Document ID: FERC-2021-0909-0001
Agency: ferc
Document Type: Proposed Rule
Title: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection
Posted Date: 2021-07-27T04:00Z

[Federal Register Volume 86, Number 141 (Tuesday, July 27, 2021)]
[Proposed Rules]
[Pages 40266-40298]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-15512]

[[Page 40265]]

Vol. 86

Tuesday,

No. 141

July 27, 2021

Part III

Department of Energy

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Federal Energy Regulatory Commission

18 CFR Part 35

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Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation and Generator Interconnection; Proposed Rule

  Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / 
Proposed Rules  

[[Page 40266]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM21-17-000]

Building for the Future Through Electric Regional Transmission 
Planning and Cost Allocation and Generator Interconnection

AGENCY: Federal Energy Regulatory Commission.

ACTION: Advance notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
issuing an Advance Notice of Proposed Rulemaking (ANOPR) presenting 
potential reforms to improve the electric regional transmission 
planning and cost allocation and generator interconnection processes. 
The Commission invites all interested persons to submit comments on the 
potential reforms and in response to specific questions.

DATES: Comments are due October 12, 2021 and Reply Comments are due 
November 9, 2021.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways. Electronic filing through https://www.ferc.gov, is 
preferred.
     Electronic Filing: Documents must be filed in acceptable 
native applications and print-to-PDF, but not in scanned or picture 
format.
     For those unable to file electronically, comments may be 
filed by U.S. Postal Service mail or by hand (including courier) 
delivery.
    [cir] Mail via U.S. Postal Service only: Addressed to: Federal 
Energy Regulatory Commission, Office of the Secretary, 888 First Street 
NE, Washington, DC 20426.
    [cir] For delivery via any other carrier (including courier): 
Deliver to: Federal Energy Regulatory Commission, Office of the 
Secretary, 12225 Wilkins Avenue, Rockville, MD 20852.
    The Comment Procedures Section of this document contains more 
detailed filing procedures.

FOR FURTHER INFORMATION CONTACT: 
David Borden (Technical Information), Office of Energy Policy and 
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734, 
david.borden@ferc.gov
Christopher Gore (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8507, 
christopher.gore@ferc.gov.
Lina Naik (Legal Information), Office of the General Counsel, 888 First 
Street NE, Washington, DC 20426, (202) 502-8882, lina.naik@ferc.gov

SUPPLEMENTARY INFORMATION:

Table of Contents

 
                                                         Paragraph Nos.
 
I. Introduction.......................................                 1
II. Background........................................                 6
    A. Regional Transmission Planning and Cost                         6
     Allocation Process...............................
        1. Regional Transmission Planning Requirements                 8
        2. Nonincumbent Transmission Developer Reforms                 9
        3. Regional Transmission Cost Allocation......                11
        4. Interregional Transmission Coordination....                12
    B. Overview of Transmission Planning..............                13
        1. Reliability Needs..........................                14
        2. Economic Needs.............................                15
        3. Public Policy Requirement Needs............                16
        4. Local Transmission Facilities in the                       17
         Regional Transmission Planning Process.......
    C. Overview of Generator Interconnection..........                18
    D. Interaction Between the Regional Transmission                  23
     Planning and Cost Allocation and Generator
     Interconnection Processes........................
    E. Current Funding Paradigm.......................                24
        1. Regional Transmission Cost Allocation......                24
        2. Local Transmission Facilities..............                25
        3. Interconnection-Related Network Upgrades...                28
III. The Potential Need for Reform....................                30
    A. The Existing Regional Transmission Planning and                30
     Cost Allocation and Generator Interconnection
     Processes May Be Inadequate To Ensure Just and
     Reasonable Rates.................................
        1. Considering Anticipated Future Generation..                31
        2. Results of Existing Local and Regional                     37
         Transmission Planning Processes..............
        3. Cost Responsibility for Transmission                       38
         Facilities and Interconnection-Related
         Network Upgrades.............................
IV. Consideration of Potential Reforms and Request for                44
 Comment..............................................
    A. Regional Transmission Planning and Cost                        44
     Allocation Processes.............................
        1. Potential Reforms and Request for Comment..                44
            a. Planning for the Transmission Needs of                 44
             Anticipated Future Generation............
            i. Future Scenarios and Modeling                          46
             Anticipated Future Generation............
            ii. Identifying Geographic Zones That Have                54
             Potential for High Amounts of Renewable
             Resource Development to Meet Increased
             Demand...................................
            iii. Incentivizing Regional Transmission                  61
             Facilities...............................
            iv. Enhanced Interregional or State-to-                   62
             State Coordination.......................
            b. Coordinating Between the Regional                      65
             Transmission Planning and Cost Allocation
             and Generator Interconnection Processes..
    B. Identification of Cost and Responsibility for                  69
     Regional Transmission Facilities and
     Interconnection-Related Network Upgrades.........
        1. Relevant Cost Causation Precedent..........                74
        2. Cost Allocation for Transmission Facilities                75
         Planned through the Regional Transmission
         Planning Process.............................
            a. Background.............................                76
            b. Potential Need for Reform..............                83
            c. Potential Reforms and Request for                      90
             Comment..................................
        3. Participant Funding and Crediting Policy                  100
         for Funding Interconnection-Related Network
         Upgrades.....................................
            a. Background.............................               101
            i. Original Rationale for the Order No.                  101
             2003 Interconnection-Related Network
             Upgrade Funding Requirements.............
            (a) Crediting Policy......................               102
            (b) Participant Funding...................               105
            b. Potential Need for Reform..............               111
            i. Participant Funding....................               111
            ii. Crediting Policy......................               120
            c. Potential Reforms and Request for                     121
             Comment..................................
            i. Eliminate Participant Funding for                     123
             Interconnection-Related Network Upgrades.
            ii. Revisions to the Existing Crediting                  131
             Policy...................................

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            (a) Transmission Providers Provide Upfront               132
             Funding for All Interconnection-Related
             Network Upgrades.........................
            (b) Interconnection Customers Contribute                 135
             to the Upfront Funding of Interconnection-
             Related Network Upgrades Through a Fee...
            (c) Transmission Providers Provide Upfront               139
             Funding for Only Higher Voltage
             Interconnection-Related Network Upgrades.
            (d) Allocate the Upfront Cost of                         146
             Interconnection-Related Network Upgrades
             on a Percentage Basis....................
            iii. Additional Considerations............               150
            (a) Interconnection-Related Network                      150
             Upgrade Cost Sharing.....................
            (b) Option To Build.......................               151
            (c) Interconnection Request Limit.........               153
            (d) Fast-Track for Interconnection of                    154
             Generating Facilities Committed to
             Regional Transmission Facilities.........
            (e) Fast-Track for Interconnection of                    157
             ``Ready'' Generating Facilities..........
            (f) Grid-Enhancing Technologies...........               158
        C. Enhanced Transmission Oversight............               159
        1. Potential Need for Reform..................               160
        2. Potential Reforms and Request for Comment..               163
            a. State Oversight........................               176
            b. Limitation on Recovery of Costs for                   178
             Abandoned Projects.......................
            c. Additional Oversight Approaches........               180
    D. Transition.....................................               181
V. Comment Procedures.................................               183
VI. Document Availability.............................               186
 

I. Introduction

    1. Pursuant to its authority under section 206 of the Federal Power 
Act (FPA),\1\ the Federal Energy Regulatory Commission (Commission) is 
considering the potential need for reforms or revisions to existing 
regulations to improve the electric regional transmission planning and 
cost allocation and generator interconnection processes.
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    \1\ 16 U.S.C. 824e. Section 206 requires that transmission rates 
be just and reasonable, and not unduly discriminatory or 
preferential.
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    2. Approximately 10 years ago, the Commission issued Order No. 
1000.\2\ That order stated its purpose generally in its introduction:
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    \2\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ] 
61,051 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 61,132, 
order on reh'g and clarification, Order No. 1000-B, 141 FERC ] 
61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 
F.3d 41 (D.C. Cir. 2014).

    The reforms herein are intended to improve transmission planning 
processes and cost allocation mechanisms under the pro forma Open 
Access Transmission Tariff (OATT) to ensure that the rates, terms 
and conditions of service provided by public utility transmission 
providers are just and reasonable and not unduly discriminatory or 
preferential. This Final Rule builds on Order No. 890,\3\ in which 
the Commission, among other things, reformed the pro forma OATT to 
require each public utility transmission provider to have a 
coordinated, open, and transparent regional transmission planning 
process. After careful review of the voluminous record in this 
proceeding, the Commission concludes that the additional reforms 
adopted herein are necessary at this time to ensure that rates for 
Commission-jurisdictional service are just and reasonable in light 
of changing conditions in the industry. In addition, the Commission 
believes that these reforms address opportunities for undue 
discrimination by public utility transmission providers.\4\
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    \3\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, 118 FERC ] 61,119, order on 
reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on reh'g, 
Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g, Order No. 
890-C, 126 FERC ] 61,228, order on clarification, Order No. 890-D, 
129 FERC ] 61,126 (2009).
    \4\ Order No. 1000, 136 FERC ] 61,051 at P 1.

    3. More than a decade after Order No. 1000, we believe it 
appropriate to review the issues addressed by that order and other 
transmission-related regulations and determine whether additional 
reforms to the regional transmission planning and cost allocation and 
generator interconnection processes or revisions to existing 
regulations are needed to ensure rates for Commission-jurisdictional 
service remain just and reasonable, and not unduly discriminatory or 
preferential. The electricity sector is transforming as the generation 
fleet shifts from resources located close to population centers toward 
resources, including renewables, that may often be located far from 
load centers. The growth of new resources seeking to interconnect to 
the transmission system and the differing characteristics of those 
resources are creating new demands on the transmission system. Ensuring 
just and reasonable rates as the resource mix changes, while 
maintaining grid reliability, remains the priority in the regional 
transmission planning and cost allocation and generator interconnection 
processes.
    4. In light of these evolving conditions, we believe it timely and 
appropriate to consider whether there should be changes in the regional 
transmission planning and cost allocation and generator interconnection 
processes and, if so, which changes are necessary to ensure that 
transmission rates remain just and reasonable and not unduly 
discriminatory or preferential and that reliability is maintained.\5\ 
Accordingly, we will consider herein whether and which reforms and 
revisions are necessary to the Commission's regulations on these 
topics. This Advanced Notice of Proposed Rulemaking (ANOPR) discusses 
proposals or concepts for changes to existing processes in several 
broad categories: Regional transmission planning, regional cost 
allocation, generator interconnection funding, generator 
interconnection queueing processes and consumer protection, and in 
several instances the ANOPR also offers a potential rationale or 
argument for potential proposals. We note that the Commission has not 
predetermined that any specific proposal discussed herein shall or 
should be made or in what final form; rather, we seek comment from the 
public on these proposals and welcome commenters to offer additional or 
alternative proposals for consideration.
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    \5\ 16 U.S.C. 824e.
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    5. We believe it appropriate to review whether there are questions 
that should be explored and possible solutions proposed regarding any 
potential shortcomings in the existing regional transmission planning 
and cost allocation and generator interconnection processes, which may 
have become evident since the Commission issued Order No. 2003,\6\ 
Order No. 890, and Order No. 1000. We seek comment on several topics 
across transmission planning and cost allocation and interconnection 
queue processes, as well as oversight of transmission infrastructure 
development. Examples

[[Page 40268]]

of such questions for which we will seek comment in this ANOPR include, 
among others: (1) Whether the existing regional transmission planning 
and cost allocation processes appropriately considers the transmission 
needs of anticipated future generation to drive study assumptions, or 
instead relies on less comprehensive information, such as existing 
interconnection requests with completed facilities studies, and whether 
such current planning criteria are appropriate or should be revised; 
(2) whether the regional transmission planning and cost allocation 
processes' consideration of transmission needs driven by reliability, 
economic considerations, and Public Policy Requirements \7\ are 
inappropriately siloed from one another, and, if so, whether this 
influences the consideration of potential benefits of a regional 
transmission facility (and the associated beneficiaries for purposes of 
allocating the costs of such a facility); \8\ (3) whether criteria in 
addition to those related to reliability, economic, and Public Policy 
Requirements needs should be planned for and considered in the 
evaluation of benefits, and used to determine cost allocation in the 
regional transmission planning process, and these needs should be 
clear, credibly quantifiable and not speculative; (4) how to 
appropriately identify and allocate the costs of new transmission 
infrastructure in a manner that satisfies the Commission's cost-
causation principle that costs are allocated to beneficiaries in a 
manner that is at least roughly commensurate with estimated benefits; 
(5) whether or not it is appropriate for the costs of state or local 
public policy-driven transmission facilities to be shifted through 
regional cost allocation to consumers in non-participating states, or 
whether changes to current interconnection cost allocation mechanisms 
may unjustly and unreasonably shift costs to customers of load serving 
entities; \9\ (6) whether and which reforms are necessary to the 
generator interconnection process to ensure a more purposeful 
integration with the regional transmission planning and cost allocation 
processes, a more efficient queueing process, and a more efficient and 
cost-effective allocation of interconnection costs; (7) whether the 
regional transmission planning and cost allocation processes may have 
resulted in transmission facilities addressing an unduly narrow set of 
transmission needs, including needs located in a single transmission 
owner's footprint, and having limited region-wide benefits, but that, 
collectively, may impose significant costs on customers; (8) whether 
and how to better coordinate between regional and local transmission 
planning processes to identify more efficient or cost-effective 
solutions; and (9) whether it is necessary, and how, to more clearly 
identify the lines of regulatory authority and oversight between states 
and federal authorities with regard to regional and local transmission 
facilities to ensure appropriate vetting of transmission 
infrastructure. In addition, we seek comment regarding whether the 
current approach to oversight of transmission investment adequately 
protects customers, particularly given the potentially significant and 
very costly investments proposed to meet the transmission needs driven 
by a changing resource mix, and, if customers are not adequately 
protected from excessive costs, which potential reforms may be required 
and are legally permissible to ensure just and reasonable rates.
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    \6\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, 104 FERC ] 61,103 (2003), order on 
reh'g, Order No. 2003-A, 106 FERC ] 61,220, order on reh'g, Order 
No. 2003-B, 109 FERC ] 61,287 (2004), order on reh'g, Order No. 
2003-C, 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of 
Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007) (NARUC 
v. FERC).
    \7\ Public Policy Requirements are requirements established by 
local, state, or federal laws or regulations (i.e., enacted statutes 
passed by the legislature and signed by the executive and 
regulations promulgated by a relevant jurisdiction, whether within a 
state or at the federal level). Order No. 1000, 136 FERC ] 61,051 at 
P 2. The Commission clarified that Public Policy Requirements 
established by state or federal laws or regulations include duly 
enacted laws or regulations passed by a local governmental agency, 
such as a municipal or county government. Order No. 1000-A, 139 FERC 
] 61,132 at P 319. Order No. 1000 left planning and cost allocation 
for Public Policy Requirements largely to the discretion of 
transmission providers. See also infra P 16.
    \8\ A regional transmission facility is a transmission facility 
located entirely in one transmission planning region. Order No. 
1000, 136 FERC ] 61,051 at n.374.
    \9\ Under current Commission policy, the costs of 
interconnection-related network upgrades are either (1) directly 
assigned to the interconnection customer or (2) funded initially by 
the interconnection customer and reimbursed through transmission 
service credits.
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II. Background

A. Regional Transmission Planning and Cost Allocation Process

    6. In 1996, the Commission issued Order No. 888 and the 
accompanying pro forma OATT, setting forth certain minimum requirements 
for transmission planning.\10\ In 2007, the Commission issued Order No. 
890 to remedy flaws in the pro forma OATT, and in so doing, required 
coordinated, open, and transparent transmission planning on both a 
local and regional level. Specifically, the Commission required, among 
other things, that each transmission provider's \11\ local transmission 
planning process satisfy nine transmission planning principles: (1) 
Coordination; (2) openness; (3) transparency; (4) information exchange; 
(5) comparability; (6) dispute resolution; (7) regional participation; 
(8) economic planning studies; and (9) cost allocation for new 
projects.\12\
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    \10\ 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) (cross-referenced 
at 75 FERC ] 61,080), order on reh'g, Order No. 888-A, FERC Stats. & 
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on 
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access 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).
    \11\ In this order, we use the term ``transmission provider'' 
when referring to a public utility that owns, controls, or operates 
transmission facilities. The term transmission provider should be 
read to include the transmission owner when the transmission owner 
is separate from the transmission provider, as is the case in 
regional transmission organizations (RTOs) and independent system 
operators (ISOs).
    \12\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
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    7. In 2011, the Commission issued Order No. 1000 to build on the 
transmission planning requirements of Order No. 890. Order No. 1000 
included a package of reforms to ensure that the transmission planning 
and cost allocation mechanisms embodied in the pro forma OATT were 
adequate to support the development of more efficient or cost-effective 
transmission facilities.\13\ The reforms in Order No. 1000 fell into 
the following categories: (1) Regional transmission planning; (2) 
transmission needs driven by Public Policy Requirements; (3) 
nonincumbent transmission developer reforms; (4) regional and 
interregional cost allocation; and (5) interregional transmission 
coordination. Here we provide a brief overview of the Order No. 1000 
regional transmission planning requirements, nonincumbent developer 
reforms, regional transmission cost allocation rules, and interregional 
transmission coordination.
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    \13\ Order No. 1000, 136 FERC ] 61,051 at PP 11-12, 42-44; Order 
No. 1000-A, 139 FERC ] 61,132 at PP 3, 4-6.
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1. Regional Transmission Planning Requirements
    8. Order No. 1000 requires that each transmission provider 
participate in a regional transmission planning process that produces a 
regional transmission plan.\14\ Through the regional transmission 
planning process, transmission providers must evaluate, in consultation 
with stakeholders,

[[Page 40269]]

alternative transmission solutions that might meet the region's 
reliability, economic, and Public Policy Requirements needs \15\ more 
efficiently or cost-effectively than solutions that transmission 
providers identified in their local transmission planning 
processes.\16\ Order No. 1000 also requires that the regional 
transmission planning process satisfy the Order No. 890 transmission 
planning principles.\17\ Therefore, these transmission planning 
principles, which the Commission adopted with respect to local 
transmission planning processes in Order No. 890, also apply to the 
regional transmission planning processes established in Order No. 1000.
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    \14\ Order No. 1000, 136 FERC ] 61,051 at PP 146, 148.
    \15\ Order No. 1000's requirement to consider transmission needs 
driven by Public Policy Requirements is described below.
    \16\ Order No. 1000, 136 FERC ] 61,051 at PP 11, 148.
    \17\ Id. P 151. Order No. 890 explains these transmission 
planning principles.
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2. Nonincumbent Transmission Developer Reforms
    9. Order No. 1000 institutes a number of reforms that seek to 
ensure that nonincumbent transmission developers have an opportunity to 
participate in the regional transmission development process.\18\ In 
particular, Order No. 1000 requires that each transmission provider 
eliminate provisions in Commission-jurisdictional tariffs and 
agreements that establish a federal right of first refusal for an 
incumbent transmission provider with respect to transmission facilities 
selected in a regional transmission plan for purposes of cost 
allocation.\19\ Order No. 1000 defines a transmission facility selected 
in a regional transmission plan for purposes of cost allocation as one 
that has been selected because it is a more efficient or cost-effective 
solution to a regional transmission need.\20\
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    \18\ For purposes of Order No. 1000, ``nonincumbent transmission 
developer'' refers to two categories of transmission developer: (1) 
A transmission developer that does not have a retail distribution 
service territory or footprint; and (2) a transmission provider that 
proposes a transmission facility outside of its existing retail 
distribution service territory or footprint, where it is not the 
incumbent for purposes of that project. Id. P 225.
    \19\ Id. P 313.
    \20\ Id. PP 5, 63.
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    10. In addition, Order No. 1000 requires that each regional 
transmission planning process include not unduly discriminatory 
qualification criteria and information requirements for transmission 
developers that want to propose a transmission facility for selection 
in the regional transmission plan for purposes of cost allocation.\21\ 
The regional transmission planning process must also have a transparent 
and not unduly discriminatory process for evaluating whether to select 
a proposed transmission facility in the regional transmission plan for 
purposes of cost allocation.\22\ Furthermore, the regional transmission 
planning process must provide a nonincumbent transmission developer 
with the same eligibility as an incumbent transmission developer to use 
a cost allocation method(s) for any sponsored transmission facility 
selected in the regional transmission plan for purposes of cost 
allocation.\23\
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    \21\ Id. PP 225, 323, 325.
    \22\ Id. P 328; Order No. 1000-A, 139 FERC ] 61,132 at P 452.
    \23\ Order No. 1000, 136 FERC ] 61,051 at P 332.
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3. Regional Transmission Cost Allocation
    11. Order No. 1000 requires each transmission provider to have in 
place a method, or set of methods, for allocating the costs of new 
regional transmission facilities selected in the regional transmission 
plan for purposes of cost allocation.\24\ Each regional cost allocation 
method must satisfy six regional cost allocation principles,\25\ 
including the principle that the cost of transmission facilities must 
be allocated to those in the transmission planning region that benefit 
from the facilities in a manner that is roughly commensurate with 
estimated benefits.\26\
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    \24\ Id. P 558.
    \25\ Id. P 603.
    \26\ Id. PP 622, 639.
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4. Interregional Transmission Coordination
    12. Order No. 1000 requires each transmission provider, through its 
regional transmission planning process, to establish further procedures 
with each of its neighboring transmission planning regions for the 
purpose of coordinating and sharing the results of respective regional 
transmission plans to identify possible interregional transmission 
facilities that could address transmission needs more efficiently or 
cost-effectively than separate regional transmission facilities. The 
interregional coordination processes must provide for: (1) The sharing 
of information regarding the respective needs of each region and 
potential solutions to those needs; and (2) the identification and 
evaluation of interregional transmission facilities that may be more 
efficient or cost-effective solutions to those regional needs.\27\
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    \27\ Id. P 396.
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B. Overview of Transmission Planning

    13. The next few paragraphs provide an overview of how transmission 
providers plan their systems to meet their reliability, economic, and 
Public Policy Requirements needs, consistent with Order Nos. 890 and 
1000.
1. Reliability Needs
    14. Transmission providers within transmission planning regions 
conduct reliability planning studies to help ensure the ability of the 
transmission system to serve firm transmission use. These studies may 
extend 10 to 15 years into the future depending on the transmission 
planning region's transmission planning process and tests for 
violations of established North American Electric Reliability 
Corporation (NERC) reliability requirements.\28\ Additional regional 
and local reliability criteria may also apply in specific transmission 
planning regions. In order to meet applicable reliability planning 
criteria, the regional transmission planning process focuses on 
studying and producing a transmission system that is robust enough to 
be able to withstand a range of probable contingencies (e.g., the 
sudden loss of a generator or high voltage transmission line) while 
reliably serving customer demand and preventing cascading outages.\29\ 
Generally, transmission providers identify areas not in compliance with 
planning criteria and develop plans to achieve compliance. Transmission 
providers examine facilities to mitigate identified reliability 
criteria violations for their feasibility, impact, and comparative 
costs, culminating in a recommended regional transmission plan.
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    \28\ For example, Reliability Standard TPL-001-4 requires that 
Transmission Planners conduct an annual planning assessment of their 
region's portion of the bulk electric system and document summarized 
results of the steady state analyses, short circuit analyses, and 
stability analyses. TPL-001-4 also requires that Transmission 
Planners conduct these analyses using a model of their systems 
operating under a wide variety of potential conditions to see under 
what, if any, conditions the system will fail to meet reliability 
criteria. TPL-001-4 lays out the variety of these conditions, 
including system peak, off-peak, single contingency, multiple 
contingencies (both sequential and simultaneous), severe 
contingencies on adjacent systems, sensitivity analyses to 
underlying model assumptions, and extreme events.
    \29\ The regional transmission planning process will identify 
the necessary transmission system facilities (which have varying 
costs and lead times for when they can be placed into service) that 
are needed to achieve reliable transmission system operations.
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2. Economic Needs
    15. Transmission providers within transmission planning regions 
also plan transmission facilities to meet economic needs. In Order No. 
1000, the Commission recognized that Order No. 890 placed no 
affirmative obligation on

[[Page 40270]]

transmission providers to perform economic planning studies absent a 
request by stakeholders. To remedy this deficiency, Order No. 1000 
required that, in addition to economic planning studies requested by 
stakeholders, transmission providers evaluate, through a regional 
transmission planning process and in consultation with stakeholders, 
alternative transmission solutions that might meet the needs of the 
transmission planning region more efficiently or cost-effectively than 
solutions identified by individual transmission providers in their 
local transmission planning process. These regional transmission 
solutions could include transmission facilities needed to meet 
reliability requirements, address economic considerations, and/or meet 
transmission needs driven by Public Policy Requirements.\30\ As Order 
No. 890 explains, the purpose of economic transmission planning is to 
plan transmission to alleviate congestion through the integration of 
new generation resources or an expansion of the regional transmission 
system, by an amount that justifies its cost, usually by a defined 
threshold.\31\ However, to implement the requirement in Order No. 1000 
to affirmatively plan for economic needs, transmission providers 
implemented thresholds that vary across the regions. Examples of 
regional transmission facilities driven by economic needs include 
transmission facilities that relieve historical or projected 
transmission congestion and allow lower-cost power to flow to 
consumers.
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    \30\ Order No. 1000, 136 FERC ] 61,051 at PP 147-148.
    \31\ Order No. 890, 118 FERC ] 61,119 at P 549.
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3. Public Policy Requirement Needs
    16. Order No. 1000 requires transmission providers to consider 
transmission needs driven by Public Policy Requirements in their local 
and regional transmission planning processes.\32\ However, the 
requirement in Order No. 1000 to consider transmission needs driven by 
Public Policy Requirements is limited, and the Commission provided 
transmission providers with flexibility in how to meet the requirement. 
For example, Order No. 1000 does not require that a separate class of 
transmission facilities be created in the regional transmission 
planning process to address transmission needs driven by Public Policy 
Requirements,\33\ nor does it mandate the consideration of any 
particular transmission need driven by a Public Policy Requirement.\34\ 
As a result, the process for identifying and considering such needs 
varies from transmission planning region to transmission planning 
region.
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    \32\ Order No. 1000, 136 FERC ] 61,051 at PP 203, 222; Order No. 
1000-A, 139 FERC ] 61,132 at P 208.
    \33\ Order No. 1000, 136 FERC ] 61,051 at P 220 (explaining that 
the Final Rule is intended to ``provide flexibility for public 
utility transmission providers to develop procedures appropriate for 
their local and regional transmission planning processes'').
    \34\ Id. P 215.
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4. Local Transmission Facilities in the Regional Transmission Planning 
Process
    17. Generally, the transmission facilities that transmission 
providers include in their individual local transmission plans are 
incorporated into regional transmission plans as inputs, with minimal 
opportunity for stakeholder review in the regional transmission 
planning process. That is because the analysis of local transmission 
plans in the regional transmission planning process is limited mainly 
to a reliability analysis to ensure that local transmission plans do 
not negatively affect the reliability of the regional transmission 
system.

