------------------------

    271. In addition, as several commenters argue, many transmission 
providers already publish congestion and curtailment data such as LMP 
data and dispatch reports on their public websites.\487\ Further, the 
NERC Transmission Loading Relief (TLR) Logs make publicly available 
information on the duration, direction, and MW total of curtailments in 
the Eastern Interconnection.\488\ We also note that some commenters 
question the usefulness of some of the data contemplated by the NOPR 
proposal to prospective interconnection customers and that others argue 
that some of this data is not available outside of RTOs/ISOs.
---------------------------------------------------------------------------

    \487\ See e.g., CAISO 2017 Comments at 20; NYISO 2017 Comments 
at 24; PJM 2017 Comments at 16.
    \488\ NERC TLR Logs, http://nerc.com/pa/rrm/TLR/Pages/TLR-Logs.aspx.
---------------------------------------------------------------------------

    272. Accordingly, we decline to adopt the proposed revisions to add 
a new paragraph (l) to 18 CFR 37.6 that would require transmission 
providers to post specific congestion and curtailment information in 
one location on OASIS.
4. Definition of Generating Facility in the Pro Forma LGIP and Pro 
Forma LGIA
a. NOPR Proposal
    273. The Commission proposed to revise the definition of 
``Generating Facility'' in the pro forma LGIP and the pro forma LGIA to 
include electric storage resources, similar to how it revised the 
definition of a ``Small Generating Facility'' in the pro forma SGIP and 
the pro forma SGIA in Order No. 792.\489\ Specifically, the Commission 
proposed to amend the definition of a Generating Facility in the pro 
forma LGIP and the pro forma LGIA as follows (with proposed additions 
in italics): ``Generating Facility shall mean 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.'' 
\490\
---------------------------------------------------------------------------

    \489\ NOPR, FERC Stats. & Regs. ] 32,719 at PP 134, 136 (citing 
Order No. 792, 145 FERC ] 61,159 at P 228 (emphasis in original)).
    \490\ Id. PP 138-139.
---------------------------------------------------------------------------

b. General
i. Comments
    274. A majority of responsive commenters, including utilities, 
RTOs/ISOs, and renewable interests, support the proposal.\491\ MISO and 
NYISO state that they already account for electric storage resources in 
their definitions.\492\ CAISO states that it has clarified that 
electric storage resources can participate as generators to ``provide 
supply'' and ancillary services. CAISO further states that it studies 
the reliability impacts of an electric storage resource's charging, but 
not as firm load.\493\ To the extent that an electric storage resource 
requires firm load treatment, CAISO states that it can apply to the 
local distribution company.\494\
---------------------------------------------------------------------------

    \491\ AFPA 2017 Comments at 12; AWEA 2017 Comments at 55; 
Bonneville 2017 Comments at 5; CAISO 2017 Comments at 20; California 
Energy Storage Alliance 2017 Comments at 4; Duke 2017 Comments at 
15; EDP 2017 Comments at 6; ESA 2017 Comments at 6; IECA 2017 
Comments at 3; ISO-NE 2017 Comments at 32-33; Joint Renewable 
Parties 2017 Comments at 10-11; MISO 2017 Comments at 29; MISO TOs 
2017 Comments at 32; Modesto 2017 Comments at 22; NEPOOL 2017 
Comments at 12-13; NextEra 2017 Comments at 26; Non-Profit Utility 
Trade Associations 2017 Comments at 17; PG&E 2017 Comments at 6; PJM 
2017 Comments at 19-20; Public Interest Organizations 2017 Comments 
at 7-8; TDU Systems 2017 Comments at 20; TVA 2017 Comments at 11.
    \492\ MISO 2017 Comments at 29; NYISO 2017 Comments at 30.
    \493\ CAISO 2017 Comments at 20.
    \494\ CAISO 2017 Comments at 20.
---------------------------------------------------------------------------

ii. Commission Determination
    275. In this final action, we adopt the NOPR proposal to modify the 
definition of ``Generating Facility'' in the pro forma LGIP and pro 
forma LGIA to include ``and/or storage for later injection.'' We find 
that this definitional change will reduce a potential barrier to large 
electric storage resources with a generating facility capacity above 20 
MW that wish to interconnect pursuant to the terms in the pro forma 
LGIP and pro forma LGIA. Additionally, this finding and definitional 
change are consistent with provisions already implemented in the pro 
forma SGIP and the pro forma SGIA.\495\
---------------------------------------------------------------------------

    \495\ Pro forma SGIP at Attachment 1 (Glossary of Terms); Pro 
forma SGIA at Attachment 1 (Glossary of Terms).
---------------------------------------------------------------------------

c. Electric Storage Resources as Transmission Assets
i. Comments
    276. ESA and California Energy Storage Alliance, both of which 
support the proposal, raise concerns that the proposal may 
inadvertently prohibit the deployment of electric storage resources as 
transmission assets.\496\ ESA recommends that the Commission state that 
neither a SGIA nor an LGIA is necessary for electric storage resources 
to be employed as transmission assets and that electric storage 
resources providing transmission services should not be excluded from 
seeking an LGIA or SGIA to provide wholesale generator services.\497\ 
Public Interest Organization

[[Page 21376]]

generally supports the proposal but opposes requiring all electric 
storage resources, including those intended to serve as transmission 
assets, to go through the formal large generator interconnection 
process.\498\
---------------------------------------------------------------------------

    \496\ ESA 2017 Comments at 6; California Energy Storage Alliance 
2017 Comments at 4.
    \497\ ESA 2017 Comments at 7 (citing Utilization of Electric 
Storage Resources for Multiple Services When Receiving Cost-Based 
Rate Recovery, 158 FERC ] 61,051 (2017)).
    \498\ Public Interest Organizations 2017 Comments at 7-8.
---------------------------------------------------------------------------

    277. AES and Alevo both oppose the change of definition, arguing 
that electric storage resources can also act as transmission assets 
instead of, or in addition to, participating in the markets and that 
the proposal may prohibit the deployment of electric storage resources 
as transmission assets.\499\
---------------------------------------------------------------------------

    \499\ AES 2017 Comments at 9-11; Alevo 2017 Comments at 2-4.
---------------------------------------------------------------------------

ii. Commission Determination
    278. We find that there is no need to further revise the definition 
of Generating Facility to address these concerns because the 
definition, as revised here, would not affect whether electric storage 
resources operate as transmission assets. The Commission previously has 
found that, in certain situations, electric storage resources can 
function as a generating facility, a transmission asset,\500\ or 
both.\501\
---------------------------------------------------------------------------

    \500\ See, e.g., Western Grid Dev., LLC, 130 FERC ] 61,056 
(Western Grid), reh'g denied, 133 FERC ] 61,029 (2010).
    \501\ See Utilization of Electric Storage Resources for Multiple 
Services When Receiving Cost-Based Rate Recovery, 158 FERC ] 61,051.
---------------------------------------------------------------------------

    279. The purpose of this definition change is to make clear that 
electric storage resources with a capacity of more than 20 MW may 
interconnect pursuant to the pro forma LGIP and pro forma LGIA. These 
final action revisions are meant to clarify that new technologies may 
avail themselves of the existing pro forma interconnection process, so 
long as they meet the threshold requirements as stated in those 
documents.
d. Characteristics of Electric Storage Resources
i. Comments
    280. ESA asserts that the proposal does not address the differences 
between electric storage resources and traditional generators.\502\ ESA 
recommends that the Commission require RTOs/ISOs to develop Electric 
Storage Interconnection Agreements and Processes that account for the 
unique characteristics of electric storage resources.\503\ In addition, 
ESA recommends that the Commission revise tariffs and modify the pro 
forma LGIP and the pro forma LGIA into a pro forma Large Facility 
Interconnection Agreement and Process, in which facilities are defined 
to consist of only a generating unit, only an electric storage unit, or 
a combination of generating units and electric storage units.\504\
---------------------------------------------------------------------------

    \502\ ESA 2017 Comments at 6.
    \503\ Id. at 7 (citing, e.g., ISO New England, Inc., 151 FERC ] 
61,024 (2015)).
    \504\ Id. at 8.
---------------------------------------------------------------------------

    281. Alevo and AES state that the proposal does not account for the 
full capability of electric storage resources.\505\ Alevo states that a 
new definition should be made separately for electric storage 
resources, while AES suggests that the development of a new 
interconnection agreement specific to electric storage resources.\506\
---------------------------------------------------------------------------

    \505\ AES 2017 Comments at 9-11; Alevo 2017 Comments at 2-4.
    \506\ AES 2017 Comments at 10-11; Alevo 2017 Comments at 2-4.
---------------------------------------------------------------------------

    282. EEI and Portland request that the Commission hold a technical 
conference on this proposal.\507\ EEI states that it is unclear how 
existing interconnection agreements and processes would account for the 
generation and load characteristics of electric storage resources.\508\ 
Portland states that further discussions are necessary to address the 
unique characteristics of electric storage resources and that a new 
definition for storage facilities may be appropriate.\509\
---------------------------------------------------------------------------

    \507\ EEI 2017 Comments at 48; Portland 2017 Comments at 3-4.
    \508\ EEI 2017 Comments at 48.
    \509\ Portland 2017 Comments at 4.
---------------------------------------------------------------------------

    283. Southern argues that redefining Generating Facility to include 
electric storage resources would complicate the pro forma LGIP and pro 
forma LGIA.\510\ Southern states that electric storage resources could 
be considered generation or load, and this could cause problems when 
discussing reactive power in article 9.6 of the pro forma LGIA, which 
references the generating facility capacity rather than the load.\511\
---------------------------------------------------------------------------

    \510\ Southern 2017 Comments at 22.
    \511\ Id.
---------------------------------------------------------------------------

    284. NYISO, while stating that it does not take a position, 
suggests that any revisions should also reflect that the facility may 
store energy for withdrawal, as energy storage facilities typically 
both inject and withdraw energy to the grid.\512\ Indicated NYTOs, who 
support the proposal, agree with NYISO on the addition of the term 
``withdrawal'' to the definition.\513\ MidAmerican states that the 
Commission should clarify that the proposal does not permit 
transmission providers to impose restrictions on withdrawals by storage 
resources in excess of restrictions imposed on any other load.\514\
---------------------------------------------------------------------------

    \512\ NYISO 2017 Comments at 30.
    \513\ Indicated NYTOs 2017 Comments at 14.
    \514\ MidAmerican 2017 Comments at 21.
---------------------------------------------------------------------------

ii. Commission Determination
    285. We disagree with EEI's and Southern's arguments that the pro 
forma LGIP and pro forma LGIA may be unable to accommodate the load 
characteristics of an electric storage resource. We note that studies 
under the pro forma LGIP already provide transmission providers with 
the flexibility to address the load characteristics of electric storage 
resources, and that electric storage resources have already 
successfully interconnected pursuant to a Commission-jurisdictional 
LGIP and LGIA.\515\ EEI and Southern provide no evidence that the 
requirements of the LGIP and LGIA cannot accommodate the load 
characteristics of electric storage resources. We note that, if a 
transmission provider finds a particular resource to be outside the 
scope of its existing LGIA, the LGIP permits a transmission provider to 
enter into non-conforming LGIAs when necessary.
---------------------------------------------------------------------------

    \515\ See, e.g., AES New Creek, Docket No. ER12-1100-000 (Apr. 
10, 2012) (delegated letter order) (accepting a non-conforming 
interconnection agreement between PJM, Virginia Electric Power, and 
a combined solar and electric storage resource).
---------------------------------------------------------------------------

    286. We find that ESA's suggestion that we remove the term 
``generator'' from the pro forma LGIA and the pro forma LGIP in favor 
of interconnection agreements based on a facility's technical and 
operational characteristics is beyond the scope of this proposal. We 
find that AES's and Alevo's assertions are beyond the scope of this 
rulemaking because, as previously noted, the final action revisions are 
meant to clarify that new technologies with a capacity of more than 20 
MW may avail themselves of the existing pro forma generator 
interconnection process and interconnection agreement rather than 
defining an electric storage resource. In response to NYISO's 
suggestion to add ``withdrawal'' to the definition, we do not believe 
it is necessary to accept this suggestion. While the meaning of NYISO's 
comment is unclear, to the extent that it refers to an electric storage 
resource's ability to charge, our adopted definition already accounts 
for this ability through the inclusion of the word ``storage.'' 
Anything beyond this interpretation is beyond the scope of this 
proceeding.
e. Other
i. Comments
    287. EEI seeks clarification on whether the proposed change will 
affect tax treatment of generators.\516\ In addition, EEI states that 
the Commission should clarify the applicability of

[[Page 21377]]

wholesale distribution charges to electric storage resources using 
distribution facilities and that the inclusion of electric storage 
resources in the definition does not affect the jurisdiction of 
interconnection studies.\517\
---------------------------------------------------------------------------

    \516\ EEI 2017 Comments at 49.
    \517\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    288. In response to EEI's concern that the proposed change to the 
pro forma LGIP and pro forma LGIA definition of generating facility 
might affect tax treatment of generators, we note that the purpose of 
this proposal is only to allow electric storage resource's with a 
capacity above 20 MW to interconnect pursuant to the pro forma LGIP and 
pro forma LGIA. It should not affect tax treatment of electric storage 
resources.
    289. We find that this definitional change will not affect the 
jurisdictional issues EEI raises. The pro forma LGIP is the process 
provided for Commission-jurisdictional interconnections by resources 
above 20 MW, and this definition change ensures that electric storage 
resources above 20 MW that seek a Commission-jurisdictional 
interconnection can access that interconnection process. All relevant 
jurisdictional delineations and precedent remain unchanged. This 
definition change also does not affect the Commission's precedent on 
wholesale distribution charges when distributed resources use the 
distribution system to reach the wholesale market.
5. Interconnection Study Deadlines
a. NOPR Proposal
    290. The pro forma LGIP requires that transmission providers use 
``reasonable efforts'' \518\ to complete feasibility studies in 45 
days, system impact studies in 90 days, and facilities studies within 
90 or 180 days.\519\ The Commission proposed to require that 
transmission providers post on their OASIS on a quarterly basis summary 
statistics indicating the number of interconnection requests withdrawn 
and interconnection studies completed and delayed, the proportion of 
studies completed within tariff timeframes, and the average time to 
complete a study. Additionally, the Commission proposed to require that 
a transmission provider that exceeds study deadlines for more than 25 
percent of any study type for two consecutive quarters must file 
informational reports at the Commission for the four calendar quarters 
(Filed Report Requirement). If during this period, the transmission 
provider exceeds more than 25 percent of study deadlines for any study 
type for two consecutive quarters, the reporting requirement would be 
retriggered for another four consecutive quarters from the date of the 
last consecutive quarter to exceed the 25 percent threshold.\520\
---------------------------------------------------------------------------

    \518\ The pro forma LGIP states that 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.'' Pro forma LGIP Section 1 
(Definitions).
    \519\ Pro forma LGIP Sections 6.3, 7.4, and 8.3.
    \520\ In this final action, we are modifying the calculation for 
determining whether a transmission provider has triggered the Filed 
Report Requirement so that it reads more simply. For example, for 
the calculation in 35.2.2(E), the new calculation will be the sum of 
35.2.2(B) plus 35.2.2(C) divided by the sum of 35.2.2(A) plus 
35.2.2(C). For ease of readership, we abbreviate here as (B + C) / 
(A + C). This calculation would represent the quarterly total of 
late studies, i.e., completed late studies plus uncompleted late 
studies, divided by the number of studies that should have been 
completed, i.e., completed studies plus uncompleted late studies. 
Although this is a simpler calculation, we note that it is 
mathematically equivalent to the calculation proposed in the NOPR, 
which we abbreviate here as 1-(A-B) / (A + C).
---------------------------------------------------------------------------

    291. To implement this proposal, the Commission proposed to modify 
section 3.4 of the pro forma LGIP \521\ to institute quarterly 
reporting requirements for transmission providers to report 
interconnection study performance on their OASIS. The Commission also 
proposed reporting requirements and justifications that would be 
triggered if a transmission provider exceeds study deadlines for more 
than 25 percent of any study type for two consecutive calendar 
quarters.
---------------------------------------------------------------------------

    \521\ In the ``Utilization of Surplus Interconnection Service'' 
section, the Commission proposed revisions to the pro forma LGIP 
that result in renumbering of several existing sections. One section 
that the Commission proposed to be renumbered is section 3.4. For 
this reason, the proposed revisions to the ``OASIS Posting'' section 
(current section 3.4) will begin at section 3.5.1.
---------------------------------------------------------------------------

    292. The Commission also sought comment on whether: (1) To require 
different interconnection processing statistics to be posted on OASIS 
by the transmission provider; (2) the Commission has proposed the 
appropriate summary data requirements to enhance transparency and what 
customizations of these requirements should be made to adjust for 
different regional processes; (3) interconnection customers have 
sufficient information regarding the cause of study delays; (4) 
transmission providers should have to provide a more detailed 
explanation to interconnection customers regarding the cause(s) of 
study delays; (5) a transmission provider should have to inform 
interconnection customers regarding its process for revising study 
timelines once a delay occurs; and (6) the transmission provider should 
also describe in sufficient detail any relevant issues that could 
further affect the revised timeline for a particular interconnection 
customer.
b. Interconnection Study Metrics Reporting
i. Comments
    293. Numerous commenters support a requirement for transmission 
providers to report on their interconnection study performance.\522\ 
AWEA states that many transmission providers consistently experience 
interconnection study delays due to factors completely within their 
control.\523\ NEPOOL states that reporting requirements will provide 
greater transmission provider accountability, thereby tending to 
improve transmission provider performance and facilitating market 
entry.\524\ NextEra notes that, while it would prefer to eliminate the 
reasonable efforts standard, the NOPR proposal will improve 
transparency into study delay causes and frequency, and this 
transparency could lead to appropriate solutions.\525\
---------------------------------------------------------------------------

    \522\ Alevo 2017 Comments at 7-8; Alliance for Clean Energy 2017 
Comments at 1; AWEA 2017 Comments at 43; Competitive Suppliers 2017 
Comments at 9; EDP 2017 Comments at 7; Joint Renewable Parties 2017 
Comments at 11; NEPOOL 2017 Comments at 13; NextEra 2017 Comments at 
27; PJM 2017 Comments at 20-21; Portland 2017 Comments at 5-6; SEIA 
2017 Comments at 19; TDU Systems 2017 Comments at 21-22.
    \523\ AWEA 2017 Comments at 43-44.
    \524\ NEPOOL 2017 Comments at 13.
    \525\ NextEra 2017 Comments at 27.
---------------------------------------------------------------------------

    294. Some commenters support requiring transmission providers to 
provide additional or even more detailed statistics than the Commission 
proposed \526\ or argue that the Commission should lower the hurdle for 
triggering the Filed Report Requirement (e.g., lowering the 25 percent 
hurdle to 10 percent).\527\
---------------------------------------------------------------------------

    \526\ Alliance for Clean Energy 2017 Comments at 1-2; AWEA 2017 
Comments at 45; EDP 2017 Comments at 7; Generation Developers 2017 
Comments at 34-36; NextEra 2017 Comments at 28.
    \527\ AWEA 2017 Comments at 44-45; Competitive Suppliers 2017 
Comments at 10; Generation Developers 2017 Comments at 35-36.
---------------------------------------------------------------------------

    295. Some supporting commenters would prefer scaling back or 
eliminating specific aspects of the NOPR proposal. PJM opposes the 
Filed Report Requirement; it argues that this requirement would not 
increase efficiency and that the ability to meet study deadlines is 
often outside the transmission provider's control.\528\ Portland also 
opposes the Filed Report Requirement, stating that this proposal could 
disproportionately affect utilities

[[Page 21378]]

with small queues or those that jointly own, but do not operate, 
transmission facilities. Portland suggests that the Commission apply a 
minimum threshold of delayed interconnection studies for triggering 
justifications and that the Commission not impose these requirements if 
the reasons for missing deadlines are outside the transmission 
provider's control.\529\
---------------------------------------------------------------------------

    \528\ PJM 2017 Comments at 20.
    \529\ Portland 2017 Comments at 5-6.
---------------------------------------------------------------------------

    296. Alevo and Invenergy favor financial incentives or penalties 
over reporting requirements to encourage timely study completion.\530\ 
Relatedly, AWEA states that a final action should include remedies for 
interconnection customers affected by transmission providers' failures 
to complete studies accurately and in a timely fashion.\531\ AWEA 
suggests that the Commission require transmission providers to specify 
remedies in their study services agreements for failure to comply with 
timeline provisions.\532\ While it concedes that the NOPR proposal 
increases transparency, Invenergy likewise argues that concrete 
incentives and penalties would result in more timely interconnection 
study performance.\533\ Generation Developers assert that the proposal 
does not respond to the issue of consistently delinquent transmission 
providers. They argue that, as a consequence, such transmission 
providers will have no motivation to improve.\534\
---------------------------------------------------------------------------

    \530\ Alevo 2017 Comments at 7-8; Invenergy 2017 Comments at 8.
    \531\ AWEA 2017 Comments at 46.
    \532\ Id.
    \533\ Invenergy 2017 Comments at 3, 7.
    \534\ Generation Developers 2017 Comments at 34.
---------------------------------------------------------------------------

    297. Some commenters express concerns regarding the potential 
administrative burden imposed by the proposal.\535\ Bonneville, PG&E, 
and Alevo argue that the proposal could divert transmission providers' 
planning resources from conducting studies to meeting administrative 
burdens with no improvement on the underlying causes of delays.\536\ 
EEI states that posting the aggregate number of employee hours and 
third party consultant hours expended toward interconnection studies is 
overly burdensome, is not helpful in evaluating performance, and raises 
customer costs.\537\ TVA notes that the process and tracking burden 
would need to be borne continually by transmission providers, without 
regard to whether a reporting trigger is met.\538\ In contrast, NextEra 
believes that the proposal would not impose a material burden on 
transmission providers because they already know the status of their 
studies.\539\
---------------------------------------------------------------------------

    \535\ See, e.g., Xcel 2017 Comments at 16.
    \536\ Bonneville 2017 Comments at 6; PG&E 2017 Comments at 6; 
Alevo 2017 Comments at 7-8.
    \537\ EEI 2017 Comments at 51.
    \538\ TVA 2017 Comments at 12.
    \539\ NextEra 2017 Comments at 27.
---------------------------------------------------------------------------

    298. APS states that the proposal compromises transmission provider 
flexibility to complete studies and argues that the time required to 
properly assess an interconnection request may vary significantly.\540\ 
APS states that the addition of metrics would constrain the 
interconnection process while providing minimal benefits to the 
interconnection customer.\541\
---------------------------------------------------------------------------

    \540\ APS 2017 Comments at 4.
    \541\ Id.
---------------------------------------------------------------------------

    299. A few commenters state that they do not object to the NOPR's 
proposed reporting requirement.\542\ MidAmerican nonetheless would 
prefer that transmission providers reform the queue process itself, 
rather than reporting on existing processes.\543\ MISO TOs also do not 
oppose the additional study reporting requirements, but they point out 
that they are already subject to extensive reporting requirements.\544\ 
For this reason, they ask the Commission to allow MISO to retain its 
existing reporting requirements, subject to modification as needed to 
include the types of information required by the final action.\545\
---------------------------------------------------------------------------

    \542\ MidAmerican 2017 Comments at 14; MISO TOs 2017 Comments at 
34; Non-Profit Utility Trade Associations 2017 Comments at 17.
    \543\ MidAmerican 2017 Comments at 14.
    \544\ MISO TOs 2017 Comments at 33 (citing Midcontinent Indep. 
Sys. Operators, Inc., 158 FERC ] 61,003, at P 108 (2017)).
    \545\ Id.
---------------------------------------------------------------------------

    300. Other commenters expressly oppose the proposal to require the 
posting of interconnection study statistics.\546\ Duke states that the 
primary reasons for delays are queue withdrawals and material 
modifications.\547\ EEI argues that the proposal fails to consider 
circumstances outside the transmission provider's control, and that 
without additional context, this information will not benefit 
interconnection customers.\548\ NYISO indicates that the 25 percent 
missed deadline requirements are unnecessarily punitive and would 
jeopardize NYISO's ability to be flexible as needed during the 
interconnection process.\549\ NYISO also argues that additional 
administrative requirements to track study statistics will not expedite 
the study process.\550\
---------------------------------------------------------------------------

    \546\ Duke 2017 Comments at 15-16; EEI 2017 Comments at 50; ISO-
NE 2017 Comments at 33-35; NYISO 2017 Comments at 32-34; Xcel 2017 
Comments at 16.
    \547\ Duke 2017 Comments at 16.
    \548\ EEI 2017 Comments at 50-51.
    \549\ NYISO 2017 Comments at 34.
    \550\ Id. at 32.
---------------------------------------------------------------------------

    301. Xcel states that delays are often caused by interconnection 
customer actions and minor disputes between interconnection customers 
and transmission providers, but there is no evidence that transmission 
providers are being opaque or have not provided sufficient 
justifications for delays. Xcel notes that interconnection customers 
can challenge unreasonable delays through a variety of means--including 
the Commission's Enforcement hotline and the FPA section 206 process--
and that Commission audits review the interconnection process.\551\ 
Xcel also argues that the NOPR proposal does not account for regions 
with fewer requests or delays caused by changes in study assumptions, 
negotiation of contractual language, or interpretation of technical 
study results. Xcel states that, if the Commission proceeds with this 
proposal, it should limit the LGIP requirements to providing a written 
description of the cause of the delay.\552\
---------------------------------------------------------------------------

    \551\ Xcel 2017 Comments at 16.
    \552\ Id.
---------------------------------------------------------------------------

    302. Some commenters consider currently available information to be 
sufficient for interconnection customers.\553\ Duke asserts that the 
LGIP already requires transmission providers to inform interconnection 
customers about the causes of study delays and schedule revisions.\554\ 
Indicated NYTOs state that NYISO currently provides sufficient 
interconnection study information on its public website and to 
interconnection customers, and NYISO updates its Transmission Planning 
Advisory Committee on the status of all pending large generator 
facility interconnections.\555\ Indicated NYTOs also state that NYISO 
updates its OASIS with additional information as to where an 
interconnection request is situated in the study process and which 
studies have been completed.\556\ Additionally, Indicated NYTOs state 
that interconnection customers receive more detailed information 
directly throughout the study process.\557\ Xcel indicates 
interconnection customers currently have sufficient transparency 
regarding the causes of delays and that any delays are discussed 
directly with the customer. Xcel states that if the customer does not 
understand the cause

[[Page 21379]]

of a delay, it can ask the transmission provider for 
clarification.\558\
---------------------------------------------------------------------------

    \553\ See, e.g., EEI 2017 Comments at 51 (citing pro forma LGIP 
Sections 6.3, 7.4, and 8.3).
    \554\ Duke 2017 Comments at 16; see also Xcel 2017 Comments at 
16.
    \555\ Indicated NYTOs 2017 Comments at 11; see also NYISO 2017 
Comments at 30.
    \556\ Indicated NYTOs 2017 Comments at 11.
    \557\ Id.
    \558\ Xcel 2017 Comments at 16.
---------------------------------------------------------------------------

    303. NYISO states that it currently maintains on its OASIS a list 
of all valid interconnection requests, together with the status of the 
interconnection request including, for example, where the project is in 
the study process and what studies have been completed.\559\ NYISO 
asserts that adding additional detail regarding the status of a 
particular study is not informative to the specific interconnection 
customer, which already knows its status. Moreover, NYISO argues that 
additional administrative requirements to track study statistics will 
not expedite the study process.\560\ NYISO contends that the best way 
to expedite interconnection studies is through targeted process 
improvements, such as those NYISO has proposed to its stakeholders; 
\561\ NYISO states that it has a number of proposals that would improve 
study processing efficiency.\562\ Similarly, MISO recommends allowing 
existing stakeholder processes to accomplish the objectives of the 
proposed reporting requirements and notes that it is currently working 
to increase study timing visibility.\563\
---------------------------------------------------------------------------

    \559\ NYISO 2017 Comments at 30.
    \560\ Id. at 32.
    \561\ Id. at 30-32.
    \562\ Id. at 32.
    \563\ MISO 2017 Comments at 30.
---------------------------------------------------------------------------

    304. NYISO urges the Commission to allow it to tailor appropriate 
process improvements with the goal of expediting the studies rather 
than merely tracking their status.\564\ NYISO contends that posting the 
requested information is only informative if a transmission provider 
reveals additional details that may require disclosure of confidential 
information. NYISO also argues that such detailed information regarding 
the status of a particular study is appropriately shared only with the 
interconnection customer, not all projects in the interconnection 
queue.\565\
---------------------------------------------------------------------------

    \564\ NYISO 2017 Comments at 32.
    \565\ Id. at 33.
---------------------------------------------------------------------------

ii. Commission Determination
    305. In this final action, we adopt the NOPR proposal modifying the 
pro forma LGIP section on OASIS Posting \566\ to require transmission 
providers to post interconnection study metrics to increase the 
transparency of interconnection study completion timeframes. We note, 
however, that we are modifying the posting location requirement, as 
discussed further below in the subsection ``Requirement to Post 
Interconnection Study Metrics on OASIS'' of this final action. As 
proposed in the NOPR, transmission providers shall post this 
interconnection study metric information on a quarterly basis. We also 
adopt the Filed Report Requirement.\567\ The revisions to the pro forma 
LGIP adopted in this final action are provided in Appendix B to Order 
No. 845.
---------------------------------------------------------------------------

    \566\ This has been renumbered to pro forma LGIP section 3.5 
through this final action.
    \567\ Any informational reports that transmission providers file 
at the Commission are for informational purposes and will not be 
formally noticed nor require additional action by the Commission. 
See Grid Assurance LLC, 154 FERC ] 61,244, at n.106, order on 
clarification, 156 FERC ] 61,027 (2016).
---------------------------------------------------------------------------

    306. The current requirement that transmission providers complete 
interconnection studies on a timely basis is based on a ``reasonable 
efforts'' \568\ standard. This standard can be challenging to apply in 
the absence of information required in this final action, including 
information about how long it takes transmission providers to complete 
studies and the resources a transmission provider uses to complete 
interconnection studies. Information on interconnection study metrics 
should provide needed transparency to allow interconnection customers 
to assess whether a transmission provider is using ``reasonable 
efforts.'' This information should also allow interconnection customers 
to develop informed expectations about how long the interconnection 
study portion of the process actually takes.
---------------------------------------------------------------------------

    \568\ ``Reasonable Efforts'' in Pro forma LGIP Section 1 
(Definitions).
---------------------------------------------------------------------------

    307. Many commenters that oppose this proposal cite concerns about 
the potential administrative burden. We find unpersuasive comments that 
these requirements will be administratively burdensome for transmission 
providers in general, to those with small queues, or those that jointly 
own, but do not operate, their transmission assets. We find that the 
reporting requirement we adopt strikes a reasonable balance between 
providing increased transparency and information to interconnection 
customers while not unduly burdening transmission providers. We find 
that the increased transparency resulting from these new requirements 
should provide for improved queue management and better informed 
interconnection customer planning--results that may be important enough 
to support some corresponding burden on transmission providers. 
Further, as noted by NextEra, transmission providers already know the 
status of their studies, which suggests that the reporting requirement 
should impose minimal, additional administrative burdens on 
transmission providers. With regard to the assertion that the reporting 
requirement will unduly burden transmission providers with smaller 
interconnection queues, we find it reasonable for a transmission 
provider with a small volume interconnection queue to detail the 
reasons for the delay of a lone study or a small number of studies, 
information that is still beneficial to interconnection customers. In 
these instances, the reporting requirement would not be more burdensome 
than for transmission providers with high volume queues that must 
provide this information for a greater number of studies, if additional 
reporting requirements are triggered. With regard to Portland's 
contention that the reporting requirement will disproportionately 
burden transmission providers that jointly own, but do not operate, 
their transmission assets, we find little evidence in the record to 
support this assertion. We note that a transmission owner's assignment 
of operational responsibility to a joint owner does not necessarily 
relieve it of its responsibilities or performance obligations.
    308. Multiple commenters argue that interconnection customers are 
often the cause of interconnection study delays. Others question the 
usefulness of the information to be posted for interconnection 
customers or other stakeholders. We find that the detailed information 
provided to the Commission through the Filed Report Requirement should 
be particularly beneficial in identifying process deficiencies and the 
causes of delays in regions that experience significant delays in 
interconnection study processing. Additionally, this requirement 
complements the requirement that the causes of study delays be provided 
to interconnection customers upon request and does not duplicate the 
requirement in sections 6.3, 7.4, and 8.3 of the pro forma LGIP related 
to informing interconnection customers about the causes of study 
delays. While those provisions require transmission providers to 
provide the reasons for study delays to individual interconnection 
customers, these newly adopted provisions require the transmission 
provider to submit study delay information to the Commission.
    309. Some commenters encourage consideration of modifications and 
alternatives to the Commission's proposal. We find that the reporting 
requirements we adopt in this final action strike a reasonable balance 
between transparency into the timing and processing of interconnection

[[Page 21380]]

requests while maintaining a transmission provider's schedule 
flexibility to process complex and interdependent interconnection 
requests. As noted in the NOPR and supporting comments, the 
requirements should identify the geographical locations where 
interconnection study delays occur most often and will document the 
delays' causes. We recognize that often a delay will not be the result 
of the transmission provider having acted inappropriately; therefore, 
we do not propose implementing automatic penalties for delayed studies, 
in recognition of this possibility. Nonetheless, we believe that 
adopting pro forma LGIP provisions will improve transparency by 
highlighting where interconnection study delays are most common and the 
causes of delays in these regions. Such information could highlight 
systemic problems for individual transmission providers and 
interconnection customers. This information could also be useful to the 
Commission in determining if additional action is required to address 
interconnection study delays.
    310. In response to commenters that seek to eliminate the Filed 
Report Requirement, we reiterate that this information should be useful 
for identifying the causes of delays in regions that experience a 
significant number of study delays. A number of entities should find 
the publication of this information useful, including stakeholders 
active in or considering entrance into a regional interconnection 
queue, the Commission, and transmission providers as they actively 
monitor their queue management efforts. We reiterate that we do not 
expect this information to be overly burdensome, as it should largely 
consist of information already tracked by the transmission provider. In 
response to commenters that propose alternative metrics to trigger 
reporting requirements, the Commission notes that the timeframes stated 
in the tariff are clear and defined and thus should be familiar to the 
transmission provider and appropriate to use for measuring transmission 
provider performance.
    311. In response to commenters that advocate development of 
solutions and requirements through the regional stakeholder process, we 
find that the information required through interconnection study 
metrics should better inform stakeholder discussions, including 
discussions about need for further action. Further, many 
interconnection customers develop generation projects in multiple 
regions. Therefore, having a minimum set of information that is 
comparable across regions would allow for quicker and more useful 
assessment by interconnection customers of the viability of potential 
projects. Furthermore, this reform is not intended to disrupt 
stakeholder processes. We note that, on compliance, each transmission 
provider may explain how it will comply with the requirements adopted 
in this final action.
c. Requirement To Post Interconnection Study Metrics on OASIS
i. Comments
    312. CAISO objects to the requirement to post interconnection study 
information on OASIS.\569\ CAISO contends that using existing public 
websites, portals, and reports should satisfy any publication 
requirement and would save ratepayers from the expense of moving data 
onto OASIS.\570\ Additionally, CAISO argues that using existing public 
websites, portals, and reports would allow the critical assets to 
remain confidential.\571\ OATI states that the metrics proposed are in 
line with similar requirements for transmission request studies but 
asks the Commission to direct this posting requirement to NAESB to 
establish a uniform location for the posting of these metrics on 
OASIS.\572\
---------------------------------------------------------------------------

    \569\ CAISO 2017 Comments at 22.
    \570\ Id.
    \571\ Id.
    \572\ OATI 2017 Comments at 6.
---------------------------------------------------------------------------

ii. Commission Determination
    313. In this final action, we are modifying the location 
requirement for the quarterly posted summary interconnection study 
metrics. In the NOPR proposal, the quarterly summary statistic 
information required posting on OASIS. However, we agree with CAISO's 
comments that transmission providers should have the flexibility to 
post this information on their OASIS sites or on a public website. If 
the transmission provider posts on its website, however, it must 
provide a clear link to the information on OASIS.
    314. In response to OATI's request, we decline to specifically 
require that transmissions providers work through NAESB to develop a 
uniform posting location for these requirements. Transmission providers 
may, of course, coordinate as they determine appropriate to implement 
the Commission's requirements and to develop any relevant posting 
protocols.
d. Reasonable Efforts Standard and Firm Study Deadlines
i. Comments
    315. Generation Developers and NextEra advocate elimination of the 
``reasonable efforts'' standard as a way to improve study 
timeliness,\573\ the result of which would be to impose firm study 
deadlines Generation Developers state that, even with the new reporting 
requirement, transmission providers still have no obligation or 
incentives to meet the study deadline in their LGIPs.\574\
---------------------------------------------------------------------------

    \573\ Generation Developers 2017 Comments at 33-34; NextEra 2017 
Comments at 27.
    \574\ Generation Developers 2017 Comments at 33-34.
---------------------------------------------------------------------------

    316. Several commenters prefer to retain the ability of 
transmission providers to use ``reasonable efforts'' to complete 
interconnection studies.\575\ According to Imperial, numerous factors 
affect timely study completion, and preserving the reasonable efforts 
standard, while imposing these new reporting requirements, will afford 
transmission providers the requisite flexibility to account for study 
delays beyond their control.\576\ NYISO states that, in its experience, 
interconnection customer non-responsiveness and inaccuracy interferes 
with its ability to perform timely interconnection studies. NYISO also 
notes that it must coordinate with all affected systems. NYISO states 
that, given these factors and other unique project complexities, the 
Commission should continue to evaluate interconnection study completion 
in accordance with the reasonable efforts standard.\577\
---------------------------------------------------------------------------

    \575\ Bonneville 2017 Comments at 6; Duke 2017 Comments at 15-
16; Imperial 2017 Comments at 19; NYISO 2017 Comments at 33-34.
    \576\ Imperial 2017 Comments at 20.
    \577\ NYISO 2017 Comments at 33-34.
---------------------------------------------------------------------------

    317. TVA expresses concern that the transmission provider efforts 
needed to meet all deadlines would reduce the current flexibility that 
benefits both interconnection customers and transmission 
providers.\578\ PG&E and Indicated NYTOs oppose establishment of fixed 
study deadlines.\579\ Indicated NYTOs argue that imposing artificial 
deadlines can lead to prematurely completed studies that do not fully 
investigate all reliability issues, which could result in transmission 
owners having to pay for later-identified upgrades.\580\
---------------------------------------------------------------------------

    \578\ TVA 2017 Comments at 12.
    \579\ Indicated NYTOs 2017 Comments at 10-11; PG&E 2017 Comments 
at 6-7.
    \580\ Indicated NYTOs 2017 Comments at 11.
---------------------------------------------------------------------------

    318. TDU Systems urge the Commission to consider adding a tolling 
provision to relevant provisions of the

[[Page 21381]]

pro forma OATT because hard deadlines can be a ``two-edged sword'' for 
interconnection customers. Thus, they urge the Commission to toll the 
deadlines during periods when the transmission provider is responding 
to questions from the interconnection customer concerning study methods 
or results. TDU Systems contend that this will ensure that the deadline 
does not serve as a reason for the transmission provider to refuse to 
respond to legitimate questions from the interconnection customer.\581\
---------------------------------------------------------------------------

    \581\ TDU Systems 2017 Comments at 21-22.
---------------------------------------------------------------------------

    319. Rather than set study timeframes, APS and Bonneville believe 
that interconnection customers would benefit more from discussion and 
establishment of realistic study timeframes than from the reporting 
requirements.\582\ APS suggests that the Commission could better 
address queue delays by empowering transmission providers to set a 
default timeframe for study completion that is tiered based on specific 
factors, such as size, location, presence of affected systems, or 
expected amount of upgrades.\583\ APS asserts that, if the Commission 
determines that an interconnection customer needs additional details 
about a request's study progress, the best solution is a requirement 
that the transmission provider coordinate more closely with the 
interconnection customer.\584\
---------------------------------------------------------------------------

    \582\ APS 2017 Comments at 5; Bonneville 2017 Comments at 6.
    \583\ APS 2017 Comments at 4.
    \584\ APS 2017 Comments at 4-5.
---------------------------------------------------------------------------

    320. If the Commission adopts the NOPR proposal, ISO-NE asks that 
the Commission revise the reporting construct so that performance is 
evaluated in accordance with the reasonable efforts standard and not 
the timeframes established in the pro forma LGIP.\585\ ISO-NE states 
that, alternatively, the Commission should allow regional flexibility 
for ISO-NE to evaluate and revise the timeframes to more realistically 
reflect the time that it takes to complete interconnection 
studies.\586\
---------------------------------------------------------------------------

    \585\ ISO-NE Comments at 35.
    \586\ Id. at 36.
---------------------------------------------------------------------------

    321. CAISO opposes the interconnection study reporting requirement 
proposal as applied to CAISO and other transmission providers with firm 
study deadlines.\587\ CAISO states that its interconnection procedures 
and transmission planning process are coordinated such that one process 
informs the other and that this linkage necessitates timely 
interconnection study completion.\588\ As such, CAISO asserts, its 
transmission owners complete studies on a timely basis, and it already 
publishes detailed study process schedules for each queue cluster on 
its public website.\589\ CAISO requests that the Commission clarify 
that this proposal is limited to those transmission providers and 
owners whose tariffs do not have firm study deadlines.\590\
---------------------------------------------------------------------------

    \587\ CAISO 2017 Comments at 21.
    \588\ Id. at 22.
    \589\ Id. (citing https://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx).
    \590\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    322. In response to concerns that the Commission is implementing 
firm interconnection study deadlines, we clarify that the NOPR did not 
propose, and the final action declines to adopt, firm deadlines for 
completing interconnection studies. Further, the NOPR did not propose 
to, and this final action does not eliminate, the reasonable efforts 
standard or reduce transmission provider flexibility. Many commenters 
seem to equate measurement of a transmission provider's ability to meet 
the study timeframes in their tariffs as the equivalent of establishing 
firm study deadlines. Many commenters argue against firm study 
deadlines and against elimination of the reasonable efforts standard.
    323. We do not believe the current record supports elimination of 
the ``reasonable efforts'' standard to meet study deadlines and to 
instead impose firm deadlines. At this time, we believe the reasonable 
efforts standard continues to be the appropriate approach to 
interconnection study processing. We find that reliance on improved 
reporting is a preferable approach to encourage timely processing of 
interconnection studies, rather than moving to a regime of firm study 
deadlines. Such reporting should also help inform the Commission if any 
future action should be considered.
    324. We disagree with ISO-NE's argument that interconnection study 
metrics should be calculated to reflect compliance with the reasonable 
efforts standard rather than tariff deadlines. The reasonable efforts 
standard is not meant to specify a timeframe but rather to impose a 
performance standard on the transmission provider. If ISO-NE's request 
\591\ is that each interconnection study conducted per an 
interconnection request have a specific amount of time determined as 
appropriate for completion under the reasonable efforts standard, we 
note that ISO-NE has tariff-prescribed timeframes that are designed to 
apply to most interconnection requests.
---------------------------------------------------------------------------

    \591\ ISO-NE 2017 Comments at 35.
---------------------------------------------------------------------------

    325. APS, Bonneville and ISO-NE contend that the Commission should 
allow transmission providers to establish interconnection study 
timeframes that more realistically reflect the time that it takes to 
complete interconnection studies. This request is outside the scope of 
this proceeding because the final action is not proposing to modify the 
study timeframes currently memorialized in transmission providers' 
LGIP.
    326. We disagree with CAISO's contention that transmission 
providers with firm deadlines should not be subject to the reporting 
requirements of this final action. Interconnection customers and the 
queue management process would still benefit from posting relevant 
metrics regarding study completion in prescribed timeframes. We also 
note that, if a transmission provider has firm study deadlines that it 
always meets, then it would not trigger the Filed Report Requirement.
e. Challenges in Calculating Reported Metrics
i. Comments
    327. Southern states that there are too many potential clock resets 
and restudies to result in any meaningful metrics.\592\ It does not see 
the value of using withdrawal metrics and considers average study cost 
to be a more meaningful metric than aggregating the total number of 
employee and third-party consultant hours.\593\ TVA asserts that, for 
the proposed metrics to be useful, there would need to be consistent 
definitions of start and stop times for each study phase and ways to 
adjust for customer[hyphen]caused delays.\594\
---------------------------------------------------------------------------

    \592\ Southern 2017 Comments at 23.
    \593\ Id.
    \594\ TVA 2017 Comments at 12-13.
---------------------------------------------------------------------------

    328. Consistent with Order No. 890, ISO-NE requests that the 
Commission clarify that the starting point for interconnection study 
metrics can be the date when the study begins or some other agreed upon 
date instead of the date the study agreement is signed.\595\
---------------------------------------------------------------------------

    \595\ ISO-NE 2017 Comments at 36 (citing Preventing Undue 
Discrimination and Preference in Transmission Service, Order No. 
890, FERC Stats. & Regs. ] 31,241, at P 747, order on reh'g, Order 
No. 890-A, FERC Stats. & Regs. ] 31,261 (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) (clarifying that the 60-day due diligence 
period starts on the date the transmission study agreement is 
executed, unless the transmission provider and the customer agree on 
an alternative day for the transmission provider to begin the study, 
and explaining that, while the transmission provider and customer 
may not alter the length of the study period, they can mutually 
agree as to the day on which the study begins)).

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

[[Page 21382]]

    329. Additionally, ISO-NE requests that the Commission extend the 
period for posting the information from 30 to 60 days to allow 
sufficient time for the transmission provider to collect the 
information, such as from third-party consultant invoices.\596\
---------------------------------------------------------------------------

    \596\ Id. at 39.
---------------------------------------------------------------------------

    330. PG&E requests clarification as to the application of the 
Commission's proposed metrics.\597\ PG&E states that it is unclear 
whether they would apply to material modification applications, to 
cluster studies only, or also to Fast Track, repowering, and in-service 
date studies.\598\
---------------------------------------------------------------------------

    \597\ PG&E 2017 Comments at 7.
    \598\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    331. In response to Southern's and TVA's comments, we clarify that 
the start date for each study included in the performance reporting 
metrics is the date that the transmission provider receives a fully 
executed study agreement. If multiple study agreements have been 
executed for an interconnection request, or interconnection studies 
have been completed, delayed, or are ongoing, then the metric reporting 
period should begin the date that the transmission provider received 
the last executed study agreement and be measured to the most recent 
relevant study conducted or planned for that study agreement. In 
response to TVA's comment about adjusting the performance metrics for 
interconnection customer-caused delays, we note that one of the 
objectives of the quarterly metrics is to identify regions where the 
transmission provider consistently completes interconnection studies on 
a delayed basis. The metric is not intended to identify the causes of 
those delays. This information is potentially useful to existing 
stakeholders as well as generation developers considering pursuing 
projects in that region and the lack of metric adjustment for delaying 
factors provides for easier comparability of interconnection study 
completion timeframes across regions. The Commission believes that 
stakeholders will be most interested in explanations for missed 
deadlines in queue backlogged regions and an informational report to 
the Commission from such regions will be useful for identifying the 
delay causes.
    332. We disagree with ISO-NE that the starting point for 
interconnection study metrics should be a date other than the date the 
transmission provider receives a fully executed study agreement. The 
metrics adopted in this final action provide information on the 
transmission provider's ability to meet the timeframes described in the 
pro forma tariff. These date ranges are clearly defined, and the period 
between the executed study agreement and the study completion date 
reflects the amount of time to complete a study after the study's terms 
are formally agreed upon. Some regions may experience significant 
delays in beginning a study after study agreements are signed; in these 
instances, metrics based on a transmission provider's performance once 
a study is begun--which could be long after executing the study 
agreement--would not be as informative and useful as the Commission's 
adopted metrics.
    333. We also disagree with ISO-NE that we should extend the posting 
time period from 30 to 60 days. Interconnection customers make 
decisions with information as it becomes available, and we believe that 
30 days allows sufficient time for the transmission provider to post 
the required information.
    334. In response to PG&E's question about the application of the 
proposed metrics, we clarify that these metrics apply to 
interconnection requests within the queue, including clustering and 
fast-track projects. We expect that a change to a project that triggers 
material modification provisions, though it will lose its queue 
position, would be in the queue as would repowering projects. Thus, the 
study performance metric calculations must include such projects.
6. Improving Coordination With Affected Systems
a. NOPR Request for Comments
    335. The interconnection of a new generating facility to a 
transmission system may affect the reliability of a neighboring, or 
affected, transmission system. Currently, section 3.5 of the pro forma 
LGIP requires the transmission provider to coordinate the conduct of 
any studies required to determine the impact of an interconnection 
request on affected systems with the affected system operators. The 
transmission provider should also, if possible, include those results 
in the applicable interconnection study. Because the affected system 
operator is not bound by the terms of the interconnection transmission 
provider's LGIP, its process and schedule may differ from the 
transmission provider's processing of the interconnection request. In 
Order No. 2003, the Commission explained that:

[a]lthough the owner or operator of an Affected System is not bound 
by the provisions of the . . . LGIP or LGIA, the Transmission 
Provider must allow any Affected System to participate in the 
process when conducting the Interconnection Studies, and incorporate 
the legitimate safety and reliability needs of the Affected 
System.\599\
---------------------------------------------------------------------------

    \599\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 121.

    336. Order No. 2003 further explained that, if the affected system 
operator does not provide information in a timely manner, a 
transmission provider may proceed without accounting for any 
information the affected system could have provided.\600\ Often, 
however, transmission providers will not proceed without receiving 
reliability-related analysis from any affected systems. AWEA raised the 
issue of affected system impacts in its petition,\601\ and the 
Commission discussed the issue at the 2016 Technical Conference.
---------------------------------------------------------------------------

    \600\ Id. On rehearing, the Commission clarified that delays by 
an affected system in performing interconnection studies or 
providing information for such studies is not an acceptable reason 
to deviate from the timetables established in Order No. 2003 unless 
the interconnection itself (as distinct from any future delivery 
service) will endanger reliability. See Order No. 2003-A, FERC 
Stats. & Regs. ] 31,160 at P 114.
    \601\ Petition at 31.
---------------------------------------------------------------------------

    337. Order No. 2003 does not require that transmission providers 
publish their affected system coordination process. During the Order 
No. 2003 proceeding, the Commission declined Duke's request to require 
affected systems to participate in the interconnection process with 
interconnection customers.\602\ The Commission reiterated, however, 
that a transmission provider must allow any affected system to 
participate in the interconnection study process and must incorporate 
the affected system's legitimate safety and reliability needs.\603\
---------------------------------------------------------------------------

    \602\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 121.
    \603\ Id. PP 120-121.
---------------------------------------------------------------------------

    338. The Commission stated in the NOPR that providing affected 
system coordination guidelines and timeframes could better inform 
interconnection customers and could result in fewer late-stage 
withdrawals due to the unforeseen cost of affected system network 
upgrades.\604\ The Commission further posited that clear procedures and 
timelines regarding the affected system's study of a proposed 
interconnection memorialized in a Commission-approved affected systems

[[Page 21383]]

analysis agreement could ameliorate delays caused by the affected 
systems coordination process.
---------------------------------------------------------------------------

    \604\ NOPR, FERC Stats. & Regs. ] 32,719 at P 158.
---------------------------------------------------------------------------

    339. In the NOPR, the Commission sought comment on the following: 
prescribing guidelines for affected systems coordination; imposing 
study requirements and associated timelines on affected systems that 
are also public utility transmission providers; standardizing the 
process for coordinating with an affected system during the 
interconnection process; developing a standard affected system study 
agreement; and additional steps (e.g., conducting a technical 
conference or workshop focused on improving issues that arise when 
affected systems are impacted).
b. Comments
    340. Multiple commenters responded to the questions posed by the 
NOPR. We have not included a summary of the comments pertaining to 
affected systems coordination because the Commission did not propose 
any specific reforms pertaining to affected systems in the NOPR and is 
considering these issues in another proceeding, as discussed below. 
However, these comments informed that discussion.
c. Commission Determination
    341. On April 3 and 4, 2018, Commission staff convened a technical 
conference in Docket No. AD18-8-000 to explore issues related to the 
coordination of affected systems raised in this proceeding. The 
technical conference also explored issues related to the coordination 
of affected systems raised in the complaint filed by EDF Renewable 
Energy, Inc. against Midcontinent Independent System Operator, Inc., 
Southwest Power Pool, Inc., and PJM Interconnection, L.L.C. in Docket 
No. EL18-26-000. The Notice Inviting Post-Technical Conference 
Comments, which issued concurrently with this final action, states that 
initial and reply comments are due within 30 days and 45 days, 
respectively, from the date of the notice's issuance. The Commission is 
considering next steps in light of the technical conference held in 
Docket Nos. AD18-8-000 and EL18-26-000. We decline to take further 
action in this rulemaking proceeding. Any further action on this issue 
would reference Docket No. AD18-8-000.

C. Enhancing Interconnection Processes

    342. In the NOPR, the Commission proposed reforms designed to 
enhance interconnection processes by making use of underutilized 
interconnection service, providing interconnection service earlier, and 
accommodating changes in the development process.
1. Requesting Interconnection Service Below Generating Facility 
Capacity
a. NOPR Proposal
    343. The Commission proposed to modify the pro forma LGIP to allow 
interconnection customers to request interconnection service that is 
lower than full generating facility capacity,\605\ recognizing the need 
for proper control technologies and penalties to ensure that the 
generation facility does not inject energy above the requested level of 
service.\606\ The Commission also requested comment on whether, instead 
of such pro forma LGIP revisions, such interconnection requests should 
be processed on an ad hoc basis.\607\
---------------------------------------------------------------------------

    \605\ The term generating facility capacity means ``the net 
capacity of the Generating Facility and the aggregate net capacity 
of the Generating Facility where it includes multiple energy 
production devices.'' Pro forma LGIA Art. 1.
    \606\ NOPR, FERC Stats. & Regs. ] 32,719 at P 167-68.
    \607\ Id. P 173.
---------------------------------------------------------------------------

    344. The Commission proposed that an interconnection customer that 
seeks interconnection service below its generating facility capacity 
should be subject to reasonable provisions that enforce a maximum 
export limit and a process for notifying an interconnection customer 
that it has exceeded such limit.
    345. The Commission also specifically proposed that interconnection 
customers be subject to reasonable penalties if they exceed their 
requested service levels, and that such penalties could be discrete 
financial penalties, a requirement to pay the cost of additional 
interconnection facilities or network upgrades, or the loss of 
interconnection rights. The Commission sought comment on the potential 
penalties that may be imposed if an interconnection customer exceeds 
its service level.\608\
---------------------------------------------------------------------------

    \608\ Id. P 168.
---------------------------------------------------------------------------

    346. The Commission also specifically sought comment on the types 
and availability of control technologies and protective equipment to 
ensure that a generating facility does not exceed its level of 
interconnection service.\609\ Finally, the Commission proposed changes 
to the definitions of ``Large Generating Facility'' and ``Small 
Generating Facility'' in the pro forma LGIP and pro forma LGIA so that 
they are based on the level of interconnection service for the 
generating facility rather than the generating facility capacity.\610\
---------------------------------------------------------------------------

    \609\ Id. P 169.
    \610\ Id. P 172.
---------------------------------------------------------------------------

    347. Consistent with the proposals above, the NOPR proposed to add 
the following new paragraph at the end of section 3.1 of the pro forma 
LGIP (with proposed new text in italics):

    The 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. 
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 as well as any 
potential penalties for exceeding the level of Interconnection 
Service established in the executed, or requested to be filed 
unexecuted, LGIA shall be established in Appendix C of that 
executed, or requested to be filed unexecuted, LGIA.\611\
---------------------------------------------------------------------------

    \611\ Id. P 174. In this final action, the adopted language 
differs slightly from the NOPR language because we remove the word 
``the'' before ``Transmission Provider.''

    348. The NOPR proposed to add the following language to the end of 
---------------------------------------------------------------------------
section 6.3 of the pro forma LGIP (with proposed new text in italics):

    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.\612\
---------------------------------------------------------------------------

    \612\ Id. P 175.

    349. The NOPR proposed to insert the following language in section 
7.3 of the pro forma LGIP in line 8 of the second paragraph (with 
---------------------------------------------------------------------------
proposed new text in italics):

    For purposes of determining necessary 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.\613\
---------------------------------------------------------------------------

    \613\ Id. P 176.

    350. The NOPR proposed to add the following language to the end of 
---------------------------------------------------------------------------
section 8.2 of the pro forma LGIP (with proposed new text in italics):

    The Facilities Study will also identify any potential control 
equipment for requests for

[[Page 21384]]

Interconnection Service that are lower than the Generating Facility 
Capacity.\614\
---------------------------------------------------------------------------

    \614\ Id. P 177.

    351. The NOPR proposed to add the following language to Appendix 1, 
Item 5, of the pro forma LGIP, as sub-item h (with proposed new text in 
---------------------------------------------------------------------------
italics):

Requested capacity (in MW) of Interconnection Service (if lower than 
the Generating Facility Capacity).\615\
---------------------------------------------------------------------------

    \615\ Id. P 178.

    352. Lastly, the NOPR proposed to change the definition of ``Large 
Generating Facility'' and ``Small Generating Facility'' in section 1 of 
the pro forma LGIP and article 1 of the pro forma LGIA as follows 
---------------------------------------------------------------------------
(proposed to delete the bracketed text and add the italicized text):

    Large Generating Facility shall mean a Generating Facility for 
which an Interconnection Customer has [having a Generating Facility 
Capacity] requested Interconnection Service of more than 20 MW.