C. Overview of Generator Interconnection

    18. In Order No. 2003, the Commission recognized a need for a 
single set of interconnection procedures for jurisdictional 
transmission providers and a single, uniformly applicable 
interconnection agreement for large generators.\35\ The Commission 
explained that generator interconnection is a ``critical component of 
open access transmission service and thus is subject to the requirement 
that utilities offer comparable service under the OATT.'' \36\ The 
Commission also determined that, because of the inefficiency of 
addressing generator interconnection issues on a case-by-case 
basis,\37\ it was appropriate to establish a standard set of generator 
interconnection procedures to ``minimize opportunities for undue 
discrimination and expedite the development of new generation, while 
protecting reliability and ensuring that rates are just and 
reasonable.'' \38\ To this end, the Commission adopted the pro forma 
Large Generator Interconnection Procedures (LGIP) and pro forma Large 
Generator Interconnection Agreement (LGIA) \39\ and required that all 
transmission providers' OATTs incorporate the pro forma LGIP and pro 
forma LGIA.
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    \35\ Order No. 2003, 104 FERC ] 61,103 at P 11.
    \36\ Id. P 9 (citing Tenn. Power Co., 90 FERC ] 61,238 (2000)).
    \37\ Id. P 10.
    \38\ Id. P 11.
    \39\ The pro forma LGIP and pro forma LGIA govern large 
generating facilities, which are generating facilities that have a 
generating facility capacity of more than 20 MW.
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    19. In Order No. 2003, the Commission also retained a distinction 
between interconnection facilities, which are located between the 
interconnection customer's generating facility and the transmission 
provider's transmission system, and network upgrades,\40\ which include 
only facilities at or beyond the point where the interconnection 
customer's generating facility interconnects to the transmission 
provider's transmission system.\41\ This distinction is important 
because the determination of which entity is ultimately responsible for 
the cost of a facility can depend on whether that facility is an 
interconnection facility or an interconnection-related network upgrade.
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    \40\ For clarity, this ANOPR will refer to these facilities as 
interconnection-related network upgrades.
    \41\ Id. P 21.
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    20. To initiate the generator interconnection process set forth in 
Order No. 2003,\42\ the interconnection customer submits an 
interconnection request associated with its proposed generating 
facility that includes preliminary site documentation, certain 
technical information about the proposed generating facility, and the 
expected in-service date along with a deposit.\43\ The transmission 
provider uses this information to determine the interconnection 
facilities and interconnection-related network upgrades necessary to 
accommodate the interconnection request and their associated costs.\44\
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    \42\ While we provide a broad description of the generator 
interconnection process under Order No. 2003 as background here, we 
recognize that many transmission providers have adopted (and the 
Commission has accepted) variations to many of the terms in the pro 
forma LGIP and the pro forma LGIA. Consequently, some or many of the 
details of a particular transmission provider's generator 
interconnection process may vary considerably from the broad 
description provided here.
    \43\ Id. P 35.
    \44\ Pro forma LGIP Section 3.1.
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    21. After the transmission provider determines that the 
interconnection request is complete, the interconnection request will 
enter the interconnection queue with other pending requests, and the 
transmission provider will assign the request a queue position based on 
the date and time of receipt. The queue position will determine the 
order in which the transmission provider will perform three phases of 
interconnection studies for the interconnection request. The three 
phases in order are: (1) The feasibility study; (2) the system impact

[[Page 40271]]

study; and (3) the facilities study, all of which are necessary to 
determine the interconnection facilities and interconnection-related 
network upgrades needed to accommodate the interconnection request and 
the interconnection customer's cost responsibility for these 
facilities.\45\
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    \45\ Order No. 2003, 104 FERC ] 61,103 at PP 35-36. The 
interconnection customer is responsible for the costs of 
interconnection studies and any necessary restudies.
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    22. At the completion of the facilities study, the transmission 
provider will issue a report, which includes a ``best estimate of the 
costs to effect the requested interconnection,'' and provide a draft 
generator interconnection agreement to the interconnection 
customer.\46\ If the interconnection customer wishes to proceed, after 
negotiations, the interconnection customer enters into a generator 
interconnection agreement with the transmission provider or requests 
that the transmission provider file the agreement with the Commission 
unexecuted.\47\
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    \46\ Id. P 38.
    \47\ Id.
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D. Interaction Between the Regional Transmission Planning and Cost 
Allocation and Generator Interconnection Processes

    23. The interaction between a transmission provider's current 
generator interconnection process and its regional transmission 
planning and cost allocation processes appears to be limited. The 
primary interaction is that the baseline regional transmission planning 
models generally only incorporate interconnection projects that are 
near the end of the interconnection process and have completed a 
facilities study. In addition, when creating interconnection study 
models, transmission providers incorporate transmission planning 
information into the interconnection base cases, but what information 
is incorporated varies for each transmission provider. The base cases 
for interconnection studies impact the cost assignment for 
interconnection customers, often dramatically, and at present, most 
transmission providers' OATTs do not contain requirements for what 
information is included in base cases.\48\
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    \48\ For example, some transmission providers have details 
regarding what information is included in an interconnection study 
base case in their tariffs, see e.g. Sw. Power Pool, Inc., 172 FERC 
] 61,283, at P10 (2020), while others limit that information to the 
business practices manuals. See, e.g., NYISO Manual 26, Reliability 
Planning Process Manual at 15-16.
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E. Current Funding Paradigm

1. Regional Transmission Cost Allocation
    24. As noted above, Order No. 1000's cost allocation reforms 
require each transmission provider to participate in a regional 
transmission planning process that features a regional cost allocation 
method or methods for allocating the cost of new regional transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation. The Commission also required that such regional cost 
allocation methods satisfy six regional cost allocation principles, 
including the principle that the cost of transmission facilities must 
be allocated to those in the transmission planning region that benefit 
from the facilities in a manner that is roughly commensurate with 
estimated benefits.\49\
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    \49\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 639. The six 
Order No. 1000 regional cost allocation principles are discussed 
further below.
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2. Local Transmission Facilities
    25. In Order No. 1000, the Commission explained that the local 
transmission planning process is the transmission planning process that 
a transmission provider performs for its individual retail distribution 
service territory or footprint pursuant to the requirements of Order 
No. 890.\50\ The outcome of the local transmission planning processes 
are local transmission facilities. In Order No. 1000, the Commission 
defined a local transmission facility as a transmission facility 
located solely within a transmission provider's retail distribution 
service territory or footprint that is not selected in the regional 
transmission plan for purposes of cost allocation.\51\
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    \50\ Id. P 68.
    \51\ Id. P 63.
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    26. The Commission clarified that, if the transmission provider has 
a retail distribution service territory and/or footprint, then only a 
transmission facility that it decides to build within that retail 
distribution service territory or footprint, and that is not selected 
in a regional transmission plan for purposes of cost allocation, may be 
considered a local transmission facility. Further, the Commission 
explained that, in the case of an RTO/ISO whose footprint covers the 
entire region, local transmission facilities are defined by reference 
to the retail distribution service territories or footprints of its 
underlying transmission owing members.\52\ The Commission did not 
require that the transmission facilities in a transmission provider's 
local transmission plan be subject to approval at the regional or 
interregional level, unless that transmission provider seeks to have 
any of those facilities selected in the regional transmission plan for 
purposes of cost allocation.\53\
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    \52\ Order No. 1000-A, 139 FERC ] 61,132 at P 429.
    \53\ Id. P 190.
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    27. Moreover, local transmission facilities planned through a local 
transmission planning process are not eligible to use the Order No. 
1000 regional cost allocation method and instead their costs are 
allocated to the transmission provider in whose retail distribution 
service territory or footprint the local transmission facility is 
located. In support of this, the Commission explained that it continues 
to permit an incumbent transmission provider to meet its reliability 
needs or service obligations by choosing to build new transmission 
facilities that are located solely within its retail distribution 
service territory or footprint as long as the transmission provider 
does not receive regional cost allocation for the facilities.\54\ 
Further, the Commission clarified that nothing in Order No. 1000 
restricts an incumbent transmission provider from developing a local 
transmission solution that is not eligible for regional cost allocation 
to meet its reliability needs or service obligations in its own retail 
distribution service territory or footprint.\55\
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    \54\ Id. PP 366, 379, 425, 428.
    \55\ Order No. 1000, 136 FERC ] 61,051 at P 329.
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3. Interconnection-Related Network Upgrades
    28. The Commission's interconnection pricing policy \56\ allows for 
two general approaches on how to assign the cost of interconnection-
related network upgrades, one of which we refer to as the crediting 
policy and the other as participant funding. We will discuss the 
rationale that the Commission provided when accepting each of the two 
approaches in later sections.
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    \56\ We use the term interconnection pricing policy to refer 
collectively to both Order No. 2003's establishment of the crediting 
policy for financing interconnection-related network upgrades and 
Order No. 2003's allowance of participant funding for 
interconnection-related network upgrades in RTOs/ISOs.
---------------------------------------------------------------------------

    29. In Order No. 2003, the Commission established the crediting 
policy as a requirement of the Commission's interconnection pricing 
policy. Pursuant to the crediting policy, the interconnection customer 
is solely responsible for the costs of interconnection facilities, and 
interconnection-related network upgrades are funded initially by the

[[Page 40272]]

interconnection customer (unless the transmission provider elects to 
fund them) and the transmission provider reimburses the interconnection 
customer through transmission service credits.\57\ The Commission 
reasoned that ``it is appropriate for the Interconnection Customer to 
pay initially the full cost of Interconnection Facilities and 
[interconnection-related] Network Upgrades that would not be needed but 
for the interconnection.'' \58\ While the interconnection customer pays 
for the costs of the interconnection-related network upgrades upfront, 
the transmission provider must reimburse the total amount that the 
interconnection customer paid for interconnection-related network 
upgrades, plus interest, as credits against the charges for 
transmission service taken with respect to the interconnection 
customer's generating facility as such charges are incurred. The 
transmission provider recovers the cost of interconnection-related 
network upgrades funded under the crediting policy through its embedded 
cost transmission rates.\59\ The second pricing approach for 
interconnection-related network upgrades is called participant funding. 
Participant funding for interconnection-related network upgrades refers 
to the direct assignment to a particular interconnection customer of 
the costs of interconnection-related network upgrades that would not be 
needed but for the interconnection.\60\ The Commission has accepted as 
just and reasonable various participant funding approaches proposed by 
RTOs/ISOs as independent entity variations from the pro forma 
requirements of Order No. 2003.
---------------------------------------------------------------------------

    \57\ Order No. 2003, 104 FERC ] 61,103 at P 22.
    \58\ Id. P 694. ``But for'' interconnection-related network 
upgrades are those interconnection-related network upgrades that 
would not have been constructed ``but for'' the interconnection 
request. See N.Y. Indep. Sys. Operator, Inc., 122 FERC ] 61,267, at 
n.3 (2008).
    \59\ The embedded cost pricing ``attempts to allocate costs 
among customers based upon usage.'' Fla. Power & Light Co., 70 FERC 
] 61,158 (1995). Embedded cost rates reflect ``system average costs 
including the cost of the [interconnection-related] network 
upgrades, and incremental cost rates ``reflect [ ] just the cost of 
the [interconnection-related] network upgrades.'' See Interstate 
Power & Light Co. v. ITC Midwest, LLC, 144 FERC ] 61,052, at P 36 
(2013) (emphasis added).
    \60\ Order No. 845-B, 166 FERC ] 61,092 at P 5; see also Order 
No. 2003, 104 FERC ] 61,103 at P 679 (pursuant to a ``policy of 
participant funding . . . those [that] benefit from a particular 
project pay for it'').
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III. The Potential Need for Reform

A. The Existing Regional Transmission Planning and Cost Allocation and 
Generator Interconnection Processes May Be Inadequate To Ensure Just 
and Reasonable Rates

    30. As a result of changing circumstances since the Commission 
issued Order Nos. 890, 1000, and 2003, we believe it is now appropriate 
to examine whether the existing regional transmission planning and cost 
allocation and generator interconnection processes adequately account 
for the transmission needs of the changing resource mix, or whether 
reforms may be necessary to ensure that transmission rates remain just 
and reasonable and not unduly discriminatory or preferential.
1. Considering Anticipated Future Generation
    31. Expansion of the transmission system generally occurs by design 
through a transmission provider's transmission planning processes, or 
ad hoc through its generator interconnection process. At present, it 
appears that regional transmission planning processes may not 
adequately model future scenarios to ensure that those scenarios 
incorporate sufficiently long-term and comprehensive forecasts of 
future transmission needs, including considering the needs of 
anticipated future generation in identifying needed transmission 
facilities. Although regional transmission planning processes may 
include some level of generation development in different future 
scenarios analyses, it appears that they tend to include in their 
baseline reliability models only those generators that have completed 
facilities studies, and thus are far along in the generator 
interconnection process. These baseline reliability models, by relying 
only on generators that have completed facilities studies, may only 
account for generation that will come online in the short term.
    32. As a result, the generator interconnection process appears to 
be the principal means by which infrastructure is built to accommodate 
new generators. That process, however, focuses on a single 
interconnection request (or cluster of requests). In other words, the 
generator interconnection process is not designed to consider how to 
address anything beyond the reliability interconnection-related network 
upgrades required for a specific interconnection request or group of 
interconnection requests.
    33. New transmission facilities often have a development lead time 
that exceeds the interconnection timing needs of those interconnection 
customers already in the queue. It appears that these types of 
transmission facilities may not currently be planned and built in 
advance to meet the needs of anticipated future generation and as a 
result, interconnection customers are assigned the costs to construct 
large, high-voltage transmission facilities.
    34. In addition, because transmission planning processes generally 
do not plan for the needs of anticipated future generation, 
transmission infrastructure that is being developed in order to 
facilitate new generation is constructed largely through the generator 
interconnection process, which is unlikely to result in the economies 
of scale that could more efficiently or cost-effectively meet the needs 
of the changing resource mix.
    35. Likewise, the existing generator interconnection process 
appears to focus on the limited set of facilities needed to reliably 
interconnect a single interconnection customer (or cluster of requests) 
at the interconnection service level that the interconnection customer 
requests. The generator interconnection process may not adequately 
consider whether it may be more efficient or cost-effective to consider 
the interconnection-related network upgrades needed for multiple 
anticipated future generators that are not in the same cluster or are 
not yet in the interconnection queue in areas that have abundant wind 
or solar attributes that could support multiple future generators.\61\
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    \61\ We note that certain regions do have the ability to share 
costs of network upgrades with future generation, but this is 
generally limited to the short term. For example, Midcontinent 
Independent System Operator, Inc.'s (MISO's) Shared Network Upgrade 
construct allows interconnection customers to be repaid for portions 
of an interconnection-related network upgrade's cost if another 
interconnection customer uses that network upgrade within five 
years.
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    36. In addition, there may be a need for coordination between the 
regional transmission planning process and the generator 
interconnection process, the absence of which may result in inefficient 
investment in transmission infrastructure and ultimately unjust and 
unreasonable or unduly discriminatory or preferential rates. By 
considering the transmission needs of anticipated future generation in 
its regional transmission planning and cost allocation processes, a 
transmission provider may identify transmission facilities that could 
facilitate both the interconnection of new generation as well as 
address other identified transmission system needs--such as mitigating 
a reliability violation or reducing congestion--at a lower total cost 
than pursuing two separate transmission projects through the

[[Page 40273]]

generator interconnection and regional transmission planning and cost 
allocation processes. Without co-optimization of the two processes, 
however, there appears to be no system in place to jointly assess the 
benefits and allocate the costs of transmission facilities that yield 
benefits to both system loads and new generation.
2. Results of Existing Local and Regional Transmission Planning 
Processes
    37. We seek to better understand whether the current transmission 
planning processes may be resulting increasingly in transmission 
facilities addressing a narrow set of transmission needs, often located 
in a single transmission owner's footprint. To the extent that the 
requirements of the regional transmission planning process result in 
transmission providers expanding predominately local transmission 
facilities, that process may fail to identify more efficient or cost-
effective transmission facilities needed to accommodate anticipated 
future generation. We seek to better understand how the reforms of the 
federal right of first refusal in Order No. 1000 have shaped the type 
and characteristics of transmission facilities developed through 
regional and local transmission planning processes, such as a relative 
increase in investment in local transmission facilities or the 
diversity of projects resulting from competitive bidding processes.
3. Cost Responsibility for Transmission Facilities and Interconnection-
Related Network Upgrades
    38. The Commission cannot ensure just and reasonable rates without 
considering how to allocate the costs of transmission facilities and 
interconnection-related network upgrades that result from the regional 
transmission planning and cost allocation and generator interconnection 
processes to the entities that benefit from those facilities. As the 
Commission explained in Order No. 1000, the costs of transmission 
infrastructure must be allocated to its beneficiaries in a manner that 
is at least roughly commensurate with the benefits that they draw from 
those facilities.\62\ We seek to better understand whether the current 
approach to allocating the costs of transmission infrastructure, 
including transmission facilities developed through the regional 
transmission planning and cost allocation processes and 
interconnection-related network upgrades planned through the generator 
interconnection process, continues to appropriately allocate the costs 
of those transmission facilities to the entities that ultimately 
benefit from them.
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    \62\ Order No. 1000, 136 FERC ] 61,051 at P 10.
---------------------------------------------------------------------------

    39. The current regional transmission planning process considers 
transmission needs driven by reliability, economics, and Public Policy 
Requirements. We seek comment whether, by separating transmission 
facilities into types, transmission planning processes may fail to take 
into account the benefits of multi-faceted projects for the purposes of 
cost allocation.
    40. The current approach to allocating the costs of 
interconnection-related network upgrades may fail to allocate costs in 
a manner that is roughly commensurate with benefits. As discussed 
above, the generator interconnection process identifies the 
interconnection facilities and interconnection-related network upgrades 
needed to interconnect a single interconnection request (or cluster of 
requests). Under the participant funding approach to financing the cost 
of interconnection-related network upgrades, the interconnection 
customer pays for the costs of such upgrades, even where they would 
provide benefits to other customers such as resolving congestion on the 
transmission system. At the time that the Commission issued Order No. 
2003, it was less likely that interconnection customers would be 
assigned significant interconnection-related network upgrades through 
the interconnection study process. Now, however, there is little 
remaining existing interconnection capacity on the transmission system, 
particularly in areas with high degrees of renewable resources that may 
require new resources to fund interconnection-related network upgrades 
that are more extensive and, as a result, more expensive. The more 
significant the interconnection-related network upgrades needed to 
accommodate a new resource, the greater the potential that such 
upgrades may benefit more than just the interconnection customer. Where 
an interconnection customer elects not to pursue a generating facility 
with system-wide benefits that exceeds such facility's cost, net 
beneficial infrastructure would not be developed, potentially leaving a 
wide range of customers worse off as a result.
    41. We also note that the cost of interconnection-related network 
upgrades can depend entirely on both the timing of when and the 
specific site where the interconnection customer enters the 
interconnection queue that may result in interconnection customers 
submitting multiple speculative interconnection requests in an effort 
to receive a favorable queue position and reduce their interconnection-
related network upgrade costs.\63\ When interconnection customers 
``test the waters'' in this manner, it may lead to late-stage 
withdrawals of the excess interconnection requests that can then impede 
the transmission provider's ability to process its interconnection 
queue in an efficient manner. Because of the changing interconnection 
landscape since Order No. 2003, the Commission's interconnection 
pricing policy, and in particular participant funding, now may result 
in a situation where interconnection customers have a financial 
incentive to submit multiple speculative projects. As a result, we 
believe it may be time to reexamine the rationale behind the 
Commission's pricing policy established for interconnection-related 
network upgrades and to consider reforms to generator interconnection 
processes that would make such processes more efficient, less costly, 
and ensure that generation projects that are more ``ready'' than others 
are not unduly delayed in the queue. In consideration of generator 
interconnection process reforms, we remain mindful of the need to 
ensure that interconnection costs are not unjustly and unreasonably 
shifted to customers of load-serving entities.
---------------------------------------------------------------------------

    \63\ See, e.g., Review of Generator Interconnection Agreements 
and Procedures, Technical Conference Transcript, Docket No. RM16-12-
000, at Tr. 211:10-21 (May 13, 2016) (Steve Naumann, Exelon 
Corporation) (filed Aug. 23, 2016) (``We would look at putting let's 
say new gas fired generation in PJM, it may have four queue 
positions. And we only intend to go through with one, that's not 
speculation, that's trying to get information on which is the most 
viable.'').
---------------------------------------------------------------------------

    42. While a reassessment of Order No. 2003's assumptions pertaining 
to the Commission's interconnection pricing policy may be necessary, 
our focus is in line with Order No. 2003's finding that ``relatively 
unencumbered entry into the market is necessary for competitive 
markets.'' \64\ Furthermore, the purpose of this examination is also 
consistent with the original objectives of Order No. 2003, namely to 
``limit opportunities for Transmission Providers to favor their owner 
generation'' and to ``facilitate market entry for generation 
competitors by reducing interconnection costs and time.'' \65\ At the 
same time, there is reason to question the contention in Order No. 2003 
that participant funding provides more ``efficient price signals and a 
more equitable allocation of costs than the crediting approach.'' \66\ 
Also, while the crediting policy ``recognizes the reliability benefits 
of a stronger

[[Page 40274]]

transmission infrastructure and more competitive power markets that 
result from a policy that facilitates the interconnection of new 
generating facilities,'' \67\ we raise questions on whether there are 
improvements that can be made to the crediting policy or whether a 
different pricing policy may be more efficient.
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    \64\ Order No. 2003, 104 FERC ] 61,103 at P 11.
    \65\ Id. P 12.
    \66\ Id. P 695.
    \67\ Order No. 2003-A, 106 FERC ] 61,220 at P 584.
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    43. We note that ensuring just and reasonable rates, while 
maintaining grid reliability, remain the priorities for regional 
transmission planning, and cost allocation processes, and generator 
interconnection processes, and any comments proposing revisions to 
existing regulations should address their impact on reliability and 
costs to customers. All proposed reforms or revisions to regulations 
proposed in this proceeding must be consistent with the Commission's 
authority under section 206 of the FPA.