    Small Generating Facility shall mean a Generating Facility for 
which an Interconnection Customer has requested Interconnection 
Service [that has a Generating Capacity] of no more than 20 MW.\616\
---------------------------------------------------------------------------

    \616\ Id. P 179.
---------------------------------------------------------------------------

b. General
i. Comments
    353. Most responsive commenters support the proposal.\617\ Alevo 
states that electric storage facilities may not plan to use the maximum 
power rating of their facilities; therefore, they should have the 
ability to request interconnection service at the power rating of their 
choice.\618\ NextEra also argues that rejecting requests for 
interconnection below full generating facility capacity can result in 
paying for unneeded interconnection facilities and network 
upgrades.\619\
---------------------------------------------------------------------------

    \617\ Alevo 2017 Comments at 8; AFPA 2017 Comments at 3; AWEA 
2017 Comments at 52; Bonneville 2017 Comments at 7; CAISO 2017 
Comments at 27; California Energy Storage Alliance 2017 Comments at 
6; Joint Renewable Parties 2017 Comments at 12; ELCON 2017 Comments 
at 7; ESA 2017 Comments at 8.
    \618\ Alevo 2017 Comments at 8.
    \619\ NextEra 2017 Comments at 34-35 (citing NOPR, FERC Stats. & 
Regs. ] 32,719 at P 167).
---------------------------------------------------------------------------

    354. A number of commenters see benefits to the proposal. Several 
commenters see the potential for lower costs.\620\ AFPA and the Public 
Interest Organizations assert that allowing for interconnection service 
below capacity will improve the efficiency and fairness of the 
interconnection process and enhance reliability.\621\ ESA agrees, 
adding that the proposal will allow interconnection customers to 
request service that reflects a given resource's intended 
operation.\622\ ESA and AFPA contend that the proposal will remove 
undue discrimination toward highly controllable or unique resources, 
such as electric storage resources or combined heat and power, in 
interconnection processes.\623\ ESA further argues that the proposal 
will facilitate market entry of electric storage resources by 
eliminating excessive costs and will allow electric storage resources 
to use spare interconnection service to repower existing conventional 
generators or firm the deliveries of variable generators.\624\
---------------------------------------------------------------------------

    \620\ AFPA 2017 Comments at 14; Public Interest Organizations 
2017 Comments at 5-8; ELCON 2017 Comments at 7; ESA 2017 Comments at 
8; IECA 2017 Comments at 3.
    \621\ AFPA 2017 Comments at 14; Public Interest Organizations 
2017 Comments at 5-8; MidAmerican 2017 Comments at 17.
    \622\ ESA 2017 Comments at 8.
    \623\ Id.; AFPA 2017 Comments at 14.
    \624\ ESA 2017 Comments at 10.
---------------------------------------------------------------------------

    355. AWEA states that developers of new technologies have an 
interest in requesting interconnection service at levels below 
generating facility capacity.\625\ It notes that wind turbine 
manufacturers often make minor upgrades to equipment or software to 
increase capacity, and these upgrades sometimes occur during the 
pendency of an interconnection request. As a result, the final 
generating facility capacity may be greater than what was originally 
specified in the interconnection request. AWEA argues that in such 
cases, the interconnection customer may prefer to avoid seeking an 
increase in interconnection service because increasing the generating 
facility capacity may constitute a material modification that triggers 
the need for a restudy.\626\ AWEA further argues that allowing an 
interconnection customer to increase its capacity without increasing 
its requested level of interconnection service and without it being 
considered a material modification would promote more efficient 
operation of wind plants.\627\ AWEA states that allowing 
interconnection service at levels below generating facility capacity 
would benefit wind facilities due to the collector system losses that 
occur, as the output of the multiple turbines at a wind farm are 
aggregated before injection to the grid. According to AWEA, these 
losses result in the maximum real power output at the point of 
interconnection being measurably lower than the combined generating 
facility capacity of the individual units.\628\
---------------------------------------------------------------------------

    \625\ AWEA 2017 Comments at 52.
    \626\ Id. at 52-53.
    \627\ Id. at 52-53.
    \628\ Id. at 53-54.
---------------------------------------------------------------------------

    356. ESA and NextEra also point out that, in Order No. 792, the 
Commission revised the pro forma SGIP to allow small generating 
facilities to attain interconnection service below installed capacity, 
if the interconnection customer installs acceptable control 
technologies to avoid violating injection limits; thus, it would be 
inconsistent to not allow the same for large generating 
facilities.\629\
---------------------------------------------------------------------------

    \629\ ESA 2017 Comments at 11 (citing Order No. 792, 145 FERC ] 
61,159 at P 230); NextEra 2017 Comments at 37.
---------------------------------------------------------------------------

    357. ELCON, ESA, and NextEra also note that the proposal will 
reduce the overbuilding of interconnection facilities and network 
upgrades.\630\ According to Industrial Energy Consumers of America, 
this reform should also increase existing asset utilization and improve 
the accuracy and reliability of interconnection studies.\631\ 
MidAmerican argues that the proposal may reduce late-stage withdrawals 
from the queue by allowing interconnection customers to operate at 
reduced output levels rather than requiring network upgrades that would 
otherwise render them non-viable.\632\ NEPOOL suggests that the 
proposal provides options and flexibility for market participants and 
could facilitate market entry of new resources.\633\
---------------------------------------------------------------------------

    \630\ ESA 2017 Comments at 8; ELCON 2017 Comments at 7; NextEra 
2017 Comments at 35.
    \631\ IECA 2017 Comments at 3.
    \632\ MidAmerican 2017 Comments at 17.
    \633\ NEPOOL 2017 Comments at 14-15.
---------------------------------------------------------------------------

    358. CAISO notes that the flexibility afforded by the proposal can 
benefit interconnection customers--especially for newer resources that 
combine storage, conventional generation, high auxiliary load, and/or 
onsite demand-side management.\634\ It further argues that the 
transmission operator is unaffected so long as the interconnection 
request studies the correct capacity and the generating facility never 
exceeds that capacity.\635\ ELCON also notes that the proposal would 
provide benefits for industrial co-generators or other behind-the-meter 
industrial generation.\636\
---------------------------------------------------------------------------

    \634\ CAISO 2017 Comments at 27.
    \635\ Id.
    \636\ ELCON 2017 Comments at 7.
---------------------------------------------------------------------------

    359. Multiple commenters note that similar programs are already in 
place in some RTOs/ISOs, either on a formal or informal basis, 
including CAISO, MISO, PJM, and ISO-NE.\637\ ESA and NextEra offer 
examples of where interconnection

[[Page 21385]]

service lower than installed capacity is already occurring without 
reliability problems.\638\ ESA provides examples in CAISO, MISO, and 
PJM, where it believes projects have been sized to allow greater 
generation deliveries over time, but where the facilities (including 
one that combines solar and storage) never deliver at maximum 
output.\639\
---------------------------------------------------------------------------

    \637\ CAISO 2017 Comments at 27; MISO 2017 Comments at 33; PJM 
2017 Comments at 23-24; NEPOOL 2017 Comments at 14-15.
    \638\ ESA 2017 Comments at 10-11; NextEra 2017 Comments at 36.
    \639\ ESA 2017 Comments at 10-11.
---------------------------------------------------------------------------

    360. CAISO and PG&E state that CAISO allows interconnection 
requests for less than generating facility capacity, as long as the 
interconnection customer installs appropriate monitoring and control 
technologies to enforce the maximum export limit.\640\ PG&E notes that 
various projects have made such requests, particularly solar 
resources.\641\
---------------------------------------------------------------------------

    \640\ CAISO 2017 Comments at 27; PG&E 2017 Comments at 7 (citing 
CAISO Business Practice Manual for Generator Management, Section 
6.5.4.1).
    \641\ PG&E 2017 Comments at 7.
---------------------------------------------------------------------------

    361. PG&E notes that CAISO also allows interconnection projects to 
downsize their capacity, which is functionally equivalent to limiting a 
project with excess capacity.\642\
---------------------------------------------------------------------------

    \642\ Id.
---------------------------------------------------------------------------

    362. MISO notes that its generator interconnection agreement allows 
interconnection customers to request interconnection service below the 
capacity of the proposed generating facility and limits the net 
injection to the allowed interconnection service level.\643\ MISO notes 
that the additional limiting language gives the transmission owner and 
MISO the right to enforce the limit.\644\ Similarly, NextEra explains 
that MISO has allowed it to amend an existing interconnection agreement 
to reflect an increase in the rating of a wind generation project 
without an increase in the level of interconnection service 
provided.\645\
---------------------------------------------------------------------------

    \643\ MISO 2017 Comments at 33.
    \644\ Id.
    \645\ NextEra 2017 Comments at 36-37.
---------------------------------------------------------------------------

    363. PJM states that it currently allows interconnection customers 
to limit injection rights subject to additional studies at both the 
requested level of interconnection service to identify required network 
upgrades, as well as at the generating facility's full capacity.\646\ 
PJM explains that these studies allow PJM to specify the system 
protections necessary in the event of system contingencies.\647\ 
NextEra states that PJM has allowed a wind generator to install 
capacity in excess of the level of interconnection service in the 
agreement.\648\
---------------------------------------------------------------------------

    \646\ PJM 2017 Comments at 24.
    \647\ Id.
    \648\ NextEra 2017 Comments at 36-37.
---------------------------------------------------------------------------

    364. ISO-NE states that it supports the proposal and has already 
implemented a similar process under its existing interconnection 
procedures.\649\ Similarly, NEPOOL states that interconnection 
customers in ISO-NE can already request an amount of interconnection 
service less than generating facility capacity at the time of the 
interconnection request or before beginning the system impact 
study.\650\ NEPOOL notes that if a generating facility consists of 
multiple generating units, ISO-NE would need to study a number of 
possible output combinations, which could increase study costs and 
timelines but could also potentially reduce upgrade requirements.\651\ 
NEPOOL states that ISO-NE studies such requests at the requested below-
generating facility capacity amount, and the interconnection customer 
must explain how it will limit output of its facility to that 
level.\652\
---------------------------------------------------------------------------

    \649\ ISO-NE 2017 Comments at 40.
    \650\ NEPOOL 2017 Comments at 15.
    \651\ NEPOOL 2017 Comments at 15.
    \652\ Id.
---------------------------------------------------------------------------

    365. Non-Profit Utility Trade Associations, NYISO, and SEIA do not 
object to the proposal.\653\ Portland generally supports this proposal, 
but states that there are potential queue and reliability impacts.\654\ 
TVA argues that the proposal imposes an undesirable monitoring and 
mitigation burden on transmission system operators, and that the 
necessary protective systems introduce undesirable reliability 
challenges.\655\ Southern expresses concern that interconnection 
customers could take advantage of this proposal to avoid costly network 
upgrades.\656\ EEI requests that the Commission ensure that any 
revisions to the pro forma LGIA or LGIP provide clear requirements for 
interconnection customers.\657\ Non-Profit Utility Trade Associations 
recommend establishing NERC reliability standards for interconnection 
customers operating at levels below their rated capacity, which would 
constrain them to the rating at which their generation was 
studied.\658\
---------------------------------------------------------------------------

    \653\ Non-Profit Utility Trade Associations 2017 Comments at 4, 
21-22; NYISO 2017 Comments at 36; SEIA 2017 Comments at 21.
    \654\ Portland 2017 Comments at 6.
    \655\ TVA 2017 Comments at 14-16.
    \656\ Southern 2017 Comments at 25.
    \657\ EEI 2017 Comments at 54; NYISO 2017 Comments at 36.
    \658\ Non-Profit Utility Trade Associations 2017 Comments at 24.
---------------------------------------------------------------------------

    366. In response to the Commission's question in the NOPR regarding 
whether, instead of revising the pro forma LGIP, such interconnection 
requests should be processed on an ad hoc basis,\659\ ESA states that 
an ad hoc basis for considering interconnection requests below 
cumulative installed capacity does not provide sufficient certainty to 
interconnection customers seeking interconnection service below a 
resource's installed capacity.\660\ NextEra agrees, arguing that an ad 
hoc approach could lead to arbitrary and potentially unduly 
discriminatory results.\661\
---------------------------------------------------------------------------

    \659\ NOPR, FERC Stats. & Regs. ] 32,719 at P 173.
    \660\ ESA 2017 Comments at 11.
    \661\ NextEra 2017 Comments at 37-38.
---------------------------------------------------------------------------

ii. Commission Determination
    367. In this final action, we adopt the NOPR proposal to modify 
sections 3.1, 6.3, 7.3, 8.2, and Appendix 1 of the pro forma LGIP to 
allow interconnection customers to request interconnection service that 
is lower than full generating facility capacity, recognizing the need 
for proper control technologies and penalties to ensure that the 
generating facility does not inject energy above the requested level of 
service.\662\ We also withdraw the proposal to revise the definitions 
of ``Large Generating Facility'' and ``Small Generating Facility'' in 
the pro forma LGIA so that they are based on the level of 
interconnection service for the generating facility rather than the 
generating facility capacity, and make certain clarifications, as 
discussed further below.
---------------------------------------------------------------------------

    \662\ We are therefore not pursuing the alternative, ad hoc 
approach to interconnections below generating facility capacity, 
about which the NOPR sought comment.
---------------------------------------------------------------------------

    368. The majority of responsive comments either support the NOPR 
proposals outright or emphasize the importance of allowing transmission 
providers to retain the tools necessary to continue to ensure reliable 
operations. Furthermore, as noted by some commenters, some RTOs/ISOs 
have already permitted such flexibility in the generator 
interconnection process without causing reliability issues.
    369. We find that the reforms and clarifications made in this final 
action, coupled with existing provisions in the pro forma LGIA, provide 
the desired flexibility for interconnection customers while allowing 
transmission providers to ensure reliability.
    370. The reforms adopted here are consistent with existing 
provisions of the pro forma LGIA. Article 6 of the pro forma LGIA 
provides transmission providers with broad ability to test and inspect 
or require the testing and inspection of interconnection facilities and 
network upgrades. Articles 7 and 8 of the pro forma LGIA provide a 
similarly broad ability to transmission

[[Page 21386]]

providers with respect to metering and communications requirements 
relevant to interconnection. All of these existing provisions would 
apply to interconnection requests that are below generating facility 
capacity, just as they do to other interconnection requests, and they 
would thus help ensure that the necessary control technologies for 
limiting injection adhere to transmission provider requirements.
    371. Most importantly, article 9 of the pro forma LGIA describes 
both the transmission provider's and the interconnection customer's 
obligations with respect to operations of the interconnection 
facilities and network upgrades and, in particular, defines system 
protection facilities to include ``the equipment, including necessary 
protection signal communications equipment, required to protect the 
transmission provider's transmission system from faults or other 
electrical disturbances occurring at the generating facility.'' \663\ 
Article 9.7.4.1 of the pro forma LGIA requires the interconnection 
customer to pay for the installation, operation, and maintenance of 
system protection facilities associated with its interconnecting 
generating facility. We find that the necessary control technologies 
for limiting injection discussed in the NOPR are a subset of the system 
protection facilities that transmission providers are empowered to 
require and all interconnection customers are required to pay for under 
article 9.7.4.1 of the pro forma LGIA.
---------------------------------------------------------------------------

    \663\ LGIA Art. 1 (Definitions) (emphasis added).
---------------------------------------------------------------------------

    372. We note that nothing in article 9.7.4.1 of the pro forma LGIA 
prevents interconnection customers from proposing system protection 
facilities to limit their injection rights to meet the transmission 
provider's requirements. Therefore, this aspect of the final action 
makes those interconnection customer rights explicit, while still 
preserving the transmission provider's ability to ensure system 
protection under the existing pro forma LGIA provisions. Commenters 
have not argued that these broad, existing authorities are insufficient 
in the context of interconnection requests operating below full 
generating facility capacity.
    373. Furthermore, article 5.9 of the pro forma LGIA permits an 
interconnection customer to request the study and, if appropriate, 
subsequent use of, a lower level of interconnection service, termed 
``limited operation,'' in cases where the transmission provider's 
interconnection facilities or network upgrades are not reasonably 
expected to be completed prior to the commercial operation date of the 
generating facility. While this existing LGIA provision is intended to 
permit temporary operation at below generating facility capacity, the 
fact that entities have successfully made use of this provision 
demonstrates that there should not be anything inherently unworkable 
about the concept of interconnection below generating facility 
capacity. Therefore, we find that this final action does not adversely 
impact transmission providers' ability to ensure reliable 
interconnection consistent with good utility practice.
    374. Finally, with respect to the Non-Profit Utility Trade 
Associations' suggestion that a NERC reliability standard be considered 
that would constrain interconnection customers operating at levels 
below their rated generating facility capacity to the rating at which 
the facilities are studied, we find that suggestion to be outside the 
scope of this rulemaking proceeding. As discussed above, the existing 
system protection facility provisions of the pro forma LGIA, which 
apply to all interconnection customers, adequately ensure that below-
generating facility capacity interconnection customers do not exceed 
the limits for which they are studied.
c. Study Assumptions and Modeling
i. Comments
    375. Commenters disagree on the appropriate way to model and 
conduct studies of resources that seek to interconnect below their 
capacity. Some commenters argue that the studies should focus solely on 
the reduced generating facility capacity. For example, AWEA, ESA, and 
NextEra assert that transmission providers should not be able to study 
interconnection requests at full generating facility capacity. They 
argue that the interconnection customer should be able to determine 
operational assumptions and limitations, especially given the 
sophisticated and reliable characteristics of available monitoring and 
control technologies.\664\
---------------------------------------------------------------------------

    \664\ AWEA 2017 Comments at 54; ESA 2017 Comments at 12; NextEra 
2017 Comments at 40-41.
---------------------------------------------------------------------------

    376. ESA argues that, if a transmission provider is skeptical that 
proposed control systems are adequate, it should identify the 
shortcomings of the proposed control scheme to the customer and suggest 
what modifications address these shortcomings.\665\ NextEra argues that 
requiring studies at full generating facility capacity would 
``undermine the very goal of the Commission's proposed reforms.'' \666\
---------------------------------------------------------------------------

    \665\ ESA 2017 Comments at 12.
    \666\ NextEra 2017 Comments at 39.
---------------------------------------------------------------------------

    377. On the other hand, NYISO contends that, to ensure reliability, 
short circuit analysis of the full generating facility capability and 
steady-state and dynamic study evaluations of the specific mechanism, 
which would serve to enforce this limit, are necessary.\667\ NYISO 
asserts that these evaluations are necessary to ensure that the 
mechanism does not impact the resource's ability to reliably 
interconnect to the New York state transmission system or distribution 
system and that, in the event that the mechanism fails, there are no 
adverse short circuit impacts.\668\
---------------------------------------------------------------------------

    \667\ NYISO 2017 Comments at 36.
    \668\ Id.
---------------------------------------------------------------------------

    378. Similarly, ESA and NextEra suggest that short circuit and 
stability studies should be performed using full generating facility 
capacity, whereas thermal studies should be at the level of 
interconnection requested.\669\ However, if a transmission provider 
decides to perform thermal studies at the full generating facility 
capacity rating, then NextEra suggests tariff language stating that 
those study costs should be borne by the transmission provider and be 
outside the normal queue timeframe.\670\ NextEra adds that a 
transmission provider should be able to refuse to grant the requested 
lower level of interconnection service just as it could refuse to 
proceed with an interconnection request, subject to dispute resolution, 
if a customer objects to a system protection facility proposed by the 
transmission provider.\671\
---------------------------------------------------------------------------

    \669\ ESA 2017 Comments at 12-13; NextEra 2017 Comments at 40.
    \670\ Id. at 41.
    \671\ Id. at 41.
---------------------------------------------------------------------------

    379. Bonneville and Non-Profit Utility Trade Associations emphasize 
that transmission providers should be able to study at full generating 
facility capacity in cases where safety or reliability concerns may 
arise.\672\ Duke goes further, stating that system impact studies and 
facilities studies should use full generating facility capacity for 
reliability reasons.\673\
---------------------------------------------------------------------------

    \672\ Bonneville 2017 Comments at 7; Non-Profit Utility Trade 
Associations 2017 Comments at 4, 21-22.
    \673\ Duke 2017 Comments at 19.
---------------------------------------------------------------------------

    380. On the other hand, TDU Systems contends that, to ensure 
transparency, the transmission provider must be able to document the 
need for a study at full generating facility capacity.\674\ EEI is not 
aware of any protection system that would eliminate the need to study 
the full generating facility capacity and

[[Page 21387]]

therefore doubts that the proposal would reduce costs.\675\
---------------------------------------------------------------------------

    \674\ TDU Systems 2017 Comments at 27-28.
    \675\ EEI 2017 Comments at 55.
---------------------------------------------------------------------------

    381. ITC and Six Cities support the NOPR proposal that the costs of 
all additional studies should be borne by the interconnection 
customer.\676\
---------------------------------------------------------------------------

    \676\ ITC 2017 Comments at 18, Six Cities 2017 Comments at 5.
---------------------------------------------------------------------------

    382. SoCal Edison takes a middle view, stating that the necessary 
studies would depend on the specifics of each interconnecting 
project.\677\ It states that, based on its experience, the cost to 
study a generating facility at less than its full capacity is either 
the same as or higher than a regular process.\678\ SoCal Edison 
suggests that dual technologies (e.g., solar coupled with energy 
storage) will require more study time than normal,\679\ and would 
actually have higher study costs, despite the fact that the output is 
limited, as two or three different scenarios would need to be evaluated 
for stability and post-transient voltage performance.\680\
---------------------------------------------------------------------------

    \677\ SoCal Edison 2017 Comments at 7.
    \678\ Id.
    \679\ Id.
    \680\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    383. We adopt the NOPR proposal that the transmission provider will 
study requests for interconnection service at the level of 
interconnection service requested by the interconnection customer for 
purposes of interconnection facilities, network upgrades, and 
associated costs, but may, at the transmission provider's discretion as 
clarified below, also perform other studies at the full generating 
facility capacity to ensure safety and reliability of the transmission 
system, with the study costs borne by the interconnection customer.
    384. We clarify that, if the transmission provider determines, 
based on good utility practice and related engineering considerations 
and after accounting for the proposed control technology, that studies 
at the full generating facility capacity are necessary to ensure safety 
and reliability of the transmission system when an interconnection 
customer requests interconnection service that is lower than full 
generating facility capacity, then it must provide a detailed 
explanation for such a determination in writing to the interconnection 
customer. For example, some interconnection customers may have proposed 
generating facilities that may raise short-circuit/fault-duty concerns 
that require certain studies to be performed at full generating 
facility capacity, even if the generating facilities will normally be 
limited to operation below full generating facility capacity. If the 
transmission provider determines in accordance with good utility 
practice and related engineering considerations after accounting for 
the proposed control technology that additional network upgrades are 
needed based on these studies, the transmission provider must: (1) 
Specify which additional network upgrade costs are based on which 
studies; and (2) provide a detailed explanation why the additional 
network upgrades are needed.
    385. In response to Duke's comment that transmission providers 
should always perform system impact studies and facilities studies at 
full generating facility capacity for reliability reasons, we reiterate 
that, if the transmission provider either accepts the interconnection 
customer's proposed control technology or designs its own control 
technology as part of the system protection facilities for the 
interconnection, then the transmission provider should, subject to the 
limited exception discussed above, perform the necessary studies to 
ensure safety and reliability of the transmission system and evaluate 
system performance to interconnect the generating facility at the 
requested generating facility capacity level. In addition, to improve 
transparency, we clarify that the transmission provider must inform the 
interconnection customer, after the feasibility study phase regarding 
which studies (e.g., steady-state, short circuit/fault duty, and 
dynamic stability analysis) will be performed at which generating 
facility capacity level.
    386. We further clarify that, if disputes related to the 
transmission provider's use of discretion while processing 
interconnection requests for interconnection service that is lower than 
full generating facility capacity cannot be resolved, the parties may 
seek dispute resolution through any process that may be available in 
the relevant LGIP, LGIA or through DRS, and/or may bring the dispute to 
the Commission under a FPA section 206 complaint or, if appropriate, as 
part of the transmission provider's filing of an unexecuted LGIA.
d. Limits on Energy Injection/Monitoring/Control
i. Comments
    387. Many commenters focus on ways to ensure that generating 
facilities do not exceed the energy injection limits in the 
interconnection agreement. Almost all agree that appropriate control 
technology is necessary to prevent interconnection customers from 
exceeding the approved interconnection service limit.\681\ Most agree 
that such tools are available, though there is wide variation in 
suggested implementation. For example, Portland agrees that sufficient 
mechanical and electronic tools exist that can restrain an 
interconnection customer from operating above its allowed service 
level, and also that transmission providers should establish such 
arrangements.\682\
---------------------------------------------------------------------------

    \681\ AFPA 2017 Comments at 14; ESA 2017 Comments at 12; AWEA 
2017 Comment at 54; California Energy Storage Alliance 2017 Comments 
at 5-6; PJM 2017 Comments at 24; Duke 2017 Comments at 18-19; EEI 
2017 Comments 2017 at 54; TDU Systems 2017 Comments at 27-28.
    \682\ Portland 2017 Comments at 7.
---------------------------------------------------------------------------

    388. AWEA notes that programmable meters and other technologies 
that allow plant operators to self-curtail are widely available,\683\ 
and ESA and NextEra state that wind and solar projects already use 
software control systems and inverters to modulate their output, and 
that equipment failure is rare.\684\
---------------------------------------------------------------------------

    \683\ AWEA 2017 Comments at 54.
    \684\ ESA 2017 Comments at 12, NextEra 2017 Comments at 39.
---------------------------------------------------------------------------

    389. CAISO states that exceeding studied interconnection capacity 
can result in serious safety and reliability risks to the grid and the 
generator itself.\685\ It argues that it is more critical to have 
tested and well-maintained protection schemes that enforce these limits 
and operate circuit breakers to disconnect the generator from the 
transmission system than an interconnection customer's contractual 
commitment to do so.\686\ CAISO supports strict enforcement of 
interconnection capacity limits, including opening breakers as 
enforcement and, if needed, terminating LGIAs.\687\ NYISO also states 
that it and the connecting transmission owner should be able to take 
action as necessary to maintain reliability--e.g., the ability to 
curtail the resource.\688\ Non-Profit Utility Trade Associations note 
that control equipment ensuring appropriate power flows is a critical 
reliability feature.\689\
---------------------------------------------------------------------------

    \685\ CAISO 2017 Comments at 27.
    \686\ Id.
    \687\ Id.
    \688\ NYISO 2017 Comments at 36-37.
    \689\ Non-Profit Utility Trade Associations 2017 Comments at 22.
---------------------------------------------------------------------------

    390. PJM explains that it currently requires that interconnection 
customers install appropriate power flow monitoring and control 
technologies at their generating facilities to limit the facilities' 
allowable injection on to the transmission system.\690\ ISO-NE argues

[[Page 21388]]

that any control equipment proposed to restrict the generating 
facility's output to the requested interconnection service levels must 
be identified in the project description at the beginning of the study 
process.\691\
---------------------------------------------------------------------------

    \690\ PJM 2017 Comments at 24-25.
    \691\ ISO-NE 2017 Comments at 41-42.
---------------------------------------------------------------------------

    391. SoCal Edison states that, to mitigate the risk of exceeding an 
interconnection service limit, the interconnection customer should have 
to install a control system that meters total output at the high side 
of the main transformer banks.\692\
---------------------------------------------------------------------------

    \692\ SoCal Edison 2017 Comments at 6.
---------------------------------------------------------------------------

    392. The Non-Profit Utility Trade Associations also argue that 
interconnection customers should bear the costs of control technologies 
and protection system costs because such equipment is not useful to 
other customers.\693\ MISO TOs, Duke and TDU Systems state that the 
interconnection customer should be obliged to install or pay for the 
necessary control technologies.\694\
---------------------------------------------------------------------------

    \693\ Non-Profit Utility Trade Associations 2017 Comments at 4, 
21-22.
    \694\ MISO TOs 2017 Comments at 36; Duke 2017 Comments at 18-19; 
TDU Systems 2017 Comments at 27-28.
---------------------------------------------------------------------------

    393. NextEra further explains that an over-delivery would only 
result from a failure of the generation control system or inverter 
controls, akin to a computer malfunction, which NextEra notes is 
theoretically possible, but very rare.\695\ NextEra also argues that, 
if a malfunction were to occur, protective relay controls could be 
installed that manually trip breakers when output levels exceed 
specified levels at the point of interconnection, establishing a 
secondary and redundant control mechanism.\696\
---------------------------------------------------------------------------

    \695\ NextEra 2017 Comments at 40.
    \696\ Id. n.26.
---------------------------------------------------------------------------

    394. In contrast, while MidAmerican agrees that the generating 
facility output must not exceed the level of interconnection service, 
it does not support a universal requirement for special hardware or 
software systems.\697\ MidAmerican sees no clear reason why resources 
having interconnection service at levels below their full output should 
be singled out for special hardware or software requirements. Further, 
it argues that the Commission's proposal for ``provisional'' service 
appears functionally equivalent to operating a generating facility for 
a period of time below its rated generating facility capacity, yet the 
proposal for provisional service makes no mention of special hardware 
or software schemes.\698\
---------------------------------------------------------------------------

    \697\ MidAmerican 2017 Comments at 18.
    \698\ Id.
---------------------------------------------------------------------------

    395. Xcel also advises the Commission to not regulate specific 
technical processes used to limit dispatch as technology may evolve and 
each region's processes are unique. Xcel notes that it uses a manual 
process for its net-zero facility in MISO, and believes its process is 
sufficient.\699\ Similarly, for inverter-based resources, California 
Energy Storage Alliance asks the Commission not to impose a requirement 
for burdensome and expensive protection equipment that may duplicate 
similar utility equipment.\700\
---------------------------------------------------------------------------

    \699\ Xcel 2017 Comments at 17.
    \700\ California Energy Storage Alliance 2017 Comments at 5-6.
---------------------------------------------------------------------------

ii. Commission Determination
    396. As discussed above, we find that the revisions and 
clarifications in this rulemaking coupled with existing provisions of 
the pro forma LGIA adequately address the Commission's proposal to 
require that any interconnection customer that seeks interconnection 
service below its generating facility capacity install appropriate 
monitoring and control technologies at its generating facility. We 
agree with ISO-NE's argument that any control technologies proposed by 
the interconnection customer to restrict the generating facility's 
output to the requested interconnection service levels must be 
identified in the project description at the beginning of the study 
process. We clarify that we see no reason to preclude a customer from 
relying on the transmission provider to identify protection and control 
technologies in the first instance. Indeed, as discussed earlier, the 
existing system protection facilities provisions in the pro forma LGIA 
already allow the transmission provider to identify and require the 
installation of appropriate system protection facilities.\701\
---------------------------------------------------------------------------

    \701\ As discussed earlier, any protection and control 
technologies necessary to restrict the generating facility's output 
to the requested interconnection service levels would be components 
of the system protection facilities associated with that generating 
facility's interconnection.
---------------------------------------------------------------------------

    397. With respect to SoCal Edison's argument that the 
interconnection customer's control technologies should have to meter 
total output at the high side of the main transformer banks, we see no 
need for this requirement because the pro forma LGIP and pro forma LGIA 
require transmission providers to make such engineering judgments 
consistent with good utility practice.
    398. With respect to the Non-Profit Utility Trade Associations' 
argument that control technologies and protection system costs should 
be treated as directly assigned costs, as discussed earlier, we find 
that these control and protection technologies are system protection 
facilities as defined in existing pro forma LGIA article 9.7.4.1, which 
already directly assigns these costs to the interconnection customer.
    399. MidAmerican and NextEra argue that facilities without special 
control systems are no more likely to over-deliver than generators that 
have not requested interconnection service below their facility 
capacity. As an example, MidAmerican points out the case of a generator 
operating under provisional interconnection service, which has the 
ability to over-generate if it does not adhere to its interconnection 
service request level. NextEra makes a similar observation with respect 
to thermal generation generally.\702\ We appreciate these points, and 
note further that many generators of various types interconnected under 
ERIS may have the technical capability to generate beyond the level to 
which they are limited by the terms of their LGIAs providing for ERIS. 
However, we note that article 9.7.4.1 of the pro forma LGIA already 
generally allows a transmission provider to require appropriate control 
technologies for limiting injection from interconnection customers. The 
revisions to sections 3.1 and 8.2 of the pro forma LGIP that we adopt 
here with regard to control technologies serve to make such provisions 
explicit in the pro forma LGIP in the case where interconnection 
service is requested below generating facility capacity, in recognition 
of the fact that, in such instances, the generating facility may be 
coordinating output from multiple generating facilities, and may 
therefore have unique control characteristics and challenges.
---------------------------------------------------------------------------

    \702\ NextEra 2017 Comments at 45.
---------------------------------------------------------------------------

    400. With regard to the type of control strategy/design that 
NextEra proposed, we expect a transmission provider to find such a 
control system, or a control system of equal dependability, acceptable 
for the purposes of evaluating interconnection requests for 
interconnection service that is lower than full generating facility 
capacity. There may be circumstances in which a transmission provider 
could reasonably find that additional back-ups or other functions are 
necessary for a control system to be acceptable. We stress that the 
transmission provider should identify such circumstances based on 
relevant technical details, reliability requirements, and good utility 
practice,

[[Page 21389]]

and that it should make such determinations in a manner that is not 
unduly discriminatory or preferential.
e. Process for Changing an Interconnection Request
i. Comments
    401. As discussed further below, in the pro forma LGIP, 
interconnection customers are allowed to reduce the level of their 
generating facility capacity at two points: prior to the system impact 
study and prior to the facilities study. Commenters suggest that the 
Commission should consider provisions to allow customers to also 
request reduced interconnection service at varying points through the 
interconnection process, though they do not necessarily agree on the 
details. For example, AWEA and EEI argue that, if an interconnection 
customer wishes to change service levels at a later time, the 
interconnection customer should be required to submit an additional 
interconnection request for the new level of service unless the new 
level of service was previously studied.\703\
---------------------------------------------------------------------------

    \703\ AWEA 2017 Comments at 54-55; EEI 2017 Comments at 54.
---------------------------------------------------------------------------

    402. Similarly, Idaho Power, Portland, and Southern assert that, if 
the customer has a future request to operate at a higher MW level, a 
new system impact study should be required.\704\ Southern further 
states that an interconnection customer's request to modify the 
interconnection service amount to less than the generating facility 
capacity should constitute a material modification to its 
interconnection request.\705\ In a related vein, NEPOOL states that 
some of its participants want flexibility for the interconnection 
customer. They request that the customer be able to base necessary 
upgrades on either a smaller generating facility that has been approved 
as non-material or based on an agreement to limit the generating 
facility output below the originally requested service. They argue that 
the customer should be able to do this once studies have started or 
after studies are completed and the transmission provider has provided 
estimates regarding upgrade costs, all without losing queue 
position.\706\ NEPOOL contends that some developers might consider 
particularly high upgrade costs unacceptable, which could result in 
more queue withdrawals if interconnection customers cannot reduce their 
requested generating facility capacity without losing their queue 
position.\707\ NEPOOL states that, in some cases even a small reduction 
in the requested amount of interconnection service can significantly 
reduce interconnection upgrade costs and make projects viable.\708\ 
NEPOOL requests that the final action clarify when interconnection 
customers can reduce their requested level of interconnection service 
and provide guidance on the appropriateness of affording any 
flexibility to reduce capacity for purposes of determining upgrades 
after interconnection studies have started or are complete.\709\
---------------------------------------------------------------------------

    \704\ Idaho Power 2017 Comments at 5; Portland 2017 Comments at 
6; Southern 2017 Comments at 25.
    \705\ Id. at 25-26.
    \706\ NEPOOL 2017 Comments at 15.
    \707\ Id.
    \708\ Id. at 15-16.
    \709\ Id. at 16.
---------------------------------------------------------------------------

    403. Similarly, Idaho Power argues that the NOPR fails to address a 
situation where a customer agrees to accept a lower level of service to 
shift network upgrade costs to other interconnection customers behind 
in the queue that may be vying for limited capacity (i.e., by delaying 
operation to the higher capacity until network upgrades have been 
funded by these projects).\710\ ITC goes further, arguing that, where a 
generator has already executed an LGIA, a request for reduced 
generating facility capacity could undermine the study assumptions for 
lower-queued projects, and therefore, the Commission should permit 
transmission providers to deny requests for reduced service where 
granting such a request would cause cascading adverse impacts.\711\
---------------------------------------------------------------------------

    \710\ Idaho Power 2017 Comments at 5.
    \711\ ITC 2017 Comments at 18-19.
---------------------------------------------------------------------------

    404. Non-Profit Utility Trade Associations argue that the 
Commission should allow for cost-sharing of upgraded systems funded by 
subsequent interconnecting customers if the generation-limited entity 
chooses to take advantage of that additional investment by subsequently 
increasing output.\712\ They state that there could be instances where 
a generation-limited entity may wish to increase its output as a result 
of subsequent interconnection customers that fund network upgrades that 
increase system capabilities. They indicate that, in such instances, 
the upgrade users, including the generation-limited entity, should 
share the costs to guard against gaming by entities that would attempt 
to ``foist upgrade costs upon subsequent interconnecting entities.'' 
\713\
---------------------------------------------------------------------------

    \712\ Non-Profit Utility Trade Associations 2017 Comments at 4, 
21-22.
    \713\ Id. at 23.
---------------------------------------------------------------------------

ii. Commission Determination
    405. The Commission agrees with those commenters that suggest that 
interconnection customers should be able to request reduced 
interconnection service after submitting an interconnection request. 
However, we do not believe this flexibility can be without limit, or it 
could adversely impact the interconnection process. As will be 
explained further below, interconnection customers already have the 
right to reduce the generating facility capacity at certain points in 
the interconnection process, even though such reductions may impact 
interconnection requests later in the queue. The provisions that allow 
an interconnection customer to reduce its requested generating facility 
capacity do not currently allow an interconnection customer to reduce 
its requested level of interconnection service at the same points. 
Therefore, in this final action, we are revising the pro forma LGIP to 
allow an interconnection customer to either request interconnection 
service below generating facility capacity at the outset or reduce its 
level of requested interconnection service at the same two points in 
the interconnection process, as set forth below. An interconnection 
customer may choose to do so if doing so is, in its business judgment, 
advantageous and if it is willing to abide by the limitations of 
interconnection service below generating facility capacity. 
Accordingly, as described further below, the Commission revises pro 
forma LGIP sections 4.4.1 and 4.4.2 to permit interconnection customers 
to reduce their requested level of interconnection service at the same 
points in the interconnection process as they are currently able to 
reduce their generating facility capacity. Specifically, this final 
action requires that interconnection customers can submit a request for 
interconnection service below generating facility capacity as its 
initial interconnection request, or may submit a request to reduce 
interconnection service below generating facility capacity at two 
points after the interconnection process has begun: (1) As a revision 
of its interconnection request prior to when the interconnection 
customer returns an executed system impact study agreement to the 
transmission provider; and (2) as a revision of its interconnection 
request prior to when the interconnection customer returns an executed 
facility study agreement to the transmission provider. These decision 
points are based on existing sections 4.4.1 and 4.4.2 of the pro forma 
LGIP.