IV. Consideration of Potential Reforms and Request for Comment

A. Regional Transmission Planning and Cost Allocation Processes

1. Potential Reforms and Request for Comment
a. Planning for the Transmission Needs of Anticipated Future Generation
    44. We seek comment regarding whether transmission providers in 
each transmission planning region should amend the regional 
transmission planning and cost allocation processes to plan for the 
transmission needs of anticipated future generation to meet a changing 
resource mix, including generation that is not yet in the 
interconnection queue. We seek comment on whether the existing regional 
transmission planning and cost allocation processes fail to adequately 
account for anticipated future generation. We also seek comment on 
whether the possible failure to account for anticipated future 
generation results in inefficient investment in transmission 
infrastructure and causes customers to pay unjust and unreasonable 
rates for transmission service. We also seek comment on whether, and, 
if so, how the Commission could structure and implement a framework for 
considering the transmission needs of anticipated future generation in 
the regional transmission planning and cost allocation processes. 
Commenters should address how each suggested reform or revision to 
existing rules is consistent with the Commission's authority under the 
FPA.
    45. Below, we describe potential changes to the regional 
transmission planning and cost allocation processes that may be 
components of a process that plans for transmission needs associated 
with anticipated future generation. We seek comment on each of these 
potential changes, including whether and, if so, how the potential 
changes may lead to identification of more efficient or cost-effective 
transmission solutions to meet the needs of anticipated future 
generation. We also seek comment on whether there exist other potential 
revisions that could improve regional transmission planning and cost 
allocation for anticipated future generation, either as alternatives to 
potential reforms discussed herein or as supplementary reforms.
i. Future Scenarios and Modeling Anticipated Future Generation
    46. We seek comment on whether reforms are needed regarding how the 
regional transmission planning and cost allocation processes model 
future scenarios to ensure that those scenarios incorporate 
sufficiently long-term and comprehensive forecasts of future 
transmission needs. We seek comment on what factors shaping the 
generation mix are appropriate to use for transmission planning 
purposes, such as, for example: (1) Federal, state, and local climate 
and clean energy laws and regulations; (2) federal, state, and local 
climate and clean energy goals that have not been enshrined into law; 
(3) utility and corporate energy and climate goals; (4) trends in 
technology costs within and outside of the electricity supply industry, 
including shifts toward electrification of buildings and 
transportation; and (5) resource retirements. With regard to each 
factor that may be considered for inclusion in scenario modeling, we 
seek comment on the source of the Commission's authority to incorporate 
that factor in the regional transmission planning and cost allocation 
processes. In addition, we seek comment on whether the Commission 
should establish minimum requirements regarding future scenarios for 
transmission providers to use in their regional transmission planning, 
including modeling anticipated future generation in those scenarios. 
Commenters should also address whether and how any reforms or revisions 
to existing rules could unjustly and unreasonably shift additional 
costs to customers of load serving entities. Commenters should also 
address whether the status quo does or does not allocate costs in a 
manner roughly commensurate with benefits, and whether the status quo 
leads to rates that are unjust or unreasonable.
    47. The current regional transmission planning and cost allocation 
processes vary regarding how far into the future transmission providers 
look when evaluating transmission needs driven by reliability, economic 
considerations, or Public Policy Requirements. In general, however, the 
extent to which regional transmission planning processes plan for 
anticipated future generation is often limited to generation in the 
generator interconnection queue with a completed facilities study, 
which represents a relatively short-term outlook, and therefore may 
under-forecast anticipated future generation on a longer-term basis 
(and the associated transmission needs of that anticipated future 
generation). As noted, planning and developing the transmission 
facilities needed to address more efficiently or cost-effectively the 
transmission needs of a changing resource mix will often take 
considerably longer than the typical development timeline of a 
generating facility that has completed a facilities study and by 
considering such a limited subset of generation resources, more cost-
effective transmission facilities that address longer-term needs may 
never be developed.
    48. In light of the above, we seek comment on whether, and if so, 
how the regional transmission planning process should be restructured 
to consider a longer-term outlook. We seek comment on whether 
developing plausible long-term scenarios would lead to the 
identification of more efficient or cost-effective transmission 
solutions in regional transmission plans, whether building transmission 
facilities to accommodate anticipated future generation is required to 
render rates just and reasonable, and whether there are deficiencies in 
existing regional transmission planning and cost allocation processes 
that would be cured by conducting such future scenarios planning. 
Specifically, we seek comment on whether the development of longer-term 
scenarios for planning purposes should be pursued and, if so: (1) The 
number of years into the future the scenarios should consider 
(including an explanation of how far ahead it is reasonable to forecast 
anticipated future generation and system requirements); (2) the inputs 
that should be considered in modeling anticipated future generation; 
(3) different transmission planning methods, including whether 
consideration should be given to multiple future scenarios, as well as 
how the planning process should consider the probabilities of future

[[Page 40275]]

scenarios; (4) whether and how transmission providers should account 
for an array of different future scenarios when identifying more 
efficient or cost-effective transmission solutions in regional 
transmission plans; (5) whether and how transmission providers should 
account for federal, state, local, and individual utility energy and 
climate goals (including federal, state and local laws and regulations, 
as well as other policies or goals), and the source of the Commission's 
authority to account for such laws, regulations, policies and goals; 
(6) whether and how transmission providers should plan for expected 
future generator retirements; (7) whether and how Grid-Enhancing 
Technologies \68\ should be accounted for in determining what 
transmission is needed under such scenarios; (8) how benefits and costs 
of transmission infrastructure should be accounted for in such models, 
including how adjusted production costs should be calculated; (9) any 
other aspects of future scenarios modeling, including planning for 
anticipated future generation and associated transmission needs that 
would be useful for the Commission to consider.
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    \68\ Grid Enhancing Technologies increase the capacity, 
efficiency, or reliability of transmission facilities. These 
technologies include, but are not limited to: (1) Power flow control 
and transmission switching equipment; (2) storage technologies, and 
(3) advanced line rating management technologies. FERC, Grid 
Enhancing Technologies, Notice of Workshop, Docket No. AD19-9-000 
(Sept. 9, 2019).
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    49. In addition, we seek comment on whether greater use of 
probabilistic transmission planning approaches may better assess the 
benefits of regional transmission facilities. While some transmission 
providers consider a small number of future scenarios as part of their 
transmission planning process, more advanced approaches, such as 
stochastic \69\ techniques, may provide an opportunity to consider a 
broader array of potential future conditions. Accordingly, we seek 
comment on potential benefits and drawbacks of such techniques in 
regional transmission planning assessments, including whether these or 
other new approaches may facilitate the co-optimization of generation 
siting and transmission development, whether such methods capture 
savings in generation capital costs as well as production expenses that 
can be realized from transmission additions, and whether implementing 
such methods is required to render rates just and reasonable.
---------------------------------------------------------------------------

    \69\ Stochastic models are frameworks for addressing 
optimization problems that involve uncertainty.
---------------------------------------------------------------------------

    50. We also seek comment on which inputs and assumptions 
transmission providers would need to model to represent new generation 
sources, such as renewable resources, in order to reflect their actual 
performance, such as active power-frequency control, reactive power-
voltage control, and fault ride-through capabilities, in the planning 
study cases and any additional studies in order to ensure that 
transmission planning solutions result in operating reliability for the 
future.
    51. We seek comment on the extent to which anticipated generation 
and transmission facility retirements are reflected in future scenarios 
modeled by transmission providers, and whether modifications to 
regional market rules and coordination processes between local and 
regional plans could facilitate more accurate regional transmission 
plans that reflect such anticipated retirements.
    52. In addition, should the use of certain long-term scenarios be 
shown appropriate as part of ensuring just and reasonable rates, we 
seek comment on whether and how the Commission should ensure that the 
regional transmission planning and cost allocation processes develop a 
sufficiently wide range of future scenarios. We seek comment on whether 
the Commission should consider principles or minimum requirements as a 
basis for establishing such scenarios. Given that states or other local 
governing bodies may be uniquely situated in determining how much 
anticipated future generation is needed, or in providing information 
related to infrastructure siting or resource mix as influenced by state 
and local policies, we seek comment on how their input should be 
reflected by transmission providers in developing a sufficiently wide 
range of future scenarios, including those for anticipated future 
generation, and the more efficient or cost-effective transmission 
facilities that may be necessary to facilitate those future scenarios. 
We seek comment on whether it is necessary to require transmission 
providers to modify the regional transmission planning and cost 
allocation processes, such as requiring additional stakeholder input, 
to develop future scenarios, including those for anticipated future 
generation, such that there are sufficient opportunities for 
stakeholders to assess the reasonableness of the results, as well as 
for future modifications to the planning process.
    53. Finally, we seek comment on whether and how such long-term 
scenarios should be used in identifying and selecting solutions to meet 
future transmission needs. For example, as discussed below, should 
transmission providers focus on a broader set of benefits for 
transmission facilities and a portfolio of transmission facilities in 
identifying the more efficient or cost-effective transmission 
solutions? If so, how should regional planning processes determine the 
right set of benefits to factor into such an evaluation? Is maximizing 
net benefits an appropriate criterion to use to identify efficient and 
cost-effective transmission solutions? Should the willingness of some 
beneficiaries to pay for certain transmission infrastructure, for 
example utilities or corporations with renewable resource or zero 
carbon goals, be considered in determining whether to include the 
benefits within a broader set of benefits from transmission facilities, 
and if so then how? Is there a need to establish a minimum set of 
transmission facility benefits that transmission providers must 
incorporate into regional transmission planning decisions, and if so, 
is there also a need to regularly update the minimum set of 
transmission facility benefits?
ii. Identifying Geographic Zones That Have Potential for High Amounts 
of Renewable Resource Development To Meet Increased Demand
    54. We seek comment on whether the Commission should require 
transmission providers in each transmission planning region to 
establish, as part of their regional transmission planning and cost 
allocation processes, a process to identify geographic zones that have 
the potential for the development of large amounts of renewable 
generation and plan transmission to facilitate the integration of 
renewable resources in those zones.
    55. Examples of transmission planning and development initiatives 
that have identified geographic zones with the potential for the 
development of significant amounts of renewable resources and 
transmission to facilitate the integration of renewable resources in 
those zones include the Public Utility Commission of Texas's (Texas 
Commission) Competitive Renewable Energy Zones (CREZ) initiative \70\ 
and MISO's Multi-Value Projects (MVP).\71\
---------------------------------------------------------------------------

    \70\ http://www.ercot.com/committee/crez.
    \71\ https://www.misoenergy.org/planning/planning/multi-value-projects-mvps/.
---------------------------------------------------------------------------

    56. California Independent System Operator Corporation (CAISO) 
offers another example of a regional transmission planning process 
identifying transmission facilities to accommodate renewable resources 
in

[[Page 40276]]

geographic zones that have the potential for high amounts of renewable 
resources. In a petition for declaratory order, the Commission approved 
a mechanism to facilitate the financing and development of transmission 
facilities to interconnect multiple resources that met CAISO's 
eligibility requirements, including a high voltage level and providing 
access to areas rich in renewable energy.\72\
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    \72\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061 (2007).
---------------------------------------------------------------------------

    57. We seek comment on whether the Commission should require 
transmission providers in each transmission planning region to 
establish, as part of their regional transmission planning and cost 
allocation processes, a process that identifies geographic zones that 
have the potential for the development of large amounts of new 
generation, particularly renewable resources. We seek comment on 
whether and how such a process might interrelate with existing regional 
transmission planning and cost allocation processes within each region, 
and how long-term scenario planning discussed above may be used in this 
process or other relevant regional transmission planning and cost 
allocation processes. In addition, we seek comment on whether reforms 
to the current interregional transmission coordination process are 
needed or appropriate for making an approach along these lines 
effective. We also seek comment on: (1) How the Commission should 
structure this potential requirement; and (2) any potential best 
practices, analyses, models, and metrics that could be used to identify 
such zones, including the amount and type of potential generation that 
could be located there. As with the future scenarios transmission 
planning discussed above, we seek comment on whether and how states and 
local entities may provide input into the identification of such zones. 
We seek comment on whether, and, if so, how transmission providers can 
assess whether there is sufficient commercial interest in developing 
generation in any potential zones and transmission to interconnect the 
potential generation (for example, through studies or formal 
declarations of interest). We also seek comment on whether and, if so, 
what safeguards or incentives might be necessary to ensure that 
transmission infrastructure is built only to satisfy expected 
transmission needs and not overly speculative commercial interests. We 
also seek comment on whether any such requirement is consistent with 
the FPA's prohibition of unduly discriminatory or preferential rates.
    58. We seek comment on whether the Commission should require 
transmission providers to account for trends in the resource mix in 
developing energy zones for anticipated future generation as part of 
planning for transmission needs related to such resources and if so, 
what would be the best way to do so? We seek comment whether it would 
be appropriate, as the resource mix further develops, to develop 
similar zones for the transmission needs driven by the development and 
interconnection of energy storage resources and how to do so.
    59. In order to ensure that the more efficient or cost-effective 
transmission facilities are selected and that rates are just and 
reasonable, we also seek comment on whether: (1) Eligibility thresholds 
or criteria (e.g., voltage levels, amount of new generation located 
within a given geographic area or load zone, etc.) may be appropriate 
to determine whether a proposed regional transmission facility should 
be considered as part of the regional transmission planning and cost 
allocation process for transmission facilities built for anticipated 
future generation; (2) whether the CREZ, MISO MVP, CAISO approaches, or 
other processes for identifying and planning for the needs of 
anticipated future generation are models for any potential requirements 
and, if so, which aspects of those initiatives the Commission should 
consider requiring transmission providers to implement, for example, 
the CREZ model of requiring future generation to financially commit in 
advance of construction; (3) whether there is a need for mechanisms to 
limit the risk to customers from planning for anticipated future 
generation, for example, we note CAISO's use of an ex ante cap on the 
total cost exposure to transmission customers in addressing generation 
resource interconnection, as one potential approach; \73\ and (4) 
whether specific proposals are consistent with the Commission's FPA 
section 206 authority.
---------------------------------------------------------------------------

    \73\ Id. P 6.
---------------------------------------------------------------------------

    60. We also seek comment on whether the regional transmission 
planning process could be structured in such a way that is more 
collaborative, relying on the knowledge and experience that 
transmission providers, project developers, state commissions, and 
other stakeholders have regarding optimal locations, the topography of 
the transmission network, and Public Policy Requirements, among other 
factors that will influence the location and amount of future renewable 
resources. We note that the CREZ process was highly collaborative, with 
the Electric Reliability Council of Texas (ERCOT) conducting workshops 
with stakeholders over a six-month period to consider and evaluate 
multiple transmission scenarios.\74\ In addition to seeking comment on 
technical and collaborative approaches to identify geographic zones for 
future renewable resources, we seek comment on potential alternative 
proposals from stakeholders on how to identify where transmission 
facilities may be needed to accommodate anticipated future generation. 
Commenters should address whether, if implemented, such a scenario 
planning process should be the same or different in non-RTO/ISO versus 
RTO/ISO regions, and if different, what those differences should be. 
Commenters should address how any proposed changes to the regional 
planning and cost allocation processes increase the efficiency, or 
lower the costs, of such processes and whether such changes will help 
ensure a reliable power supply and/or will reduce or control the costs 
of transmission and generation services that are ultimately passed on 
to customers of load serving entities. Commenters should also address 
proposed cost allocation.
---------------------------------------------------------------------------

    \74\ See Texas Commission, Order on Rehearing, Docket No. 33672, 
at 3 (Oct. 7, 2008).
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iii. Incentivizing Regional Transmission Facilities
    61. To prioritize regional transmission facilities that may have 
greater benefit-to-cost ratios than local alternatives, we seek comment 
on whether and, if so, how to expand or improve any incentives to 
incent the development of regional transmission facilities that 
demonstrably may offer a more efficient or cost-effective solution to 
an identified need than local alternatives. As an example of a possible 
regional transmission incentive, we seek comment on whether or not any 
available return on equity adder incentive that may be available for 
RTO/ISO participation should be limited in applicability only to 
regional, and not local, transmission facilities, when those regional 
transmission facilities are selected as the more efficient or cost-
effective solution to an identified transmission need.
iv. Enhanced Interregional or State-to-State Coordination
    62. We recognize that potential reforms discussed for comment above 
may require greater interregional or

[[Page 40277]]

state-regional coordination to be fully realized in a just, reasonable 
and not unduly discriminatory or preferential manner. As a result, we 
seek comment on whether reforms to the current interregional 
transmission coordination process, including potentially requiring 
interregional transmission planning, are needed or appropriate for 
making the potential approaches discussed above effective, and whether 
such reforms are consistent with the Commission's authority under 
section 206 of the FPA.
    63. We seek comment on whether, because an interregional project 
must first be selected in each of the neighboring regions' regional 
planning processes before being selected in the interregional process, 
this challenge to the current interregional coordination process is 
impeding the selection and development of efficient, cost-effective 
interregional projects and, if so, what revisions are necessary to 
address that barrier. Should the Commission require joint planning 
processes, rather than simply joint coordination, for neighboring 
regions? In light of the potential reforms to regional planning and 
cost allocation and generator interconnection processes being 
considered in this ANOPR, are there core principles or approaches that 
the Commission should also consider when reviewing the existing 
approach to interregional planning? For example, should the Commission 
establish interregional reliability planning criteria or consider 
renewable resource geographic zones during interregional planning? 
Beyond interregional planning, can and should the Commission provide 
alternate pathways for transmission facilities that benefit multiple 
regions to be assigned cost allocation to customers across multiple 
regions? For example, should the Commission allow for identification of 
benefits, and allocation of commensurate costs, to one region of a 
project selected in a neighboring region's regional transmission 
planning process? Finally, comments should address whether taking any 
proposed action is consistent with the Commission's authority under 
section 206 of the FPA.
    64. In addition, we seek comment on whether and, if so, how a 
regional states committee or other organized body of state officials 
should participate in the development and evaluation of assumptions or 
criteria used for regional transmission planning and cost allocation 
and interregional coordination and cost allocation for transmission 
needs related to future scenarios, including for anticipated future 
generation or geographic generation zones.
b. Coordinating Between the Regional Transmission Planning and Cost 
Allocation and Generator Interconnection Processes
    65. We seek comment on whether reforms are needed to improve the 
coordination between the regional transmission planning and cost 
allocation and generator interconnection processes. We seek comment on 
whether the Commission should require transmission providers to operate 
their regional transmission planning and cost allocation and generator 
interconnection processes on concurrent, coordinated timeframes, with 
the same or similar assumptions and methods, and whether such a 
potential requirement may identify more efficient or cost-effective 
transmission solutions that could address needs shared between the two 
processes.
    66. We seek comment on how the regional transmission planning and 
cost allocation and generator interconnection processes could be better 
coordinated or integrated. For example, would use of similar timeframes 
and assumptions facilitate more efficient or cost-effective 
transmission solutions? How could these processes most effectively be 
co-optimized? We seek comment on whether and, if so, how 
interconnection requests that trigger the need for interconnection-
related network upgrades that may provide regional transmission 
benefits could be studied in a way that accounts for the potential 
broader transmission benefits associated with, for example, resource 
adequacy, operating reliability, and similar needs, and in coordination 
with the regional transmission planning process? We seek comment on 
whether and how relevant information from the generator interconnection 
process could be integrated into regional transmission planning in a 
timely manner, and whether and how transmission providers could move 
beyond using the outputs of each process as a deterministic input into 
the other rather than optimizing together across approaches. We also 
seek comment on whether it may be possible and beneficial to combine 
certain aspects of the transmission planning and generator 
interconnection processes, and if so, how?
    67. We also seek comment on whether and how the Commission could 
revise transmission planning criteria that transmission providers use 
in the generator interconnection process so that they could better 
identify more efficient or cost-effective interconnection-related 
network upgrades. As indicated earlier, we also seek comment on whether 
and how transmission providers could incorporate anticipated future 
generation, including resources in the interconnection queue, in the 
regional transmission planning and cost allocation processes. In 
particular, we encourage commenters to discuss how to address concerns 
regarding uncertainty, including speculative projects, in planning for 
anticipated future generation.
    68. Further, we seek comment on whether and how more effectively 
accounting for anticipated future generation in transmission planning 
may reduce the costs of interconnection-related network upgrades. To 
the extent this is the case, how should such benefits be identified, 
and should they factor into the regional transmission planning and cost 
allocation process?