[[Page 21390]]

    406. Section 4.4.1 of the pro forma LGIP allows interconnection 
customers to decrease the electrical output of the proposed project by 
up to 60 percent before the interconnection customer returns an 
executed system impact study agreement to the transmission 
provider.\714\ Additionally, section 4.4.2 of the pro forma LGIP allows 
customers to decrease the plant size by an additional 15 percent prior 
to the return of an executed facility study agreement.\715\ As 
originally written, these sections allow interconnection customers to 
reduce the generating facility capacity from that proposed in the 
original interconnection request (i.e., interconnection customers may 
request to build a smaller plant). In other words, as originally 
written, these sections do not allow for reductions in interconnection 
service (i.e., for interconnection customers to lower interconnection 
service levels without altering the size of the generating facility). 
However, with the appropriate transmission provider-approved control 
technologies in place, we see no reason why interconnection customers 
should not also have the option of reducing the level of 
interconnection service at these two stages of the interconnection 
process. Therefore, we revise pro forma LGIP sections 4.4.1 and 4.4.2 
as follows (with new text in italics):
---------------------------------------------------------------------------

    \714\ Pro forma LGIP Section 4.4.1. Prior to the return of the 
executed Interconnection System Impact Study Agreement to the 
Transmission Provider, modifications permitted under this Section 
shall include specifically: (a) a reduction up to 60 percent (MW) of 
electrical output of the proposed project; (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 the end of the queue for the purposes of 
cost allocation and study analysis.
    \715\ Pro forma LGIP Section 4.4.2. Prior to the return of the 
executed Interconnection Facility Study Agreement to the 
Transmission Provider, the modifications permitted under this 
Section shall include specifically: (a) additional 15 percent 
decrease in plant size (MW), and (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.

    4.4.1. Prior to the return of the executed Interconnection 
System Impact Study Agreement to the Transmission Provider, 
modifications permitted under this Section shall include 
specifically: (a) a reduction up to 60 percent (MW) of electrical 
output 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) 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 the end of the 
queue for the purposes of cost allocation and study analysis.
    4.4.2. Prior to the return of the executed Interconnection 
Facility Study Agreement to the 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, and (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.

    407. We disagree with Southern's contention that an interconnection 
customer's request to modify the interconnection service amount to less 
than the generating facility capacity should always constitute a 
material modification of its interconnection request. A request to 
reduce the interconnection service amount is similar in many respects 
to a request to reduce generating facility capacity. Because the pro 
forma LGIP already permits reductions in generating facility capacity 
at certain points in the interconnection process without triggering 
material modification provisions, the Commission finds that requests to 
reduce the interconnection service amount at those same points within 
the interconnection process should also not trigger material 
modification provisions. We also note that the phrase ``additional 15 
percent'' is meant to allow a total of up to a 75 percent reduction (60 
percent plus 15 percent) from the original interconnection request.
    408. ITC argues that transmission providers should be able to deny 
requests to reduce interconnection service where such a request would 
adversely affect lower-queued interconnection requests. Similarly, 
Idaho Power and Non-Profit Utility Trade Associations argue that the 
Commission has either failed to address the situation where a request 
to reduce interconnection service would adversely affect lower-queued 
interconnection requests or that appropriate cost-sharing provisions 
should apply if a below-generating facility capacity interconnection 
customer later requests an increase in interconnection service to take 
advantage of upgraded systems funded by subsequent interconnection 
requests. We find that no additional LGIP or LGIA revisions are 
necessary to address these scenarios because reductions in 
interconnection service level are similar in their queue-related 
impacts to reductions in generating facility capacity, which the 
existing pro forma LGIP already permits.
    409. Furthermore, lower-queued interconnection requests have always 
faced potential impacts from the decisions of higher-queued 
interconnection requests. For example, lower-queued interconnection 
requests are frequently impacted by the withdrawal of higher-queued 
interconnection requests. The impact on lower-queued interconnection 
requests from a withdrawal higher in the queue is similar to what would 
happen when a higher-queued interconnection customer requests a 
reduction in interconnection service level. In both cases, the higher-
queued interconnection request could avoid paying for some level of 
network upgrades (if such upgrades are required), and lower-queued 
interconnection requests could be impacted as a result. Furthermore, if 
an interconnection customer limited in output to below generating 
facility capacity later seeks an increase in interconnection service, 
this will be a new interconnection request with a new position at the 
end of the interconnection queue, very similar to the situation where a 
higher-queued interconnection request withdraws and later re-enters the 
queue. While we recognize that these two scenarios are not identical in 
all respects, we nevertheless believe that they are similar enough that 
the normal queue management and interconnection processes, including 
being subject to the full slate of interconnection studies and being 
potentially responsible for the cost of new network upgrades, can 
adequately address the issues raised by commenters.
f. Penalties
i. Comments
    410. Commenters disagree regarding penalties for over-generation. 
Some argue that no additional penalties are necessary. NextEra, NYISO, 
ESA, and MidAmerican argue that existing provisions in the pro forma 
LGIA are

[[Page 21391]]

sufficient.\716\ NextEra explains that in CAISO, their combined solar/
battery storage project relies solely on the remedies provided for in 
the existing LGIA. According to NextEra, one other LGIA for a project 
in CAISO includes additional language about the ability to curtail, but 
it does not provide for penalties. NextEra notes that MISO has also 
taken a similar approach. NextEra states that PJM has added significant 
language to its interconnection agreements below full generating 
capacity but notes that this language repeats the pro forma 
indemnification responsibilities. NextEra and ESA also argue that any 
other financial penalties would be punitive and inconsistent with 
existing and reasonable practices in CAISO, MISO and PJM.\717\
---------------------------------------------------------------------------

    \716\ NextEra 2017 Comments at 43; NYISO 2017 Comments at 36-37; 
ESA 2017 Comments at 13; MidAmerican 2017 Comments at 18.
    \717\ NextEra 2017 Comments at 43; ESA 2017 Comments at 13.
---------------------------------------------------------------------------

    411. NextEra also notes that thermal generation may be able to 
produce higher levels of output under certain conditions and does not 
have any additional requirements, nor are there special requirements 
for the operation of System Protection Facilities.\718\ NextEra argues 
that, if the Commission creates any additional penalties, it would need 
to do so equally to all generation under all circumstances to avoid 
undue discrimination.\719\
---------------------------------------------------------------------------

    \718\ NextEra 2017 Comments at 45.
    \719\ Id.
---------------------------------------------------------------------------

    412. Xcel states that, although penalties may sometimes be 
appropriate, if the system can reliably accept the energy, over-
generation may sometimes be beneficial or may not be a significant 
reliability or free rider issue.\720\
---------------------------------------------------------------------------

    \720\ Xcel 2017 Comments at 17-18.
---------------------------------------------------------------------------

    413. Some commenters see the value of additional penalties. For 
instance, Bonneville, ITC, TDU Systems, Six Cities, SoCal Edison, Xcel, 
Portland, and Duke support both financial and non-financial penalties, 
including curtailment, if an interconnection customer exceeds its 
service limit to maintain reliability.\721\ MISO TOs support imposition 
of penalties for exceeding authorized levels of service but defer to 
RTOs/ISOs to develop the specifics of such penalties.\722\
---------------------------------------------------------------------------

    \721\ Bonneville 2017 Comments at 7; ITC 2017 Comments at 18; 
Duke 2017 Comments at 18; TDU Systems 2017 Comments at 27-28; Six 
Cities 2017 Comments at 5; SoCal Edison 2017 Comments at 6; Xcel 
2017 Comment at 17; Portland 2017 Comments at 6.
    \722\ MISO TOs 2017 Comments at 36.
---------------------------------------------------------------------------

    414. Six Cities observes that a requirement to pay incremental 
network upgrade costs may be most appropriate in circumstances where an 
interconnection customer has consistently exceeded its specified level 
of interconnection service over some period of time, while a monetary 
penalty may be most appropriate to address isolated exceedances. Six 
Cities argues that RTOs/ISOs are in the best position to develop 
appropriate penalty proposals for application in their respective 
regions.\723\
---------------------------------------------------------------------------

    \723\ Six Cities 2017 Comments at 5.
---------------------------------------------------------------------------

    415. SoCal Edison requests that the Commission clarify that 
penalties apply to interconnection customers whose agreed-upon 
interconnection service level is for the full generating facility 
capacity, not just those whose agreed-upon interconnection service 
levels are below the full generating facility capacity.\724\ SoCal 
Edison suggests that penalties should range from temporary disruption 
of service to permanent termination of service.\725\
---------------------------------------------------------------------------

    \724\ SoCal Edison 2017 Comments at 6.
    \725\ Id. at 6.
---------------------------------------------------------------------------

ii. Commission Determination
    416. With respect to penalties, based on the record here, we find 
that current provisions in the pro forma LGIA, which allow a 
transmission provider to curtail service or terminate an LGIA, are 
sufficient to ensure proper behavior by interconnection customers. As 
noted by NextEra, thermal generation may be able to produce higher 
levels of output than the interconnection service level under certain 
conditions, such as lower than benchmark ambient air temperature, and 
does not face any additional penalty requirements beyond curtailment of 
service or termination of its LGIA for breach if a party defaults and 
fails to cure that default.\726\ The Commission agrees that this is an 
analogous situation to interconnection below generating facility 
capacity, and therefore the same treatment with respect to penalties 
should apply. Furthermore, as NextEra also notes, there are no special 
penalty requirements beyond these for the operation of system 
protection facilities. As discussed earlier, this final action finds 
that the control technologies at issue are system protection 
facilities. Based on these facts, we decline to generically adopt into 
the pro forma LGIP any additional financial penalties for exceeding the 
limitations for interconnection service established in the 
interconnection agreements. However, if a transmission provider can 
justify a need for additional penalties, it may propose such penalties 
in a section 205 filing.
---------------------------------------------------------------------------

    \726\ NextEra 2017 Comments at 45.
---------------------------------------------------------------------------

    417. As mentioned above, article 17 of the pro forma LGIA provides 
a process for termination of an LGIA if a party defaults \727\ on its 
obligations and fails to cure such defaults. Given the potential 
reliability and operational ramifications, failure to adhere to the 
injection limits included in a below-generating facility capacity LGIA 
could rise to the level of default, and termination of the LGIA would 
be a serious consequence for an interconnection customer, as the 
resulting disconnection and idling of the generating facility could 
cause significant economic losses. Furthermore, existing article 9.7.2 
of the LGIA allows the transmission provider to reduce deliveries from 
(i.e., curtail) an interconnection customer if required by good utility 
practice. Because of these existing provisions, and the fact that no 
other consequences currently apply in the analogous situations 
described above, we see no need to devise new penalties at this time.
---------------------------------------------------------------------------

    \727\ The pro forma LGIA defines default as ``the failure of a 
Breaching Party to cure its Breach in accordance with Article 17.'' 
Pro forma LGIA Art. 1 (Definitions). A breach is ``the failure of a 
Party to perform or observe any material condition'' of the pro 
forma LGIA. Id.
---------------------------------------------------------------------------

g. Changes to the Definitions of Large and Small Generating Facilities
i. Comments
    418. TDU Systems conditionally support the Commission's proposal to 
change the definitions of Large Generating Facility and Small 
Generating Facility in the pro forma LGIP and pro forma LGIA to base 
them on the level of interconnection service actually provided, rather 
than on the generating facility's capacity, subject to the transmission 
provider being able to study the full generating facility capacity if 
it believes there is a need to do so at the cost of the interconnection 
customer.\728\ However, TDU Systems urge the Commission to ensure that 
the interconnection customer (or potential interconnection customer) 
knows what upgrade costs it may incur if seeks to use the generating 
facility's full capacity.\729\
---------------------------------------------------------------------------

    \728\ TDU Systems 2017 Comments at 27.
    \729\ Id.
---------------------------------------------------------------------------

    419. Similarly, IECA argues that industrial combined heat and power 
and waste heat recovery facilities with net generating capacities in 
excess of 20 MW can export far less total electricity to the grid than 
a wind or solar facility with similar or less generating facility 
capacity.\730\ IECA indicates that a generator's size classification 
should be based on the maximum amount of power that could be exported 
to the grid

[[Page 21392]]

under normal manufacturing operations at the combined heat and power 
and waste heat recovery facility location, rather than being based on 
net generation.\731\
---------------------------------------------------------------------------

    \730\ IECA 2017 Comments at 3.
    \731\ Id. at 3-4.
---------------------------------------------------------------------------

    420. On the other hand, Portland opposes the proposal to redefine 
the term generating facility based on the level of interconnection 
service. Instead, Portland argues that generating facility definitions 
should be based on nameplate capacity.\732\ TVA thinks that the 
Commission should define generating facility capacity more 
specifically, particularly with regard to certain parameters such as 
what power factor is measured and whether it is gross or net of station 
service load.\733\ It also notes that many transmission owners and 
providers have MW thresholds that trigger more robust interconnection 
facility requirements, and states that interconnection for less than 
the full generator output should not be allowed to circumvent these 
thresholds.\734\
---------------------------------------------------------------------------

    \732\ Portland 2017 Comments at 7.
    \733\ TVA 2017 Comments at 15.
    \734\ Id. at 15-16.
---------------------------------------------------------------------------

    421. Six Cities states it is not sure what the Commission means by 
the statement that these definition changes ``are not intended to 
conflict with any applicable [NERC] Reliability Standards or NERC's 
compliance registration process.'' \735\ Six Cities seeks clarity as to 
whether the current NERC compliance registration criteria for 
generating facilities will continue to be based on nameplate ratings 
irrespective of the requested level of interconnection service, or if 
the Commission intends for the registration criteria to be revised 
based upon the level of interconnection service that is requested and 
implemented.\736\
---------------------------------------------------------------------------

    \735\ Six City 2017 Comments at 7 (citing NOPR, FERC Stats. & 
Regs. ] 32,719 at P 180).
    \736\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    422. Upon consideration of the comments, we withdraw the NOPR 
proposal to change the definitions of large and small generating 
facilities so that they are based on the level of interconnection 
service for the generating facility rather than the generating facility 
capacity.\737\ Our particular concern is the possibility of unintended 
and unforeseen consequences with respect to the interconnection study 
process and NERC compliance registration process.
---------------------------------------------------------------------------

    \737\ As a result of the withdrawal of this proposal, the 
determination of whether a generator is large or small, including 
for purposes of whether it qualifies for the LGIP or SGIP, will 
continue to be based on the generating facility capacity.
---------------------------------------------------------------------------

    423. As we have withdrawn this proposal, there is no need to 
address comments on the proposal or to address IECA's argument that a 
transmission provider should base a combined heat and power and waste 
heat recovery facility's size classification on the maximum amount of 
power that could be exported to the grid under normal manufacturing 
operations.
2. Provisional Interconnection Service
a. NOPR Proposal
    424. The Commission proposed to allow interconnection customers to 
enter into provisional agreements for limited interconnection service 
prior to the completion of the full interconnection process. Under this 
proposal, interconnection customers with provisional agreements would 
be able to begin operation up to the MW level permitted by a previously 
conducted, readily available interconnection study (available study), 
additional studies as necessary, and regularly updated studies. In the 
NOPR, the Commission noted that the transmission provider may require 
milestone payments prior to submission of the provisional agreement. 
The provisional agreement would be in effect while awaiting the final 
results of the interconnection studies, the execution of a LGIA, and 
the construction of any additional interconnection facilities and/or 
network upgrades that may result from the full interconnection process. 
The Commission also proposed that provisional large generator 
interconnection agreements and the associated provisional 
interconnection service would terminate upon completion of construction 
of network upgrades required for the interconnection customer's full 
level of service.\738\
---------------------------------------------------------------------------

    \738\ NOPR, FERC Stats. & Regs. ] 32,719 at P 186.
---------------------------------------------------------------------------

    425. The Commission proposed that interconnection customers with 
provisional agreements must still assume all risk and liabilities 
associated with the required interconnection facilities and network 
upgrades for their interconnection that are identified pursuant to the 
full set of interconnection studies for the requested interconnection 
service.\739\
---------------------------------------------------------------------------

    \739\ Id. P 187.
---------------------------------------------------------------------------

    426. The Commission therefore proposed to require that transmission 
providers allow interconnection customers to request provisional 
interconnection service and operate under provisional interconnection 
agreements based on available or additional studies as necessary and 
regularly updated studies that demonstrate that necessary 
interconnection facilities and network upgrades are in place to meet 
applicable NERC or other regional reliability requirements for new, 
modified, and/or expanded generating facilities. If available studies 
do not demonstrate whether the transmission provider can reliably 
accommodate provisional interconnection service, the transmission 
provider would perform additional studies as necessary. An evaluation 
of provisional service by the transmission provider would determine 
whether stability, short circuit, and/or voltage issues would arise if 
the interconnection customer seeking provisional interconnection 
service interconnects without modifications to the generating facility 
or the transmission provider's system. The Commission also proposed 
that transmission providers must assess any safety or reliability 
concerns posed by provisional agreements, and establish a process for 
the interconnection customer to mitigate any reliability risks 
associated with operation pursuant to provisional agreements.\740\
---------------------------------------------------------------------------

    \740\ Id. P 188.
---------------------------------------------------------------------------

    427. The Commission sought additional comment on the proposal and 
the means by which transmission providers and interconnection customers 
could mitigate any risks and/or liabilities for provisional 
interconnection service. The Commission, acknowledging that 
transmission providers have limited resources to conduct studies, also 
sought comment on the circumstances under which provisional 
interconnection service would be beneficial and how common such 
circumstances would be for potential interconnection customers.\741\
---------------------------------------------------------------------------

    \741\ Id.
---------------------------------------------------------------------------

    428. The Commission proposed to add the following new definitions 
to Section 1 of the pro forma LGIP, and to article 1 of the pro forma 
LGIA (with proposed additions in italics):

    Provisional Interconnection Service shall mean interconnection 
service provided by the Transmission Provider associated with 
interconnecting the Interconnection Customer's Generating Facility 
to the 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

[[Page 21393]]

Interconnection Agreement and, if applicable, the Tariff.\742\
---------------------------------------------------------------------------

    \742\ In this final action, the adopted language differs 
slightly from the NOPR language because we remove the word ``the'' 
before ``Transmission Provider.''
---------------------------------------------------------------------------

    Provisional Large Generator Interconnection Agreement shall mean 
the interconnection agreement for Provisional Interconnection 
Service established between the 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.\743\
---------------------------------------------------------------------------

    \743\ Id. P 189. In this final action, the adopted language 
differs slightly from the NOPR language because we remove the word 
``the'' before ``Transmission Provider.''

    429. Additionally, the Commission proposed a new article 5.10 for 
the pro forma LGIA that defines the requirements for transmission 
providers to provide provisional interconnection service and the 
responsibilities of the interconnection customer. The Commission did 
not propose a pro forma Provisional Large Generator Interconnection 
Agreement, reasoning that parties could develop such agreements on an 
ad hoc basis or transmission providers could establish their own pro 
forma agreements. Nonetheless, the Commission sought comment on the 
need to establish a pro forma Provisional Large Generator 
Interconnection Agreement as well as any details related to 
interconnection service. The proposed new article 5.10 to the pro forma 
---------------------------------------------------------------------------
LGIA reads as follows (with proposed text in italics):

    5.10 Provisional Interconnection Service.
    Upon the request of Interconnection Customer, and prior to 
completion of requisite Network Upgrades, the 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 Provider's system. Transmission Provider shall 
determine whether any Network Upgrades, Interconnection Facilities, 
Distribution Upgrades, or System Protection Facilities that are 
necessary to meet the requirements of NERC, 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 Network Upgrades, 
Interconnection Facilities, 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 quarterly basis. 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 
Network Upgrades, Interconnection Facilities, Distribution Upgrades, 
and/or System Protection Facilities cost responsibilities.\744\
---------------------------------------------------------------------------

    \744\ Id. P 190.
---------------------------------------------------------------------------

b. General
i. Comments
    430. Most responsive commenters either support the proposal \745\ 
or do not oppose it.\746\ ISO-NE, Tri-State, and TVA oppose the 
proposal.\747\ NEPOOL takes no position, but states that it would 
oppose the proposal if it raises system reliability concerns, 
introduces interconnection study delays, or degrades ISO-NE's 
interconnection/forward capacity market processes.\748\
---------------------------------------------------------------------------

    \745\ AES 2017 Comments at 11; Alevo 2017 Comments at 9; AFPA 
2017 Comments at 15; AWEA 2017 Comments at 56; Bonneville 2017 
Comments at 8; California Energy Storage Alliance 2017 Comments at 
13; Duke 2017 Comments at 20; Forecasting Coalition 2017 Comments at 
4; EDP 2017 Comments at 8; ELCON 2017 Comments at 7; ESA 2017 
Comments at 15; Idaho Power 2017 Comments at 6; IECA 2017 Comments 
at 3; ITC 2017 Comments at 19; Joint Renewable Parties 2017 Comments 
at 12; MidAmerican 2017 Comments at 18-19; NextEra 2017 Comments at 
46; Public Interest Organizations 2017 Comments at 6; TDU Systems 
2017 Comments at 28-29; Xcel 2017 Comments at 18.
    \746\ Non-Profit Utility Trade Associations 2017 Comments at 24; 
NYISO 2017 Comments at 37; PJM 2017 Comments at 25.
    \747\ ISO-NE 2017 Comments at 43-44; Tri-State 2017 Comments at 
9; TVA 2017 Comments at 16.
    \748\ NEPOOL 2017 Comments at 16-17.
---------------------------------------------------------------------------

    431. Alevo, ITC, MISO TOs, NextEra, and Six Cities agree that the 
interconnection customers should assume all associated risks and 
liabilities with regard to provisional interconnection service.\749\ 
Alevo asks for clarification on whether a provisional interconnection 
can become permanent at the provisional MW level.\750\
---------------------------------------------------------------------------

    \749\ Alevo 2017 Comments at 9; ITC 2017 Comments at 19; MISO 
TOs 2017 Comments at 37-38; NextEra 2017 Comments at 46; PJM 2017 
Comments at 25-26; and Six Cities 2017 Comments at 6.
    \750\ Alevo 2017 Comments at 9.
---------------------------------------------------------------------------

    432. As noted in the NOPR, certain regions already include some 
form of provisional interconnection service.\751\ Bonneville states 
that it already allows limited facility operation using existing 
interconnection capacity prior to the completion of upgrades needed for 
the full interconnection request.\752\ MISO states that its GIP 
includes a process for obtaining a provisional GIA that is subject to 
study and the maximum permissible output of the facility is updated on 
a quarterly basis. MISO notes that the provisional GIA is replaced by a 
``permanent'' GIA upon the completion of the interconnection customer's 
assigned network upgrades.\753\ NYISO states that it already provides 
provisional interconnection service under the limited operation 
provision of NYISO's LGIA.\754\ However, Indicated NYTOs state that the 
Commission must ensure that any final action to accommodate provisional 
interconnection service does not diminish the superior interconnection 
standards in regions like NYISO.\755\
---------------------------------------------------------------------------

    \751\ NOPR, FERC Stats. & Regs. ] 32,719 at P 183.
    \752\ Bonneville 2017 Comments at 8.
    \753\ MISO 2017 Comments at 34-35.
    \754\ NYISO 2017 Comments at 37.
    \755\ Indicated NYTOs 2017 Comments at 9.
---------------------------------------------------------------------------

    433. CAISO provides different avenues for ``provisional'' 
interconnection service.\756\ However, CAISO requests clarification 
regarding the NOPR statement that ``in some cases, there is a certain 
amount of interconnection capacity that has already been studied.'' 
\757\ It argues that the only interconnection capacity that it has 
studied is already in use or planned to be in use soon. CAISO supports 
the proposal to the extent that the NOPR is consistent with this 
understanding.\758\ PG&E states that interconnection customers are able 
to obtain limited interconnection service prior to the completion of 
the full interconnection process in some circumstances, and CAISO 
conducts a limited operation study six months ahead of a project's in-
service date and allows phased projects and energy-only projects to 
interconnect before certain upgrades or studies are completed.\759\
---------------------------------------------------------------------------

    \756\ CAISO 2017 Comments at 28.
    \757\ Id. (citing NOPR, FERC Stats. & Regs. ] 32,719 at P 181).
    \758\ Id.
    \759\ PG&E 2017 Comments at 8.
---------------------------------------------------------------------------

    434. SoCal Edison supports the existing CAISO process but argues 
that the NOPR proposal may unintentionally

[[Page 21394]]

degrade safety and reliability.\760\ SoCal Edison states that, while 
interconnection capacity may be temporarily available due to 
construction delay, there is no assurance that short-circuit duty 
levels will be within allowable limits or that overall system 
performance would meet all NERC reliability criteria.\761\
---------------------------------------------------------------------------

    \760\ SoCal Edison 2017 Comments at 8.
    \761\ Id.
---------------------------------------------------------------------------

    435. Eversource states that transmission providers should have 
discretion to determine whether there is capacity available to 
accommodate provisional interconnection service.\762\ It also states 
that any provisional process should be tailored, adapted to, and 
consistent with each region's existing interconnection and market 
rules.\763\
---------------------------------------------------------------------------

    \762\ Eversource 2017 Comments at 16.
    \763\ Id.
---------------------------------------------------------------------------

    436. EEI states that an interconnection customer should only be 
able to use provisional interconnection service when: (1) Studies 
indicate that there is a level of interconnection that can occur 
without any additional upgrades and the interconnection customer wishes 
to make use of that level of interconnection while the upgrades 
required for its full interconnection request are completed; and (2) 
where a previously completed study indicates there is a level of 
interconnection that can occur without any additional upgrades while 
such study is updated.\764\ Southern agrees that all provisional 
service should be limited to the amount of service that can be provided 
until all required network upgrades identified by interconnection 
studies are in service.\765\
---------------------------------------------------------------------------

    \764\ EEI 2017 Comments at 57.
    \765\ Southern 2017 Comments at 26.
---------------------------------------------------------------------------

    437. ISO-NE opposes the establishment of provisional 
interconnection service, arguing that it would unnecessarily increase 
uncertainty and create difficult obligations for system operators.\766\ 
ISO-NE further argues that the proposal would allow an interconnection 
customer requesting provisional interconnection service to jump ahead 
of a higher-queued interconnection request and would require the 
transmission provider to conduct studies for the provisional 
interconnection request before completing a higher-queued project's 
studies.\767\ It states that, if the proposal is adopted, the 
Commission should provide regional flexibility for ISO-NE to deviate 
from the final action.\768\
---------------------------------------------------------------------------

    \766\ ISO-NE 2017 Comments at 43-44.
    \767\ Id. at 45-46.
    \768\ Id. at 47.
---------------------------------------------------------------------------

ii. Commission Determination
    438. In this final action, we adopt the NOPR proposal to define 
Provisional Interconnection Service and Provisional Large Generator 
Interconnection Agreement in section 1 of the pro forma LGIP and 
article 1 of the pro forma LGIA; and add article 5.9.2 \769\ to the pro 
forma LGIA, as modified below. We require transmission providers to 
make the changes to their LGIPs and LGIAs so that all interconnection 
customers may request provisional interconnection service, but we 
modify the proposed pro forma LGIA provisions to allow transmission 
providers to determine the frequency for updating provisional 
interconnection studies, and to clarify the cost responsibilities of 
the interconnection customer.
---------------------------------------------------------------------------

    \769\ To avoid extensive renumbering of the article 5 of the pro 
forma LGIA, the Commission is re-titling article 5.9 ``Other 
Interconnection Options.'' Existing article 5.9 Limited Operation 
will now be article ``5.9.1 Limited Operation,'' and the newly 
adopted Provisional Interconnection Service provision will be 
article 5.9.2 instead of 5.10.
---------------------------------------------------------------------------

    439. In response to Alevo's question regarding whether provisional 
interconnection service could become permanent, we clarify that 
provisional interconnection service could not become permanent because 
it is only available to interconnection customers awaiting the 
completion of the full interconnection process and will terminate upon 
completion of construction of interconnection facilities and network 
upgrades.
    440. In response to CAISO, we clarify that ``a certain amount of 
capacity already studied'' \770\ refers to situations where, for 
example, available studies or additional studies as necessary indicate 
that there is a certain amount of interconnection service available 
without the need for additional network upgrades and the transmission 
provider can reliably accommodate the interconnection service. In such 
cases, an interconnection customer may use the identified 
interconnection service while it awaits the completion of the full 
interconnection process.
---------------------------------------------------------------------------

    \770\ NOPR, FERC Stats. & Regs. ] 32,719 at P 181.
---------------------------------------------------------------------------

    441. In response to requests for clarification of the conditions 
for requesting provisional interconnection service, we clarify that 
interconnection customers may seek provisional interconnection service 
when available studies or additional studies as necessary indicate that 
there is a level of interconnection that can occur without any 
additional interconnection facilities and/or network upgrades and the 
interconnection customer wishes to make use of that level of 
interconnection service while the facilities required for its full 
interconnection request are completed.
    442. In response to ISO-NE's objection that the provisional 
interconnection service proposal could cause lower-queued projects to 
``leapfrog'' higher-queued interconnection customers, we acknowledge 
that there may be instances when a lower-queued project may 
interconnect and receive provisional interconnection service before a 
higher-queued project completes the full interconnection process. It is 
possible that the resources needed to complete the transmission 
provider's interconnection studies may be required to perform 
provisional studies for a lower-queued interconnection customer. But, a 
higher-queued interconnection customer should have the opportunity to 
request provisional service prior to a lower-queued interconnection 
customer. The availability of this service would not unduly 
disadvantage higher-queued interconnection customers, which would have 
the first chance to use any available provisional service, but may have 
been unable or uninterested in doing so. In addition, the availability 
of provisional service should not advantage lower-queued 
interconnection customers in the processing of their full 
interconnection service request. We emphasize that provisional 
interconnection service may not provide an interconnection customer its 
full requested level of interconnection service. We further note that 
any interconnection customer, regardless of queue position, may request 
provisional interconnection service.
c. Pro Forma Provisional Interconnection Agreement
i. Comments
    443. Duke, Xcel, and Southern see no need for the Commission to 
develop a pro forma provisional interconnection service agreement at 
this time.\771\ MISO agrees because its GIP includes a process for 
obtaining a provisional GIA and because MISO already conducts quarterly 
provisional interconnection service studies.\772\ NYISO states that a 
separate provisional interconnection agreement would unnecessarily 
complicate and prolong the interconnection agreement negotiations.\773\ 
PJM opposes the creation of a separate provisional interconnection 
agreement because

[[Page 21395]]

PJM's current interconnection agreement already provides for the 
service.\774\
---------------------------------------------------------------------------

    \771\ Duke 2017 Comments at 21; Xcel 2017 Comment at 18; 
Southern 2017 Comments at 26.
    \772\ MISO 2017 Comments at 34-35.
    \773\ NYISO 2017 Comments at 38.
    \774\ PJM 2017 Comments at 26.
---------------------------------------------------------------------------

ii. Commission Determination
    444. In this final action, we agree with commenters and decline to 
adopt a separate pro forma Provisional Large Generator Interconnection 
Agreement.
d. Additional Studies
i. Comments
    445. EEI argues that a transmission provider should not have to 
perform additional studies to offer provisional interconnection service 
and should not have to perform periodic studies to update the level of 
maximum permissible provisional interconnection service.\775\ Southern 
agrees and also argues that transmission providers should have 
discretion over granting provisional interconnection service based on 
standard interconnection studies or any other applicable and valid 
studies.\776\
---------------------------------------------------------------------------

    \775\ EEI 2017 Comments at 58.
    \776\ Southern 2017 Comments at 26.
---------------------------------------------------------------------------

    446. Duke and NYISO oppose the requirement to conduct quarterly 
restudies.\777\ Instead, NYISO proposes to define a timeframe for which 
provisional service will be provided, and study the proposed project to 
determine the permissible output level of the project over the entire 
defined provisional timeframe. NYISO further proposes to retain the 
discretion to update its analysis as necessary based on system 
changes.\778\
---------------------------------------------------------------------------

    \777\ Duke 2017 Comments at 21; NYISO 2017 Comments at 38.
    \778\ Id.
---------------------------------------------------------------------------

    447. Eversource argues that additional studies could turn the 
interconnection process into a protracted iterative design process 
while the interconnection customer determines its cheapest option for 
network upgrades.\779\ Six Cities also has concerns that additional 
studies may prolong the interconnection process.\780\ Tri-State and TVA 
argue that the proposal burdens transmission providers because it 
requires regularly-updated or additional studies,\781\ or imposes 
distracting monitoring and/or mitigation burdens.\782\
---------------------------------------------------------------------------

    \779\ Eversource 2017 Comments at 17.
    \780\ Six Cities 2017 Comments at 6.
    \781\ Tri-State 2017 Comments at 9.
    \782\ TVA 2017 Comments at 16.
---------------------------------------------------------------------------

ii. Commission Determination
    448. In this final action, we modify the NOPR proposal and article 
5.9.2 of the pro forma LGIA, Provisional Interconnection Service, to 
allow transmission providers to determine the frequency for updating 
provisional interconnection studies. This flexibility will allow 
transmission providers to determine a study frequency that best suits 
their individual needs. However, the determined frequency should be 
consistent across all interconnection customers seeking provisional 
interconnection service. In addition, we modify the NOPR proposal, and 
add article 5.9.2 of the pro forma LGIA, to clarify that any study 
performed by the transmission provider to update the available maximum 
provisional interconnection service will be at the expense of the 
interconnection customer. To effectuate this change, we renumber 
existing article 5.9 as follows (deleting bracketed text and adding the 
italicized text):

    5.9 [Limited Operation] Other Interconnection Options
    5.9.1 Limited Operation
* * * * *

    449. We also revise article 5.9.2 of the LGIA from the version 
proposed in the NOPR as follows (deleting bracketed, un-italicized text 
and adding the italicized text):

    5.9.[1]2[0] 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 
[the ]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 Provider's system. 
Transmission Provider shall determine whether any [Network 
Upgrades,] Interconnection Facilities, Network Upgrades, 
Distribution Upgrades, or System Protection Facilities that are 
necessary to meet the requirements of NERC, 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 [Network Upgrades,] 
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.] [on a quarterly basis]. 
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 [Network 
Upgrades,] Interconnection Facilities, Network Upgrades, 
Distribution Upgrades, and/or System Protection Facilities cost 
responsibilities.\783\
---------------------------------------------------------------------------

    \783\ NOPR, FERC Stats. & Regs. ] 32,719 at P 190.

    450. In response to Tri-State's and TVA's concern about the 
additional burden associated with providing provisional interconnection 
service, and Eversource's and Six Cities' concern that provisional 
interconnection service will prolong the interconnection process, we 
acknowledge that providing provisional interconnection service may 
require additional studies, which could prolong the interconnection 
process for some interconnection customers. However, because 
provisional interconnection service is partly based on the results of 
available studies, and the studies to confirm that provisional service 
continues to be available are less intensive than full interconnection 
studies, interconnection customers in the queue that do not select 
provisional interconnection service should not experience additional 
significant delay. In the regions where provisional interconnection 
service is currently available, the Commission is unaware of any delays 
to the interconnection process due to transmission provider processing 
of provisional studies. Furthermore, as stated above, we recognize the 
individual needs of the transmission providers, and the modification 
from the NOPR proposal to allow transmission providers the flexibility 
to determine the frequency to study and update the maximum permissible 
output of the generating facility should further minimize delays and 
lessen any burden.
e. Other
i. Comments
    451. Imperial and Modesto ask the Commission to clarify how the 
provisional service would be subject to section 3.5 of the pro forma 
LGIP, which provides for coordination of any study required to 
determine the

[[Page 21396]]

interconnection request's impact on affected systems, and how the 
transmission provider would conduct the studies for provisional 
interconnection service in conjunction with affected systems.\784\
---------------------------------------------------------------------------

    \784\ Imperial 2017 Comments at 13; Modesto 2017 Comments at 18.
---------------------------------------------------------------------------

ii. Commission Determination
    452. In response to concerns about negative effects to other 
systems or system reliability, we emphasize that available studies or 
additional studies as necessary performed by transmission providers at 
the interconnection customer's expense, should identify any associated 
negative effects on system reliability. We also reiterate that 
Commission staff convened a technical conference in Docket No. AD18-8-
000 to explore issues related to the coordination of affected systems 
raised in this proceeding and from a complaint filed in Docket No. 
EL18-26-000. Thus, while the Commission is not taking action on 
affected systems issues in this rulemaking, the Commission is 
considering these kinds of issues. As a reminder, the Notice Inviting 
Post-Technical Conference Comments in Docket No. AD18-8-000, which 
issued concurrently with this final action, states that initial and 
reply comments are due within 30 days and 45 days, respectively, from 
the date of the notice's issuance.
3. Utilization of Surplus Interconnection Service
a. NOPR Proposal
    453. In the NOPR, the Commission proposed to add a new definition 
for Surplus Interconnection Service to section 1 of the pro forma LGIP 
and to article 1 of the pro forma LGIA, and a requirement that 
transmission providers provide an expedited process for interconnection 
customers to utilize or transfer surplus interconnection service at 
existing generating facilities.\785\ The intent of this proposal was to 
allow another interconnecting resource owned by an existing generating 
facility owner or an affiliated owner the ability to use any surplus 
interconnection service associated with the existing generating 
facility. The Commission also proposed that transmission providers 
establish open and transparent processes for generating facilities that 
wish to transfer that surplus interconnection service to others if the 
generating facility owner and its affiliates elect not to use it.\786\
---------------------------------------------------------------------------

    \785\ NOPR, FERC Stats. & Regs. ] 32,719 at P 201.
    \786\ Id.
---------------------------------------------------------------------------

    454. In the NOPR, the Commission pointed to MISO's Net Zero 
Interconnection Service, which is offered under MISO's tariff. MISO 
designed this service ``to allow an existing interconnection customer 
to increase the gross generating capacity at the point of 
interconnection of an existing generating facility without increasing 
the total interconnection service at the point of interconnection.'' 
\787\ In its order accepting MISO's proposal for Net Zero 
Interconnection Service, the Commission directed MISO to submit a 
compliance filing to ensure that MISO offered Net Zero Interconnection 
Service ``on a fair, transparent, and non-discriminatory basis.'' \788\
---------------------------------------------------------------------------

    \787\ Id. P 193 (citing MISO FERC Electric Tariff, Attachment X, 
Section 1 (Definitions) (47.0.0) (``Net Zero Interconnection Service 
shall mean a form of Energy Resource Interconnection Service that 
allows an interconnection customer to alter the characteristics of 
an existing generating facility, with the consent of the existing 
generating facility, at the same [point of interconnection] such 
that the Interconnection Service limit remains the same'')).
    \788\ Midwest Indep. Transmission Sys. Operator, Inc., 138 FERC 
] 61,233, at P 302 (2012).
---------------------------------------------------------------------------

    455. To ensure system reliability, the Commission proposed to 
require reactive power, short circuit/fault duty, and stability 
analyses studies for this service, and that transmission providers 
perform steady-state (thermal/voltage) analyses as necessary to ensure 
evaluation of all required reliability conditions.\789\ The Commission 
also proposed that, if the transmission provider does not study surplus 
interconnection service under off-peak conditions, it would perform 
off-peak steady state analyses to the level necessary to demonstrate 
reliability.\790\ The Commission further proposed that, if the original 
system impact study is not available while the surplus interconnection 
service is going through the study process, both off-peak and peak 
analyses may be necessary for the existing generating facility 
associated with the request for surplus interconnection service.\791\ 
Additionally, the Commission proposed that a process for the use or 
transfer of surplus interconnection service be available for any 
quantity of surplus interconnection service that currently exists.\792\
---------------------------------------------------------------------------

    \789\ NOPR, FERC Stats. & Regs. ] 32,719 at P 202.
    \790\ Id.
    \791\ Id.
    \792\ Id.
---------------------------------------------------------------------------

    456. The Commission proposed to require that the transmission 
provider, transmission owner (as applicable), and the surplus 
interconnection service customer execute, or file unexecuted, a new 
agreement for surplus interconnection service. The Commission noted 
that the surplus interconnection customer could be the interconnection 
customer for the existing generating facility, one of its affiliates, 
or a new interconnection customer selected through an open and 
transparent solicitation process.\793\ In addition to the new 
interconnection agreement for surplus interconnection service, the 
Commission recognized that other contractual arrangements may be 
necessary.\794\
---------------------------------------------------------------------------

    \793\ Id. P 203.
    \794\ Id.
---------------------------------------------------------------------------

    457. While the Commission did not propose specific contractual 
arrangements with respect to surplus interconnection service in the 
NOPR, the Commission sought comment on how these arrangements should 
work and on whether requirements for such arrangements should be 
established in the Commission's pro forma LGIP and pro forma LGIA.\795\ 
The Commission also sought comment on whether the interconnection 
agreement for surplus interconnection service should terminate upon the 
retirement of the existing generating facility, or whether there are 
circumstances under which the surplus interconnection service customer 
may operate its generating facility under the terms of the surplus 
interconnection service agreement after the retirement of the existing 
generating facility.\796\
---------------------------------------------------------------------------

    \795\ Id. P 204.
    \796\ Id.
---------------------------------------------------------------------------

    458. Under the NOPR proposal, an existing generating facility owner 
or its affiliate would have priority to use any surplus interconnection 
service and would be able to execute or request the filing of an 
unexecuted surplus interconnection service agreement without posting 
that service to OASIS or going through an open solicitation 
process.\797\ However, if an existing generating facility owner that 
has surplus interconnection service wished to transfer it but did not 
wish to use the surplus interconnection service itself or to transfer 
it to one of its affiliates, the existing generator would conduct an 
open and transparent solicitation process for that surplus 
interconnection service.\798\ While the Commission proposed that 
priority be given to the existing generating facility owner of the 
surplus interconnection service or its affiliates, the Commission 
sought comment on the need for further limitations on the entities with 
priority use of that surplus interconnection service.\799\
---------------------------------------------------------------------------

    \797\ Id. P 206.
    \798\ Id.
    \799\ Id.

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

[[Page 21397]]

    459. With regard to specific requirements, the Commission proposed 
to add the following new definition to section 1 of the pro forma LGIP 
---------------------------------------------------------------------------
and to article 1 of the pro forma LGIA (with proposed text in italics):

    Surplus Interconnection Service shall mean any unused portion of 
Interconnection Service established in a Large Generator 
Interconnection Agreement, such that if Surplus Interconnection 
Service is utilized the Interconnection Service limit at the Point 
of Interconnection would remain the same.\800\
---------------------------------------------------------------------------

    \800\ Id. P 208. With respect to these new additions to the pro 
forma LGIP and pro forma LGIA, we make minor clarifying edits to the 
pro forma tariff language originally proposed in the NOPR, as shown 
in Appendices B and C to Order No. 845. Specifically, the term 
``unused'' is replaced with the term ``unneeded,'' and the term 
``Interconnection Service limit'' is replaced with ``total amount of 
Interconnection Service.''

    460. The Commission proposed to add a new section 3.3 to the pro 
forma LGIP that requires the transmission provider to establish a 
process for the use of surplus interconnection service as follows (with 
---------------------------------------------------------------------------
proposed text in italics):

    Utilization of Surplus Interconnection Service. The Transmission 
Provider must provide a process that allows an Interconnection 
Customer to utilize or transfer Surplus Interconnection Service at 
an existing Generating Facility. 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 through an open and transparent 
solicitation process.\801\
---------------------------------------------------------------------------

    \801\ Id. P 209. With respect to these new additions to the pro 
forma LGIP, we make minor clarifying edits to the pro forma tariff 
language originally proposed in the NOPR, as shown in Appendix B to 
Order No 845. Specifically, in the first sentence, the words 
``Generating Facility'' are replaced with the words ``Point of 
Interconnection'' and in the last sentence, the words ``through an 
open and transparent solicitation process'' are struck.

    461. The Commission proposed to add a new section 3.3.1 to the pro 
forma LGIP that describes the process for using surplus interconnection 
---------------------------------------------------------------------------
service (with proposed text in italics):

    Surplus Interconnection Service Requests. Surplus 
Interconnection Service requests may be made by the existing 
Generating Facility or one of its affiliates. Surplus 
Interconnection Service requests also may be made by another 
Interconnection Customer selected through an open and transparent 
solicitation process. The 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 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.\802\
---------------------------------------------------------------------------

    \802\ Id. P 210. With respect to these new additions to the pro 
forma LGIP, we make minor clarifying edits to the pro forma tariff 
language originally proposed in the NOPR, as shown in Appendix B to 
Order No. 845. Specifically, the first sentence is modified as 
follows (with additions made in italics): ``Surplus Interconnection 
Service requests may be made by the existing Interconnection 
Customer whose Generating Facility is already interconnected or one 
of its affiliates.'' Additionally, the second sentence is modified 
by striking the words ``selected through an open and transparent 
solicitation process.'' We also remove the word ``the'' before 
``Transmission Provider.''

    462. Finally, the Commission proposed to add a new section 3.3.2 to 
the pro forma LGIP that establishes the open and transparent 
solicitation process for surplus interconnection service (with proposed 
---------------------------------------------------------------------------
text in italics):

    Solicitation Process for Surplus Interconnection Service. If the 
existing Generating Facility owner elects to transfer rights for 
Surplus Interconnection Service to an unaffiliated Interconnection 
Customer, it must do so through an open and transparent solicitation 
process. The existing Generating Facility owner must first request 
that the Transmission Provider post on its website that it is 
willing to accept requests for Surplus Interconnection Service at 
the existing Point of Interconnection. Such posting will include the 
name of the existing Generating Facility, the exact electrical 
location of the physical termination point of the Surplus 
Interconnection Service, including proposed breaker position(s) 
within its substation, the state and county of the existing 
Generating Facility, and a valid email address and phone number to 
contact the representative of the existing Generating Facility. The 
existing Generating Facility owner must provide the Transmission 
Provider with the System Impact Study performed for the existing 
Generating Facility with its request for posting Surplus 
Interconnection Service or indicate that such study is not 
available.
    After the existing Generating Facility owner requests that the 
Transmission Provider post the availability of Surplus 
Interconnection Service, the Transmission Provider will also post on 
its website a description of the selection process for transferring 
rights to the Surplus Interconnection Service that will include a 
timeline and the selection criteria developed by the existing 
Generating Facility owner. The selection process may vary among 
existing Generating Facility owners but the existing Generating 
Facility owner will choose the winning request after all necessary 
studies have been performed by the Transmission Provider. The 
existing Generating Facility owner will submit to the Transmission 
Provider, for posting on the Transmission Provider's website, the 
results of the selection process and will include a description of 
whose proposal for the Surplus Interconnection Service was selected 
and why. After an Interconnection Customer has been chosen, the new 
Interconnection Customer will execute, or request the filing of an 
unexecuted, interconnection agreement with the Transmission Provider 
and Transmission Owner (as applicable) upon completion of all 
necessary studies for its new Generating Facility.\803\
---------------------------------------------------------------------------

    \803\ Id. P 211.
---------------------------------------------------------------------------

b. General
i. Comments
    463. Several commenters support this proposal. ESA supports the 
proposal and the ability to transfer interconnection capacity between 
parties because it may encourage co-location of storage and generation. 
It also states that the net-zero model developed by MISO, following the 
Commission's guidance in that proceeding, does not meet the objective 
of encouraging the use of surplus interconnection service and that a 
separate, faster process to transfer surplus is necessary.\804\ AWEA 
states that better use of interconnection capacity would reduce system 
costs and improve competition. AWEA argues that an interconnection 
customer would benefit from being able to split its GIA into multiple 
GIAs when it is a party to a Power Purchase Agreement that does not 
account for all of the capacity under the customer's interconnection 
agreement.\805\ Xcel supports a ``net-zero-like'' interconnection 
service and argues that existing interconnection customers or 
affiliates should have priority to use any available surplus 
interconnection service.\806\ Duke supports the proposal if it is like 
MISO's net-zero program and suggests that MISO's interconnection 
agreement is a good model for such transactions.\807\ FTC states that 
transferred interconnection capacity rights can play a significant role 
in providing transmission capacity for use by generation entrants 
quickly and at low cost.\808\ TDU Systems argue that the

[[Page 21398]]

transmission provider must give comparable service to non-affiliates as 
they do to their own affiliates.\809\ MISO generally supports the 
Commission's proposal, as do Alliant, ITC, MidAmerican, MISO TOs, and 
TDU Systems.\810\
---------------------------------------------------------------------------

    \804\ ESA 2017 Comments at 13-14.
    \805\ AWEA 2017 Comments at 58.
    \806\ Xcel 2017 Comments at 19.
    \807\ Duke 2017 Comments at 22.
    \808\ FTC 2017 Comments at 10.
    \809\ TDU Systems 2017 Comments at 19-20.
    \810\ MISO 2017 Comments at 5; Alliant 2017 Comments at 8; ITC 
2017 Comments at 121; MidAmerican 2017 Comments at 19; MISO TOs 2017 
Comments at 40; TDU Systems 2017 Comments at 19-20.
---------------------------------------------------------------------------

    464. Several commenters express concerns with some aspects of, but 
do not completely oppose, the Commission's proposal. For example, EEI 
states that the concept is reasonable but would burden transmission 
providers and should thus be optional.\811\ NYISO opposes simple 
transfer of capacity from an interconnection customer to another party 
because more than just MW capacity is needed for safe and reliable 
interconnection (for example, evaluation of short circuit issues). If 
the new interconnection customer is under 20 MW, NYISO suggests that it 
might be easier to use the SGIP and SGIA where it is easier to waive 
certain studies.\812\ PJM does not support the proposed open 
solicitation for transfer of any surplus interconnection service. PJM 
contends that there are no surplus capacity rights on its system 
because capacity is based on tested output. PJM asserts that it would 
have to create some form of energy rights that could be transferred. 
PJM prefers to continue using the transfer process contained in its 
tariffs and manuals.\813\
---------------------------------------------------------------------------

    \811\ EEI 2017 Comments at 59.
    \812\ NYISO 2017 Comments at 39.
    \813\ PJM 2017 Comments at 27-28.
---------------------------------------------------------------------------

    465. Other commenters, including several RTOs/ISOs, oppose the 
proposal entirely. For example, ISO-NE states that its markets are 
already managing surplus transfers through its process that integrates 
its forward capacity market with its interconnection queue. ISO-NE 
argues that the Commission proposal would significantly disrupt or 
misalign this process.\814\ CAISO appeals to the Commission to ``not 
sacrifice reliability studies on the altar of convenience.'' \815\ 
CAISO questions the need for this proposal, stating that 
interconnection customers can already retire/replace, repower, or 
assign available capacity through bilateral transactions, which 
according to CAISO work better than the administrative process in the 
NOPR.\816\ SoCal Edison supports the Commission's goal but does not 
support the NOPR due to the expedited process and concerns that the 
expedited NOPR process: (1) May be inferior to current processes like 
CAISO's Material Modification Assessment; (2) may encourage 
interconnection customers to request more interconnection service than 
they intend to use; and (3) should not enable a surplus interconnection 
customer to avoid the installation of necessary facilities to enable a 
safe and reliable interconnection.\817\ SEIA does not support the 
creation of a process to reassign surplus interconnection 
capacity.\818\ NYISO asserts that the NOPR may conflict with the 
principle of open access and might allow for undue discrimination by 
establishing a process that favors affiliates of an existing 
interconnection customer over other interconnection customers.\819\ AES 
states that this proposal could reduce flexibility to the transmission 
provider or reliability coordinator, and they would prefer that RTOs/
ISOs determine for themselves how to address the topic of transferring 
surplus capacity.\820\
---------------------------------------------------------------------------

    \814\ ISO-NE 2017 Comments at 48.
    \815\ CAISO 2017 Comments at 32.
    \816\ Id. at 34.
    \817\ SoCal Edison 2017 Comments at 9-13.
    \818\ SEIA 2017 Comments at 21.
    \819\ NYISO 2017 Comments at 39-40 (citing Midwest Indep. 
Transmission Sys. Operator, Inc., 140 FERC ] 61,237, at PP 50-51 
(2012), and Midwest Indep. Transmission Sys. Operator, Inc., 155 
FERC ] 61,274, at P 19 (2016)).
    \820\ AES 2017 Comments at 11-12.
---------------------------------------------------------------------------

    466. Several commenters state that either there is no surplus on 
their systems or that it is unclear what ``surplus'' means. For 
example, CAISO questions how to define surplus interconnection capacity 
and states that it assigns interconnection capacity by the actual size 
of the generator; thus, there is no surplus service in its region.\821\ 
Similarly, PJM states that it does not permit excess capacity to be 
obtained through the initial request. PJM rates interconnection 
capacity at the tested output of the generator after installation.\822\ 
Southern questions whether capacity being ``surplus'' should refer to 
its lack of use in operation, in the interconnection study, or in the 
interconnection request.\823\ NYISO's LGIA requires interconnection 
customers to inform NYISO if the built generating facility is smaller 
than what had been proposed, which initiates a process to consider 
amending the interconnection agreement, or requires a new 
interconnection request if the interconnection customer proposes to 
expand its facility.\824\ NYISO allows interconnection customers to pay 
for larger network upgrades than required for the initial project, as 
long as they are reasonably related to the interconnection of the 
proposed project.\825\ According to NYISO, another later 
interconnection customer can also use these network upgrades, so long 
as it reimburses the earlier interconnection customer that paid for 
them.\826\
---------------------------------------------------------------------------

    \821\ CAISO 2017 Comments at 31-32.
    \822\ PJM 2017 Comments at 27.
    \823\ Southern 2017 Comments at 28.
    \824\ NYISO 2017 Comments at 40.
    \825\ Id. at 42.
    \826\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    467. In this final action, we adopt, with certain modifications and 
clarifications, the NOPR proposals to: (1) Add a definition for 
``Surplus Interconnection Service'' to section 1 of the pro forma LGIP 
and to article 1 of the pro forma LGIA; (2) add a new section 3.3 to 
the pro forma LGIP that requires the transmission provider to establish 
a process for the use of surplus interconnection service; and (3) add a 
new section 3.3.1 to the pro forma LGIP that describes the process for 
using surplus interconnection service.\827\ As described in more detail 
below, we will withdraw the NOPR proposal to add a new section 3.3.2 to 
the pro forma LGIP that establishes an open and transparent 
solicitation process for surplus interconnection service. We affirm 
that requiring transmission providers to establish an expedited 
process, separate from the interconnection queue, for the use of 
surplus interconnection service could reduce costs for interconnection 
customers by increasing the utilization of existing interconnection 
facilities and network upgrades rather than requiring new ones, improve 
wholesale market competition by enabling more entities to compete 
through the more efficient use of surplus existing interconnection 
capacity, and remove economic barriers to the development of 
complementary technologies such as electric storage resources that may 
be able to easily tailor their use of interconnection service to adhere 
to the limitations of the surplus interconnection service that may 
exist. Further, we find that facilitating the use of surplus 
interconnection service could improve capabilities at existing 
generating facilities, prevent stranded costs, and improve access to 
the transmission system.
---------------------------------------------------------------------------

    \827\ With respect to these new additions to the pro forma LGIP 
and pro forma LGIA, we make minor clarifying edits to the pro forma 
tariff language originally proposed in the NOPR, as shown in 
Appendix B and C to Order No. 845.
---------------------------------------------------------------------------

    468. We clarify that surplus interconnection service is created 
because generating facilities may not operate at full capacity at all 
times. Consistent with the requirements of

[[Page 21399]]

Order No. 2003, transmission providers assume that each interconnection 
customer is fully utilizing its interconnection service when studying 
other requests for new interconnections. Thus, currently, even if a 
generating facility only operates a few days a year, or routinely 
operates at a level below its maximum capacity, the remaining, unused 
interconnection service is assumed to be unavailable to other 
prospective interconnection customers.
    469. As noted above, Order No. 2003 mandates that transmission 
providers assume that generating facilities operate at their full 
capacity. To illustrate this, we note that Order No. 2003 listed, as 
separate services, Energy Resource Interconnection Service (ERIS),\828\ 
a ``basic or minimum interconnection service,'' \829\ and Network 
Resource Interconnection Service (NRIS),\830\ a ``more flexible and 
comprehensive service.'' \831\ In Order No. 2003, the Commission stated 
that, for a generating facility with ERIS, ``[t]he Interconnection 
Studies to be performed . . . would identify the Interconnection 
Facilities required as well as the Network Upgrades needed to allow the 
proposed Generating Facility to operate at full output'' and ``the 
maximum allowed output of the Generating Facility without Network 
Upgrades.'' \832\
---------------------------------------------------------------------------

    \828\ 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.
    Pro forma LGIP Section 1 (Definitions).
    \829\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 752.
    \830\ 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 all other Network Resources. Network Resource 
Interconnection Service in and of itself does not convey 
transmission service.
    Pro forma LGIP Section 1 (Definitions).
    \831\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 752.
    \832\ Id. P 753 (emphasis added).
---------------------------------------------------------------------------

    470. Similarly, Order No. 2003 stated that NRIS ``provides for all 
of the Network Upgrades that would be needed to allow the 
Interconnection Customer to designate its Generating Facility as a 
Network Resource and obtain Network Integration Transmission Service'' 
so that for ``an Interconnection Customer [that] has obtained Network 
Resource Interconnection Service, any future transmission service 
request for delivery from the Generating Facility would not require 
additional studies or Network Upgrades.'' \833\ To allow for this, 
``[t]he Transmission Provider would study the Transmission System at 
peak load, under a variety of severely stressed conditions, to 
determine whether, with the Generating Facility at full output, the 
aggregate of generation in the local area can be delivered to the 
aggregate of load, consistent with the Transmission Provider's 
reliability criteria and procedures'' and ``would assume that some 
portion of the capacity of existing Network Resources is displaced by 
the output of the new Generating Facility.'' \834\
---------------------------------------------------------------------------

    \833\ Id.
    \834\ Id. P 755 (emphasis added).
---------------------------------------------------------------------------

    471. Thus, to provide interconnection service to an original 
interconnection customer at a particular point of interconnection, the 
transmission provider must conduct a study that assumes that the 
generating facility will produce at its full output and that the 
interconnection customer will fully utilize the amount of 
interconnection service requested. Consequently, it is possible for an 
original interconnection customer to have surplus interconnection 
service at a particular interconnection point because the generating 
facility capacity that the transmission provider originally studied 
pursuant to the pro forma LGIP may be in excess of the actual 
interconnection service required by the generating facility, at least 
during some periods. For these reasons, we find that, where proper 
precautions are taken to ensure system reliability, it would be unjust 
and unreasonable to deny an original interconnection customer the 
ability either to transfer or use for another resource surplus 
interconnection service.
    472. As established in this final action and explained further 
below, surplus interconnection service cannot exceed the total 
interconnection service already provided by the original 
interconnection customer's LGIA. Furthermore, if the original LGIA is 
for ERIS, any surplus interconnection customer associated with the 
original LGIA at the same point of interconnection would also need to 
be an ERIS customer in order to avoid the potential need for new 
network upgrades. If the original LGIA is for NRIS, then either ERIS or 
NRIS service could be offered to the surplus interconnection service 
customer. The provisions addressed in this final action will allow an 
existing interconnection customer to make a specified and limited 
amount of surplus interconnection service available at a particular 
interconnection point under a variety of circumstances, including, for 
example, on a continuous basis (i.e., a certain number of MW of surplus 
interconnection service always available for use by a co-located 
generating facility), or on a scheduled, periodic basis (i.e., a 
specified number of MW available intermittently).\835\ In contrast, an 
interconnection customer making a new interconnection request can 
request any level of interconnection service at or below its resource's 
generating facility capacity, and ERIS, NRIS, or provisional 
interconnection service.
---------------------------------------------------------------------------