B. Identification of Cost and Responsibility for Regional Transmission 
Facilities and Interconnection-Related Network Upgrades

    69. The Commission has repeatedly recognized that, where cost 
allocation methods do not appropriately account for benefits associated 
with new transmission facilities, they may result in rates that are not 
just and reasonable or are unduly discriminatory or preferential.\75\
---------------------------------------------------------------------------

    \75\ See Order No. 890, 118 FERC ] 61,119 at P 557 (finding that 
how ``the costs of new transmission facilities are allocated is 
critical to the development of new infrastructure'' because 
``[t]ransmission providers and customers cannot be expected to 
support the construction of new transmission unless they understand 
who will pay the associated cost''); Order No. 1000, 136 FERC ] 
61,051 at PP 484-487; see also Ill. Commerce Comm'n v. FERC, 576 
F.3d 470, 476 (7th Cir. 2009) (ICC v. FERC).
---------------------------------------------------------------------------

    70. We seek comment on whether the existing approach to cost 
allocation in regional transmission planning processes fails to 
consider the full suite of benefits--and the associated beneficiaries--
produced by transmission facilities developed to meet the transmission 
needs of the changing resource mix. We seek comment on whether the 
current approach omits relevant benefits of new transmission 
infrastructure and, if so, thereby fails to consider the entities that 
receive those benefits in the cost allocation process. What, 
specifically, are those other benefits that should be considered? In 
addition, while the regional transmission planning process considers 
transmission needs driven by reliability, economic considerations, and 
Public Policy Requirements, these types of transmission needs are, in

[[Page 40278]]

many cases, considered in isolation from one another and the cost 
allocation methods for transmission facilities developed in response to 
these needs are generally separated by type. We seek comment as to 
whether the existing regional transmission planning and cost allocation 
processes may not fully account for the full suite of benefits, 
including hard-to-quantify benefits, and may impede the allocation of 
the costs of transmission facilities needed to meet the transmission 
needs of the changing resource mix in a manner that is at least roughly 
commensurate with the actual benefits of those facilities. Getting that 
balance right is important not only to comply with the cost causation 
principle, but also because efforts to plan the transmission system to 
meet the needs of the changing resource mix will succeed only if the 
associated cost allocation methods are transparent, equitable, and 
practicable.\76\
---------------------------------------------------------------------------

    \76\ Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 
268-269 (D.C. Cir. 2014) (BNP Paribas Energy) (``[T]he cost 
causation principle itself manifests a kind of equity. This is most 
obvious when we frame the principle (as we and the Commission often 
do) as a matter of making sure that burden is matched with 
benefit.'' (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d 
1361, 1368 (D.C. Cir. 2004) and Se. Mich. Gas Co. v. FERC, 133 F.3d 
34, 41 (D.C. Cir. 1998))); Order No. 1000, 136 FERC ] 61,051 at P 
669 (explaining that requiring cost allocation methods be open and 
transparent ensures that such methods are just and reasonable and 
not unduly discriminatory or preferential, aids in development and 
construction of new transmission, and may avoid contentious 
litigation or prolonged stakeholder debate); KN Energy, Inc. v. 
FERC, 968 F.2d 1295, 1300-01 (D.C. Cir. 1992) (describing properly 
designed rates as producing revenues `` `which match, as closely as 
practicable, the costs to serve each class or individual customer' 
'' (emphasis in original)) (quoting Ala. Elec. Coop., Inc. v. FERC, 
684 F.2d 20, 27 (D.C. Cir. 1982)); Pub. Serv. Co. of Colo., 163 FERC 
] 61,204, at P 14 (2018) (recognizing that ``feasibility'' is part 
of ratemaking, such that the Commission may appropriately ``balance 
maximally reflecting cost causation with other competing policy 
goals,'' such as promoting more efficient or cost-effective regional 
transmission planning).
---------------------------------------------------------------------------

    71. With respect to cost allocation in the generator 
interconnection process, we seek comment as to whether the participant 
funding approach for interconnection-related network upgrades required 
for an interconnection request in RTOs/ISOs may no longer be just and 
reasonable. Participant funding may result in costly interconnection-
related network upgrades being allocated entirely to interconnection 
customers while failing to account for the significant benefits that 
these interconnection-related network upgrades may provide to other 
anticipated future generators seeking to interconnect and/or existing 
or future transmission customers. We further seek comment on whether 
the narrow focus of the generator interconnection process results in 
only a subset of beneficiaries paying for transmission infrastructure 
that, in practice, may benefit many.
    72. We seek comment on whether separating the regional transmission 
planning and cost allocation and generator interconnection processes 
may increasingly result in an only partial-accounting of the benefits 
of new transmission infrastructure, leaving some transmission and 
interconnection customers potentially bearing a disproportionate cost 
burden. We seek comment on whether any changes to the criteria used for 
considering which transmission facilities are selected in the regional 
transmission plan for purposes of regional cost allocation, as well as 
the formula for the regional allocation of costs of regional 
transmission facilities and for the cost of interconnection-related 
network upgrades, including changes to the definition of beneficiary, 
hold the potential to unjustly and unreasonably shift costs to 
customers of load serving entities. We seek comment on how any 
contemplated reforms or revisions to existing regulations are 
consistent with the FPA and its requirement for just and reasonable and 
not unduly discriminatory or preferential rates.
    73. In the following sections, we address the relevant court and 
Commission precedent governing cost allocation and seek comment on a 
number of potential reforms to address these concerns and ensure that 
transmission rates remain just and reasonable and not unduly 
discriminatory or preferential.
1. Relevant Cost Causation Precedent
    74. Pursuant to FPA sections 205 and 206, the Commission is 
responsible for ensuring that the rates, terms, and conditions for 
transmission of electricity in interstate commerce are just, 
reasonable, and not unduly discriminatory or preferential.\77\ For a 
cost allocation approach to satisfy this standard, it must satisfy the 
cost causation principle. The cost causation principle requires that 
``all approved rates reflect to some degree the costs actually caused 
by the customer who must pay them'' \78\ and that costs ``be allocated 
to those who cause the costs to be incurred and reap the resulting 
benefits.'' \79\ As the U.S. Court of Appeals for the Seventh Circuit 
(Seventh Circuit) further explained, to ``the extent that a utility 
benefits from the costs of new facilities, it may be said to have 
`caused' a part of those costs to be incurred, as without the 
expectation of its contributions the facilities might not have been 
built, or might have been delayed.'' \80\ Courts ``evaluate compliance 
with this . . . principle by comparing the costs assessed against a 
party to the burdens imposed or benefits drawn by that party.'' \81\ In 
ICC v. FERC, the Seventh Circuit also stated that a cost allocation 
method can satisfy the cost causation principle if the Commission ``has 
an articulable and plausible reason to believe that the benefits are at 
least roughly commensurate with'' the allocation of the costs.\82\ The 
Seventh Circuit stated, however, that satisfying this requirement does 
not require exacting precision, and the Commission need not ``calculate 
benefits to the last penny, or for that matter to the last million or 
ten million or perhaps hundred million dollars.'' \83\
---------------------------------------------------------------------------

    \77\ 16 U.S.C. 824d, 824e.
    \78\ KN Energy, Inc. v. FERC, 968 F.2d at 1300.
    \79\ S.C. Pub. Serv. Auth., 762 F.3d at 87 (quoting NARUC v. 
FERC, 475 F.3d at 1285).
    \80\ ICC v. FERC, 576 F.3d at 476.
    \81\ Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368.
    \82\ 576 F.3d at 477.
    \83\ Id. (citing Midwest ISO Transmission Owners v. FERC, 373 
F.3d at 1369).
---------------------------------------------------------------------------

2. Cost Allocation for Transmission Facilities Planned Through the 
Regional Transmission Planning Process
    75. Potential reforms for which we seek comment in this ANOPR 
contemplate a more forward-looking approach to the regional 
transmission planning process that plans for anticipated future 
generation, potentially producing a different and broader set of 
benefits and beneficiaries. The following sections seek comment on 
potential reforms that may be necessary to ensure that the costs of 
transmission facilities developed to meet the transmission needs of the 
changing resource mix are allocated in a manner that is roughly 
commensurate with those benefits, while ensuring that any potential 
reforms or revisions to existing cost-allocation rules do not unjustly 
or unreasonably shift costs to any type of market participant or 
customers of load serving entities. We seek comment on whether certain 
benefits are not appropriate to account for under the FPA, and whether 
allocation of costs based on such benefits may be inconsistent with the 
Commission's statutory mandate.
a. Background
    76. In Order No. 1000, the Commission determined that the lack of 
clear ex ante cost allocation methods that identify beneficiaries of 
proposed regional transmission facilities was

[[Page 40279]]

impairing the ability of transmission providers to implement more 
efficient or cost-effective transmission solutions identified in the 
regional transmission planning process. According to the Commission, 
the failure to address cost allocation in a way that aligns with the 
benefits of new transmission facilities could lead to needed 
transmission facilities not being built, adversely impacting 
ratepayers.\84\ The Commission therefore required transmission 
providers to have in place a method, or set of methods, for allocating 
the costs of new transmission facilities selected in a regional 
transmission plan for purposes of cost allocation. To guide 
transmission providers, the Commission established a set of cost 
allocation principles that transmission providers' cost allocation 
methods must satisfy, with the goal of ensuring that the costs of 
transmission solutions chosen to meet regional transmission needs would 
be allocated to those that received benefits from them.\85\ The 
Commission determined that this principles-based approach would result 
in the allocation of the costs of new transmission facilities in a 
manner that is at least roughly commensurate with the benefits received 
by those that pay those costs while allowing for regional 
flexibility.\86\
---------------------------------------------------------------------------

    \84\ Order No. 1000, 136 FERC ] 61,051 at P 499.
    \85\ Id. PP 9, 482-83.
    \86\ Id. P 10; Order No. 1000-A, 139 FERC ] 61,132 at P 647.
---------------------------------------------------------------------------

    77. The six regional cost allocation principles that the Commission 
adopted in Order No. 1000 are: (1) Costs of transmission facilities 
must be allocated to those within the transmission planning region that 
benefit from those facilities in a manner that is at least roughly 
commensurate with estimated benefits; (2) those that receive no benefit 
from transmission facilities, either at present or in a likely future 
scenario, must not be involuntarily allocated any of the costs of those 
transmission facilities; \87\ (3) a benefit to cost threshold ratio, if 
adopted, cannot exceed 1.25 to 1; \88\ (4) costs must be allocated 
solely within the transmission planning region unless another entity 
outside the region voluntarily assumes a portion of those costs; \89\ 
(5) the method for determining benefits and identifying beneficiaries 
must be transparent; \90\ and (6) there may be different methods for 
different types of transmission facilities, such as those needed for 
reliability, congestion relief, or to achieve Public Policy 
Requirements.\91\ Although the Commission required the regional cost 
allocation methods to determine benefits and identify beneficiaries in 
a transparent manner, the Commission also recognized that ``identifying 
which types of benefits are relevant for cost allocation purposes, 
which beneficiaries are receiving those benefits, and the relative 
benefits that accrue to various beneficiaries can be difficult and 
controversial.'' \92\ Consistent with this notion, the Commission 
declined to require transmission providers to adopt a universal or 
comprehensive definition of ``benefits'' and ``beneficiaries'' \93\ of 
regional transmission facilities, instead allowing for regional 
flexibility and examining each region's definitions on compliance.
---------------------------------------------------------------------------

    \87\ Order No. 1000, 136 FERC ] 61,051 at P 637.
    \88\ Id. P 646.
    \89\ Id. P 657.
    \90\ Id. P 668.
    \91\ Id. P 685.
    \92\ Id. P 501.
    \93\ Order No. 1000-A, 139 FERC ] 61,132 at P 679 (explaining 
that Order No. 1000 does not define benefits and beneficiaries but 
rather requires transmission providers to be definite about benefits 
and beneficiaries for purposes of their cost allocation methods).
---------------------------------------------------------------------------

    78. The result is that transmission providers in each transmission 
planning region have implemented varying regional transmission cost 
allocation methods to comply with the cost allocation principles of 
Order No. 1000, the majority of which allocate the costs of regional 
transmission facilities that address reliability needs separately from 
those that address economic needs and separately from those that 
address Public Policy Requirements. In other words, most regional 
transmission cost allocation methods do not consider whether a regional 
transmission facility addresses more than one category of needs, and 
therefore provides more than one category of transmission benefits.
    79. That said, some transmission providers' Order No. 1000-
compliant regional transmission cost allocation methods may recognize a 
broader number of benefits than others and identify the broader 
benefits across a portfolio of transmission facilities rather than on a 
facility-by-facility basis, whereas others may be more constrained. For 
example, MISO's MVP process is designed to identify a portfolio of 
regional transmission facilities that: (1) Reliably and economically 
enable regional public policy needs; (2) provide multiple types of 
regional economic value; and/or (3) provide a combination of regional 
reliability and economic value. Specifically, MISO MVPs must be above 
100 kV, have a project cost of $20 million or more, and have a combined 
benefit-to-cost ratio greater than 1.0 and must be evaluated as part of 
a portfolio of transmission projects.\94\ The costs of this MVP 
portfolio are allocated on a postage stamp basis across the MISO 
region.\95\
---------------------------------------------------------------------------

    \94\ MISO, FERC Electric Tariff, Attachment FF, Section II.C 
(85.0.0).
    \95\ Id. Section III.A.2.g.
---------------------------------------------------------------------------

    80. Southwest Power Pool's (SPP) Balanced Portfolio process 
similarly considers broader transmission benefits.\96\ SPP evaluates 
economic benefits of a portfolio of transmission facilities to achieve 
a balance where the benefits of the portfolio to each zone (as measured 
by adjusted production cost savings) equal or exceed the costs 
allocated to each zone over a 10-year period. By allocating costs such 
that the benefits to each zone will equal or exceed those costs, the 
Balanced Portfolio process ensures that SPP allocates costs in a manner 
that is least roughly commensurate with benefits by design. In 
addition, SPP may reallocate costs to ensure that the portfolio is 
balanced and, under certain conditions, including cancellation of a 
transmission facility or unanticipated decreases in benefits or 
increases in costs, may review a previously approved Balanced Portfolio 
and recommend reconfiguring the portfolio.\97\
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    \96\ SPP's Balanced Portfolio was an initiative to develop a 
group of economic transmission projects that benefit the entire SPP 
region and to allocate those transmission project costs regionally. 
The SPP Board of Directors approved the Balanced Portfolio 
transmission projects in April 2009.
    \97\ SPP OATT, attach. J (Recovery of Costs Associated With New 
Facilities), Section III.D.
---------------------------------------------------------------------------

    81. As for allocating the costs of regional transmission facilities 
to generators, in Order No. 1000, while commenters requested that the 
Commission allow such costs to be allocated to generators as 
beneficiaries, the Commission determined that generator interconnection 
was outside the scope of the rulemaking.\98\ However, the Commission 
also stated that transmission providers could propose a regional 
transmission cost allocation method that allocates costs directly to 
generators as beneficiaries, but any effort to do so must not be 
inconsistent with the Order No. 2003 generator interconnection process. 
The Commission noted that in not addressing these issues, it was 
neither minimizing the importance of evaluating the impact of generator 
interconnection requests during transmission planning, nor limiting the 
ability of transmission providers to use requests for generator 
interconnections in developing assumptions to be used in

[[Page 40280]]

the regional transmission planning process.\99\
---------------------------------------------------------------------------

    \98\ Order No. 1000, 136 FERC ] 61,051 at P 760.
    \99\ Id. P 760.
---------------------------------------------------------------------------

    82. Nevertheless, at least one transmission provider considers 
interconnection customers as beneficiaries of new transmission 
facilities. The Commission approved CAISO's proposal whereby 
transmission customers initially fund the transmission expansion needed 
to facilitate interconnection through the transmission revenue 
requirement of the constructing transmission provider, and 
interconnection customers are assigned their pro rata share of the 
going-forward costs of using the transmission facility as their 
generators interconnect to the transmission system. Under CAISO's 
proposal, all transmission system users pay the costs of the 
unsubscribed portion of a new transmission facility until the line is 
fully subscribed.\100\ The CAISO approach also includes an ex ante cap 
on the total cost exposure to transmission customers, which was set at 
15% of the sum total of the net high-voltage transmission plant of all 
transmission providers, as reflected in their transmission revenue 
requirements and in the CAISO transmission access charge.\101\
---------------------------------------------------------------------------

    \100\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061.
    \101\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061, at P 
6.
---------------------------------------------------------------------------

b. Potential Need for Reform
    83. This statement in Order No. 1000 rings as true today as it did 
then--``identifying which types of benefits are relevant for cost 
allocation purposes, which beneficiaries are receiving those benefits, 
and the relative benefits that accrue to various beneficiaries can be 
difficult and controversial.'' \102\ This is especially true for 
larger, regional transmission facilities that are both costly and could 
have potentially broad benefits. As the Commission recognized in Order 
No. 890, the manner in which the costs of new transmission facilities 
are allocated is ``critical'' to developing those facilities as is 
identifying the types of benefits and the associated beneficiaries of 
those facilities.\103\
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    \102\ Order No. 1000, 136 FERC ] 61,051 at P 501.
    \103\ Order No. 890, 118 FERC ] 61,119 at P 557.
---------------------------------------------------------------------------

    84. The possible reforms for which we seek comment in this ANOPR 
seek to ensure the development of regional transmission facilities 
needed to meet the transmission needs of the changing resource mix 
occurs in a more efficient or cost-effective manner, at just and 
reasonable rates. Commenters should also address whether and how any 
reforms or revisions to existing rules could unjustly and unreasonably 
shift additional costs to customers of load serving entities. These 
reforms cannot be successful without ensuring that transmission 
providers and customers alike are able to identify the types of 
benefits of these transmission facilities can provide and also identify 
the beneficiaries that would receive those benefits, along with the 
relative proportion of benefits that accrue to each of those 
beneficiaries. The failure to account for all the benefits of a 
transmission facility while taking into account all the costs of the 
transmission facility does not allow for a fair examination of whether 
the costs are allocated roughly commensurate with the benefits. We seek 
comment on whether ignoring benefits of these transmission facilities 
may impair more efficient or cost-effective transmission development by 
limiting the number of facilities that overcome the cost-benefit 
threshold needed to justify the cost of new transmission, and if so, 
what the appropriate standard should be for identifying such benefits. 
This potential concern goes to the need to not only identify the types 
of benefits of these new transmission facilities, and to quantify those 
benefits where possible, but likewise to the need for transparent 
methods to calculate benefits and ascertain beneficiaries without being 
so burdensome that the methods hinder transmission development. We seek 
comment on whether customers of load serving entities should be 
required to pay the costs of regional transmission facilities that 
provide them only with unquantifiable or purported benefits, or be 
required to pay for costs driven by the public policies of state and 
local governments in states other than their own.\104\
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    \104\ See, e.g., PJM's State Agreement Approach. PJM 
Interconnection, L.L.C., 142 FERC ] 61,214, at PP 142-143 (2013), 
order on reh'g and compliance, 147 FERC ] 61,128, at P 92 (2014);
---------------------------------------------------------------------------

    85. Currently, most regional cost allocation methods do not 
consider whether a regional transmission facility addresses more than 
one category of needs, thereby providing more than one category of 
transmission benefits. Specifically, although the regional transmission 
planning process considers transmission needs driven by reliability, 
economic considerations, and Public Policy Requirements,\105\ these 
types of transmission needs are generally considered in a silo from one 
another; the cost allocation methods for regional transmission 
facilities developed in response to these needs are similarly for the 
most part separated by type. We seek comment on whether the result is a 
paradigm that may potentially fail to consider the suite of benefits 
that transmission facilities provide and therefore fails to allocate 
the costs of such facilities roughly commensurate with the benefits.
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    \105\ Order No. 1000 left planning and cost allocation for 
Public Policy Requirements largely to the discretion of transmission 
providers. See supra P 16. Moreover, under PJM's State Agreement 
Approach (see supra n.104), the costs of transmission facilities 
required to meet the public policy requirements of an individual 
state or group of states may not be shifted to customers in other, 
non-participating states.
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    86. We seek comment as to whether a shift to a more integrated and 
holistic process for regional transmission planning and cost allocation 
is appropriate. Such a shift may raise novel questions around which 
customers should pay for new transmission facilities and concerns about 
free riders benefitting from the transmission expansion without paying 
for their fair share. Under the potential reforms for which we seek 
comment in this ANOPR, the regional transmission planning process would 
identify transmission facilities that support future scenarios, 
including anticipated future generation, and improve pricing and cost 
allocation for interconnection-related network upgrades. In that 
scenario, interconnection customers themselves could be considered 
beneficiaries of transmission facilities that facilitate their 
interconnection, even if those transmission facilities were built prior 
to the generators entering the interconnection queue. We seek comment 
on whether merely making interconnection customers the beneficiaries 
fails to capture all of the relevant types of benefits for purposes of 
cost allocation of a regional transmission facility built to 
accommodate anticipated future generation. We also seek comment on 
whether it may therefore be preferable to consider developing new 
regional transmission cost allocation methods that measure all of the 
benefits of regional transmission facilities that are being assessed 
for potential selection in the regional transmission plan for purposes 
of cost allocation and that accrue to both transmission and 
interconnection customers.
    87. We cannot ignore, of course, that it may be difficult to 
precisely quantify some of the benefits of transmission facilities, 
which can be a barrier to more broadly allocating the costs of those 
facilities among transmission and interconnection customers. Unlike 
costs, which are clearly defined and easily quantified, the scope of 
which transmission benefits count for purposes of cost allocation, and 
how well they need to be documented in order to be allocated to 
customers, is a distinct

[[Page 40281]]

challenge to achieving a fair allocation. Requiring transmission 
providers to produce overly detailed reports on benefits before the 
costs of a transmission facility can be allocated to transmission and 
interconnection customers could lead to cost allocations that 
undervalue the largest transmission expansions, no matter their 
efficiency. The task is in striking the right balance to ensure just 
and reasonable rates and the allocation of transmission costs roughly 
commensurate with benefits.
    88. We also note that, with greater deployment of renewable 
resources, and in part to the extent that regions focus on a project-
specific regional transmission cost allocation method, it is possible 
that benefits may be distributed unevenly across regions. For example, 
there are likely zones or sub-zones within a region that are rich in 
renewable resources and therefore have generation significantly in 
excess of the local load. These zones, and generators in these zones, 
may not be the only beneficiaries of regional transmission facilities 
built to access these resources as customers outside those zones may 
reap reliability or economic benefits that result from the expanded 
transmission system and access to low cost resources. We seek comment 
on whether current regional transmission cost allocation approaches may 
not adequately address these circumstances and may not provide workable 
frameworks for the identification of transmission beneficiaries and 
sharing of benefits.
    89. We seek comment on whether there should be reforms to cost 
allocation in regional transmission planning and cost allocation 
processes, including considering potentially a portfolio approach to 
assessing regional transmission facilities and consideration of a 
minimum set of transmission benefits, while seeking additional 
information about cost allocation approaches that may inform such 
reforms. Commenters proposing specific changes to cost allocation 
should address how such proposals will result in costs being allocated 
in a manner roughly commensurate with benefits, and demonstrate that 
costs will not be disproportionately borne by any given class of 
customers in a manner inconsistent with the requirements of the FPA and 
precedent. Commenters should also address how such proposals impact 
customers of load serving entities and whether and how proposed new 
cost allocation formulae may shift costs to new categories of customers 
and whether such cost-shifting is just and reasonable and consistent 
with the requirements of the FPA.
c. Potential Reforms and Request for Comment
    90. We seek comment on whether broader transmission benefits should 
be taken into account when planning the transmission system for 
anticipated future generation, and how such benefits should be 
identified and quantified. Some transmission providers, e.g., SPP, 
MISO, CAISO, and recently the New York Independent System Operator, 
Inc. (NYISO), have used broader transmission benefits in selecting 
regional transmission facilities for purposes of cost allocation in 
their regional transmission planning processes.
    91. In addition, under a portfolio approach to regional 
transmission cost allocation, multiple transmission facilities are 
considered together, and the collective benefits of the transmission 
facilities are measured. MISO's MVP and SPP's Balanced Portfolio method 
are examples of portfolio approaches to regional transmission cost 
allocation. We seek comment on whether a portfolio approach recognizes 
that a regional transmission planning process that considers a group of 
transmission facilities that collectively provide multiple benefits, 
including reliability, economic, and Public Policy Requirements 
benefits, among others, may be able to better identify more efficient 
or cost-effective transmission facilities when compared to a process 
that focuses only on individual transmission facilities or individual 
benefits. We seek comment on whether an approach that both estimates 
broader transmission benefits for regional transmission facilities 
beyond those that are currently considered and that also allocates the 
costs for a portfolio of those individual transmission facilities may 
provide a cost allocation method that better matches benefits to 
burdens over time.\106\ We seek comment on whether such an approach may 
also be more accurate or less likely to lead to anomalous results.
---------------------------------------------------------------------------

    \106\ See BNP Paribas Energy, 743 F.3d at 268-69 (framing the 
cost causation principle ``as a matter of making sure that burden is 
matched with benefit'').
---------------------------------------------------------------------------

    92. At the same time, we seek comment on whether there are 
circumstances in which the use of criteria other than reliability and 
economic considerations may result in projects being selected in the 
regional transmission plan for purposes of cost allocation that do not 
represent the optimal solution to the reliability or congestion 
problems identified and thus may not represent the most efficient or 
cost-effective solution for customers of the load serving entities both 
inside an RTO/ISO and in non-RTO/ISO region. Any proposals for changes 
to planning criteria and cost allocation should consider whether such 
proposals result in unjustly and unreasonably shifting costs to 
customers. We seek comment on whether the use of planning criteria 
beyond reliability and economic considerations may place the burden for 
the costs driven by Public Policy Requirements of one state on 
customers of load serving entities in non-participating states.
    93. We seek comment on the current approaches that transmission 
providers take in defining transmission benefits for purposes 
transmission planning and cost allocation. For example, we are 
interested in how transmission providers calculate adjusted production 
costs, the extent to which transmission providers go beyond adjusted 
production costs in identifying transmission benefits, the types of 
benefits, and the methods for estimating. We also seek comment on the 
extent to which it may be challenging, for certain types of benefits, 
to identify the beneficiaries for cost allocation purposes. We seek 
comment on the extent to which the same set of benefits is currently 
used in regional transmission planning processes and their associated 
cost allocation processes, or whether some benefits are identified but 
not factored into cost allocation. Should the same set of benefits be 
used in all processes? If not, would it be appropriate to consider 
different benefits during the transmission planning and cost allocation 
stages? If so, what would be the basis for doing so?
    94. We seek comment on the types of benefits provided by 
transmission facilities needed to meet the transmission needs of 
anticipated future generation that are relevant for cost allocation 
purposes and the manner in which those benefits can be quantified, if 
at all. This includes consideration of whether there are transmission 
benefits beyond those that transmission providers already take into 
account in allocating costs that the Commission should require all 
transmission providers to consider for regional transmission 
facilities. In other words, should the Commission require transmission 
providers to establish a broader set of transmission benefits for 
purposes of cost allocation than currently in use and, likewise, should 
the Commission adopt a minimum set of transmission benefits that must 
be considered? Such benefits could encompass economic benefits (e.g.,

[[Page 40282]]

congestion reduction); resource adequacy benefits (e.g., allowing 
imports to replace more expensive local generation, lowering required 
planning targets through increased diversity benefits); and reliability 
benefits (e.g., avoided or deferred reliability transmission 
facilities, improved reserves sharing, increased voltage support). And 
to what extent are there benefits that will differ from region-to-
region?
    95. If there are types of benefits that cannot be quantified, but 
which are real and relevant to allocating the costs of regional 
transmission facilities roughly commensurate with benefits, we seek 
comment on how transmission providers can document and account for 
those benefits in crafting a cost allocation method. Similarly, we seek 
comment on whether the inability to precisely quantify benefits of 
transmission facilities can be a barrier to the development of those 
facilities, particularly those with potentially broad transmission 
benefits. If so, we are interested in what types of transmission 
facilities are most impacted and what types of benefits are typically 
associated with those types of transmission facilities, and how those 
benefits can be justified and quantified.
    96. To the extent that there are relevant benefits that are 
difficult to quantify, we seek comment on ways in which the Commission 
can consider whether those benefits are appropriately credited to a 
regional transmission facility and accounted for as part of allocating 
the costs to beneficiaries. This includes consideration of when 
benefits of a transmission facility are sufficiently certain to justify 
a commensurately broad cost allocation, especially where those benefits 
are not susceptible to precise quantification. We also seek comment on 
whether it is appropriate to credit benefits that cannot be credibly 
quantified and whether, and if so, how, it is appropriate to factor 
such benefits into regional cost allocation.
    97. In addition to identifying benefits, we also seek comment on 
best practices for identifying the beneficiaries of a transmission 
facility. For example, some interconnection-related network upgrades 
for generator interconnection may benefit more than a single 
interconnecting generator, however the scope (temporal and geographic) 
of such beneficiaries may not be clear. We seek comment on the efficacy 
and desirability of a regional transmission planning and cost 
allocation process that seeks to plan for future scenarios, including 
planning for anticipated future generation. What methods for 
ascertaining beneficiaries are most effective in allocating the costs 
of such facilities roughly commensurate with benefits? Are there 
threshold transmission system conditions that would enable the 
Commission to reasonably conclude that regional (or some greater or 
lesser geographical scope) allocation of costs is appropriate (such as 
the amount of congestion or level of interconnectedness in a particular 
area)? This necessarily links to our earlier questions about how to 
quantify benefits and what level of precision is required.
    98. Along the same lines of identifying beneficiaries, we seek 
comment on whether the costs of transmission facilities planned in the 
regional transmission planning process for which we seek comment in 
this ANOPR should be allocated to both transmission and interconnection 
customers. As explained earlier, we are concerned about potential free-
rider problems associated with interconnection customers that later 
connect to transmission facilities planned for anticipated future 
generation. We are therefore interested in approaches to cost 
allocation to ensure that both transmission and interconnection 
customers that benefit from those facilities pay their fair share. 
While we propose to potentially reform participant funding by 
interconnection customers of interconnection-related network upgrades, 
we are also considering how best to allocate costs of regional 
transmission facilities to interconnection customers (e.g., whether 
cost allocation methods for regional transmission facilities should 
allocate a portion of the costs of a regional transmission facility 
directly to interconnection customers based on, for example, the 
capacity of the interconnection customer's generating facility).
    99. We seek comment on the cost effectiveness of the reforms 
discussed herein. If the regional transmission planning and cost 
allocation processes are to consider transmission needs driven by 
anticipated future generation, is there a tradeoff between facilitating 
the construction of transmission facilities that are needed to connect 
such anticipated future generation, and ensuring against building more 
transmission than is necessary? If so, how should the Commission 
approach that tradeoff?
3. Participant Funding and Crediting Policy for Funding 
Interconnection-Related Network Upgrades
    100. Since the issuance of Order No. 2003, the composition of the 
generation fleet has rapidly shifted from predominately large, 
centralized resources to include a large proportion of smaller 
renewable generators that, due to their distance from load centers, 
often require extensive interconnection-related network upgrades to 
interconnect to the transmission system. The significant 
interconnection-related network upgrades necessary to accommodate 
geographically remote generation are a result that the Commission did 
not contemplate when it established the interconnection pricing policy 
for interconnection-related network upgrades. Because the large-scale 
changes since Order No. 2003 may have impacted the underlying rationale 
for the interconnection pricing policy, we seek comment on whether the 
Commission should modify the participant funding and crediting 
policies, as discussed in further detail below.
a. Background
i. Original Rationale for the Order No. 2003 Interconnection-Related 
Network Upgrade Funding Requirements
    101. As discussed above, the Commission in Order No. 2003 described 
two general approaches for assigning the costs of interconnection-
related network upgrades needed to interconnect a generating facility 
to the transmission system: (1) the crediting policy, whereby the 
interconnection customer initially funds the interconnection-related 
network upgrades and is reimbursed through transmission credits; \107\ 
and (2) participant funding, where the costs of interconnection-related 
network upgrades in RTOs/ISOs are assigned directly to the 
interconnection customer. Central to discussions of the Commission's 
interconnection-related network upgrade funding requirements is Order 
No. 2003's continued prohibition of ``and'' pricing. This prohibition 
provides that, when ``a Transmission Provider must construct

[[Page 40283]]

[interconnection-related] Network Upgrades to provide new or expanded 
transmission service, the Commission generally allows the Transmission 
Provider to charge the higher of the embedded costs of the Transmission 
System with expansion costs rolled in, or incremental expansion costs, 
but not the sum of the two.'' \108\ The Commission also explained that 
allowing the transmission provider to charge either the higher of an 
embedded cost rate for transmission service or an incremental rate 
designed to recover the cost of the interconnection-related network 
upgrades ``provides the Transmission Provider with a cost recovery 
mechanism that ensures that native load and other transmission 
customers will not subsidize service to the Interconnection Customer.'' 
\109\
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    \107\ Order No. 2003-B states that ``the period for 
reimbursement may not be longer than the period that would be 
required if the Interconnection Customer paid for transmission 
service directly and received credits on a dollar-for-dollar basis, 
or 20 years [from the generating facility's commercial operation 
date], whichever is less.'' Order No. 2003-B, 109 FERC ] 61,287 at 
PP 3, 36. If credits have not fully reimbursed the upfront payment 
within 20 years, Order No. 2003 requires ``a balloon payment'' at 
the end of year 20. Id. P 36. The crediting policy also requires 
that affected system operators provide credits for transmission 
service taken on an affected system. Id. P 42. Even if the 
interconnection customer does not take transmission service over the 
affected system, however, the affected system operator must still 
provide the 20-year balloon payment to refund any remaining balance 
to the interconnection customer. Order No. 2003-C, 111 FERC ] 61,401 
at P 13.
    \108\ Order No. 2003, 104 FERC ] 61,103 at n.111.
    \109\ Order No. 2003-A, 106 FERC ] 61,220 at P 613.
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(a) Crediting Policy
    102. The Commission instituted the crediting policy to achieve 
multiple objectives. First, the Commission found that this policy would 
avoid prohibited ``and'' pricing for interconnection-related network 
upgrades because it ensures that the interconnection customer will not 
be charged twice for the use of the transmission system by paying both 
for the incremental cost of the upgrade and an embedded-cost rate (with 
the cost of that interconnection-related network upgrade rolled in) for 
use of the transmission system.\110\ Also, the Commission stated that 
the crediting policy was intended to facilitate the efficient 
construction of interconnection-related network upgrades and enhance 
competition in bulk power markets by promoting the construction of new 
generation \111\ Furthermore, the Commission found that the crediting 
policy would ensure comparable treatment for interconnection customers 
that are not affiliated with the transmission provider, as transmission 
providers traditionally roll the costs of interconnection-related 
network upgrades associated with their own generating facilities into 
their transmission rates.\112\
---------------------------------------------------------------------------

    \110\ Order No. 2003, 104 FERC ] 61,103 at P 694.
    \111\ Id. PP 612, 694.
    \112\ Id. P 694.
---------------------------------------------------------------------------

    103. Additionally, in Order No. 2003-A, the Commission stated that 
it does ``not believe that the costs of [interconnection-related] 
Network Upgrades required to interconnect a Generating Facility to the 
Transmission System of a non-independent Transmission Provider are 
properly allocable to the Interconnection Customer through direct 
assignment because upgrades to the transmission grid benefit all 
customers.'' \113\ The Commission also stated that the crediting policy 
has a two-fold purpose. First, by providing the transmission provider 
with a source of funds to construct the interconnection-related network 
upgrades, the upfront payment by the interconnection customer 
alleviates any delay that might result if the transmission provider 
were forced to secure funding elsewhere. Second, by placing the 
interconnection customer initially at risk for the full cost of the 
interconnection-related network upgrades, the upfront payment provides 
the interconnection customer with a strong incentive to make efficient 
siting decisions and, in general, to make good faith requests for 
interconnection service.\114\
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    \113\ Order No. 2003-A, 106 FERC ] 61,220 at P 212. As noted in 
the discussion below on participant funding, the Commission has 
allowed direct assignment of interconnection-related network upgrade 
costs to generators interconnecting to independent transmission 
providers such as RTOs/ISOs.
    \114\ Id. P 613.
---------------------------------------------------------------------------

    104. In NARUC v. FERC,\115\ multiple petitioners challenged the 
crediting policy established in Order No. 2003. The petitioners argued 
that the crediting policy was inconsistent with the cost causation 
principle because they disagreed with the Commission's conclusions that 
``[interconnection-related] Network Upgrades benefit the entire 
network,'' \116\ and therefore, all transmission customers should 
essentially pay for those interconnection-related network upgrades 
through the crediting policy.\117\ The U.S. Court of Appeals for the 
District of Columbia Circuit (D.C. Circuit) agreed with the 
Commission's position and noted that the D.C. Circuit had previously 
``endorsed the approach of `assign[ing] the costs of system-wide 
benefits to all customers on an integrated transmission grid.' '' \118\
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    \115\ 475 F.3d 1277.
    \116\ Id., 475 F.3d at 1285.
    \117\ Id. (citing Pub. Serv. Co. of Colo., 62 FERC ] 61,013, at 
61,061 (1993)).
    \118\ Id. (citing W. Mass. Elec. Co. v. FERC, 165 F.3d 922, 927 
(DC Cir. 1999)).
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(b) Participant Funding
    105. In Order No. 2003, the Commission stated that ``under the 
right circumstances, a well-designed and independently administered 
participant funding policy for [interconnection-related] Network 
Upgrades offers the potential to provide more efficient price signals 
and a more equitable allocation of costs than the crediting approach.'' 
\119\ Therefore, the Commission stated that it would provide RTOs/ISOs 
with the flexibility to propose participant funding for 
interconnection-related network upgrades for a generator 
interconnection.\120\ In accordance with this flexibility, the 
Commission did not prescribe specific policies for RTOs/ISOs but 
instead provided them with the flexibility to adopt policies of their 
own choosing, subject to Commission approval.\121\ Over time, each RTO/
ISO sought, and the Commission accepted, independent entity variations 
to adopt some form of participant funding rather than the crediting 
policy.
---------------------------------------------------------------------------

    \119\ Order No. 2003, 104 FERC ] 61,103 at P 695.
    \120\ Id. P 28.
    \121\ Order No. 2003-A, 106 FERC ] 61,220 at P 696.
---------------------------------------------------------------------------

    106. The Commission expressed its willingness to consider a well-
designed participant funding approach in response to commenter concerns 
that the crediting policy ``mutes somewhat the Interconnection 
Customer's incentive to make an efficient siting decision that takes 
new transmission costs into account, and it provides the 
Interconnection Customer with what many view as an improper subsidy, 
particularly when the Interconnection Customer chooses to sell its 
output off-system.'' \122\ Additionally, while the Commission mandated 
the crediting policy for non-independent transmission providers, Order 
No. 2003 acknowledged that the concerns that gave rise to the adoption 
of the crediting policy do not apply to RTOs/ISOs. For example, Order 
No. 2003 noted that ``a number of aspects of the `but for' approach are 
subjective, and a Transmission Provider that is not an independent 
entity has the ability and the incentive to exploit this subjectivity 
to its own advantage'' by, for example, finding ``that a 
disproportionate share of the costs of expansions needed to serve its 
own power customers is attributable to competing Interconnection 
Customers.'' \123\ In contrast, however, the Commission noted that RTOs 
and ISOs are independent, and neither own nor have affiliates that own 
generating facilities and thus do not have an incentive to discourage 
new generation by competitors.\124\
---------------------------------------------------------------------------

    \122\ Order No. 2003, 104 FERC ] 61,103 at P 695.
    \123\ Id. n.111.
    \124\ Order No. 2003-A, 106 FERC ] 61,220 at P 691.
---------------------------------------------------------------------------

    107. The Commission also explained that participant funding might 
speed up the development of new transmission infrastructure. In 
particular, Order No. 2003 postulated that ``participant

[[Page 40284]]

funding of [interconnection-related network] upgrades may provide the 
pricing framework needed to overcome the reluctance of incumbent 
Transmission Owners in many parts of the country to build transmission, 
with the result that badly needed transmission infrastructure could be 
put in place quickly.'' \125\
---------------------------------------------------------------------------

    \125\ Order No. 2003, 104 FERC ] 61,103 at P 703.
---------------------------------------------------------------------------

    108. RTOs/ISOs that have adopted a participant funding approach do 
not reimburse interconnection customers with transmission service 
credits for the cost of the interconnection-related network upgrades. 
Instead, the Commission allowed interconnection customers to receive 
well-defined capacity rights that are created by the interconnection-
related network upgrades.\126\ As an example, the Commission in Order 
No. 2003 pointed to PJM Firm Transmission Rights and Capacity 
Interconnection Rights, which, it stated, are ``created by the 
[interconnection-related] Network Upgrades for which the 
Interconnection Customer pays, and they are well-defined, long-term and 
tradeable.'' \127\ The Commission stated that provision of such ``well-
defined capacity rights'' in lieu of credits does not violate the 
prohibition of ``and'' pricing because the ``Interconnection Customer 
pays separate charges for separate services,'' namely ``an access 
charge for transmission service that may involve an obligation to pay 
congestion charges, and in exchange for its `but for' payment, [the 
interconnection customer] receives these well-defined capacity rights, 
which provide some protection for having to actually pay the congestion 
charges.'' \128\
---------------------------------------------------------------------------

    \126\ Id. P 700.
    \127\ Id.
    \128\ Id.
---------------------------------------------------------------------------

    109. Commission precedent makes clear that the purpose of providing 
``well-defined'' rights is not to provide full reimbursement for the 
costs of interconnection-related network upgrades. In fact, where an 
RTO/ISO adopts a participant funding approach for interconnection-
related network upgrades required to interconnect an interconnection 
customer, there is no requirement that the capacity rights being 
awarded for interconnection-related network upgrades have equal value 
to the cost of the interconnection-related network upgrades because the 
costs would not exist ``but for'' the proposed interconnection and are 
simply part of a project's construction costs and business risk that 
the interconnection customer must consider.\129\ Moreover, RTOs/ISOs 
are ``not required to provide transmission capacity rights where . . . 
the network upgrades create no additional transmission capability.'' 
\130\ To this point, the Commission in Old Dominion Electric 
Cooperative v. PJM Interconnection, L.L.C. explained that, while Order 
No. 2003 ``stated that generation interconnection customers would 
receive capacity rights, those statements were based on the assumption 
that a network upgrade provided by an interconnection customer would 
create additional transmission capability beyond that needed to simply 
interconnect with the grid.'' \131\
---------------------------------------------------------------------------

    \129\ PJM Interconnection, L.L.C., 108 FERC ] 61,025, at P 20 
(2004); see also Midwest Indep. Transmission Sys. Operator, Inc., 
114 FERC ] 61,106, at P 66 (2006).
    \130\ Old Dominion Elec. Coop. v. PJM Interconnection, L.L.C., 
119 FERC ] 61,052, at P 18 (2007) (ODEC v. PJM).
    \131\ ODEC v. PJM, 119 FERC ] 61,052 at P 18; see also id. P 16 
(``Not every system upgrade required simply to interconnect a 
generating facility safely to the grid entitles the generator to 
capacity rights; however, a generation interconnection customer 
would be `allowed to receive' capacity rights if a [interconnection-
related] network upgrade creates additional transmission 
capability.'').
---------------------------------------------------------------------------

    110. Again, each RTO/ISO sought an independent entity variation to 
adopt a participant funding approach rather than adopt the crediting 
policy. In MISO, an interconnection customer is responsible for 100% of 
interconnection-related network upgrade costs, with a possible 10% 
reimbursement or ``crediting'' for interconnection-related network 
upgrades that are 345 kV and above.\132\ In CAISO, the interconnection 
customer's cost responsibility for a particular interconnection-related 
network upgrade depends on how CAISO classified the interconnection-
related network upgrade (i.e., whether the interconnection-related 
network upgrade is considered area, local, or reliability) and the 
interconnection-related network upgrade's deliverability status (e.g., 
full capacity, partial capacity, or energy-only).\133\ In CAISO, full 
cash reimbursement is only available for the costs of certain 
categories of interconnection-related network upgrades, up to $60,000 
per MW of installed generation capacity, and interconnecting generators 
receive congestion revenue rights in exchange for funding any upgrades 
that are not eligible for cash reimbursement. SPP, NYISO, PJM, and ISO-
New England, Inc. use a participant funding approach where the 
transmission provider assigns 100% of the interconnection-related 
network upgrade costs to the interconnection customer and the 
interconnection customer may receive compensation through transmission 
capacity rights.\134\
---------------------------------------------------------------------------

    \132\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 164 
FERC ] 61,158, at P 5 (2018) (``MISO's Interconnection Customer 
Funding Policy . . . requiring the interconnection customer to 
`participant fund' 90-100 percent of its [interconnection-related] 
network upgrades . . . was accepted, under the Order No. 2003 
independent entity variation standard in 2009.''); Midwest Indep. 
Transmission Sys. Operator, Inc., 129 FERC ] 61,060, at P 8 (2009) 
(accepting MISO's ``proposed change [that] would result in the 
interconnection customer bearing 100 percent of the costs of 
[interconnection-related] network upgrades rated below 345 kV and 
bearing 90 percent of the costs of [interconnection-related] network 
upgrades rated at 345 kV and above (with the remaining 10 percent 
being recovered on a system-wide basis'')); Midwest Indep. Trans. 
Sys. Operator, Inc., 114 FERC ] 61,106, at P 62 (2006).
    \133\ Cal. Indep. Sys. Operator Corp., 140 FERC ] 61,070, at PP 
24-27 (2012).
    \134\ PJM Interconnection, L.L.C., 108 FERC ] 61,025 (2004); Sw. 
Power Pool, Inc., 127 FERC ] 61,283 (2009); Sw. Power Pool, Inc., 
171 FERC ] 61,272 (2020); N.Y. Indep. Sys. Operator, Inc., 108 FERC 
] 61,159 (2004), order on reh'g, 111 FERC ] 61,347 (2005); ISO New 
Eng. Inc., 133 FERC ] 61,229 (2010).
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b. Potential Need for Reform
i. Participant Funding
    111. Since the issuance of Order No. 2003, changing circumstances 
have cast doubt on whether it continues to be just and reasonable to 
provide RTOs/ISOs with the flexibility to adopt participant funding 
approaches for interconnection-related network upgrades. We seek 
comment on whether these developments suggest that the allowance of 
participant funding for interconnection-related network upgrades, both 
as a concept and in its application, may no longer be just and 
reasonable. Moreover, it appears that the incentives created by 
participant funding in this context may produce outcomes that are 
counter to the Commission's intentions in allowing flexibility for 
RTOs/ISOs to adopt participant funding in Order No. 2003.
    112. To begin with, participant funding may allocate the costs of 
extensive interconnection-related network upgrades entirely to 
interconnection customers without accounting for the significant 
benefits that these interconnection-related network upgrades may 
provide to transmission customers. As a result, there are circumstances 
where this allocation of interconnection-related network upgrade costs 
may not be roughly commensurate with the distribution of benefits. For 
instance, a large interconnection-related network upgrade built on a 
consistently congested portion of the transmission system may provide 
significant