    \835\ This would include situations where existing generating 
facilities operate infrequently, such as peaker units, or operate 
often below their full generating facility capacity, such as 
variable generation.
---------------------------------------------------------------------------

    473. We note that, to avoid abuse of this reform, which is intended 
to increase utilization of existing, underutilized interconnection 
service provided at a particular point of interconnection, we are 
restricting surplus interconnection service when new interconnection 
service would be more appropriate. Specifically, surplus 
interconnection service cannot be offered if the original 
interconnection customer's generating facility is scheduled to retire 
and permanently cease commercial operation before the surplus 
interconnection service customer's generating facility begin commercial 
operation. This restriction is consistent with the Commission's 
statement in Order No. 2003 that interconnection service is 
``associated with interconnecting the Interconnection Customer's 
Generating Facility to the Transmission Provider's Transmission 
System.'' \836\
---------------------------------------------------------------------------

    \836\ Pro forma LGIP Secction 1 (Definitions); pro forma LGIA 
Art. 1 (Definitions).
---------------------------------------------------------------------------

    474. As this statement demonstrates, the interconnection service 
provided under an original interconnection customer's LGIA is 
associated with interconnecting that interconnection customer's 
generating facility. Once that original generating facility retires and 
ceases commercial operation, whether that retirement was scheduled or 
caused prematurely by unexpected circumstances, there is no longer any 
interconnection service being provided under the original 
interconnection customer's LGIA. Because surplus interconnection 
service is inherently derived from an original interconnection 
customer's interconnection service under its LGIA, retirement and 
permanent cessation of commercial operation of the original

[[Page 21400]]

interconnection customer's generating facility would eliminate any 
potential surplus interconnection service that might otherwise have 
been available.
    475. We note that this final action makes it possible for a surplus 
interconnection service customer to increase the total generating 
facility capacity at a point of interconnection, provided that the 
total combined generating output at the point of interconnection for 
both the original and surplus interconnection customer is limited to 
and shall not exceed the maximum level allowed under the original 
interconnection customer's LGIA.
    476. Comments on the NOPR reveal substantial regional variation in 
the potential availability of surplus interconnection service and 
existing or prospective processes that would facilitate its use. To the 
extent that a transmission provider believes that it already complies 
with the surplus interconnection service requirements of this final 
action, it may include an explanation in its compliance filing in 
response to this final action.
    477. We clarify that, for a process to be consistent with or 
superior to, or an independent entity variation from, the final 
action's surplus interconnection service requirements, the transmission 
provider must demonstrate, at a minimum, that its tariff: (1) Includes 
a definition of surplus interconnection service consistent with the 
final action; (2) provides an expedited interconnection process outside 
of the interconnection queue for surplus interconnection service, 
consistent with the final action; (3) allows affiliates of the original 
interconnection customers to use surplus interconnection service for 
another interconnecting generating facility consistent with the final 
action; (4) allows for the transfer of surplus interconnection service 
that the original interconnection customer or one of its affiliates 
does not intend to use; and (5) specifies what reliability-related 
studies and approvals are necessary to provide surplus interconnection 
service and to ensure the reliable use of surplus interconnection 
service.
    478. As a threshold consideration, we respond to NYISO's concern 
regarding whether the NOPR proposal on surplus interconnection service 
is consistent with the principles of open access.
    479. While open access principles are fundamental to the 
Commission's regulation of transmission in interstate commerce,\837\ we 
find that, in light of the substantial potential benefits of and 
inherent practical limitations on the use of surplus interconnection 
service, open access requirements such as those the Commission 
previously imposed upon MISO's Net Zero Interconnection Service are not 
currently necessary to achieve the Commission's open access goals. This 
finding is consistent with the perspective that the Commission adopted 
in Order No. 807, where the Commission amended:
---------------------------------------------------------------------------

    \837\ See Promoting Wholesale Competition Through Open Access 
Non-Discriminatory Transmission Services by Public Utilities; 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order 
on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, 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 Policy Study Group v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 
(2002).

its regulations to waive the Open Access Transmission Tariff (OATT) 
requirements of 18 CFR 35.28, the Open Access Same-Time Information 
System (OASIS) requirements of 18 CFR 37, and the Standards of 
Conduct requirements 18 CFR 358, under certain conditions, for the 
ownership, control, or operation of Interconnection Customer's 
Interconnection Facilities (ICIF).\838\
---------------------------------------------------------------------------

    \838\ Open Access and Priority Rights on Interconnection 
Customer's Interconnection Facilities, Order No. 807, FERC Stats. & 
Regs. ] 31,367, at P 1 (Order No. 807), order on reh'g, Order No. 
807-A, 153 FERC ] 61,047 (2015).

    In Order No. 807, the Commission concluded that the waived 
requirements were not ``necessary to achieve the Commission's open 
access goals.'' \839\ In coming to this conclusion, the Commission 
stated, among other things, that given the limited nature of the ICIF 
and practical benefits provided by Order No. 807, the waived 
requirements were not necessary to achieve open access. \840\
---------------------------------------------------------------------------

    \839\ Id. P 18.
    \840\ Id. PP 38, 55.
---------------------------------------------------------------------------

    480. We find that policy considerations comparable to those that 
the Commission relied upon to support Order No. 807 are present here. 
Surplus interconnection service is not available to third parties 
absent some process for allowing the use or transfer of the surplus 
interconnection service to another interconnection customer. As 
described above, some original interconnection customers do not use the 
full generating facility capacity of their interconnection service due 
to the nature of their operations. In these circumstances, no other 
interconnection customer would be able to obtain interconnection 
service associated with the network upgrades funded by the original 
interconnection customer. Creation of a surplus interconnection service 
that allows another interconnection customer to make use of surplus 
interconnection service will enhance access to the transmission system 
at the point of interconnection.
    481. The question is then how to align the process for determining 
which resources may access surplus interconnection service with the 
Commission's goals to promote transparent and nondiscriminatory 
practices. We are convinced, as we were in Order No. 807, that certain 
requirements and processes--in this instance, a competitive 
solicitation--are not necessary to achieve our overall open access 
goals. As a general matter, we note that surplus interconnection 
service is, by definition, limited in nature. This is because: (1) The 
total output of the original interconnection customer plus the surplus 
interconnection service customer behind the same point of 
interconnection shall be limited to the maximum total amount of 
interconnection service granted to the original interconnection 
customer; (2) the original interconnection customer must be able to 
stipulate the amount of surplus interconnection service that is 
available, to designate when that service is available, and to describe 
any other conditions under which surplus interconnection service at the 
point of interconnection may be used; and (3) surplus interconnection 
service shall only be available at the preexisting point of 
interconnection of the original interconnection customer.
    482. Furthermore, we note that the Commission is making no changes 
to the open access nature of the generator interconnection process 
established by Order No. 2003. This final action requirement does not 
restrict a new interconnection customer's ability to submit an 
interconnection request for any requested point of interconnection 
directly with the transmission provider, rather than seeking surplus 
interconnection service with respect to an original interconnection 
customer's point of interconnection. Therefore, an original 
interconnection customer with surplus interconnection service shall not 
be capable of preventing a new interconnection customer from exercising 
its open access rights to the transmission grid.
    483. In order to realize the benefits of an efficiently-used 
transmission system, the final action adopts the NOPR proposal to allow 
an original interconnection customer or its affiliate to use any 
surplus interconnection service. Additionally, we withdraw the NOPR 
proposal to require an open and transparent solicitation process if an 
original interconnection customer that has surplus interconnection 
service

[[Page 21401]]

wishes to transfer this surplus interconnection service to a non-
affiliated third party. Consequently, we will revise proposed pro forma 
section 3.3 as follows (deleting the bracketed text from, and adding 
the italicized text to, proposed language):

    Utilization of Surplus Interconnection Service. [The 
]Transmission Provider must provide a process that allows an 
Interconnection Customer to utilize or transfer Surplus 
Interconnection Service at an existing [Generating Facility] 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 [through an open and transparent solicitation 
process].\841\
---------------------------------------------------------------------------

    \841\ NOPR, FERC Stats. & Regs. ] 32,719 at P 209.

    484. We acknowledge that the requirements adopted here reflect a 
change in Commission policy with respect to some of the requirements 
previously imposed on MISO's Net Zero Interconnection Service.\842\ 
Because of the history of that service (namely the fact that only one 
party has sought MISO's Net Zero Interconnection Service), and in light 
of the record and discussion above, we find it appropriate to revisit 
and modify our position on the topic of surplus interconnection 
service.
---------------------------------------------------------------------------

    \842\ See, e.g., Midwest Indep. Transmission Sys. Operator, 138 
FERC ] 61,233 at P 302.
---------------------------------------------------------------------------

c. Expedited Process
i. Comments
    485. Commenters disagree on whether there should be an expedited 
process for transferring surplus interconnection capacity. For example, 
California Energy Storage Alliance supports a faster process that does 
not require additional interconnection studies.\843\ Xcel and AWEA 
argue for a new process outside the LGIP that would handle all 
transfers of interconnection capacity.\844\ On the other hand, some 
transmission providers oppose any expedited process that departs from 
the interconnection queue order. SoCal Edison states that, in order to 
properly identify required upgrades and define proper cost assignment, 
technical studies need to follow a rational order that must be 
predicated on relative queue position.\845\ Southern opposes an 
expedited process that allows a new interconnection customer to ``jump 
up'' in the queue, as this would be unfair to others in the queue.\846\
---------------------------------------------------------------------------

    \843\ California Energy Storage Alliance 2017 Comments at 7.
    \844\ Xcel 2017 Comments at 19; AWEA 2017 Comments at 59.
    \845\ SoCal Edison 2017 Comments at 2.
    \846\ Southern 2017 Comments at 31.
---------------------------------------------------------------------------

ii. Commission Determination
    486. As described earlier, we adopt the NOPR proposal to add a new 
definition for ``Surplus Interconnection Service'' to section 1 of the 
pro forma LGIP and to article 1 of the pro forma LGIA that requires 
transmission providers to provide an expedited process for 
interconnection customers to utilize or transfer surplus 
interconnection service at a particular point of interconnection. This 
process would be expedited in the sense that it would take place 
outside of the interconnection queue. Some commenters argue that this 
would result in inappropriate queue jumping.
    487. In response to those comments, we clarify that the use or 
transfer of surplus interconnection service does not entail queue 
jumping because surplus interconnection service does not compete for 
the same potential network upgrades that may be at issue in the normal 
interconnection queue. Surplus interconnection service is more limited 
interconnection service because it can only be located at the original 
interconnection customer's previously studied and approved point of 
interconnection. The requirements for the use of surplus 
interconnection service: (1) Provide efficient use of the transmission 
system; (2) ensure that the use of surplus interconnection service is 
safe and reliable; and (3) help mitigate the possibility of unduly 
discriminatory treatment. Because the necessary studies for surplus 
interconnection service shall confirm that the combination of the 
surplus interconnection customer's generating facility with the 
original interconnection customer's generating facility does not result 
in a need for new network upgrades, it would be inefficient to put 
surplus interconnection customers into the interconnection queue.
    488. Furthermore, transmission providers in some regions routinely 
conduct similar studies outside of the interconnection process. For 
example, MISO frequently conducts Quarterly Operating Limits studies, 
which are similar in nature to the studies required for surplus 
interconnection service, and the Commission is unaware of any delays to 
other customers related to the processing of these studies.\847\ We 
also clarify that original interconnection customers are not required 
to make surplus interconnection service available to potential 
customers. If they do make it available, transmission providers are not 
required to execute an interconnection agreement for surplus 
interconnection service if arrangements do not meet the definition set 
forth in their tariff or if the customer does not agree to the terms of 
such service, including any requirements that may be identified by the 
transmission provider in the studies for surplus interconnection 
service. If the surplus interconnection service customer disputes an 
issue in the interconnection agreement for surplus interconnection 
service, the transmission provider must file the unexecuted surplus 
interconnection service agreement with the Commission if requested to 
do so by the surplus interconnection service customer.
---------------------------------------------------------------------------

    \847\ See, e.g., MISO, FERC Electric Tariff, Attachment X 
(76.0.0), Section 11.5.
---------------------------------------------------------------------------

d. Interconnection Capacity Hoarding or Squatting
i. Comments
    489. SoCal Edison expresses concern that the proposal might 
encourage interconnection customers to request more interconnection 
capacity than they intend to use, in order to create a surplus that 
they might sell later.\848\ Southern agrees and adds that this could 
create costs for later-queued customers that they otherwise would not 
have to pay.\849\ Xcel expresses concerns that such practices could 
lead to capacity ``squatting (i.e., hoarding).'' \850\ However, 
Competitive Suppliers oppose these positions and state that reductions 
in interconnection service to eliminate surplus by transmission 
providers amounts to confiscation of the rights of the interconnection 
customers.\851\
---------------------------------------------------------------------------

    \848\ SoCal Edison 2017 Comments at 10.
    \849\ Southern 2017 Comments at 29-30.
    \850\ Xcel 2017 Comments at 21.
    \851\ Competitive Suppliers 2017 Comments at 8.
---------------------------------------------------------------------------

ii. Commission Determination
    490. As discussed earlier, the interconnection service provided 
under any LGIA is associated with interconnecting that interconnection 
customer's generating facility to the transmission provider's system, 
with a maximum level equal to the generating facility capacity. 
Accordingly, an interconnection customer cannot amass large excesses of 
interconnection service beyond its own needs. Furthermore, as discussed 
earlier, interconnection customers are free to seek interconnection 
service through the non-surplus interconnection process of the 
transmission provider. While an original interconnection customer could 
maintain control over a certain amount

[[Page 21402]]

of interconnection service, that service will be limited to the 
original interconnection customer's generating facility capacity (which 
is based on the size of the generating facility it constructs and 
continues to operate). If the original interconnection customer does 
not construct the facility it has represented to the transmission 
provider, or retires that facility, the transmission provider may 
terminate the customer's LGIA in accordance with applicable provisions 
in its tariff. Accordingly, we see no significant concern with hoarding 
interconnection service.
e. Property Rights
i. Comments
    491. As further described below, some commenters assert that the 
NOPR's surplus interconnection proposals treat interconnection service 
as a property right of the interconnection customer even though they 
may not have been so treated in the past. CAISO states that Commission 
precedent holds that the interconnection capacity does not confer a 
property right, and that where an interconnection customer builds less 
generating facility capacity than that for which it requested 
interconnection service, it does not retain that interconnection 
capacity indefinitely, and transmission providers like CAISO may 
subsequently remove it from their base case.\852\ NYISO asserts that 
the NOPR would expand what is currently a contractual right, namely the 
right to a particular point of interconnection, into a property right 
by allowing a generator to transfer interconnection service to a third 
party.\853\ SoCal Edison states that the NOPR assumes that 
interconnection capacity is a property right, but that in many cases 
the interconnection customer did not pay for the ``surplus.'' \854\
---------------------------------------------------------------------------

    \852\ CAISO 2017 Comments at 32 (citing CalWind Resources Inc. 
v. California Independent System Operator Corp., 146 FERC ] 61,121, 
at PP 33 et seq. (2014)).
    \853\ NYISO 2017 Comments at 41.
    \854\ SoCal Edison 2017 Comments at 9.
---------------------------------------------------------------------------

    492. On the other hand, some interconnection customers assert that 
contracted interconnection service is indeed a property right. 
Generation Developers support recognizing that surplus capacity is a 
property right and asset of the existing interconnection customer.\855\ 
Cogeneration Association argues that transfer of capacity cannot be 
done without the consent of the existing interconnection customer, and 
that the existing interconnection customer should be able to negotiate 
the terms and compensation for the transfer of capacity.\856\
---------------------------------------------------------------------------

    \855\ Generation Developers 2017 Comments at 41.
    \856\ Cogeneration Association 2017 Comments at 3.
---------------------------------------------------------------------------

ii. Commission Determination
    493. We are, in this final action, adopting a requirement that 
transmission providers establish a process for the use or transfer of 
surplus interconnection service, and we do not view that policy as 
establishing a new property right to interconnection service. Rather, 
as NYISO contends, interconnection service is a contractual right 
provided by an LGIA. We also agree with CAISO that where the original 
interconnection customer, for example, reduces the generating facility 
capacity of its facility from what was originally proposed for 
interconnection, it would not retain rights indefinitely to any excess 
interconnection capacity thus created.
f. Original Interconnection Customer's Priority
i. Comments
    494. Some commenters argue that the proposed priority for original 
interconnection customers and their affiliates should have a limited 
term. MidAmerican \857\ and CAISO \858\ support a limit of three years 
from when the original generation facility last produced energy. EDP 
proposes a minimum of five years. EDP cites compatibility with the 
five-year safe harbor granted to interconnection customer 
interconnection facilities in Order No. 807 as support for a five year 
priority here.\859\ MISO TOs,\860\ PJM,\861\ and TDU Systems \862\ 
support a time limit, either after the original commercial operations 
date if the interconnection customer has failed to achieve commercial 
operations, or for some period after it has ceased commercial 
operations, but do not specify a duration, preferring to leave each RTO 
or ISO with discretion to determine appropriate duration.
---------------------------------------------------------------------------

    \857\ MidAmerican 2017 Comments at 20.
    \858\ CAISO 2017 Comments at 33.
    \859\ EDP 2017 Comments at 8.
    \860\ MISO TOs 2017 Comments at 40.
    \861\ PJM 2017 Comments at 26.
    \862\ TDU Systems 2017 Comments at 29-30.
---------------------------------------------------------------------------

ii. Commission Determination
    495. While the Commission sought comment in the NOPR on whether any 
limitations should be placed on the original interconnection customer's 
priority use of its interconnection service, we find that the original 
interconnection customer, through its LGIA, may use or transfer any 
surplus interconnection service until it retires the generating 
facility that is the subject of the LGIA. We see no reason to modify 
that ability. Accordingly, original interconnection customers will 
retain the ability to use, either for themselves, for an affiliate, or 
for sale to a third party of their choosing, any surplus 
interconnection service that may exist under their LGIAs, until their 
original generating facility retires. However, as described more fully 
in subsection (h) below, this right becomes more limited once the 
original interconnection customer schedules the retirement of its 
original generating facility.
g. Contractual Arrangements
i. Comments
    496. Commenters that were responsive to the Commission's questions 
regarding contractual arrangements generally agree that contractual 
arrangements are necessary between the surplus interconnection customer 
and the original interconnection customer, as well as with the 
transmission owner.\863\ Specifically, Cogeneration Association states 
that collateral agreements between the interconnection customers are 
necessary, as dealing with rights and obligations between the original 
interconnection customer and new interconnection customer may not be 
included in the LGIA.\864\ Similarly, AWEA supports the idea of the 
original and new interconnection customers each having a separate 
LGIA.\865\
---------------------------------------------------------------------------

    \863\ Cogeneration Association 2017 Comments at 5; ITC 2017 
Comments at 20; Generation Developers 2017 Comments at 41; Duke 2017 
Comments at 22.
    \864\ Cogeneration Association 2017 Comments at 5.
    \865\ AWEA 2017 Comments at 59.
---------------------------------------------------------------------------

    497. ITC argues that the Commission should specify in the pro forma 
LGIA that the original interconnection customer will serve as the 
single point of contact for operational directives and outage 
coordination by the transmission provider and/or transmission owner. 
According to ITC, transmission providers/owners should not be required 
to coordinate these operational issues with multiple, potentially-
unaffiliated parties. Rather, ITC argues, it is appropriate that the 
original interconnection customer that elects to make surplus capacity 
available assume the obligation of coordinating with surplus 
customers.\866\
---------------------------------------------------------------------------

    \866\ ITC 2017 Comments at 20.
---------------------------------------------------------------------------

    498. Generation Developers argue that the Commission should require 
a transmission provider to have a pro forma surplus interconnection 
agreement.\867\ Duke agrees with the

[[Page 21403]]

NOPR proposal that a new interconnection agreement for surplus 
interconnection service must be executed, or filed unexecuted, by the 
transmission provider, transmission owner (as applicable), and the 
surplus interconnection service customer and suggests that the MISO 
LGIA template provides a framework for such agreements between the 
interconnection customers and transmission providers.\868\
---------------------------------------------------------------------------

    \867\ Generation Developers 2017 Comments at 41.
    \868\ Duke 2017 Comments at 22.
---------------------------------------------------------------------------

ii. Commission Determination
    499. We agree with commenters that agreements between the original 
interconnection customer, the surplus interconnection service customer 
(whether affiliated or not), and the transmission provider are 
necessary to establish conditions such as the term of operation, the 
interconnection service limit, and the mode of operation for energy 
production (i.e., common or singular operation) and to establish the 
roles and responsibilities of the parties for maintaining the operation 
of the facility within the parameters of the surplus interconnection 
service agreement. Therefore, we require that the original 
interconnection customer, the surplus interconnection service customer, 
and the transmission provider enter into such agreements for surplus 
interconnection service and that they be filed by the transmission 
provider with the Commission, because any surplus interconnection 
service agreement will be an agreement under the transmission 
provider's OATT.
    500. However, we decline to establish these agreements as part of 
the pro forma LGIA or prescribe their terms and conditions. This will 
give transmission providers flexibility to establish agreements 
appropriate for their region (e.g., they may be different for RTO/ISO 
and non-RTO/ISO regions) and the unique conditions of each agreement 
for surplus interconnection service. It will also alleviate some 
potential burden by allowing transmission providers to either file pro 
forma versions of these agreements with the Commission, as was done in 
MISO, or execute them as needed and file them with the Commission on an 
ad hoc basis.
h. Retirement, Repowering and Continuation of Surplus Interconnection 
Service After the Original Interconnection Customer's Generating 
Facility Retires
i. Comments
    501. Some commenters discuss the NOPR as it might relate to 
retirement of generators and replacement or repowering.\869\ Xcel 
argues that the retention of rights by the interconnection customer or 
its affiliates may be helpful at the current time when many utilities 
are going through retirement and replacement or repowering.\870\ Xcel 
argues that using this approach for repowering leads to efficiency 
because re-using brownfield sites is the most cost-effective approach 
to repowering, and suggests that the Commission should encourage this 
practice.\871\ CAISO states that it allows repowering, and notes that, 
in some cases, this process has led to the replacement of conventional 
generation by electric storage.\872\ PG&E supports the CAISO repowering 
process for allowing new generation on the grid while potentially 
minimizing interconnection and network upgrade costs.\873\ ISO-NE 
states that its forward capacity market can accommodate repowering by 
maintaining the interconnection service while the interconnection 
customer builds a new generating facility that can take the place of a 
retiring unit.\874\
---------------------------------------------------------------------------

    \869\ For purposes of this final action, we adopt CAISO's 
definition of ``repowering,'' which defines repowering as a 
modification of existing generating units that does not: (i) 
Increase the total capability of the plant; or (ii) substantially 
change its electrical characteristics such that original reliability 
studies would be affected. See Section 25.1.2 of the CAISO tariff; 
Section 12 of the business practice manuals for Generator 
Management, https://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Generator%20Management.
    \870\ Xcel 2017 Comments at 19.
    \871\ Id. at 20.
    \872\ CAISO 2017 Comments at 33.
    \873\ PG&E 2017 Comments at 9.
    \874\ ISO-NE 2017 Comments at 50.
---------------------------------------------------------------------------

    502. Other commenters discuss whether surplus interconnection 
service should terminate at the same time the original interconnection 
customer's generating facility retires. Cogeneration Association argues 
that this matter should be stated in the LGIA or collateral agreement, 
but that the default position should be that the termination of rights 
of the surplus interconnection customer should occur simultaneously 
with the termination of rights of the original interconnection 
customer.\875\ Generation Developers argue for the survivorship of the 
surplus interconnection service when the original interconnection 
customer's generating facility retires, on the basis that the surplus 
interconnection customer would have paid the original interconnection 
customer for the interconnection rights.\876\ Xcel supports 
survivorship because of greater commercial attractiveness and helping 
the new interconnection customers to get financing.\877\
---------------------------------------------------------------------------

    \875\ Cogeneration Association 2017 Comments at 5-6.
    \876\ Generation Developers 2017 Comments at 42.
    \877\ Xcel 2017 Comments at 21.
---------------------------------------------------------------------------

ii. Commission Determination
    503. The purpose of this reform is to enable the efficient use of 
any surplus interconnection service that may exist in connection with 
an original interconnection customer's use of its generating facility. 
The retirement or repowering of that original interconnection 
customer's generating facility would represent activities outside the 
normal use of that generating facility. Accordingly, we find that, with 
one exception discussed below, retirement and repowering issues are 
outside the scope of this rulemaking, and should instead be addressed 
elsewhere (e.g., through the existing processes discussed by some 
commenters).
    504. With respect to continuation of surplus interconnection 
service after the retirement of the original interconnection customer's 
generating facility, we find that surplus interconnection service is, 
by definition, tied to the continued existence of the original 
interconnection customer's interconnection service. There must be some 
existing interconnection service from which the ability to provide 
surplus interconnection service has been identified. As described 
above, once the original interconnection service terminates, there is 
no longer an original interconnection service from which the ability to 
provide surplus interconnection service could be identified. Therefore, 
surplus interconnection service shall not be available when the 
original interconnection customer retires and permanently ceases 
commercial operation.
    505. However, we believe it is appropriate to permit a limited 
continuation of surplus interconnection service following the 
retirement and permanent cessation of commercial operation of the 
original interconnection customer's generating facility to ameliorate 
the business and financial risk to the surplus interconnection service 
customer if the original interconnection customer retires unexpectedly, 
when two conditions are met. First, the surplus service interconnection 
customer's generation facility must have been studied by the 
transmission provider for sole operation at the point of 
interconnection at the time of the interconnection of the surplus 
service interconnection customer. Second, the original interconnection 
customer (and now

[[Page 21404]]

retiring) must have agreed in writing that the surplus interconnection 
service customer may continue to operate at either its limited share of 
the original interconnection customer's generating facility capacity in 
the original interconnection customer's LGIA, as reflected in its 
surplus interconnection service agreement, or at any level below such 
limit upon the retirement and permanent cessation of commercial 
operation of the original interconnection customer's generating 
facility.
    506. If these conditions are met, then the transmission provider 
must permit the surplus interconnection service customer to continue 
the surplus interconnection service for a limited period not to exceed 
one year. To prevent gaming and abuse of the continuation of surplus 
interconnection service, such service shall be limited to no more than 
one year after the date of retirement and permanent cessation of 
commercial operation of the original interconnection customer. If these 
conditions are not met, then those agreements regarding the surplus 
interconnection service must be drafted to, and must, terminate 
simultaneously with the termination of the original interconnection 
agreement from which surplus interconnection service was provided.
    507. We note again that interconnection customers are under no 
obligation to choose surplus interconnection service rather than 
seeking their own stand-alone interconnection service directly from the 
transmission provider. Therefore, any interconnection customers that 
require greater assurance up front that their interconnection service 
will not be affected by the retirement of another generating facility 
should carefully consider whether surplus interconnection service is 
the right match for their particular needs.
i. Relationship to MISO Net Zero Interconnection Service
i. Comments
    508. MISO argues that, as a part of the final action, the 
Commission should allow MISO to remove certain restrictions on its 
existing Net Zero Interconnection Service that it argues exceed the 
restrictions proposed for the surplus interconnection service.\878\
---------------------------------------------------------------------------

    \878\ MISO 2017 Comments at 36.
---------------------------------------------------------------------------

ii. Commission Determination
    509. We agree with MISO that this final action includes fewer 
restrictions on the use of surplus interconnection service than what 
the Commission imposed on MISO's Net Zero Interconnection Service, 
which has a similar goal. As noted above, the requirements we enact in 
this final action for surplus interconnection service depart in some 
respects from our precedent regarding MISO's Net Zero Interconnection 
Service. This final action reflects a shift in the Commission's view of 
these issues as described in earlier subsections of this final action. 
To the extent that MISO wishes to modify the procedures surrounding its 
Net Zero Interconnection Service, MISO may propose to do so on 
compliance in this proceeding, and the Commission will evaluate that 
proposal to determine if it complies with the requirements of the final 
action.
4. Material Modification and Incorporation of Advanced Technologies
a. NOPR Proposal
    510. Under the pro forma LGIP, an interconnection customer can 
modify its interconnection request and still retain its queue position 
if the modifications are either explicitly allowed under the pro forma 
LGIP or if the transmission provider determines that the modifications 
are not material. The pro forma LGIA defines material modifications as 
``those modifications that have a material impact on the cost or timing 
of any Interconnection Request with a later queue priority date.'' 
\879\ Under the pro forma LGIP, an interconnection customer must submit 
to the transmission provider, in writing, modifications to any 
information provided in the interconnection request.\880\ The pro forma 
LGIP directs transmission providers to commence any necessary 
additional studies related to the interconnection customer's 
modification request no later than 30 calendar days after receiving 
notice of the request.\881\ If the transmission provider determines 
that the proposed modification is material, the interconnection 
customer can choose to abandon the proposed modification or proceed and 
lose its queue position.
---------------------------------------------------------------------------

    \879\ Pro forma LGIA Art. 1.
    \880\ See pro forma LGIP Section 4.4.
    \881\ See pro forma LGIP Section 4.4.4.
---------------------------------------------------------------------------

    511. In the NOPR, the Commission explained that the pro forma LGIP 
does not contain guidance regarding analysis and modeling for the 
incorporation of technological advancements into an existing 
interconnection request. The Commission preliminarily found that the 
discretion resulting from this lack of guidance can lead to unjust and 
unreasonable rates, terms, and conditions, and unduly discriminatory or 
preferential practices, especially for technological advancements.\882\ 
The Commission thus proposed to require transmission providers to 
establish a technological change procedure in their LGIPs to assess 
and, if necessary, study whether they can accommodate a technological 
advancement without the change being considered material.\883\ The 
Commission stated that such a procedure would allow an interconnection 
customer to provide an analysis of how its proposed technological 
advancement would result in electrical performance that is equal to or 
better than the electrical performance expected prior to the 
change.\884\ Using such a procedure, a transmission provider would 
determine whether a technological advancement is a material 
modification. If it was not a material modification, the 
interconnection customer could incorporate the technological 
advancement without losing its queue position.
---------------------------------------------------------------------------

    \882\ NOPR, FERC Stats. & Regs. ] 32,719 at P 216.
    \883\ Id. P 217.
    \884\ Id. PP 217-18.
---------------------------------------------------------------------------

    512. In the NOPR, the Commission also proposed to require 
transmission providers to develop a definition of permissible 
technological advancements that the interconnection process can 
accommodate without the change being considered a material 
modification.\885\ Thus, pursuant to this proposal, a permissible 
technological advancement is a technological advancement that, by 
definition, does not constitute a material modification. Further, the 
Commission proposed that this definition should contemplate 
advancements that provide cost efficiency and/or electrical performance 
benefits.\886\ The Commission proposed that in the scenario where a 
transmission provider requires a study for a proposed technological 
advancement to not be considered a material modification, the 
interconnection customer should tender an appropriate study deposit and 
provide the necessary modeling data that sufficiently models the 
behavior of the new equipment and any other required data about the 
technological advancement to the transmission provider.\887\
---------------------------------------------------------------------------

    \885\ Id. P 217.
    \886\ Id. P 212.
    \887\ Id. P 219.
---------------------------------------------------------------------------

    513. To implement the technological change procedure, the 
Commission also proposed to require transmission providers to define 
technological advancements in their LGIPs. The Commission stated that 
the definition should consider technological advancements to equipment 
that may

[[Page 21405]]

achieve cost and grid performance efficiencies.\888\ Finally, the 
Commission proposed to permit interconnection customers to submit 
technological advancement requests for incorporation any time before 
the execution of the facilities study agreement.\889\
---------------------------------------------------------------------------

    \888\ Id. P 222.
    \889\ Id. P 223.
---------------------------------------------------------------------------

    514. Accordingly, the Commission proposed to revise section 4.4.2 
of the pro forma LGIP as follows (with proposed deletions in brackets 
and with proposed additions in italics):

    4.4.2 Prior to the return of the executed Interconnection 
Facility Study Agreement to the Transmission Provider, the 
modifications permitted under this Section shall include 
specifically: (a) Additional 15 percent decrease in plant size (MW), 
[and] (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 technological 
advancement for the Large Generating Facility after the submission 
of the interconnection request. Section 4.4.4 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 Technological Advancement.\890\
---------------------------------------------------------------------------

    \890\ With respect to this new provisions to the pro forma LGIP, 
we make minor clarifying edits to the pro forma tariff language 
originally proposed in the NOPR, as shown in Appendix B to Order No. 
845. Specifically, the comma after section 4.4.2(a)(2) will be 
replaced with a semicolon, and pro forma section 4.4.2 will no 
longer capitalize ``Technological Change Procedure.'' Additionally, 
in the last sentence of pro forma section 4.4.2, ``technological 
advancement'' will now say ``Permissible Technological 
Advancement.'' Also, section 1 of the pro forma LGIP will contain a 
placeholder for the definition of ``Permissible Technological 
Advancement, and there is now a placeholder for each transmission 
provider's technological change procedure in pro forma LGIP section 
4.4.4.
---------------------------------------------------------------------------

b. Technological Change Procedure
i. Comments
    515. The majority of commenters support \891\ or do not object 
\892\ to the proposal. AFPA and ELCON cite the proposal's potential to 
lower interconnection costs and avoid costly delays in commercial 
operation.\893\ AWEA comments that the proposal will provide 
transparency and certainty to both the transmission provider and the 
interconnection customer, and will remove a barrier to the use of the 
most modern, cost effective technology.\894\ NextEra states that 
transmission providers are inconsistent in considering potential 
changes to the equipment being installed under an interconnection 
agreement.\895\ Alliant asserts that the current definition of material 
modification is unclear and that more guidance is needed from the 
Commission in terms of what would trigger a material modification 
study.\896\ Idaho Power agrees with the proposal provided that an 
interconnection customer will be responsible for any necessary network 
upgrades that are identified and for which the transmission provider 
committed expenses before the technological advancement request.\897\ 
TDU Systems supports the flexibility built into the proposal and adds 
that, if technological advancements include changes to the equipment's 
electrical characteristics, then the models require modification, the 
simulations must be re-run, and the results require reevaluation.\898\
---------------------------------------------------------------------------

    \891\ Alliant 2017 Comments at 13; AFPA 2017 Comments at 16; 
AWEA 2017 Comments at 60; CAISO 2017 Comments at 35; Joint Renewable 
Parties 2017 Comments at 12; ELCON 2017 Comments at 7; Idaho Power 
2017 Comments at 6; IECA Comments at 3; ISO-NE 2017 Comments at 51; 
MISO 2017 Comments at 5; NEPOOL 2017 Comments at 18; NextEra 2017 
Comments at 52; TDU Systems 2017 Comments at 30-31; PJM 2017 
Comments at 30.
    \892\ APPA/LPPC 2017 Comments at 26; NYISO 2017 Comments at 43; 
SEIA 2017 Comments at 21.
    \893\ AFPA 2017 Comments at 4; ELCON 2017 Comments at 7.
    \894\ AWEA 2017 Comments at 60.
    \895\ NextEra 2017 Comments at 52.
    \896\ Alliant 2017 Comments at 13.
    \897\ Idaho Power 2017 Comments at 6.
    \898\ TDU Systems 2017 Comments at 30-31.
---------------------------------------------------------------------------

    516. Multiple RTOs/ISOs support or do not oppose the NOPR's 
technological advancement proposal, while some do not necessarily 
believe that the NOPR proposal is necessary. For example, CAISO states 
that it supports the proposal.\899\ MISO also supports the proposal, 
and comments that interconnection customers should not forfeit 
interconnection rights simply because the technology of their 
generating facility has become outdated.\900\ ISO-NE and NEPOOL state 
that ISO-NE's 2016 revisions to its interconnection procedures already 
establish clear rules to consistently and expeditiously determine 
whether a proposed modification is material.\901\ ISO-NE states that it 
developed its rules to respond to continuous requests for technical 
changes, which were one contributing factor to the Maine queue 
backlog.\902\ ISO-NE states that its recent tariff changes have 
addressed these issues. NYISO asserts that it does not oppose the NOPR 
proposal if it is limited to assessing the materiality and 
consideration of whether the transmission provider can accommodate a 
modification to the specific technology type initially proposed (as 
opposed to changing from gas to wind, for example).\903\ PJM states 
that it is not opposed to accounting for technological changes during 
the study process.\904\ However, PJM cites to its current practice of 
incorporating technological changes and states that a separate 
``technological change procedure'' is not necessary to determine 
whether such a modification is material.\905\
---------------------------------------------------------------------------

    \899\ CAISO 2017 Comments at 35.
    \900\ MISO 2017 Comments at 5.
    \901\ ISO-NE 2017 Comments at 52; NEPOOL 2017 Comments at 18.
    \902\ ISO-NE 2017 Comments at 52-53. ISO-NE noted that the 
revisions were developed with stakeholders to address 
interconnection challenges that have led to a backlog of 
interconnection requests for 4,000 MW of primarily wind generation 
in Maine. See ISO New England Inc. and Participating Transmission 
Owners Admin. Comm., 155 FERC ] 61,031, at P 2 (2016).
    \903\ NYISO 2017 Comments at 43.
    \904\ PJM 2017 Comments at 30.
    \905\ PJM 2017 Comments at 30.
---------------------------------------------------------------------------

    517. Other commenters do not support the NOPR proposal or believe 
that the proposed changes are unnecessary. For example, EEI and some 
public utility transmission providers outside the RTOs/ISOs comment 
that current material modification provisions are adequate.\906\ EEI 
asserts that the Commission has not clearly explained the difference 
between a technological advancement and a material modification and 
that the proposal unreasonably limits a transmission provider's ability 
to evaluate reliability impacts.\907\ EEI states that, if the 
Commission decides to establish more granular procedures for 
technological advancements, it should not duplicate the material 
modification requirements. Instead, EEI suggests that the Commission 
could require transmission providers to explain whenever a change that 
is not explicitly listed in the pro forma LGIP constitutes a material 
modification.\908\ EEI also states that it is reasonable to leave 
significant discretion to sound engineering judgment in order to 
balance the need to implement technological advancements, improve 
performance and efficiencies, and to maintain safe, reliable 
service.\909\ Southern adds that the concern should not be about 
developing types of advanced technologies, but how that

[[Page 21406]]

technology impacts already queued requests.\910\ TVA suggests that, 
rather than identifying specific pre-qualified technical advancements, 
interconnection customers should update their model data before 
starting the system impact study.\911\ Xcel notes that the types and 
impacts of changes evolve as technology advances, and while it does not 
consider a pro forma LGIP change necessary, it encourages customers to 
provide studies and evidence that any change is immaterial.\912\ Xcel 
also recommends that the Commission hold a technical conference or 
workshop to discuss material modification issues, which it anticipates 
will show the variation and difficulty involved in evaluating such 
modifications.\913\
---------------------------------------------------------------------------

    \906\ AES 2017 Comments at 8-9; Duke 2017 Comments at 24; EEI 
2017 Comments at 67; PG&E 2017 Comments at 9 (citing CAISO Business 
Practice Manual for Generator Management Section 6); Southern 2017 
Comments at 32; TVA 2017 Comments at 18; Xcel 2017 Comment at 22.
    \907\ EEI 2017 Comments at 5, 67, 68-69.
    \908\ Id. at 69, 73.
    \909\ Id. at 73.
    \910\ Southern 2017 Comments at 32.
    \911\ TVA 2017 Comments at 18.
    \912\ Xcel 2017 Comment at 22.
    \913\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    518. We adopt the NOPR proposal subject to certain clarifications. 
We require transmission providers to include in their pro forma LGIP a 
technological change procedure. They must also assess, and if 
necessary, study whether proposed technological advancements can be 
incorporated into interconnection requests without triggering the 
material modification provisions of the pro forma LGIP. Furthermore, 
transmission providers must, consistent with the guidance provided in 
this final action, develop a definition of permissible technological 
advancement. Such permissible technological advancements would, by 
definition, not constitute material modifications.
    519. The technological change procedure must specify what 
technological advancements can be incorporated at various stages of the 
interconnection process, and the procedure must clearly identify which 
requirements apply to the interconnection customer and which apply to 
the transmission provider. The procedure should state that, if an 
interconnection customer seeks to incorporate technological 
advancements into its generating facility, it should submit a 
technological advancement request. For the transmission provider to 
determine that a proposed technological advancement is not a material 
modification, the procedure must specify the information that the 
interconnection customer must submit as part of a technological 
advancement request. The procedure must also specify the conditions 
under which a study will or will not be necessary to determine whether 
a proposed technological advancement is a material modification.
    520. For a transmission provider to be able to determine whether a 
proposed technological advancement is not a material modification, the 
interconnection customer's technological advancement request must 
demonstrate that the proposed incorporation of the technological 
advancement would result in electrical performance that is equal to or 
better than the electrical performance expected prior to the technology 
change and not cause any reliability concerns (i.e., materially impact 
the transmission system with regard to short circuit capability limits, 
steady-state thermal and voltage limits, or dynamic system stability 
and response).\914\
---------------------------------------------------------------------------

    \914\ In the next section, we respond to EEI's comment as to 
what was meant by ``performance that is equal or better than the 
electrical performance expected prior to the technology change.''
---------------------------------------------------------------------------

    521. The transmission provider must determine whether a requested 
technological advancement is a material modification and whether or not 
a study is necessary to complete the analysis of whether the 
technological advancement is a material modification. The procedure 
must state that, if a study is necessary to evaluate whether a 
particular technological advancement is a material modification, the 
transmission provider must clearly indicate to the interconnection 
customer the types of information and/or study inputs that the 
interconnection customer must provide to the transmission provider, 
including for example, study scenarios, modeling data, and any other 
assumptions. The procedure should also explain how the transmission 
provider will evaluate the technological advancement request to 
determine whether it is a material modification.
    522. If the transmission provider cannot accommodate a proposed 
technological advancement without triggering the material modification 
provision of the pro forma LGIP, the transmission provider shall 
provide an explanation to the interconnection customer regarding why 
the technological advancement is a material modification.
    523. We find that the current definition of material modification 
may create uncertainty about whether a transmission provider must 
consider a technological advancement to be a material modification, and 
we agree with commenters that the requirement that we adopt in this 
final action will increase transparency, create process efficiencies, 
and encourage technological innovation that could lower consumer 
costs.\915\ We find that, contrary to the assertions that the existing 
material modification procedures are adequate, the proposed reforms are 
necessary to improve certainty and transparency.
---------------------------------------------------------------------------

    \915\ See AFPA 2017 Comments at 16; AWEA 2017 Comments at 60-61; 
ELCON 2017 Comments at 7; NextEra 2017 Comments at 52.
---------------------------------------------------------------------------

    524. Some transmission providers, such as PJM, believe that a 
technological change procedure is unnecessary because their tariffs 
already include a method to determine whether a change to an 
interconnection request is a material modification. In response to 
these comments, if a transmission provider believes its existing 
interconnection procedures regarding the incorporation of technological 
advancements would qualify for a variation from the final action 
requirements or that it already complies with the requirements adopted 
in this final action, it may provide such an explanation in its 
compliance filing.
    525. EEI, Duke, Southern, TVA, and Xcel assert that the existing 
material modification procedures are adequate to incorporate 
technological advancements. However, they do not dispute our concern 
that transmission providers have significant discretion over what 
equipment changes constitute material modifications. EEI takes issue 
with the proposal for transmission providers to specify in the 
technological change procedure the conditions when a study is 
necessary.\916\ EEI further asserts that the Commission has not clearly 
explained the difference between a technological advancement and a 
material modification and that the proposal unreasonably limits a 
transmission provider's ability to evaluate reliability impacts.\917\ 
In response to these concerns, we note that the purpose of the 
technological change procedure is to allow for equipment changes 
resulting in electrical performance that is equal to or better than an 
interconnection request's previously projected electrical performance 
and not cause any reliability concerns.\918\ We have designed the 
technological change procedure to allow transmission providers to 
evaluate whether equipment changes in an interconnection request should 
trigger

[[Page 21407]]

the material modification provisions. This new requirement increases 
transparency in the interconnection process and allows transmission 
providers to evaluate the impact of a proposed technological 
advancement to determine whether it qualifies as a material 
modification, and, thus will result in the interconnection customer 
losing its queue position.
---------------------------------------------------------------------------

    \916\ EEI 2017 Comments at 69-70.
    \917\ Id. at 5, 67, 68-69.
    \918\ For example, an interconnection customer may elect to 
incorporate a smart inverter that is capable of sensing and 
autonomously reacting to changes on the grid.
---------------------------------------------------------------------------

    526. Regarding Xcel's request for a technical conference, we 
believe our determination here is supported by the record evidence and 
therefore do not believe that a technical conference on this issue is 
necessary.
c. Definition of Permissible Technological Advancements
i. Comments
    527. A handful of commenters offer suggestions regarding the 
definition of permissible technological advancements. Some caution 
against an overly prescriptive definition to account for the 
unpredictability of technology evolution.\919\ Alliant and AWEA support 
an inclusive definition of technological advancement that accounts for 
changes that already exist.\920\ Alliant states that while a ``loose'' 
definition of material modification creates uncertainty and additional 
risk associated with replacing equipment or completing normal unit 
maintenance, an overly rigid definition could burden generator owners 
with unnecessary costs and the system operator with a longer backlog or 
strained resources.\921\ Other commenters assert that the rate of 
technological advancement makes it difficult to speculate which 
technologies to include.\922\ MISO TOs request clearer Commission 
direction to develop clear material modification guidelines.\923\ They 
also state that RTO/ISO guidelines should specify that a change that 
does not exceed the interconnection customer's interconnection rights 
or materially impact short circuit capability limits, steady-state 
thermal and voltage limits, or dynamic system stability and response is 
not a material modification.\924\
---------------------------------------------------------------------------

    \919\ AWEA 2017 Comments at 62; Alliant 2017 Comments at 13-14; 
Duke 2017 Comments at 25; EEI 2017 Comments at 6.
    \920\ Alliant 2017 Comments at 13-14; AWEA 2017 Comments at 62.
    \921\ Alliant 201 Comments at 13-14.
    \922\ Duke 2017 Comments at 25; EEI 2017 Comments at 69.
    \923\ MISO TOs 2017 Comments at 41.
    \924\ MISO TOs 2017 Comments at 42.
---------------------------------------------------------------------------

    528. EDP argues that changes between wind and solar technologies 
should be treated as non-material modifications.\925\ Other commenters 
disagree and request that the Commission make clear that permissible 
technological advancements exclude changes in generation technology 
type.\926\ NextEra argues that an incremental change within the same 
technology class, e.g., substituting a newer model of solar panel than 
originally planned, is not material.\927\ NYISO states that it opposes 
any tariff changes that would consider changes ``to the technology type 
that would essentially constitute a new facility as non-material 
modifications--e.g., the addition of a battery element to a wind 
project or the addition of a solar element to a wind project.'' \928\ 
NextEra submits that transmission providers should be able to define a 
category of permissible technological advancements that will not need 
extensive studies.\929\ EEI supports leaving the definition to the 
transmission provider's discretion.\930\
---------------------------------------------------------------------------

    \925\ EDP 2017 Comments at 9.
    \926\ EEI 2017 Comments at 71; NYISO Comments at 43.
    \927\ NextEra 2017 Comments at 52.
    \928\ NYISO 2017 Comments at 43.
    \929\ NextEra 2017 Comments at 52.
    \930\ EEI 2017 Comments at 70.
---------------------------------------------------------------------------

    529. EEI requests further clarification of what is meant by 
``performance that is equal or better than the electrical performance 
expected prior to the technology change.'' \931\ EEI also states that 
some material considerations such as electrical characteristics (e.g., 
reactive power), capacity factor, and time of use should be studied 
holistically.\932\
---------------------------------------------------------------------------

    \931\ Id.
    \932\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    530. We adopt the NOPR proposal and require transmission providers 
to develop a definition of permissible technological advancements that 
the interconnection process can accommodate without triggering the 
material modification provision of the pro forma LGIP. We are providing 
transmission providers with the flexibility to propose a unique 
definition for permissible technological advancements in their 
compliance filings. Some commenters caution against an overly 
prescriptive definition to account for the unpredictability of 
technology evolution.\933\ We agree that transmission providers should 
have the flexibility to account for the rapid pace of innovation when 
developing the definition. The definition must make clear what category 
of technological advancements can be accommodated that do not require 
extensive or additional studies to determine whether a proposed 
technological advancement is a material modification.\934\ As noted in 
the NOPR, such permissible changes may include, for example, 
advancements to turbines, inverters, plant supervisory controls, or 
other technological advancements that may affect a generating 
facility's ability to provide ancillary services.\935\ We clarify that 
the assessment of whether a technological advancement is permissible is 
limited to assessing the materiality of the change and consideration of 
whether the transmission provider can accommodate a modification to the 
specific technology type initially proposed in the interconnection 
request. Although some commenters argue that changes between wind and 
solar technologies should be treated as non-material 
modifications,\936\ we disagree since such changes involve a change in 
the electrical characteristics of an interconnection request, and the 
transmission provider would likely need to evaluate the impacts of such 
changes. We also agree that the definition of permissible technological 
advancements must not include changes in generation technology or fuel 
type \937\ (e.g., from gas to wind) because they involve a change in 
the electrical characteristics of an interconnection request.
---------------------------------------------------------------------------

    \933\ AWEA 2017 Comments at 62; Alliant 2017 Comments at 13-14; 
Duke 2017 Comments at 25; EEI 2017 Comments at 6.
    \934\ See e.g., NextEra 2017 Comments at 52.
    \935\ NOPR, FERC Stats. & Regs. ] 32,719 at P 212.
    \936\ See e.g., EDP 2017 Comments at 9.
    \937\ EEI 2017 Comments at 71; NYISO Comments at 43.
---------------------------------------------------------------------------

    531. MISO TOs request clearer Commission direction to develop 
material modification guidelines. They state that RTO/ISO guidelines 
should clarify that a change that does not exceed the interconnection 
customer's interconnection rights or materially impact short circuit 
capability limits, steady-state thermal and voltage limits, or dynamic 
system stability and response, is not a material modification.\938\ 
Responding to comments questioning whether certain technological 
advancements can be accommodated without materially affecting other 
interconnection customers in the queue as well as EEI's comment as to 
what was meant by ``performance that is equal or better than the 
electrical performance expected prior to the technology change,'' we 
find that a technological advancement that does not increase the 
interconnection customer's requested interconnection service or cause 
any reliability concerns

[[Page 21408]]

(i.e., materially impact the transmission system with regard to short 
circuit capability limits, steady-state thermal and voltage limits, or 
dynamic system stability and response), is generally not a material 
modification. Further, we clarify that technological advancements that 
do not degrade the electrical characteristics of the generating 
equipment (e.g., the ratings, impedances, efficiencies, capabilities, 
and performance of the equipment under steady state and dynamic 
conditions) qualify as performance that is ``equal to or better than 
the performance expected prior to the change.'' \939\
---------------------------------------------------------------------------

    \938\ MISO TOs 2017 Comments at 42.
    \939\ We note that TDU Systems argue for a similar 
interpretation of permissible technological advancement. TDU Systems 
2017 Comments at 30-31.
---------------------------------------------------------------------------

d. Timing and Deposits
i. Comments
    532. With regard to timing, EEI supports a 30-day study result 
deadline from commencement and a deposit of at least $10,000 per 
material modification proposal and clarification that the 
interconnection customer is financially responsible for necessary 
additional studies.\940\ NYISO supports only allowing modifications 
early in the interconnection study process.\941\ EEI requests 
clarification on when an interconnection customer should be able to 
request the incorporation of advanced technology; it is unsure if the 
Commission proposes to allow different technological advancements to 
trigger the procedure at different points or a single set of 
technological advancements prior to the facilities study agreement's 
execution.\942\ It further argues that technology changes without a 
change of queue position could result in additional studies and delays, 
particularly if the change is material or if the process to study the 
technological advancement negatively impacts the overall 
interconnection study process.\943\ EEI states that any final action 
should provide the flexibility for a transmission provider to evaluate 
the impact of a proposed technological advancement, relative to 
allowing it in the current study or requiring the generator to reenter 
the queue.\944\
---------------------------------------------------------------------------

    \940\ EEI 2017 Comments at 72-73.
    \941\ NYISO 2017 Comments at 44.
    \942\ EEI 2017 Comments at 71.
    \943\ Id. at 71-72.
    \944\ Id. at 72.
---------------------------------------------------------------------------

    533. AWEA supports allowing technological advancements at any point 
including after an interconnection agreement is executed and a 
generating unit is online.\945\ Generation Developers argue that 
transmission providers should have to respond to technological 
advancement analyses within 15 days.\946\ Conversely, Bonneville 
opposes a specific study completion timeframe, and suggests that a 
transmission provider would meet its obligation if it uses reasonable 
efforts.\947\
---------------------------------------------------------------------------

    \945\ AWEA 2017 Comments at 62.
    \946\ Generation Developers 2017 Comments at 44.
    \947\ Bonneville 2017 Comments at 11.
---------------------------------------------------------------------------

ii. Commission Determination
    534. We adopt the NOPR proposal to require the interconnection 
customer to tender a deposit if the transmission provider determines 
that additional studies are needed to evaluate whether a technological 
advancement is a material modification. We find that the amount of the 
deposit should be specified in the transmission provider's 
technological change procedure. Requiring such a deposit is just and 
reasonable because a deposit will reimburse the transmission provider 
for the time and effort needed to complete the technological 
advancement study as well as minimize the submission of frequent and/or 
frivolous technological advancement requests. The transmission provider 
shall describe for the interconnection customer any costs incurred to 
conduct any necessary additional studies, provide its costs to the 
interconnection customer, and either refund any overage or charge for 
any shortage for costs that exceed the deposit amount. We are setting 
the default deposit amount at $10,000. However, to the extent that a 
transmission provider considers a $10,000 deposit to be too high or 
low, it may propose a reasonable alternative amount in its compliance 
filing and include justification supporting this alternative amount. We 
agree with EEI that the interconnection customer should bear financial 
responsibility for any necessary additional studies that may need to be 
performed to determine whether a technological advancement is a 
material modification.\948\
---------------------------------------------------------------------------

    \948\ See EEI 2017 Comments at 72-73.
---------------------------------------------------------------------------

    535. Each transmission provider's technological change procedure 
must also include the timeframe for the transmission provider to 
perform the study it needs to determine whether the proposed 
technological advancement is a material modification and return the 
results to the interconnection customer. We note that some commenters 
suggested a 30-day study result deadline to determine whether a 
proposed technological advancement is material.\949\ After 
consideration of comments and the record in this proceeding, we believe 
that it is appropriate to establish a 30-day study result deadline. 
Accordingly, transmission providers must perform and complete any 
necessary additional studies as soon as practicable, but no later than 
30 days after the interconnection customer submits a formal 
technological advancement request to the transmission provider. 
Although Bonneville opposes a specific study completion timeframe, and 
suggests that a transmission provider would meets its obligation if it 
uses reasonable efforts,\950\ we find that, given that the pro forma 
LGIP currently contains no requirement for such studies to be completed 
within a specified timeframe, a 30-day requirement to determine whether 
the proposed technological advancement is a material modification adds 
certainty to the interconnection process.
---------------------------------------------------------------------------

    \949\ See, e.g., id.
    \950\ Bonneville 2017 Comments at 11.
---------------------------------------------------------------------------

    536. Regarding the question of when in the process the transmission 
provider is no longer required to accommodate technological 
advancements, we adopt the NOPR proposal to permit interconnection 
customers to submit requests to incorporate technological advancements 
prior to the execution of the interconnection facilities study 
agreement. In response to commenters that suggest that interconnection 
customers should be able to incorporate technological advancements at 
any point in the interconnection process without possible loss of queue 
position,\951\ we disagree. We believe that we are establishing a 
reasonable cut-off point for allowing technological advancements that 
will not be considered material modifications given that changes 
requested during the facilities study could delay the transmission 
provider's ability to tender an interconnection service agreement and, 
consequently, delay other projects.\952\ In addition, in response to 
EEI's concerns regarding whether the Commission envisions allowing 
different technological advancements to trigger the procedure at 
different points in the interconnection process, or if the Commission 
is proposing to allow one single set of technological advancements 
prior to the execution of the interconnection facilities study 
agreement, we clarify that interconnection customers must submit

[[Page 21409]]

a technological advancement request for any type of technological 
advancement in the interconnection process up until execution of the 
interconnection facilities study agreement. However, to the extent that 
a transmission provider believes that it is appropriate to establish 
rules that permit technological advancements only at a single point in 
its interconnection process (prior to the execution of the 
interconnection facilities study agreement), we permit transmission 
providers to propose such a practice in their compliance filings.
---------------------------------------------------------------------------

    \951\ See, e.g., AWEA 2017 Comments at 62 (stating that ``the 
technological change procedure should be allowed at any point in the 
interconnection process'').
    \952\ PJM 2017 Comments at 30.
---------------------------------------------------------------------------

5. Modeling of Electric Storage Resources for Interconnection Studies
a. NOPR Proposal
    537. The NOPR proposed to require that transmission providers 
evaluate their methods for modeling electric storage resources for 
interconnection studies, identify whether their current modeling and 
study practices adequately and efficiently account for the operational 
characteristics of electric storage resources, and explain why and how 
their existing practices are or are not sufficient. The Commission also 
sought comment on whether establishing a unified model for studying 
electric storage resources would expedite the study process and 
therefore reduce time and costs expended by transmission providers. The 
Commission also asked what information electric storage resources 
should provide when submitting interconnection requests that 
transmission providers do not already require.
b. Comments
    538. Several commenters support the proposal to require 
transmission providers to evaluate their methods for modeling electric 
storage resources for interconnection studies.\953\ MISO TOs state that 
MISO lacks clear standards for modeling electric storage, and ask that 
the Commission convene a workshop or technical conference to allow the 
industry to determine best practices.\954\ NEPOOL argues that the NOPR 
proposal would improve modeling of storage and facilitate entry of 
storage resources into the markets.\955\ Non-Profit Utility Trade 
Associations and PJM state that they do not object to the 
proposal.\956\
---------------------------------------------------------------------------

    \953\ AFPA 2017 Comments at 17; California Energy Storage 
Alliance 2017 Comments at 9-11; Joint Renewable Parties 2017 
Comments at 12-13; MISO TOs 2017 Comments at 43; NEPOOL 2017 
Comments at 18; NextEra 2017 Comments at 53; Public Interest 
Organizations 2017 Comments at 8-9; Indicated NYTOs 2017 Comments at 
15.
    \954\ MISO TOs 2017 Comments at 43.
    \955\ NEPOOL 2017 Comments at 18.
    \956\ Non-Profit Utility Trade Associations 2017 Comments at 26; 
PJM 2017 Comments at 30.
---------------------------------------------------------------------------

    539. Other commenters support the proposal but ask the Commission 
to give transmission providers flexibility to address any necessary 
changes.\957\ For example, Indicated NYTOs state that the evaluation of 
storage-related interconnection must be conducted in the context of 
each regional stakeholder process.\958\ Duke and NYISO take a similar 
view. They oppose a unified model for studying electric storage 
resources because it could remove a transmission provider's flexibility 
to study the various use cases for storage.\959\
---------------------------------------------------------------------------

    \957\ Indicated NYTOs 2017 Comments at 15; ITC 2017 Comments at 
20-21; Bonneville 2017 Comments at 11-12.
    \958\ Indicated NYTOs 2017 Comments at 15.
    \959\ Duke 2017 Comments at 25; NYISO 2017 Comments at 45.
---------------------------------------------------------------------------

    540. Public Interest Organizations ask the Commission not to 
require all electric storage resources, including electric storage 
resources that will serve as a transmission asset, to go through the 
formal large generator interconnection process.\960\ Similarly, Schulte 
Associates suggests that an energy storage resource should be able to 
interconnect as a generator under the LGIP and LGIA and the electric 
storage resource should be able to also act as a transmission asset, if 
applicable.\961\
---------------------------------------------------------------------------

    \960\ Public Interest Organizations 2017 Comments at 8-9.
    \961\ Schulte Associates 2017 Comments at 4.
---------------------------------------------------------------------------

    541. Other commenters, primarily the RTOs/ISOs, believe current 
modeling practices are adequate for the interconnection of electric 
storage resources.\962\ ISO-NE and PJM state that their modeling 
practices are able to study storage resources when they are either 
charging or discharging energy.\963\ NYISO adds that modeling electric 
storage resources can be challenging because it depends on the services 
the resource wants to provide, but that current modeling approaches are 
sufficient as long as the interconnection customer provides accurate 
modeling data and validation of such data.\964\ CAISO states that its 
stakeholders support CAISO's modeling of electric storage resources' 
charging function as ``negative generation'' in lieu of conducting 
traditional firm load studies, which some participants and commenters 
identified as a best practice during the Commission's 2016 Technical 
Conference and in post-technical conference comments.\965\ Idaho Power 
asks the Commission to elaborate on the size and capacity of electric 
storage resources to be evaluated.\966\
---------------------------------------------------------------------------

    \962\ CAISO 2017 Comments at 36-37; ISO-NE 2017 Comments at 55; 
MISO 2017 Comments at 39; NYISO 2017 Comments at 45; PJM 2017 
Comments at 31; AVANGRID 2017 Comments at 25.
    \963\ ISO-NE 2017 Comments at 55; PJM 2017 Comments at 31.
    \964\ NYISO 2017 Comments at 45.
    \965\ CAISO 2017 Comments at 37.
    \966\ Idaho Power 2017 Comments at 7.
---------------------------------------------------------------------------

    542. Schulte Associates suggests that electric storage resources 
should be able to propose consideration as a transmission asset under 
the pro forma LGIP and the pro forma LGIA and that this would require 
the RTOs/ISOs to consider the potential benefits and costs to the 
transmission system as part of its modeling methods going forward.\967\ 
ESA, NextEra, TVA, and Xcel support modeling an electric storage 
resource based on its intended use,\968\ and MISO and Duke provide 
examples of specific information interconnection customers should 
provide.\969\
---------------------------------------------------------------------------

    \967\ Schulte Associates 2017 Comments at 4.
    \968\ ESA 2017 Comments at 17-18; NextEra 2017 Comments at 54; 
TVA 2017 Comments at 18-19; Xcel 2017 Comment at 23.
    \969\ Duke 2017 Comments at 26-27; MISO 2017 Comments at 39.
---------------------------------------------------------------------------

    543. Some commenters argue that there is a need for clear modeling 
guidelines for electric storage resources. MISO and ESA recommend that 
the Commission require a consistent means by which transmission 
providers and system operators model electric storage charging.\970\ 
Several commenters support the ``negative generation'' approach 
employed in CAISO.\971\
---------------------------------------------------------------------------

    \970\ MISO 2017 Comments at 39; ESA 2017 Comments at 16-17.
    \971\ Id. at 17; NextEra 2017 Comments at 53; PG&E 2017 Comments 
at 9.
---------------------------------------------------------------------------

c. Commission Determination
    544. In consideration of the comments, we decline to move forward 
with any requirements for modeling electric storage resources in this 
final action. We agree with commenters that modeling electric storage 
resources as a single asset, as opposed to separate generation and load 
assets, and based on their intended use has merits. These approaches 
could streamline the interconnection of electric storage resources, 
save costs, and avoid modeling the charging of electric storage 
resources the same as other unpredictable, non-controllable load 
resources. However, given the limited experience interconnecting 
electric storage resources and the abundant desire for regional 
flexibility, we are not imposing any standard requirements at this time 
and instead continue to allow transmission providers to model electric

[[Page 21410]]

storage resources in ways that are most appropriate in their respective 
regions. Additionally, in response to Schulte Associates, we are not 
requiring Transmission Providers to model electric storage resources 
serving as transmission assets under the pro forma LGIP and the pro 
forma LGIA at this time. Given the flexibility that we are providing, 
we find that gathering additional information on potential approaches 
for modeling electric storage resources is not necessary at this time, 
but we encourage transmission providers to continue to consider 
approaches to modeling electric storage resources that will save costs 
and improve the efficiency of the interconnection process.