[[Page 40285]]

economic and reliability benefits to transmission customers. Also, 
transmission customers, in some instances, can make use of any excess 
transmission capacity created by a participant funded interconnection-
related network upgrade without paying any of the capital costs that 
are paid for through a participant funding approach. Allowing 
transmission customers to receive the benefits of interconnection-
related network upgrades without paying for a proportionate share of 
their costs is an example of the ``free rider'' problem that the 
Commission's ``beneficiary pays'' cost causation principle is supposed 
to avoid.\135\
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    \135\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 562 
(``Given the nature of transmission operations, it is possible that 
an entity that uses part of the transmission grid will obtain 
benefits from transmission facility enlargements and improvements in 
another part of that grid regardless of whether they have a contract 
for service on that part of the grid and regardless of whether they 
pay for those benefits. This is the essence of the `free rider' 
problem the Commission is seeking to address through its cost 
allocation reforms.'').
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    113. Furthermore, while the interconnection customer may receive 
well-defined capacity rights associated with the increased transfer 
capability caused by the interconnection-related network upgrade, these 
well-defined capacity rights do not compensate the interconnection 
customer for the broad range of benefits that the interconnection-
related network upgrades can provide to the transmission system and 
therefore do not solve the ``free rider'' problem. This is because the 
well-defined capacity rights do not capture reductions in congestion 
costs paid by transmission customers that were the result of the 
expansion of the transfer capability created by the interconnection-
related network upgrade; nor do they capture transmission service 
charges for use of the excess capacity created by the interconnection-
related network upgrade. Instead, well-defined capacity rights capture 
congestion costs paid by transmission customers on a going forward 
basis across the relevant transmission path on which the 
interconnection-related network upgrade increased transmission 
capacity. To the extent that the interconnection-related network 
upgrade may have eliminated most of the ex ante congestion on the 
relevant paths, the transmission customers that transact across such 
paths and have their congestion costs reduced as a result of the large 
interconnection-related network upgrade now in service will receive 
this benefit for free in most cases.
    114. We seek comment on whether costs allocated to interconnection 
customers pursuant to participant funding approaches have increased 
over time, and if so, why. We seek comment on whether this increase in 
costs is evidence that regional transmission planning processes are not 
building adequate transmission system capacity. We seek comment on 
whether the Commission's policies on participant funding have impacted 
the interconnection queue, e.g., through late-state withdrawals, and if 
so, how and to what degree. In the case that there are late-stage 
withdrawals from the interconnection queue, we seek comment on the 
ability of transmission providers to efficiently process 
interconnection requests from other interconnection customers affected 
by the withdrawal. Finally, we seek comment on whether uncertainty 
regarding interconnection costs drives up the cost of developing supply 
resources and thereby ultimately increases the cost of electricity 
supply for customers.
    115. Participant funding also may create a separate incentive for 
the interconnection customer that may undermine the development of 
interconnection-related network upgrades that produce greater benefits. 
Specifically, the interconnection customer, knowing that it will be 
responsible for all interconnection-related network upgrade costs, is 
likely to strongly oppose any addition or modification to the 
transmission system beyond what is necessary to support its own 
interconnection, even if such additions and modifications may 
ultimately benefit it and others by providing improved reliability or 
economic outcomes.\136\
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    \136\ See Review of Generator Interconnection Agreements and 
Procedures, Technical Conference Transcript, Docket No. RM16-12-000 
at Tr: 193: 20-24 (Steve Naumann, Exelon) (filed Aug. 23, 2016) 
(``[Y]ou need to also deal with the [interconnection] customer who 
says, `Okay, I will be perfectly willing to take the risk, but I 
don't want to pay for a single upgrade more than I have to [to] have 
a the reliability interconnection.'').
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    116. An additional rationale that the Commission provided in Order 
No. 2003 for allowing participant funding was the concern that the 
interconnection crediting policy would ``mute somewhat the 
Interconnection Customer's incentive to make an efficient siting 
decision that takes transmission costs into account.'' \137\ The 
Commission in Order No. 2003 also found that participant funding in 
RTOs/ISOs is consistent with the policy of promoting competitive 
wholesale markets because it causes the interconnection customer to 
face the same marginal cost price signal that it would face in a 
competitive market.\138\ We seek comment on whether to reconsider these 
findings in light of current circumstances.
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    \137\ Order No. 2003, 104 FERC ] 61,103 at P 695.
    \138\ Id. P 702.
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    117. We note, for instance, that the Commission's view of efficient 
siting of generation in Order No. 2003 was from a transmission costs 
perspective, i.e., which points of interconnection would require the 
least expensive interconnection-related network upgrades. We seek 
comment on whether this perspective may be at odds with the primary 
siting considerations for renewable generation developers decades 
later. That is, interconnection at locations where renewable generation 
may experience higher efficiency factors (e.g., because they have 
abundant wind or sun) may still be uneconomic where participant funding 
applies because the costs of interconnection-related network upgrades 
for that location may be significant and would not be allocated beyond 
the interconnection customer. We seek comment on whether 
interconnection at such locations may be considered economic, however, 
if the cost of the interconnection-related network upgrades were 
allocated more broadly among those that benefit. Thus, because the 
price signal participant funding sends does not account for the broader 
economic efficiencies from siting renewable generation in fuel-rich 
areas, it can instead encourage the development of renewable generation 
in less productive locations. Because increased renewable resource 
penetration in RTOs/ISOs is likely to continue, it may make less sense 
to retain a policy that encourages renewable developers to develop 
lower quality, less dependable renewable resources.
    118. Further, given the uncertainty created by the RTO/ISO queue 
backlogs and cascading interconnection-related network upgrade cost 
allocations that move from withdrawing higher-queued interconnection 
customers to lower-queued interconnection customers, participant 
funding may no longer provide efficient price signals that allow 
generators to act freely to achieve the desirable level of entry of new 
cost-effective generating capacity. We understand that a contributing 
factor to the interconnection queue backlog is a tendency by 
interconnection customers to submit multiple interconnection requests 
at different points of interconnection, with the intention of 
discovering the lowest cost site for a

[[Page 40286]]

project (from an interconnection perspective), and then withdrawing 
higher-cost projects from the queue later in the process. This tendency 
can require numerous restudies and reallocation of interconnection-
related network upgrade costs, compounding the uncertainty surrounding 
the amount of interconnection-related network upgrade costs that will 
be attributable to viable projects as the queue progresses.
    119. We seek comment on whether it is appropriate to eliminate or 
reduce participant funding for interconnection-related network upgrades 
in RTOs/ISOs and whether any specific proposed changes to 
interconnection funding mechanisms allocate costs in a manner roughly 
commensurate with benefits and are otherwise consistent with the 
Commission's authority under the FPA and do not unjustly or 
unreasonably shift costs to customers of load serving entities.
ii. Crediting Policy
    120. We seek comments on whether we should revisit the crediting 
policy in all regions by requiring that transmission providers, instead 
of interconnection customers, fund upfront all or a portion of the 
interconnection-related network upgrade costs. We describe multiple 
variations of this proposal below. Some generation developers may find 
it difficult to provide upfront funding for the costs of network 
upgrades when the reimbursement period can be as long as 20 years. 
Accordingly, we seek comment on whether the current approach may 
unjustly and unreasonably allocate significant financing costs for 
interconnection-related network upgrades to interconnection customers 
when the benefits of the interconnection-related network upgrades 
accrue to the broader system. We seek comment on whether, if 
interconnection-related network upgrade costs are increasing on 
average, it is possible that these upfront funding costs may pose an 
unjust and unreasonable barrier to entry for generation developers. 
Given these considerations, below we seek comment on some potential 
reforms to the crediting policy.
c. Potential Reforms and Request for Comment
    121. We seek comment on whether the Commission should eliminate the 
independent entity variations that allow RTOs/ISOs to use participant 
funding for interconnection-related network upgrades. We also seek 
comment on potential approaches for modifying or replacing the existing 
crediting policy for the costs of interconnection-related network 
upgrades in all regions. We seek comment on these options and invite 
alternative suggestions by commenters that take into consideration the 
concerns discussed above.
    122. Additionally, for each of the reforms contemplated below, we 
seek comment on whether there are articulable and plausible reasons to 
believe that these reforms would allocate the costs of interconnection-
related network upgrades in a manner that is at least roughly 
commensurate with the benefits of those interconnection-related network 
upgrades and that do not unjustly and unreasonably shift costs to 
customers of load serving entities or are otherwise inconsistent with 
the Commission's statutory authority.
i. Eliminate Participant Funding for Interconnection-Related Network 
Upgrades
    123. We seek comment on whether participant funding of 
interconnection-related network upgrades may be unjust and 
unreasonable. We seek comment on whether RTOs/ISOs with previously 
approved independent entity variations that directly assign some or all 
the cost responsibility for interconnection-related network upgrades to 
interconnection customers should be required to revise their tariffs to 
remove the participant funding of interconnection-related network 
upgrade requirements and instead implement the crediting policy as 
prescribed in the pro forma LGIA.
    124. The potential proposal to eliminate participant funding of 
interconnection-related network upgrades in RTOs/ISOs would recognize, 
however, that simply because an interconnection request makes an 
interconnection-related network upgrade necessary for interconnection 
(and in that sense, ``causes'' the need for interconnection-related 
network upgrades that would not be needed ``but for'' an 
interconnection request), an interconnection-related network upgrade 
may sufficiently benefit transmission customers that it is appropriate 
to allocate the interconnection-related network upgrade costs more 
broadly. Also, this potential proposal could address the free rider 
problem that is created by participant funding of interconnection-
related network upgrades. We note, however, that the specific proposal 
is to eliminate participant funding and replace it with the crediting 
policy, a pricing approach that still requires interconnection 
customers to initially fund interconnection-related network 
upgrades.\139\ Moreover, no potential reform presented here would 
modify the existing requirement that an interconnection customer bear 
cost responsibility for the interconnection facilities that would not 
be needed but for its interconnection request.
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    \139\ As noted below, however, we are exploring reforms to the 
existing crediting policy approach (that could be adopted alone or 
in combination with the elimination of participant funding) that 
could reduce the level of upfront funding to be provided by the 
interconnection customers.
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    125. We seek comment on whether the removal of participant funding 
of interconnection-related network upgrades may also have the potential 
to increase integration of generation by removing the possibly 
prohibitive cost assignment that participant funding can place on some 
interconnection customers. Furthermore, it may reduce cost uncertainty 
to those resources in the interconnection queue, and by extension, 
increase the likelihood that an interconnection request will result in 
a developed generating facility.\140\
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    \140\ See, e.g., Review of Generator Interconnection Agreements 
and Procedures, Technical Conference Transcript, Docket No. RM16-12-
000, at Tr. 25: 8-15 (May 13, 2016) (Dean Gosselin, NextEra) (filed 
Aug. 23, 2016) (``I'd like to just talk about what is optimal . . . 
as a developer . . . trying to advance [a project] to fruition . . . 
. I would say for the interconnection queue that the initial results 
closely match final results in a defined and reasonable timeline, 
that would be my definition.''); id. at 134:5-7 (Omar Martino, EDF 
Renewable Energy) (``[C]osts can change dramatically between [the] 
system impact and [the] facility study.'').
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    126. Additionally, we seek comment on whether eliminating 
participant funding may reduce the queue backlogs that plague many 
regions because interconnection customers would have less incentive to 
submit multiple interconnection requests in an attempt to lower their 
interconnection costs, and may no longer drop out of interconnection 
queues at late stages due to unforeseen interconnection-related network 
upgrade cost increases. To these points, we seek comment on the number 
of interconnection requests that have withdrawn from the queue because 
the direct assignment of significant interconnection-related network 
upgrade costs made otherwise viable interconnection requests 
uneconomic.
    127. We seek comment on whether the independent entity variation 
granted to RTOs/ISOs in Order No. 2003 is no longer just and 
reasonable. In general, we seek comment on whether the incentives 
created by participant funding of interconnection-related network 
upgrades in RTOs/ISOs may produce outcomes that are counter to the 
Commission's transmission planning and cost allocation efforts.

[[Page 40287]]

    128. We are aware that there could be complications associated with 
implementing the crediting policy in RTOs/ISOs with zonal transmission 
rates that do not occur outside RTOs/ISOs. Outside RTOs/ISOs, a single 
transmission provider owns and operates its transmission system and 
generally charges a single rate for the entire system, regardless of 
the specific transmission customer's location. In contrast, an RTO/ISO 
operates the combined transmission assets of multiple transmission 
owners within its footprint at non-pancaked transmission rates, and 
generally has separate transmission pricing zones. The transmission 
rates for each zone are generally designed to recover the costs of 
transmission facilities located within each zone. As a result, we seek 
comment on whether simply applying the crediting policy currently used 
outside RTOs/ISOs in RTOs/ISOs may disproportionately increase the 
burden to the native load of transmission zones where large amounts of 
interconnection-related network upgrades are constructed to facilitate 
the interconnection of location-constrained resources, which ultimately 
may benefit the entire RTO/ISO footprint.
    129. Under a crediting policy in an RTO/ISO, there may be a need 
for an appropriate mechanism to reimburse the interconnection 
customers, including a mechanism for determining which transmission 
owner(s) or zonal transmission rates will include the interconnection-
related network upgrade costs. For example, there is a question of 
whether it would be just and reasonable to allocate the costs only 
within the transmission zone where the interconnection-related network 
upgrade is located or more broadly to multiple transmission zones.\141\ 
We therefore seek comment on how to implement the crediting policy in 
RTOs/ISOs and what principles should be used to guide the application 
of the crediting policy in RTOs/ISOs.
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    \141\ See, e.g., Interstate Power & Light Co. v. ITC Midwest, 
LLC, 144 FERC ] 61,052, at P 40 (2013), order on reh'g, 
clarification and compliance, 146 FERC ] 61,113 (2014). See also Sw. 
Power Pool, Inc., 127 FERC ] 61,283, at P 5 (2009).
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    130. Finally, given the concerns about the free-rider problem and 
whether the ``well-defined capacity rights'' received by 
interconnection customers capture the benefits the interconnection-
related network upgrades provide to the system, we seek comment on: (1) 
The value of the ``well-defined capacity rights'' that interconnection 
customers have received for funding interconnection-related network 
upgrades; and (2) the value of the benefits that interconnection-
related network upgrades have provided to the system, such as the value 
of congestion relieved by interconnection-related network upgrades. We 
are also interested in any other concerns related to the ``well-defined 
capacity rights'' that interconnection customers receive and the 
ability of these ``well-defined capacity rights'' to reflect the value 
of the full incremental capacity and congestion benefits added to the 
transmission system by the interconnection-related network upgrades.
ii. Revisions to the Existing Crediting Policy
    131. We seek comment on possible revisions to the Order No. 2003 
interconnection crediting policy, which requires that interconnection 
customers provide upfront funding for interconnection-related network 
upgrades and receive reimbursement through transmission service credits 
or a balloon payment after 20 years. We enumerate multiple proposals 
below. Not all of these proposals are mutually exclusive, and some 
could be implemented in tandem.
(a) Transmission Providers Provide Upfront Funding for All 
Interconnection-Related Network Upgrades
    132. Pursuant to this potential proposal, each transmission 
provider would provide upfront funding for all the interconnection-
related network upgrades on its transmission system. Then, once such an 
interconnection-related network upgrade is in service, the transmission 
provider would be able to include the cost of that interconnection-
related network upgrade in its transmission service rate base and 
recover a return on, and of, the network upgrade capital costs through 
the cost-of-service transmission rates in its OATT. Thus, 
interconnection customers that take transmission service on a 
transmission system would still pay for a portion of interconnection-
related network upgrades through transmission rates. We seek comment on 
(1) this approach and (2) how this approach could be implemented in a 
just and reasonable manner.
    133. This option would reduce the initial financing burden that 
interconnection customers currently may encounter when significant 
interconnection-related network upgrades are required for their 
interconnection request. Furthermore, this option may increase 
generator competition by lowering barriers to entry, which in turn will 
benefit customers by creating a more competitive market for energy.
    134. There may also be additional efficiency benefits to removing 
the crediting policy because the financing of interconnection-related 
network upgrades would follow the same financing process that the 
transmission owners apply to the other transmission infrastructure that 
they fund and build on their system. That is, there could be an 
efficiency gain from using one financing process for all transmission 
system facilities instead of the existing two: one for interconnection-
related network upgrades and another for other transmission system 
facilities. In addition to that particular inefficiency, under the 
current crediting approach applied in non-RTO/ISO regions, each 
interconnection-related network upgrade is financed twice--initially by 
the interconnection customer and then again by the transmission 
provider when the interconnection customer receives credits as it takes 
transmission service or receives a balloon payment after 20 years. 
Without the initial funding by the interconnection customer, 
interconnection-related network upgrades would only need to be financed 
once.
(b) Interconnection Customers Contribute to the Upfront Funding of 
Interconnection-Related Network Upgrades Through a Fee
    135. Another possible reform to the current crediting policy is to 
consider the establishment of a non-refundable fee to be charged for 
submitting an interconnection request and that is not reimbursable 
through transmission service credits. Under this approach, an 
appropriate fee should not be so large that it creates barriers to 
entry for smaller developers. Potential benefits of this type of fee 
could include: (1) Defraying some of the cost to transmission customers 
for interconnection-related network upgrades and therefore decreasing 
the overall impact on transmission customers of the related potential 
reform to eliminate participant funding of interconnection-related 
network upgrades in RTOs/ISOs; (2) discouraging the submission of 
speculative interconnection requests; and (3) for some variable fees, 
providing a price signal to interconnection customers that could incent 
efficient siting decisions where possible. We seek comment on (1) 
whether to impose a non-refundable, non-reimbursable fee on each 
submitted interconnection request and (2) how this approach could be 
implemented in a just and reasonable manner.

[[Page 40288]]

    136. We seek comment on two specific versions of this approach. 
First, we seek comment on the potential establishment of a fixed fee 
applied to each interconnection request, which would be the same for 
all interconnection requests, irrespective of the generating facility's 
capacity or project location. We seek comment on whether establishing a 
fixed fee would be appropriate and, if so, the appropriate amount of 
such a fee.
    137. Second, we seek comment on the potential establishment of a 
variable fee applied to each interconnection request. The amount of the 
variable fee could depend upon the generating facility capacity 
associated with the interconnection request and/or the identified 
interconnection-related network upgrades. For example, the fee could be 
based on a percentage of the estimated interconnection-related network 
upgrade costs or be calculated based on the generating facility 
capacity and/or the voltage rating of the interconnection-related 
network upgrade. We seek comment on the appropriate size of this fee 
and the structure of the fee, if the Commission were to require one. We 
also seek comment on whether it is possible to use a percentage of 
interconnection-related network upgrade cost estimates for this fee, 
and if so, at which point in the generator interconnection process a 
transmission provider would calculate that cost.
    138. Finally, we seek comment on whether such a fee should be 
established at the outset of the generator interconnection process, or 
whether an escalating fee should be imposed as the interconnection 
request moves through the study process. For example, a smaller fee 
could be required for entry into the feasibility study phase, with a 
larger fee for the system impact study phase and the largest fee 
required to enter the facilities study.\142\ In this manner, 
speculative projects could be discouraged from entering the later 
stages of the generator interconnection process, while still allowing 
interconnection customers to use the feasibility study process as it 
was designed, to determine project feasibility for a broader range of 
project sizes and locations.
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    \142\ These non-refundable fees would be in addition to, and 
distinct from, the initial deposit submitted with an interconnection 
request and study deposits that are applied toward an 
interconnection customer's interconnection study costs.
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(c) Transmission Providers Provide Upfront Funding for Only Higher 
Voltage Interconnection-Related Network Upgrades
    139. We seek comment on whether it would be appropriate to require 
transmission providers to fund upfront the costs of any 
interconnection-related network upgrade that is rated at or above a 
certain voltage threshold. Interconnection customers would be 
responsible for upfront funding the cost of interconnection-related 
network upgrades below that threshold and be reimbursed through 
transmission service credits pursuant to the crediting policy.
    140. Because higher voltage transmission facilities tend to produce 
greater and broader benefits to transmission systems than lower voltage 
transmission facilities, this option may better satisfy the requirement 
that the allocation of costs be at least roughly commensurate with the 
distribution of benefits.\143\ Thus, where an interconnection-related 
network upgrade's voltage exceeds a defined threshold and is likely to 
produce system-wide benefits, it may be appropriate to require that 
transmission providers fund the costs of such interconnection-related 
network upgrades upfront.
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    \143\ See, e.g., Old Dominion Elec. Coop. v. FERC, 898 F.3d 
1254, 1260 (D.C. Cir. 2018) (adopting Commission finding that 
``high-voltage power lines produce significant regional benefits'').
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    141. The Commission could also adopt a modified version of this 
approach by requiring transmission providers to upfront fund the 
portion of the costs of higher voltage interconnection-related network 
upgrades that exceeds a pre-determined cost threshold. For example, the 
Commission could require transmission providers to upfront fund the 
costs of a 345 kV interconnection-related network upgrade that exceed 
$10 million. Pursuant to this modified version, in this example of a 
345 kV interconnection-related network upgrade, the Commission would 
require the interconnection customer to fund all network upgrade costs 
up to $10 million and require the transmission provider to provide 
upfront funding for all interconnection-related network upgrade costs 
above the $10 million threshold. Even in this situation, however, the 
transmission provider would still have to provide transmission service 
credits to reimburse the interconnection customer for its $10 million 
subject to the crediting policy.
    142. We note that the Commission has approved a version of this 
cost sharing approach in MISO, albeit in the context of responsibility 
for payment of interconnection-related network upgrade costs themselves 
and not just the upfront funding of them as discussed here. MISO's 
tariff provides for some cost sharing for interconnection-related 
network upgrades under which transmission providers recover the costs 
of 10% of interconnection-related network upgrades rated 345 kV and 
above on a system-wide basis while directly assigning through 
participant funding 90% of the costs of such upgrades to the 
interconnection customer whose interconnection required the network 
upgrade.\144\ Furthermore, on multiple occasions, the Commission has 
permitted RTOs/ISOs to define different transmission facility 
categories and adopt different cost allocation methods for transmission 
facilities based on the transmission facility's voltage threshold.\145\
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    \144\ MISO Tariff, Attach. FF (Transmission Expansion Planning 
Protocol), Section III.A2.d (81.0.0).
    \145\ See Midcontinent Indep. Sys. Operator, Inc., 172 FERC ] 
61,095 (2020) (accepting MISO's proposal to change the qualifying 
voltage threshold for a certain class of project from 345 kV to 230 
kV).
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    143. If the Commission were to split the upfront funding 
responsibility for interconnection-related network upgrades between the 
transmission provider and the interconnection customer, it may be 
useful to create a split based on voltage. For example, adopting an 
interconnection-related network upgrade voltage threshold to be funded 
upfront by the transmission provider has the potential to significantly 
reduce interconnection-related network upgrade financing costs by 
eliminating interconnection customers' need to fund upfront the likely 
more expensive higher voltage interconnection-related network upgrades. 
It could be appropriate to require the transmission provider to fund 
upfront the cost of higher voltage interconnection-related network 
upgrades because higher voltage transmission facilities are likely to 
produce greater region-wide benefits than lower voltage ones.
    144. Whatever the selected voltage threshold might be, 
interconnection customers would still be required to upfront fund the 
costs of interconnection-related network upgrades (subject to the 
crediting policy) that do not meet that threshold. Thus, the selection 
of a voltage threshold would necessarily exclude from transmission 
provider upfront funding some interconnection-related network upgrades 
that produce regional

[[Page 40289]]

transmission benefits. We think it important to ensure that, if the 
Commission requires that transmission providers establish a voltage 
threshold for sharing the responsibility to fund upfront the cost of 
interconnection-related network upgrades, then the voltage threshold 
should be based upon the likelihood that interconnection-related 
network upgrades that meet that threshold produce more transmission 
benefits than interconnection-related network upgrades below that 
threshold. Furthermore, we recognize that there is some tension between 
such an approach, which would eliminate the requirement that 
interconnection customers upfront fund some interconnection-related 
network upgrades based on voltage, thus reducing the interconnection 
customers' financing costs only on larger interconnection-related 
network upgrades, and Order No. 2003's general acknowledgement that 
interconnection-related network upgrades, regardless of voltage or 
size, ``benefit all users.'' \146\ Additionally, if the Commission 
adopted this option, in order to avoid the responsibility to upfront 
fund, transmission providers will have an incentive to identify a lower 
voltage interconnection-related network upgrade rather than identifying 
a higher voltage project that may be more efficient or cost-effective.
---------------------------------------------------------------------------

    \146\ Order No. 2003, 104 FERC ] 61,103 at P 65.
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    145. We seek comment on: (1) This approach; (2) the appropriate 
voltage threshold and any pre-determined cost threshold; and (3) how 
this approach could be implemented in a just and reasonable manner.
(d) Allocate the Upfront Cost of Interconnection-Related Network 
Upgrades on a Percentage Basis
    146. We seek comment on whether to reduce the allowable percentage 
of interconnection-related network upgrade costs that interconnection 
customers must fund upfront (i.e., from 100% to a lower percentage). 
The crediting policy would apply to the portion of the interconnection-
related network upgrade costs that the interconnection customer upfront 
funds. To allow flexibility, we seek comment on whether an 
interconnection customer should have the option to elect to upfront 
fund 100% of the interconnection-related network upgrade if it chooses.
    147. This method could benefit both the interconnection customer 
and the transmission provider. With the ability to provide partial to 
full upfront funding for interconnection-related network upgrades, 
interconnection customers will have the ability to retain some control 
over the speed of interconnection-related network upgrade construction 
because they will be able to provide initial funding in cases where the 
transmission owner does not have the funding readily on hand to pay for 
certain construction milestones. Transmission providers will benefit 
because this construct will retain the price signal to interconnection 
customers regarding siting decisions, as interconnection customers 
would still have to upfront fund (i.e., finance) the costs of more 
expensive larger interconnection-related network upgrades associated 
with their interconnection requests and the costs related to financing 
interconnection-related network upgrades (e.g., interest payments due 
on the loan) should increase as the costs of the interconnection-
related network upgrades increase.
    148. We note that adoption of the transmission planning and cost 
allocation reforms discussed above is likely to result in the 
development of regional transmission facilities intended to accommodate 
significant amounts of generation, and thus, has the potential to 
reduce the need for more extensive and costly interconnection-related 
network upgrades relative to those identified in the generator 
interconnection process at present. Thus, the adoption of this 
generator interconnection reform, in conjunction with the regional 
transmission planning and cost allocation reforms discussed above, 
could result in a significant reduction in interconnection customer 
financing costs while still maintaining a price signal for siting 
decisions.
    149. We seek comment on: (1) This approach; (2) the appropriate 
percentage for the interconnection customer's upfront funding; and (3) 
how this approach could be implemented in a just and reasonable manner. 
As part of this inquiry, we are interested in hearing perspectives on 
the extent to which partial upfront funding by an interconnection 
customer may preserve or reduce the incentive for that customer to 
efficiently site a project. We seek comment on whether there are there 
other mechanisms, beyond customer upfront funding, that may incent a 
customer to site efficiently, and that could be adopted in conjunction 
with the elimination of participant funding.
iii. Additional Considerations
(a) Interconnection-Related Network Upgrade Cost Sharing
    150. If the Commission does not eliminate participant funding of 
interconnection-related network upgrades, we seek comment regarding 
potential cost-sharing measures to account for the fact that later-in-
time interconnection customers may accrue benefits from 
interconnection-related network upgrades built to accommodate a prior 
interconnection request. That is, if a later-in-time interconnection 
customer benefits from the interconnection-related network upgrades 
required to interconnect an earlier-in-time interconnection customer, 
the later-in-time interconnection customers may also be assigned a 
portion of those costs. The transmission provider could require the 
allocation of costs in proportion to the benefits that the later-in-
time interconnection customers receive from network upgrades or be 
based on a different method, such as a percent share based on usage. To 
make this approach workable, the transmission provider could also 
dictate a point after which a later-in-time interconnection customer 
would be insulated from bearing the costs of a specific 
interconnection-related network upgrade, e.g., prohibiting allocation 
of interconnection-related network upgrade costs to interconnection 
customers that enter the queue five years or more after the 
interconnection-related network upgrade's energization.\147\ As we 
noted above, the Commission has previously approved tariff provisions 
pursuant to which earlier-in-time interconnection customers receive a 
form of reimbursement for the network upgrade costs from later-in-time 
customers.\148\ We note that the sharing of costs between earlier-in-
time and later-in-time interconnection customers would only apply in 
situations where the earlier-in-time interconnection customer was 
assigned any of the costs of the interconnection-related network 
upgrade under the participant funding framework. We seek comment on a 
just and reasonable method to calculate cost sharing for shared network 
upgrades. We also seek comment on whether to require, and the 
appropriate duration of, a time after which a later-in-time 
interconnection customer would not be

[[Page 40290]]

allocated the costs of an interconnection-related network upgrade.
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    \147\ For the purpose of this order, we will refer to this time 
period as the sunset period.
    \148\ See NYISO Tariff, attach S (Rules to Allocate 
Responsibility for the Cost of New Interconnection Facilities), 
Section 25.7.2; see also MISO Tariff, Attach. FF Section III.A.2.d.2 
(81.0.0).
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(b) Option To Build
    151. Order No. 2003 established, and Order No. 845 expanded, the 
interconnection customer's option to build transmission provider's 
interconnection facilities \149\ and stand alone network upgrades.\150\ 
In a non-RTO/ISO, if an interconnection customer elects to exercise the 
option to build, the interconnection customer assumes the 
responsibility to design, procure, and construct the transmission 
provider's interconnection facilities and stand alone network upgrades 
and is repaid by the transmission provider pursuant to the crediting 
policy.
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    \149\ Order No. 2003 defined two categories of interconnection 
facility: (1) Transmission provider's interconnection facilities, 
which refer to all facilities and equipment owned, controlled or 
operated by the transmission provider from the point of change of 
ownership to the point of interconnection, including any 
modifications, additions or upgrades to such facilities and 
equipment;'' and (2) interconnection customer's interconnection 
facilities, which are located between the generating facility and 
the point of change of ownership and which the interconnection 
customer must design, procure, construct, and own. See pro forma 
LGIA art. 1 (Definitions); pro forma LGIA art. 5.10.
    \150\ Order No. 2003, 104 FERC ] 61,103 at P 353; Reform of 
Generator Interconnection Procedures and Agreements, Order No. 845, 
163 FERC ] 61,043, at P 85 (2018), order on reh'g, Order No. 845-A, 
166 FERC ] 61,137, order on reh'g, Order No. 845-B, 168 FERC ] 
61,092 (2019). Stand alone network upgrades refer to 
interconnection-related network upgrades ``that are not part of an 
Affected System that an Interconnection Customer may construct 
without affecting day-to-day operations of the Transmission System 
during their construction. 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.'' See pro forma 
LGIP Section 1 (Definitions).
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    152. Importantly, the option to build allows interconnection 
customers to have some control over their own timelines and 
construction schedules and potentially achieve cost savings associated 
with the design, procurement, and construction of the transmission 
provider's interconnection facilities and stand alone network upgrades. 
If the Commission revises the requirement that interconnection 
customers upfront fund all or some of the costs all of interconnection-
related network upgrades, corresponding changes may be necessary to the 
option to build provisions as they apply to stand alone network 
upgrades to recognize that an interconnection customer that wants to 
exercise the option to build would no longer be responsible to upfront 
fund the full cost of those network upgrades. Therefore, we seek 
comment on what changes may be necessary to ensure that the option to 
build provisions remain just and reasonable and to retain flexibility 
for interconnection customers in light of the potential change to the 
funding policy.
(c) Interconnection Request Limit
    153. We understand that a contributing factor to the 
interconnection queue backlog is a tendency by interconnection 
customers to submit multiple interconnection requests at different 
points of interconnection, with the intention of discovering the lowest 
cost location to site the generating facility (from an interconnection 
perspective), and then withdrawing higher-cost interconnection requests 
from the queue later in the process. We also understand that, absent an 
appropriately-sized penalty (or reasonable restriction) associated with 
submitting an interconnection request and then subsequently withdrawing 
such an interconnection request, there still may be an incentive to 
submit speculative interconnection requests under any of the potential 
interconnection reforms discussed above. Therefore, we seek comment on 
whether there should penalties for submitting speculative requests, how 
such should be defined, and whether there should be a limit on the 
number of interconnection requests that a developer can submit in an 
interconnection queue study year and how narrowly such a limit should 
apply (e.g., by transmission provider or by transmission pricing zone). 
We also seek comment on how to determine a just and reasonable limit to 
the number of interconnection requests. Finally, we seek comment on how 
to address interconnection requests made by affiliated companies and 
whether those interconnection requests should count against the limit 
to the number of interconnection requests if one is imposed.
(d) Fast-Track for Interconnection of Generating Facilities Committed 
to Regional Transmission Facilities
    154. As discussed above, we seek comment on the model established 
by ERCOT to construct the CREZ transmission projects. For those 
transmission projects to be approved, ERCOT required a certain 
percentage of capacity to be reserved by generation developers with 
existing projects, projects under construction, projects with signed 
interconnection agreements, or posted collateral. In the case that this 
model may improve the coordination between transmission planning and 
the development of future generation, it may become important to 
streamline the generator interconnection process for generating 
facilities that are committed to interconnecting to these transmission 
facilities.
    155. Therefore, we seek comment on whether a fast-track generator 
interconnection process should be developed to facilitate 
interconnection of generating facilities that have firmly committed to 
connecting to new regional transmission facilities. An example of such 
a fast-track option may be to allow the transmission provider to 
perform a limited system impact study for only the cluster of 
generating facilities committed under the regional transmission 
planning process and to move to the facilities study without waiting 
for earlier studies to complete. We recognize that the timeline for 
transmission facility permitting and construction often far exceeds 
that of the generator interconnection and construction process but seek 
comment nonetheless on whether a faster generator interconnection 
process in this scenario would be beneficial.
    156. We seek comment on whether such a process would constitute 
inappropriate ``queue jumping,'' or instead would be more appropriately 
viewed as an extension of the previously approved first-ready, first-
served queueing practice. In this case, are generating facilities that 
have put up financial collateral to ensure that a regional transmission 
facility is constructed to serve them appropriately considered 
``ready'' projects? We seek comment on the feasibility of establishing 
such a proposal, as well as the implications on the rest of the 
generator interconnection queue and on any legal challenges related to 
a potential ``queue jumping'' concern.
(e) Fast-Track for Interconnection of ``Ready'' Generating Facilities
    157. In addition to considering a fast-track generator 
interconnection process for interconnection customers that have 
committed financially to new regional transmission facilities, we are 
considering whether allowing a fast-track for ``ready'' interconnection 
requests would remove barriers to entry for interconnection requests 
that have met certain readiness criteria. For example, interconnection 
requests for which the developer has already executed a power purchase 
agreement or that have been chosen in a state or utility request for 
proposals may be appropriately deemed more ``ready'' than projects that 
enter the interconnection queue without either contractual arrangement. 
Another

[[Page 40291]]

example of an interconnection request that demonstrates a higher degree 
of readiness could be one sited at a previously developed point of 
interconnection that can make use of existing interconnection 
facilities. Such interconnection requests may be considered more ready 
because they have more ready access to the transmission system. Both of 
these examples could be considered more ready than interconnection 
requests proposed at points of interconnection where the 
interconnection customer or the transmission provider must acquire new 
rights-of-way, permits, and agreements with landowners, or that face 
other obstacles to rapid development. We seek comment on which types of 
interconnection requests could be considered more ``ready'' and able to 
advance through the interconnection queue more quickly, as well as 
comments on the just and reasonable structure for such a fast-track 
option. We also seek comment on how to implement such a proposal in a 
manner that is not unduly discriminatory. As in the prior proposed 
reform, we seek comment on how to address possible concerns related to 
what some may consider ``queue jumping'' or whether appropriate factors 
may justify such measures.
(f) Grid-Enhancing Technologies
    158. We seek comment on whether there is the potential for Grid-
Enhancing Technologies not only to increase the capacity, efficiency, 
and reliability of transmission facilities, but, in so doing, also to 
reduce the cost of interconnection-related network upgrades.\151\ In 
light of the potential of Grid-Enhancing Technologies, we seek comment 
on whether the Commission should require that transmission providers 
consider Grid-Enhancing Technologies in interconnection studies to 
assess whether their deployment can more cost-effectively facilitate 
interconnections. To the extent transmission providers currently 
consider Grid-Enhancing Technologies in the generator interconnection 
process, what, if any, shortcomings exist in that consideration? If the 
Commission were to require greater consideration of Grid-Enhancing 
Technologies, how should it do so? What, if any, challenges exist in 
establishing such a requirement and how might these challenges be 
addressed?
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    \151\ Commission staff led a workshop in 2019 to explore the 
role, benefits, and challenges of Grid-Enhancing Technologies. FERC, 
Grid-Enhancing Technologies, Notice of Workshop, Docket No. AD19-19-
000 (Sept. 9, 2019).
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C. Enhanced Transmission Oversight

    159. The potential for a significant investment in the transmission 
system in the coming years underscores the importance of ensuring that 
ratepayers are not saddled with costs for transmission facilities that 
are unneeded or imprudent. As part of this package of potential 
reforms, we are considering whether reforms may be needed to enhance 
oversight of transmission planning and transmission providers' spending 
on transmission facilities to ensure that transmission rates remain 
just and reasonable.
1. Potential Need for Reform
    160. As discussed above, the electricity sector is in the midst of 
a fundamental transition as the generation mix shifts rapidly from 
largely centralized resources located close to population centers 
towards renewable resources located far from customers. Potential 
reforms to regional transmission planning and cost allocation and 
generator interconnection should help protect customers throughout this 
transition by directing planning toward the more efficient or cost-
effective transmission facilities. Nevertheless, particularly in light 
of potential costs of new transmission infrastructure that may be 
needed to meet the needs of the changing resource mix, we seek comment 
on whether additional measures may be necessary to ensure that the 
planning processes for the development of new transmission facilities, 
and the costs of the facilities, do not impose excessive costs on 
consumers.
    161. We seek comment on whether the relatively large investment in 
transmission facilities resulting from the regional transmission 
planning and cost allocation processes reflects the more efficient or 
cost-effective solutions for meeting transmission needs, including 
those associated with a changing resource mix. The transparency with 
which transmission needs are identified and transmission facilities 
approved is an important element in ensuring that excessive costs are 
not being imposed on consumers. Although Order No. 890 requires that 
transmission planning processes comply with the transmission planning 
principles, including transparency and openness, transmission providers 
comply with those requirements in various ways.
    162. We seek comment on whether the current transmission planning 
processes provide sufficient transparency for stakeholders to 
understand how best to obtain information and fully participate in the 
various processes. For example, we seek comment whether in non-RTO/ISO 
regions individual transmission owning members' local transmission 
planning processes may not be as well publicized or follow as well 
understood processes to provide information as in RTO/ISO regions. We 
seek comment on whether this may result in material costs being imposed 
on consumers with limited visibility into the actual need for a local 
transmission facility or support for a specific local transmission 
solution. We also seek comment on whether, in light of the significant 
potential costs of transmission and this potential deficit in 
transparency, customers and other stakeholders might benefit from 
enhanced oversight over identification and costs of transmission 
facilities.
2. Potential Reforms and Request for Comment
a. Independent Transmission Monitor
    163. We seek comment on which potential measures the Commission 
could take to ensure that there is appropriate oversight over how new 
regional transmission facilities are identified and paid for. For 
example, we seek comment on whether, to improve oversight of 
transmission facility costs, it would be appropriate for the Commission 
to require that transmission providers in each RTO/ISO, or more 
broadly, in non-RTO/ISO transmission planning regions, establish an 
independent entity to monitor the planning and cost of transmission 
facilities in the region.
    164. We seek comment on the Commission's authority to require an 
independent entity to monitor transmission spending in each 
transmission planning region, as well as the role that such monitor(s) 
would play. For example, this independent transmission monitor might 
potentially review transmission planning processes, planning criteria 
that lead to the identification of particular transmission needs and 
facilities, as well as the rules and regulations governing such 
processes. Additionally, the independent transmission monitor could 
review transmission provider spending on transmission facilities and 
identify instances of potentially excessive transmission facility 
costs, including through inefficiencies between local and regional 
transmission planning processes. Further, the independent transmission 
monitor could identify instances in which transmission facilities were 
selected in the regional transmission plan for cost allocation when it 
may not be clear that such projects were the more efficient or

[[Page 40292]]

cost-effective transmission solutions, or were approved for regional 
cost allocation when credible less-costly alternatives were available. 
If the independent transmission monitor identifies such examples, it 
could make a referral to the Commission. The Commission could then 
conduct a review of the relevant transmission planning processes and/or 
transmission facility costs under section 206 of the FPA. We seek 
comment on the proposal outlined in this paragraph.
    165. We seek comment on whether the independent transmission 
monitor's review could potentially focus on the transmission planning 
process and costs of transmission facilities before construction 
starts.\152\ We seek comment on whether and how the Commission might 
modify the regional transmission planning and cost allocation processes 
or rate recovery rules and procedures so as to facilitate such up-front 
review.
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    \152\ This is different than the safeguards provided under the 
transmission formula rate protocols that have been implemented for 
formula rates in transmission providers' OATTs. The transmission 
formula rate protocols are generally designed to provide interested 
parties sufficient opportunity to obtain and review information 
necessary to evaluate the implementation of the formula rate, which 
allows public utilities to recover the cost for transmission 
facilities that are already constructed and placed in service, 
except in limited circumstances (e.g., a transmission provider may 
recover a return on costs of plant that is in the process of 
construction by receiving regulatory approval to include such costs 
of construction work in progress in rate base under its formula 
rate). The protocols outline the process for the annual formula rate 
informational filing at the Commission, transparency around the 
transmission formula rate information exchange, the scope of 
participation, and the ability of customers to challenge 
transmission providers' implementation of the formula rate. See 
Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ] 61,127 
(2012); Midwest Indep. Transmission Sys. Operator, Inc., 143 FERC ] 
61,149 (2013); Midcontinent Indep. Sys. Operator, Inc., 146 FERC ] 
61,212 (2014); Midcontinent Indep. Sys. Operator, Inc., 150 FERC ] 
61,025 (2015).
---------------------------------------------------------------------------

    166. We also seek comment on how an independent transmission 
monitor could approach cost oversight. One possible method would be to 
scrutinize the relevant regional transmission plan(s) to determine 
whether a different portfolio of local and regional transmission 
facilities would lead to higher net benefits. With regard to individual 
transmission facilities selected via the regional transmission planning 
processes or chosen through the local transmission planning processes, 
the independent entity could provide information to assist the 
Commission in determining whether the selection of a given transmission 
facility warrants additional Commission review. Such assistance may 
include the development of independent cost estimates for transmission 
facilities. Given the challenges of reviewing all transmission 
facilities, we seek comment on whether it would be useful for the 
Commission or the independent entity to develop criteria (such as a 
minimum spending threshold) to determine which transmission facilities 
should be subject to review.
    167. We seek comment on tools that could be developed to assist 
such a transmission monitor or the Commission in reviewing 
transmission-related spending. For example, such a monitor might 
develop benchmark cost estimates that would be independent of cost 
estimates developed by a transmission provider, which could serve as a 
mechanism to assess performance for each transmission provider for the 
applicable transmission facilities. The independent transmission 
monitor could create separate estimates for regional versus local 
transmission facilities and classify facility costs by criteria (such 
as voltage level), with estimates based on well-established methods 
using the best information available just prior to the start of 
construction to minimize the error in cost estimation. The Commission 
could then review the costs for transmission facilities that 
significantly exceed the cost estimates, either sua sponte or on the 
recommendation of the independent transmission monitor or a third 
party. An independent transmission monitor could also seek information 
from transmission providers regarding the variances between actual and 
estimated costs for selected regional transmission facilities and use 
this information in its assessment of whether further Commission review 
is recommended.
    168. We seek comment on whether an independent transmission monitor 
should provide advice on the design and implementation of the regional 
transmission planning and cost allocation processes in addition to 
oversight of the regional transmission planning process and the costs 
of the development of individual transmission facilities. The 
independent transmission monitor could review the design of the 
regional transmission planning and cost allocation processes on an 
ongoing basis and highlight areas where improvements could be made (for 
example, optimization between local and regional transmission 
planning). The independent transmission monitor could also review 
mechanisms used in transmission planning processes, such as adjusted 
production cost modeling tools, and assess the extent to which 
modifications to such mechanisms might yield more efficient 
transmission spending decisions.
    169. The independent transmission monitor could also identify and 
report on situations in which non-wires alternatives could more cost-
effectively address transmission system needs. We seek comment on the 
value of such reporting and whether such information could improve the 
ability for states to participate in the regional transmission planning 
process and provide a greater opportunity for input. Similarly, we seek 
comment on whether an independent transmission monitor or other 
oversight mechanism should evaluate and report on transmission 
providers' consideration of Grid-Enhancing Technologies in the 
transmission planning process. If so, how should that evaluation be 
conducted and what information should be reported?
    170. Additionally, we seek comment on whether oversight of the 
planning and approval of local transmission facilities is necessary to 
ensure that transmission rates are just and reasonable. We seek comment 
on whether an independent transmission monitor should evaluate whether 
the transmission needs identified in the local transmission planning 
processes could be better considered during regional transmission 
planning processes to allow for the identification of more efficient or 
cost-effective transmission solutions. In addition, we seek comment on 
whether oversight should consider the development and application of 
transmission planning criteria. Finally, we encourage commenters to 
identify any other factors that they believe the Commission should 
consider for oversight within the local transmission planning process. 
At the same time, we seek comment on whether such a role for a 
federally-regulated regional transmission monitor would improperly or 
inappropriately expand the role of federal regulation over local 
utility regulation and/or potentially increase administrative and legal 
costs of local transmission planning with no commensurate benefits for 
customers. More broadly, we seek comment on whether there is a need to 
delineate more clearly the oversight roles of federal and state 
regulators over local transmission planning.
    171. In addition, we seek comment on whether there is sufficient 
clarity on the roles and responsibilities between state and federal 
regulators regarding the local transmission planning criteria and the 
development of local transmission facilities (e.g., ``Supplemental 
Projects'' in PJM). We seek comment on whether such transmission 
facilities require additional oversight and whether

[[Page 40293]]

additional coordination among state and federal regulators would be 
beneficial. Similarly, we seek comment on whether and how greater 
oversight may improve coordination between individual transmission 
provider's planning processes and regional transmission planning 
processes. Order No. 1000 requires the evaluation of ``alternative 
transmission solutions that might meet the needs of the transmission 
planning region more efficiently or cost-effectively than solutions 
identified by individual public utility transmission providers.'' \153\ 
We seek comment on whether current rules and processes are adequately 
aligned with and facilitate such consideration or evaluation, and if 
not, whether there are oversight measures or other mechanisms, 
including via an independent transmission monitor, that could better 
facilitate the consideration of more efficient or cost-effective 
alternatives. For example, we seek comment on whether individual 
transmission provider practices regarding retirement and replacement of 
transmission facilities sufficiently align with the directive to ensure 
evaluation of alternative transmission solutions and whether these 
practices sufficiently consider the more efficient or cost-effective 
ways to serve future needs. We also seek comment on whether sufficient 
transparency exists in retirement decisions to allow for such regional 
assessment. We seek comment on what role can or should an independent 
transmission monitor play in facilitating enhanced coordination.
---------------------------------------------------------------------------

    \153\ Order No. 1000, 136 FERC ] 61,050 at P 148.
---------------------------------------------------------------------------

    172. Furthermore, we seek comment on whether additional 
transparency measures are appropriate or should be in place for 
transmission providers, including those outside of RTO/ISO regions. If 
so, we seek comment on whether the Commission should apply transparency 
measures, some of which are currently utilized within RTO/ISO regions 
(e.g., dedicated transmission planning web pages, requirements to 
publish and detail full transmission plan at end of each transmission 
planning cycle, scorecards), or consider different or new transparency 
measures for transmission providers outside of RTO/ISO regions. We seek 
comment on whether new or different transparency measures are needed 
within the RTO/ISO regions.
    173. An independent transmission monitor would not replace the 
Commission's rate jurisdiction but instead could provide the Commission 
with an additional means of ensuring that rates are just and 
reasonable. With respect to other aspects of prudence, or transmission 
facility selection against alternatives, the independent transmission 
monitor would not supplant the Commission's authority with respect to 
prudence, but could inform the Commission as to whether a further 
review is warranted; the final determination on whether costs are 
prudently incurred remains with the Commission. Similarly, the record 
created by the independent transmission monitor could help the 
Commission in ensuring that the design of the regional transmission 
planning and cost allocation processes remain just and reasonable and 
not unduly discriminatory or preferential.
    174. We seek comment on (1) the independent transmission monitor 
proposal, and (2) any alternative options for improving oversight of 
transmission costs or the effectiveness of transmission planning 
processes. Additionally, we seek comment on whether the concerns 
regarding transmission oversight are best addressed by an independent 
entity similar to the role of an independent market monitor, or whether 
the concerns can be adequately addressed by the RTO/ISO or transmission 
providers in non-RTO/ISO regions, or through another approach.
    175. We also seek comment on (1) how an independent transmission 
monitor (or set of regional monitors) would be created or authorized; 
(2) whether a single monitor should be appointed for each transmission 
region, or instead a given monitor might review transmission across 
several regions; (3) the Commission's authority to require an 
independent transmission monitor in all transmission planning regions; 
(4) how this entity would work in practice, in both the RTO/ISO and 
non-RTO/ISO regions; and (5) the scope of review such monitor(s) should 
be charged with carrying out, including whether such monitoring should 
extend to oversight of the generator interconnection process.
b. State Oversight
    176. Another way to add oversight to the transmission planning and 
cost allocation processes could be to involve state commissions in 
those processes. By way of example, SPP has a Regional State Committee 
(RSC), which provides collective state regulatory agency input in areas 
under the RSC's primary responsibilities and on matters of regional 
importance related to the development and operation of the bulk 
electric transmission system. Pursuant to the SPP Bylaws, ``with 
respect to transmission planning, the RSC will determine whether 
transmission upgrades for remote resources will be included in the 
regional transmission planning process and the role of transmission 
owners in proposing transmission upgrades in the regional planning 
process.'' \154\
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    \154\ SPP, Governing Documents Tariff, Bylaws, Section 7.2 
(Regional State Committee) (1.0.0).
---------------------------------------------------------------------------