D. Other Issues

1. Whether Proposed Reforms Should Be Applied to Small Generation
a. Comments
    545. In response to the Commission's question in the NOPR,\972\ 
several commenters suggest that new proposals accepted for the LGIP and 
LGIA should also apply to the SGIP and SGIA.\973\ Joint Renewable 
Parties also contend that improved transparency would assist small 
generators in locating their facilities and moving through the 
interconnection process efficiently and cost-effectively.\974\ ESA 
supports extending the proposals regarding interconnection service 
below facility capacity, surplus interconnection service, provisional 
interconnection service, and electric storage modeling to apply to the 
pro forma SGIA and SGIP.\975\ California Energy Storage Alliance also 
suggests that the Commission consider simplified procedures for 
interconnecting distributed electric storage resources that desire to 
participate in wholesale markets, either as a standalone resources or 
as part of an aggregation.\976\ TVA states that the small generator 
interconnection process could benefit from the proposed reforms and 
discussions involving affected system studies and any guidelines for 
modeling and evaluating electric storage resources.\977\
---------------------------------------------------------------------------

    \972\ NOPR, FERC Stats. & Regs. ] 32,719 at P 11.
    \973\ California Energy Storage Alliance 2017 Comments at 11; 
Joint Renewable Parties 2017 Comments at 3; ISO-NE 2017 Comments at 
56.
    \974\ Joint Renewable Parties 2017 Comments at 11.
    \975\ ESA 2017 Comments at 18.
    \976\ California Energy Storage Alliance 2017 Comments at 11-13.
    \977\ TVA 2017 Comments at 19.
---------------------------------------------------------------------------

    546. Others argue that the proposed reforms should not apply to 
small generating facilities.\978\ Duke, for instance, argues that the 
SGIP and SGIA processes are designed to be streamlined and that states 
use the processes as the bases for state small generator 
interconnection processes.\979\ Modesto asserts that, if the Commission 
believes it should make comparable revisions to the SGIP and SGIA, such 
revisions should be subject to appropriate notice and comment 
rulemaking procedures.\980\ Xcel states that if the Commission wishes 
to pursue this possibility, it should initiate a notice of 
inquiry.\981\
---------------------------------------------------------------------------

    \978\ Duke 2017 Comments at 3-4; Modesto 2017 Comments at 22; 
SoCal Edison 2017 Comments at 2; Xcel 2017 Comments at 5; see also 
Imperial 2017 Comments 20-21.
    \979\ Duke 2017 Comments at 3-4.
    \980\ Modesto April 2017 Comments at 22; Xcel 2017 Comments at 
5.
    \981\ Id.
---------------------------------------------------------------------------

    547. PG&E and SoCal Edison ask the Commission to confirm that the 
NOPR does not require changes to PG&E's wholesale distribution access 
tariff and GIPs, which primarily concern SGIAs.\982\ PG&E states that 
the administrative burden and costs of doing so outweighs the 
benefits.\983\ PG&E states that, as explained in section 2.13 of the 
wholesale distribution access tariff, such interconnection facilities 
are considered distribution facilities for purposes of the wholesale 
distribution access tariff.\984\
---------------------------------------------------------------------------

    \982\ PG&E 2017 Comments at 2; SoCal Edison 2017 Comments at 1-
2.
    \983\ PG&E 2017 Comments at 2.
    \984\ Id. (citing Pac. Gas & Elec. Co., 77 FERC ] 61,077 (1996); 
see also SoCal Edison 2017 Comments at 1-2.
---------------------------------------------------------------------------

b. Commission Determination
    548. We decline to make the new requirements from this final action 
applicable to the pro forma SGIP and the pro forma SGIA. Although the 
Commission sought comment on whether any of the proposed reforms should 
be applied to small generating facilities and implemented in the pro 
forma SGIP and pro forma SGIA, the Commission did not make any specific 
proposals as to the pro forma SGIP or pro forma SGIA. We also note that 
the majority of responsive commenters oppose such a change.\985\
---------------------------------------------------------------------------

    \985\ Duke 2017 Comments at 3-4; Modesto 2017 Comments at 22; 
SoCal Edison 2017 Comments at 2; Xcel 2017 Comments at 5; see also 
Imperial 2017 Comments 20-21.
---------------------------------------------------------------------------

    549. In response to the parties that support adopting the final 
action reforms for small generators, we find that, while some of these 
reforms have the potential to aid small generator interconnection, the 
differences between the large and small interconnection processes are 
significant enough to prevent us from acting in this proceeding.
2. Issues Not Raised in the NOPR
a. Comments
    550. Multiple commenters have commented on issues not raised in the 
NOPR. For instance, Joint Renewable Partners argue that the Commission 
has allowed the states to continue to administer Qualifying Facility 
(QF) interconnections where the QF sells the entire net output to the 
interconnecting utility, which has resulted in less favorable 
interconnection practices for QFs.\986\ Additionally, IECA urges the 
Commission to alter the QF minimum export threshold to be based on 
``total energy'' exported to the grid and not on net system capacity 
because the current system discriminates against combined heat and 
power and waste heat recovery facilities in favor of other types of 
facilities.\987\
---------------------------------------------------------------------------

    \986\ Joint Renewable Parties 2017 Comments at 13-15.
    \987\ IECA 2017 Comments at 3.
---------------------------------------------------------------------------

    Forecasting Coalition states that rates for interconnection service 
will decrease, and reliability will increase, if LGIPs require 
transmission providers to consider non-transmission alternatives, 
including dynamic line ratings.\988\ First Solar states that there is 
also significant misalignment in CAISO's deliverability allocation 
procedures where upgrade cost caps deprive generators of the ability to 
deliver a plant's full output, which can prevent interconnection 
customers from competing in solicitations or force them to withdraw 
from the queue.\989\ Invenergy argues that the Commission should update 
pro forma LGIA article 5.17 to incorporate recent changes in the 
Internal Revenue Service safe harbor rules.\990\ CAISO, Xcel, and 
Southern express views that the Commission move away from a first-come, 
first-served standard to a first-ready, first-served standard.\991\
---------------------------------------------------------------------------

    \988\ Forecasting Coalition 2017 Comments at 1.
    \989\ First Solar 2017 Comments at 1.
    \990\ Invenergy 2017 comments at 16.
    \991\ CAISO 2017 Comments at 38-39; Xcel 2017 Comments at 6-7; 
Southern 2017 Comments at 6.
---------------------------------------------------------------------------

b. Commission Determination
    551. We consider the comments summarized in the above section to be 
outside the scope of this proceeding. The NOPR proposed a number of 
specific reforms, to which commenters have reacted. The comments 
discussed in the above section have raised issues unrelated to the 
NOPR's proposed reforms. Even if we were inclined to agree with the 
proposals made in these comments, we would not adopt them

[[Page 21411]]

here given the inadequacy of the record on such proposals.
3. Process Considerations
a. Comments
    552. Duke recommends that any new information required to be posted 
on OASIS be permitted to be posted without requiring new templates to 
be created through the NAESB process.\992\ OATI states that if the 
final action requires new informational postings by transmission 
providers, the Commission should direct the nature and standards for 
those postings to NAESB.\993\ OATI states that access to any additional 
postings made on a transmission provider's OASIS site requires secure 
and controlled access. OATI asks the Commission to assess the impact of 
new information on OASIS to decide if OASIS is the appropriate location 
for additional information and, if so, determine how currently 
available information on OASIS is accessed, and what would be necessary 
to post additional information.\994\
---------------------------------------------------------------------------

    \992\ Duke 2017 Comments at 28.
    \993\ OATI 2017 Comments at 1-2.
    \994\ Id. at 7.
---------------------------------------------------------------------------

b. Commission Determination
    553. We decline to specifically require that transmission providers 
work through NAESB for the development of templates or standards for 
any OASIS postings they make in compliance with this final action. 
Transmission providers may coordinate as they determine appropriate to 
implement the Commission's requirements and to develop relevant posting 
protocols. Additionally, we note that, in this final action, we adopt 
OASIS requirements for the ``Transparency Regarding Study Models and 
Assumptions'' and ``Interconnection Study Deadlines'' sections. 
Additionally, in the ``Transparency Regarding Study Models and 
Assumptions'' and ``Interconnection Study Deadlines'' adopted 
requirements, we allow transmission providers to only include a link on 
OASIS to the information required if it is posted on the transmission 
provider's website.
4. Compliance and Implementation
a. Comments
    554. EEI, Duke, ITC, MISO TOs, and Xcel request that the Commission 
allow 180 days for compliance with any final action.\995\ Duke and ITC 
also request a date of one year after the final action for 
implementation of the revised OATTs included in the compliance 
filings.\996\
---------------------------------------------------------------------------

    \995\ EEI 2017 Comments at 77; Duke 2017 Comments at 28; ITC 
2017 Comments at 21; MISO TOs 2017 Comments at 44; Xcel 2017 
Comments at 23.
    \996\ Duke 2017 Comments at 28; ITC 2017 Comments at 21.
---------------------------------------------------------------------------

b. Commission Determination
    555. Section 35.28(f)(1) of the Commission's regulations requires 
every public utility with a non-discriminatory OATT on file to also 
have on file the pro forma LGIP and pro forma LGIA ``required by 
Commission rulemaking proceedings promulgating and amending'' such 
agreements. Despite the comments described above, we see no reason to 
delay the effective date or extend the compliance deadline of this 
final action. Therefore, the Commission is requiring all public utility 
transmission providers to submit compliance filings to adopt the 
requirements of this final action as revisions to the LGIP and LGIA in 
their OATTs no later than 90 days after the issuance of this final 
action in the Federal Register.\997\
---------------------------------------------------------------------------

    \997\ NOPR, FERC Stats. & Regs. ] 32,719 at P 231.
---------------------------------------------------------------------------

    556. Some public utility transmission providers may have provisions 
in their existing LGIPs or LGIAs subject to the Commission's 
jurisdiction that the Commission has deemed to be consistent with or 
superior to the pro forma LGIP or pro forma LGIA or permissible under 
the independent entity variation standard or regional reliability 
standard.\998\ Where these provisions are modified by this final 
action, public utility transmission providers must either comply with 
this final action or demonstrate that these previously-approved 
variations continue to be consistent with or superior to the pro forma 
LGIP and pro forma LGIA as modified by this final action or continue to 
be permissible under the independent entity variation standard or 
regional reliability standard.\999\ We also find that transmission 
providers that are not public utilities must adopt the requirements of 
this final action as a condition of maintaining the status of their 
safe harbor tariff or otherwise satisfying the reciprocity requirement 
of Order No. 888.\1000\
---------------------------------------------------------------------------

    \998\ See Order No. 792, 145 FERC ] 61,159 at P 270.
    \999\ See 18 CFR 35.28(f)(1)(i) (2017).
    \1000\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------

V. Information Collection Statement

    557. The collection of information contained in this final action 
is being submitted to the Office of Management and Budget (OMB) for 
review under section 3507(d) of the Paperwork Reduction Act of 
1995.\1001\ OMB's regulations,\1002\ in turn, require approval of 
certain information collection requirements imposed by agency rules. 
Upon approval of a collection(s) of information, OMB will assign an OMB 
control number and an expiration date. Respondents subject to the 
filing requirements of a 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.
---------------------------------------------------------------------------

    \1001\ See 44 U.S.C. 3507(d) (2012).
    \1002\ 5 CFR part 1320 (2017).
---------------------------------------------------------------------------

    558. The reforms adopted in this final action revise the 
Commission's pro forma LGIP and pro forma LGIA. This final action 
requires each public utility transmission provider to amend its LGIP 
and LGIA to: (1) Remove the limitation that interconnection customers 
may only exercise the option to build transmission provider's 
interconnection facilities and stand alone network upgrades in 
instances when the transmission owner cannot meet the dates proposed by 
the interconnection customer; (2) require that transmission providers 
establish interconnection dispute resolution procedures that would 
allow a disputing party to unilaterally seek non-binding dispute 
resolution; (3) require transmission providers to outline and make 
public a method for determining contingent facilities; (4) require 
transmission providers to list the specific study processes and 
assumptions for forming the network models used for interconnection 
studies; (5) revise the definition of ``Generating Facility'' to 
explicitly include electric storage resources; (6) establish reporting 
requirements for aggregate interconnection study performance; (7) allow 
interconnection customers to request a level of interconnection service 
that is lower than their generating facility capacity; (8) require 
transmission providers to allow for provisional interconnection 
agreements that provide for limited operation prior to completion of 
the full interconnection process; (9) require transmission providers to 
create a process for interconnection customers to use surplus 
interconnection service at existing points of interconnection; and (10) 
require transmission providers to set forth a procedure to allow 
transmission providers to assess and, if necessary, study an 
interconnection customer's technology changes without affecting the 
interconnection customer's queued position. The reforms adopted in this 
final action require revised filings of LGIPs and LGIAs with the

[[Page 21412]]

Commission. The Commission anticipates the revisions required by this 
final action, once implemented, will not significantly change currently 
existing burdens on an ongoing basis. With regard to those public 
utility transmission providers that believe they already comply with 
the revisions adopted in this final action, they can demonstrate their 
compliance in the filing required 90 days after the issuance of this 
final action in the Federal Register. The Commission will submit the 
proposed reporting requirements to OMB for its review and approval 
under section 3507(d) of the Paperwork Reduction Act.\1003\
---------------------------------------------------------------------------

    \1003\ 44 U.S.C. 3507(d) (2012).
---------------------------------------------------------------------------

    559. While the Commission expects the revisions adopted in this 
final action will provide significant benefits, the Commission 
understands that implementation can be a complex and costly endeavor. 
The Commission solicited comments on the accuracy of the provided 
burden and cost estimates and any suggest methods for minimizing the 
respondents' burdens. The Commission did not receive any comments 
concerning its burden or cost estimates. However, the Commission has 
made changes to its NOPR proposals that are adopted in this final 
action. First, the Commission has withdrawn the proposals regarding 
scheduled periodic restudies, self-funding by the transmission owner, 
and modeling of electric storage resources. Second, the Commission has 
modified the dispute resolution requirements so that they will apply 
both inside and outside RTOs/ISOs. Therefore, we have adjusted the 
burden estimate accordingly.
    Burden Estimate and Information Collection Costs: The Commission 
believes that the burden estimates below are representative of the 
average burden on respondents. The estimated burden and cost \1004\ for 
the requirements contained in this final action follow.
---------------------------------------------------------------------------

    \1004\ The estimated hourly cost (salary plus benefits) provided 
in this section is based on the salary figures for May 2016 posted 
by the Bureau of Labor Statistics for the Utilities sector 
(available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000) 
and scaled to reflect benefits using the relative importance of 
employer costs in employee compensation from June 2016 (available at 
https://www.bls.gov/oes/current/naics2_22.htm). The hourly estimates 
for salary plus benefits are:
    Auditing and accounting (code 13-2011), $53.00.
    Computer and Information Systems Manager (code 11-3021), 
$100.68.
    Computer and mathematical (code 15-0000), $60.70.
    Economist (code 19-3011), $77.96.
    Electrical Engineer (code 17-2071), $68.12.
    Information and record clerk (code 43-4199), $39.14.
    Information Security Analyst (code 15-1122), $66.34.
    Legal (code 23-0000), $143.68.
    Management (code 11-0000), $81.52.
    The average hourly cost (salary plus benefits), weighting all of 
these skill sets evenly, is $76.79. The Commission rounds it to $77 
per hour.

                                                    FERC 516F
----------------------------------------------------------------------------------------------------------------
                                Number of                                                          Total annual
                                applicable  Annual number of   Total number of   Average burden   burden hours &
                                registered    responses per       responses     (hours) & costs    total annual
                                 entities      respondent                         per response         cost
                                       (1)  (2).............  (1) * (2) = (3).  (4)............  (3) * (4) = (5)
----------------------------------------------------------------------------------------------------------------
Issue A1--Scheduled periodic           126  N/A.............  N/A.............  N/A............  N/A.
 restudies \1005\.                       6  N/A.............  N/A.............  N/A............  N/A.
Issue A2--Interconnection              126  1 (Year 1); 0     126 (Year 1); 0   4 hrs. (Year     504 hrs. (Year
 customer's option to build                  (Ongoing)         (Ongoing).        1); $308.        1); $38,808.
 (Non-RTO/ISO).                              \1006\.                            0 hrs.           0 hrs.
                                                                                 (Ongoing); $0.   (Ongoing); $0.
Issue A2--Interconnection                6  1 (Year 1); 0     6 (Year 1); 0     4 hrs. (Year     24 hrs. (Year
 customer's option to build                  (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
 (RTO/ISO).                                                                     0 hrs.           0 (Ongoing); $0
                                                                                 (Ongoing); $0.
Issue A3--Self-funding by the          126  N/A.............  N/A.............  N/A............  N/A.
 transmission owner \1007\
 (Non-RTO/ISO).
Issue A3--Self-funding by the            6  N/A.............  N/A.............  N/A............  N/A.
 transmission owner (RTO/ISO).
Issue A4--RTO/ISO dispute              126  1 (Year 1); 0     126 (Year 1); 0   4 hrs. (Year     504 hrs. (Year
 resolution (Non-RTO/ISO).                   (Ongoing).        (Ongoing).        1); $308.        1); $38,808.
                                                                                0 hrs.           0 hrs.
                                                                                 (Ongoing).       (Ongoing); $0.
Issue A4--RTO/ISO dispute                6  1 (Year 1); 0     6 (Year 1); 0     4 hrs. (Year     24 hrs. (Year
 resolution (RTO/ISO).                       (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
                                                                                0 hrs.           0 (Ongoing) $0.
                                                                                 (Ongoing).
Issue A5--Capping costs for            126  N/A.............  N/A.............  N/A............  N/A.
 network upgrades \1008\ (Non-
 RTO/ISO).
Issue A5--Capping costs for              6  N/A.............  N/A.............  N/A............  N/A.
 network upgrades (RTO/ISO).
Issue B1--Identification and           126  1 (Year 1); 0     126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 definition of contingent                    (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 facilities (Non-RTO/ISO).                                                      0 hrs.;           $776,160.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue B1--Identification and             6  1 (Year 1); 0     6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 definition of contingent                    (Ongoing).        (Ongoing).        1); $6,160.      1);
 facilities (RTO/ISO).                                                          0 hrs.;          $36,960.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue B2--Transparency in the          126  1 (Year 1); 0     126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 interconnection process (Non-               (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 RTO/ISO).                                                                      0 hrs.;           $776,160.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue B2--Transparency in the            6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 interconnection process (RTO/               (Ongoing).        (Ongoing).        1); $6,160.      1);
 ISO).                                                                          0 hrs.;          $36,960.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue B3--Curtailment                  126  N/A.............  N/A.............  N/A............  N/A.
 concerns (Non-RTO/ISO).
Issue B3--Curtailment                    6  N/A.............  N/A.............  N/A............  N/A.
 concerns (RTO/ISO).
Issue B4--Definition of                126  1 (Year 1); 0     126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 generating facility (non-RTO/               (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 ISO).                                                                          0 hrs.;           $776,160.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue B4--Definition of                  6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 generating facility (RTO/                   (Ongoing).        (Ongoing).        1); $6,160.      1);
 ISO).                                                                          0 hrs.;          $36,960.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.

[[Page 21413]]

 
Issue B5--Interconnection              126  1 (Year 1); 4     126 (Year 1);     4 hrs. (Year     504 hrs. (Year
 study deadlines (non-RTO/                   (Ongoing).        504 (Ongoing).    1); $308.        1); $38,808.
 ISO).                                                                          4 hrs.           2,016 hrs.
                                                                                 (Ongoing) $308.  (Ongoing);
                                                                                                  $155,232.
Issue B5--Interconnection                6  1 (Year 1) 4      6 (Year 1); 24    4 hrs. (Year     24 hrs. (Year
 study deadlines (RTO/ISO).                  (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
                                                                                4 hrs.           96 hrs.
                                                                                 (Ongoing);       (Ongoing);
                                                                                 $308.            7,392.
Issue B6--Improving                    126  N/A.............  N/A.............  N/A............  N/A.
 Coordination of Affected
 Systems \1009\ (non-RTO/ISO).
Issue B6--Improving                      6  N/A.............  N/A.............  N/A............  N/A.
 Coordination of Affected
 Systems (RTO/ISO).
Issue C1--Requesting                   126  1 (Year 1) 0      126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 interconnection service                     (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 below generating facility                                                      0 hrs.;           $776,160.
 capacity (Non-RTO/ISO).                                                         (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue C1--Requesting                     6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 interconnection service                     (Ongoing).        (Ongoing).        1); $6,160.      1);
 below generating facility                                                      0 hrs.;          $36,960.
 capacity (RTO/ISO).                                                             (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue C2--Provisional                  126  1 (Year 1) 0      126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 agreements (non-RTO/ISO).                   (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
                                                                                0 hrs.;           $776,160.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue C2--Provisional                    6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 agreements (RTO/ISO).                       (Ongoing).        (Ongoing).        1); $6,160.      1);
                                                                                0 hrs.;          $36,960.
                                                                                 (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue C3--Utilization of               126  1 (Year 1) 0      126 (Year 1); 0   4 hrs. (Year     504 hrs. (Year
 surplus interconnection                     (Ongoing).        (Ongoing).        1); $308.        1); $38,808.
 service (non-RTO/ISO).                                                         0 hrs.           0 hrs.
                                                                                 (Ongoing) $0.    (Ongoing); $0.
Issue C3--Utilization of                 6  1 (Year 1) 0      6 (Year 1); 0     4 hrs. (Year     24 hrs. (Year
 surplus interconnection                     (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
 service (RTO/ISO).                                                             0 hrs.           0 (Ongoing) $0.
                                                                                 (Ongoing) $0.
Issue C4--Material                     126  1 (Year 1) 0      126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 modification and                            (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 incorporation of advanced                                                      0 hrs.;           $776,160.
 technologies (non-RTO/ISO).                                                     (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue C4--Material                       6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 modification and                            (Ongoing).        (Ongoing).        1); $6,160.      1);
 incorporation of advanced                                                      0 hrs.;          $36,960.
 technologies (RTO/ISO).                                                         (Ongoing); $0.  0 hrs.
                                                                                                  (Ongoing); $0.
Issue C5--Modeling of                  126  N/A.............  N/A.............  N/A............  N/A.
 electric storage resources
 \1010\ (non-RTO/ISO).
Issue C5--Modeling of                    6  N/A.............  N/A.............  N/A............  N/A.
 electric storage resources
 (RTO/ISO).
----------------------------------------------------------------------------------------------------------------
    Total....................       Non-RTO/ISO, Year 1       1,260...........  62,244 hrs.; $4,792,788
                                    Non-RTO/ISO, Ongoing      504.............  2,016 hrs.; $155,232
                                      RTO/ISO, Year 1         60..............  2,976 hrs.; $229,152
                                      RTO/ISO, Ongoing        24..............  96 hrs.; $7,392
----------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the cost of compliance 
as follows:
---------------------------------------------------------------------------

    \1005\ There are no estimates for this section, because the 
Commission has withdrawn the NOPR proposal.
    \1006\ Ongoing refers to Year 2 and ongoing.
    \1007\ There are no estimates for this section, because the 
Commission has withdrawn the NOPR proposal.
    \1008\ There are no estimates for this issue, because the NOPR 
did not propose, and the final action did adopt, any requirements 
for this issue.
    \1009\ There are no estimates for this issue, because the NOPR 
did not propose, and the final action did adopt, any requirements 
for this issue.
    \1010\ There are no estimates for this section, because the 
Commission has withdrawn the NOPR proposal.

 Year 1: $5,021,940
 Ongoing: $162,624

    Year 1 costs reflect costs to comply with the final action. Year 2 
represents ongoing costs that the transmission provider will face on an 
ongoing basis to fulfill the directives of this final action. The 
reforms adopted in this final action, once implemented, would not 
significantly change existing burdens on an ongoing basis.
    The one-time burden of 65,220 hours will be averaged over three 
years (65,220 / 3 = 21,740 hours/year over three years).
    The ongoing burden of 2,112 hours applies to only Year 2 and 
beyond.
    The number of responses is also averaged over three years (1,320 
responses (one-time) + 528 responses (Year 2) + 528 responses (Year 3)) 
/ 3 = 792 responses/year.
    The responses and burden for Years 1-3 will total respectively as 
follows:
    Year 1: 792 responses; 21,740 hours.
    Year 2: 792 responses; 21,740 hours + 2,112 hours + 2,112 hours = 
25,964 hours.
    Year 3: 792 responses; 21,740 hours + 2,112 hours + 2,112 hours = 
25,964 hours.
    Title: FERC-516F, Electric Rate Schedules and Tariff Filings.
    Action: Proposed information collection.
    OMB Control No.: TBD.
    Respondents for Proposal: Businesses or other for profit and/or 
not-for-profit institutions.
    Frequency of Information: One-time during Year 1. Multiple times 
during subsequent years.
    Necessity of Information: The Commission issues this final action 
to address interconnection practices that may be resulting in unjust 
and unreasonable or unduly discriminatory or preferential rates, terms, 
and conditions. The reforms are designed to improve certainty in the 
interconnection process, to promote more informed

[[Page 21414]]

interconnection decisions by interconnection customers, and to enhance 
interconnection processes.
    Internal Review: The Commission has reviewed the proposed changes 
and has determined that such changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has specific, objective support for the burden estimates 
associated with the information collection requirements.
    560. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen 
Brown, Office of the Executive Director], email: 
[email protected], phone: (202) 502-8663, fax: (202) 273-0873.
    561. Comments concerning the collection of information and the 
associated burden estimate(s) in the final action should be sent to the 
Commission in this docket and may also be sent to the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street NW, Washington, DC 20503 [Attention: Desk Officer for 
the Federal Energy Regulatory Commission].
    562. Due to security concerns, comments should be sent 
electronically to the following email address: 
[email protected]. Comments submitted to OMB should refer to 
FERC-516F and OMB Control No. to be determined.

VI. Environmental Analysis

    563. 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.\1011\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this final action 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.\1012\
---------------------------------------------------------------------------

    \1011\ Regulation Implementing National Environmental Policy Act 
of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \1012\ 18 CFR 380.4(a)(15) (2017).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    564. The Regulatory Flexibility Act of 1980 (RFA) \1013\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. The RFA 
mandates consideration of regulatory alternatives that accomplish the 
stated objectives of a rule and that minimize any significant economic 
impact on a substantial number of small entities. The Small Business 
Administration's (SBA) Office of Size Standards develops the numerical 
definition of a small business.\1014\ The small business size standards 
are provided in 13 CFR 121.201.
---------------------------------------------------------------------------

    \1013\ 5 U.S.C. 601-12 (2012).
    \1014\ 13 CFR 121.101 (2017) Sector 22 (Utilities), NAICS code 
22121 (Electric Power Transmission and Control).
---------------------------------------------------------------------------

    565. The Commission estimates that the total number of public 
utility transmission providers that would have to modify the LGIPs and 
LGIAs within their currently effective OATTs is 132. Of these, the 
Commission estimates that approximately 43 percent are small entities 
(approximately 57 entities). The Commission estimates the average total 
cost to each of these entities will require on average 494 hours or 
$38,045 in Year 1,\1015\ and 16 hours or $1,232 in subsequent 
years.\1016\ 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.'' \1017\ The Commission does not 
consider the estimated burden to be a significant economic impact. As a 
result, the Commission certifies that the revisions adopted in this 
final action will not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \1015\ 65,220 hours / 132 = 494 hours/respondent; $5,021,940 / 
132 = $38,045/respondent.
    \1016\ 2,112 hours / 132 = 16 hours/respondent; $162,624 / 132 = 
$1,232/respondent.
    \1017\ U.S. Small Business Administration, A Guide for 
Government Agencies: How to Comply with the Regulatory Flexibility 
Act, at 18 (August 2017), https://www.sba.gov/sites/default/files/advocacy/How-to-Comply-with-the-RFA-WEB.pdf.
---------------------------------------------------------------------------

VIII. Document Availability

    566. 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 Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE, Room 2A, 
Washington, DC 20426.
    567. 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 of this document, excluding the last three digits, in 
the docket number field.
    568. 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

    569. The final action is effective July 23, 2018. The Commission 
has determined with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB that this action is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. This final action is being 
submitted to the U.S. Senate, the U.S. House of Representatives, and 
the U.S. Government Accountability Office.

List of Subjects in 18 CFR Part 37

    Conflicts of interest, Electric power plants, Electric utilities, 
Reporting and recordkeeping requirements.

    By the Commission.

    Issued: April 19, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2018-08659 Filed 5-8-18; 8:45 am]
 BILLING CODE 6717-01-P