    177. We seek comment on whether this type of model, or other models 
that may be proposed, could be expanded to other regions and other 
topics; for example, whether a state-led committee could: Provide 
insight into regional transmission facility costs and cost allocation 
methods; evaluate whether the transmission needs identified in the 
local transmission planning processes could be better considered during 
regional transmission planning processes; inform the Commission as to 
whether a further review is warranted of whether incurred costs are 
prudent; or provide the Commission with an additional means of ensuring 
that rates are just and reasonable. We also seek comment on how such a 
model may be combined with other oversight tools or mechanisms explored 
herein. For example, given state regulatory authority over the approval 
of non-wires solutions, can or should a regional state committee play a 
role in identifying circumstances under which a non-wires solution 
would be the more efficient or cost-effective solution to solving an 
identified regional transmission need, and facilitating a process by 
which the relevant state regulator could be given an opportunity to 
approve such a solution?
c. Limitation on Recovery of Costs for Abandoned Projects
    178. There is always a risk that once approved, a regional project 
may be abandoned before going into service for a variety of reasons 
including a failure to obtain all necessary state and federal 
approvals, including, for example, state certificates of public 
convenience and necessity. The Commission's general policy for recovery 
of the costs of abandoned plant under section 205 of the FPA allows 
recovery of and return on 50% of the prudently incurred investment 
costs incurred in connection with the abandoned plant.\155\ In

[[Page 40294]]

addition, the Commission may grant as an incentive under section 219 of 
the FPA for transmission facilities meeting the qualifications for the 
incentive, recovery of 100% of prudently-incurred costs related to such 
facilities if they are abandoned for reasons beyond the control of the 
transmission owner.\156\ In light of potential costs of new regional 
transmission infrastructure and the corresponding risk that some of 
those projects may be abandoned, we seek comment on whether the 
Commission should revisit its policies regarding abandoned plant to 
better protect consumers from increased costs due to never-built 
transmission facilities.
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    \155\ New Eng. Power Co., Opinion No. 295, 42 FERC ] 61,016, at 
61,081-82, order on reh'g, Opinion No. 295-A, 43 FERC ] 61,285 
(1988). The Commission also allows recovery under section 205 of 
return on 50% of investment costs incurred to construct transmission 
facilities (and other non-pollution control plant) through the 
inclusion of Construction Work in Progress (CWIP) in rate base 
during the construction period, provided certain conditions are met. 
Construction Work In Progress for Public Utilities; Inclusion of 
Costs in Rate Base, Order No. 298, 48 FR 24,323 (June 1, 1983), FERC 
Stats. & Regs. ] 30,455, order on reh'g, Order No. 298-A, 48 FR 
46,012 (Oct. 11, 1983), FERC Stats. & Regs., ] 30,500 (1983), order 
on reh'g, Order No. 298-B, 48 FR 55,281 (Dec. 12, 1983), FERC Stats. 
& Regs. ] 30,524 (1983) (Order No. 298).
    \156\ Promoting Transmission Investment through Pricing Reform, 
Order No. 679, 116 FERC ] 61,057, order on reh'g, Order No. 679-A, 
117 FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 (2007).
---------------------------------------------------------------------------

    179. For example, one proposal to protect consumers would be to 
limit the recovery of costs through abandonment by allowing only the 
recovery of some portion of actual development or pre-commercial costs, 
and/or no recovery of a return on equity on such costs prior to the 
project receiving all necessary regulatory approvals. We therefore seek 
comment on this or other proposals to limit the amount that can be 
recovered for regional transmission facilities that are abandoned prior 
to going into service. Commenters are, of course, welcome to address 
all issues and concerns pertinent to such proposals.
d. Additional Oversight Approaches
    180. Finally, we seek comment on additional oversight approaches 
the Commission might take to ensure that wholesale transmission 
spending is cost effective. For example, performance-based regulation. 
We ask how performance-based regulation may be designed to ensure that 
rates are just and reasonable, ensure reliability of the transmission 
system, promote regional expansion of transmission facilities for a 
sufficiently wide range of future scenarios, including anticipated 
future generation, and encourage transmission provider participation.

D. Transition

    181. To implement any of the proposals outlined above, transmission 
providers must transition to new interconnection pricing paradigms and 
new regional transmission planning and cost allocation processes. 
Therefore, we seek comment on appropriate transition plans, including 
treatment of interconnection customers in the various stages of the 
generator interconnection process and those that have already 
interconnected as well as when the more holistic regional transmission 
planning and cost allocation processes would begin (including when the 
broader category of regional transmission facilities would be 
established).
    182. The Commission also seeks input as to the length of time that 
might be necessary to implement any reforms that result from this 
process. Specifically, the Commission requests input as to how much 
time transmission providers might need to develop compliance filings 
related to all of the proposals in this ANOPR.

V. Comment Procedures

    183. The Commission invites interested persons to submit comments 
on these matters and any related matters or alternative proposals that 
commenters may wish to discuss. Comments are October 12, 2021 and Reply 
Comments are due November 9, 2021. Comments must refer to Docket No. 
RM21-17-000 and must include the commenter's name, the organization 
they represent, if applicable, and their address in their comments. All 
comments will be placed in the Commission's public files and may be 
viewed, printed, or downloaded remotely as described in the Document 
Availability section below. Commenters on this proposal are not 
required to serve copies of their comments on other commenters
    184. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software must be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    185. Commenters that are not able to file comments electronically 
may file an original of their comment by USPS mail or by courier-or 
other delivery services. For submission sent via USPS only, filings 
should be mailed to: Federal Energy Regulatory Commission, Office of 
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of 
filings other than by USPS should be delivered to: Federal Energy 
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.

VI. Document Availability

    186. 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 (https://www.ferc.gov). At 
this time, the Commission has suspended access to the Commission's 
Public Reference Room due to the President's March 13, 2020 
proclamation declaring a National Emergency concerning the Novel 
Coronavirus Disease (COVID-19).
    187. From the Commission's Home Page on the internet, this 
information is available in its eLibrary. The full text of this 
document is available in the 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.
    188. 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 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.
    By direction of the Commission. Chairman Glick and Commissioner 
Clements are concurring with a joint separate statement attached. 
Commissioner Chatterjee is not participating. Commissioner Danly is 
concurring with a separate statement. Commissioner Christie is 
concurring with a separate statement.

    Issued: July 15, 2021.
Debbie-Anne A. Reese,
Deputy Secretary.

Department of Energy

Federal Energy Regulatory Commission

Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation and Generator Interconnection

Docket No. RM21-17-000
    GLICK, Chairman, CLEMENTS, Commissioner, concurring:
    1. The generation resource mix is changing rapidly. Due to a myriad 
of factors--including improving economics, customer and corporate 
demand for clean energy, public utility commitments and integrated 
resource plans, as well as federal, state, and local public policies--
renewable resources in particular are coming online at an

[[Page 40295]]

unprecedented rate.\1\ As a result, the transmission needs of the 
electricity grid of the future are going to look very different than 
those of the electricity grid of the past.
---------------------------------------------------------------------------

    \1\ See, e.g., Joseph Rand et al., Queued Up: Characteristics of 
Power Plants Seeking Transmission Interconnection as of the End of 
2020, Lawrence Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/queued_up_may_2021.pdf; 
Electric Power Monthly, Table 6.1 Electric Generating Summer 
Capacity Changes (MW), U.S. Energy Information Administration, (Mar. 
2021 to Apr. 2021), https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=table_6_01.
---------------------------------------------------------------------------

    2. We are concerned that the current approach to transmission 
planning and cost allocation cannot meet those future transmission 
needs in a manner that is just and reasonable and not unduly 
discriminatory or preferential. In particular, we believe that the 
status quo approach to planning and allocating the costs of 
transmission facilities may lead to an inefficient, piecemeal expansion 
of the transmission grid that would ultimately be far more expensive 
for customers than a more forward-looking, holistic approach that 
proactively plans for the transmission needs of the changing resource 
mix. A myopic transmission development process that leaves customers 
paying more than necessary to meet their transmission needs is not just 
and reasonable.
    3. In that regard, we are pleased to see the Commission taking a 
consensus first step toward updating its rules and regulations to 
ensure that we are meeting the nation's evolving transmission needs in 
a cost-effective and efficient fashion. Today's action complements our 
recently established joint federal-state task force with the National 
Association of Regulatory Utility Commissioners,\2\ which we expect to 
produce a robust dialogue on many of the issues addressed herein. In 
our view, this advance notice of proposed rulemaking (ANOPR) is just 
the first step. Ensuring that transmission rates remain just and 
reasonable will require further action, including reforms to 
interregional transmission planning and cost allocation, as well as 
other reforms to our regional transmission planning and cost allocation 
and generator interconnection processes beyond those contemplated 
herein. Nevertheless, we believe that today's unanimous Commission 
action represents a solid foundation for an expeditious inquiry into 
how we can regulate to achieve the transmission needs of our changing 
electricity system in a manner consistent with our statutory 
obligations under the Federal Power Act.
---------------------------------------------------------------------------

    \2\ Joint Federal-State Task Force on Electric Transmission, 175 
FERC ] 61,224 (2021).
---------------------------------------------------------------------------

* * * * *
    4. The generation mix is shifting rapidly from large resources 
located close to population centers toward renewable resources, often 
combined with onsite storage, that tend to be located where their fuel 
source is best--i.e., where the wind blows hardest or the sun shines 
brightest. According to the National Renewable Energy Laboratory 
(NREL), total renewable generation capacity nearly doubled from 2009 to 
2018, increasing from 11.7% of total generation capacity to 20.5%.\3\ 
And that is just the beginning: Of the roughly 750 GW of generation in 
interconnection queues around the country, nearly 700 GW are renewable 
resources,\4\ providing every reason to believe that the dramatic shift 
toward renewable generation will only accelerate in the years ahead.
---------------------------------------------------------------------------

    \3\ 2018 Renewable Energy Data Book at 26, NREL, https://www.nrel.gov/docs/fy20osti/75284.pdf. Wind and solar resources, in 
particular, have grown at a disproportionate rate, with solar 
generation capacity increasing roughly 5,000% from 1,054 MW to 
51,899 MW nationwide, and wind generation capacity more than 
tripling from 31,155 MW to 96,442 MW.
    \4\ See Joseph Rand, Queued Up: Characteristics of Power Plants 
Seeking Transmission Interconnection as of the End of 2020, Lawrence 
Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/queued_up_may_2021.pdf. 
Equally important, this shift is taking place across the country, 
not just in a few areas. For example, as of the issuance of this 
ANOPR, in Midcontinent Independent System Operator, Inc. (MISO), 
solar and wind projects comprise 80% of all active projects in the 
current interconnection queue, or about 73 GW of total capacity. 
MISO, Generator Interconnection Queue--Active Projects Map, https://giqueue.misoenergy.org/PublicGiQueueMap/index.html. Similarly, in 
PJM Interconnection, L.L.C. (PJM), solar and wind projects with a 
total capacity of 62 GW comprise 79% of all active projects in the 
current interconnection queue as of the issuance of this ANOPR. PJM, 
New Services Queue, https://www.pjm.com/planning/services-requests/interconnection-queues.aspx. In California Independent System 
Operator Corporation (CAISO), renewable and storage capacity of 23 
GW comprise 78% of all active projects in the current 
interconnection queue as of the issuance of this ANOPR. CAISO, 
Generator Interconnection Queue, https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueueExcel.xls.
---------------------------------------------------------------------------

    5. That shift is the result of many factors. First and foremost, 
the cost of renewable resources is plummeting. For example, in its 
annual report on the levelized cost of energy, Lazard found that 
between 2009 to 2020, the levelized cost of energy from unsubsidized 
wind generation and unsubsidized utility-scale solar generation 
decreased by 71% and 90%, respectively \5\--enough to make utility-
scale solar and wind generation cost-competitive with central station 
fossil generation sources in many parts of the country.\6\ Moreover, 
customers--both residential and commercial--are increasingly demanding 
clean energy, particularly energy from renewable resources--which is 
itself causing utilities and independent power producers to attempt to 
send large quantities of renewable energy onto the grid.\7\ In 
addition, dozens of the biggest utilities in the country have 
established their own decarbonization goals, the achievement of which 
will require their

[[Page 40296]]

own significant investment in renewable generation.\8\
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    \5\ See, e.g., Lazard's Levelized Cost of Energy Analysis--
Version 14.0, at 9 (Oct. 19, 2020), https://www.lazard.com/
perspective/levelized-cost-of-energy-and-levelized-cost-of-storage-
2020/#:~:text=Lazard's%20latest%20annual%20Levelized% 
20Cost,build%20basis%2C%20continue%20to%20maintain; Ryan Wiser et 
al., Expert elicitation survey predicts 37% to 49% declines in wind 
energy costs by 2050, Lawrence Berkeley National Laboratory (Apr. 
2021), https://eta-publications.lbl.gov/sites/default/files/wind_lcoe_elicitation_ne_pre-print_april2021.pdf (finding that the 
decrease in levelized cost of energy for wind power from 2015-2020 
outpaced the decrease predicted by experts, and that experts 
continue to predict significant declines in levelized cost of 
energy).
    \6\ See Lazard's Levelized Cost of Energy Analysis--Version 
14.0, at 3, 7 (Oct. 19, 2020), https://www.lazard.com/perspective/
levelized-cost-of-energy-and-levelized-cost-of-storage-2020/
#:~:text=Lazard's%20latest%20annual%20Levelized% 
20Cost,build%20basis%2C%20continue%20to%20maintain.
    \7\ See, e.g., Deloitte Resources 2020 Study at 22, https://www2.deloitte.com/content/dam/insights/us/articles/6655_Resources-study-2020/DI_Resources-study-2020.pdf (showing that U.S. corporate 
renewable generation purchase power agreements increased from 0.3 GW 
in 2009 to 13.6 GW in 2019); Kevin O'Rourke & Charles Harper, 
Corporate Renewable Procurement and Transmission Planning: 
Communicating Demand to RTOs Necessary to Secure Future Procurement 
Options, A Renewable America (October 2018), https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf (indicating that a group of corporations, 
forming the Renewable Energy Buyers Alliance, has set a goal to 
purchase 60 GW of new renewable energy capacity in the U.S. by 
2025); Stanley Porter et al., Utility Decarbonization Strategies, 
Renew, Reshape, and Refuel to Zero, Deloitte Insights (Sept. 2021), 
https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/utility-decarbonization-strategies.html (indicating that 
43 of 55 utilities surveyed have emissions reductions targets and 22 
have net-zero or carbon-free electricity goals); Esther Whieldon, 
Path to net zero: 70% of biggest US utilities have deep 
decarbonization targets, S&P Global Market Intelligence (Dec. 9, 
2020) at 3-6, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651 (indicating 
that review of utilities' climate goals decarbonization plans, as of 
December 2020, shows that 70% of the 30 largest utilities have net-
zero carbon targets or are moving to comply with similarly 
aggressive state mandates); see also Rich Glick and Matthew 
Christiansen, FERC and Climate Change, 40 Energy L.J. 1, 7-12 (2019) 
(``The growth of renewable resources is also a function of 
consumers' desire for clean energy. Customers--including 
residential, commercial, and even industrial consumers--are 
increasingly demanding that their energy come from renewable or 
zero-emissions sources'').
    \8\ See, e.g., Corporate Renewable Procurement and Transmission 
Planning: Communicating Demand to RTOs Necessary to Secure Future 
Procurement Options, A Renewable America, October 2018, https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf; Esther Whieldon, Path to 
net zero: 70% of biggest US utilities have deep decarbonization 
targets, S&P Global Market Intelligence, Dec. 9, 2020, at 3-6, 
https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651.
---------------------------------------------------------------------------

    6. Finally, federal, state, and local policymakers have adopted a 
range of public policies that are driving the changing resource mix. 
For example, 30 states and the District of Columbia have adopted 
renewable portfolio standards,\9\ with those standards contributing to 
roughly 50% of the total growth in renewable generation over the last 
two decades.\10\ In addition, several states have doubled down on the 
clean energy transition by enacting measures that require that most or 
all of their electricity come from zero emissions resources.\11\ All 
told, ``states and utilities that have committed to transitioning to 
100 percent clean power serve nearly 83 million households and 
businesses, representing around 50 percent of all U.S. electricity 
demand in 2019.'' \12\
---------------------------------------------------------------------------

    \9\ Nat'l Conference of State Legislatures, State Renewable 
Portfolio Standards and Goals (Nov. 7, 2021), https://www.ncsl.org/
research/energy/renewable-portfolio-
standards.aspx#:~:text=Thirty%20states%2C%20Washington%2C%20DC%2C,hav
e%20set%20renewable%20energy%20goals. Renewable portfolio standards 
are policies that are designed to increase the amount of renewable 
energy sources used for electricity generation.
    \10\ See, e.g., Berkeley Lab, U.S. Renewables Portfolio 
Standards: 2019 Annual Status Update (Aug. 2019), https://emp.lbl.gov/publications/us-renewables-portfolio-standards-2.
    \11\ Carbon Pricing in Organized Wholesale Elec. Markets, 175 
FERC ] 61,036, at P 2 (2021) (``Thirteen states--California, Hawaii, 
Maine, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New 
York, Oregon, Vermont, Virginia, and Washington--and the District of 
Columbia have adopted clean energy or renewable portfolio standards 
of 50% or greater.''). In addition, ``a number of states--including 
Colorado, Connecticut, Nevada, Rhode Island, and Wisconsin--have 
established 100% clean electricity goals or targets by executive 
order or other non-binding commitment.'' See id. At the local level, 
cities and counties are also accelerating clean energy commitments. 
Kelly Trumbull et al., Progress Toward 100% Clean Energy in Cities 
and States Across the U.S., University of California--Los Angeles 
Luskin Center for Innovation (November 2019) at 10, https://innovation.luskin.ucla.edu/wp-content/uploads/2019/11/100-Clean-Energy-Progress-Report-UCLA-2.pdf (finding over 200 cities and 
counties across 37 U.S. states have 100 percent clean energy 
commitments).
    \12\ National Resources Defense Council (NRDC), NRDC's 8th 
Annual Energy Report: Slow and Steady Will Not Win the Climate Race 
(Dec. 2, 2020), https://www.nrdc.org/resources/nrdcs-8th-annual-energy-report-slow-and-steady-will-not-win-race?nrdcpreviewlink=rmmB6NM6zpiOTruhuObZJdH92bCOvmZTY1hx72xCSzQ#renewables.
---------------------------------------------------------------------------

    7. Dramatic changes in the resource mix inevitably come with 
similarly dramatic changes in transmission needs. As noted, the 
increasingly cost-competitive renewable resources that customers and 
public policies demand tend to be developed farther away from customers 
where their fuel sources are strong and development costs are low 
rather than in close proximity to their ultimate customers. As a 
result, the future resource mix will likely present new transmission 
needs, different from those of the large resources located close to 
population centers that have dominated electricity generation in the 
past. Meeting those transmission needs will likely require both the 
infrastructure necessary to interconnect new resources to the 
transmission system efficiently and the infrastructure necessary to 
reliably move the electricity produced by those resources to where it 
is needed. This could make it considerably more expensive than 
necessary to bring in the low-cost generation demanded by customers and 
meet federal, state, and local public policies.
    8. This Commission cannot sit idly by. Our role is to ensure just 
and reasonable rates and support reliability in light of changes in the 
market, not to pretend those changes are not happening. We are 
concerned that, in light of evolving transmission needs, the current 
regional transmission planning and cost allocation and generator 
interconnection processes may no longer ensure just and reasonable 
rates for transmission service.\13\ In particular, we are concerned 
that existing regional transmission planning processes may be siloed, 
fragmented, and not sufficiently forward-looking, such that 
transmission facilities are being developed through a piecemeal 
approach that is unlikely to produce the type of transmission solutions 
that could more efficiently and cost-effectively meet the needs of the 
changing resource mix. Regional transmission planning processes 
generally do little to proactively plan for the resource mix of the 
future, including both commercially established resources, such as 
onshore wind and solar, as well as emerging ones, such as offshore 
wind. We are also concerned that current regional transmission planning 
processes are not sufficiently integrated with the generator 
interconnection processes, and are overwhelmingly focused on relatively 
near-term transmission needs, and that attempting to meet the needs of 
the changing resource mix through such a short-term lens will lead to 
inefficient transmission investments. As a result, under the status 
quo, customers could end up paying far more to meet their transmission 
needs than they would under a more forward-looking approach that 
identifies the more efficient or cost-effective investments in light of 
the changing resource mix.\14\
---------------------------------------------------------------------------

    \13\ 16 U.S.C. 824e.
    \14\ See generally Eric Larson et al., Net-Zero America: 
Potential Pathways, Infrastructure, and Impact (2020), 
Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf (discussing 
different pathways for meeting decarbonization goals, including 
differing approaches to transmission investment).
---------------------------------------------------------------------------

    9. Relatedly, we are also concerned that the current approach to 
transmission planning and cost allocation is failing to adequately 
identify the benefits and allocate the costs of new transmission 
infrastructure. Although the regional transmission planning process 
considers transmission needs driven by reliability, economics, and 
Public Policy Requirements,\15\ those transmission needs are often 
viewed in isolation from one another and the cost allocation methods 
for projects selected to meet those needs are similarly siloed. As a 
result, the status quo may be disproportionately producing transmission 
facilities that address a narrow set of needs, providing comparatively 
modest benefits, but at a still-substantial total cost instead of 
developing the type of transmission infrastructure that could provide 
the most significant benefits for customers. In the same vein, we are 
also concerned that many customers who share in the diverse array of 
benefits that transmission infrastructure can offer may not be paying 
their fair share, as required by the cost causation principle.\16\
---------------------------------------------------------------------------

    \15\ See Transmission Planning and Cost Allocation by 
Transmission Owning and Operating Public Utilities, Order No. 1000, 
136 FERC ] 61,051, at P 11 (2011), order on reh'g, Order No. 1000-A, 
139 FERC ] 61,132, order on reh'g and clarification, Order No. 1000-
B, 141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d 41 (D.C. Cir. 2014).
    \16\ Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 
268-269 (D.C. Cir. 2014) (``[T]he cost causation principle itself 
manifests a kind of equity. This is most obvious when we frame the 
principle (as we and the Commission often do) as a matter of making 
sure that burden is matched with benefit.'' (citing Midwest ISO 
Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) 
and Se. Michigan Gas Co. v. FERC, 133 F.3d 34, 41 (D.C. Cir. 
1998))).
---------------------------------------------------------------------------

    10. In addition, we are concerned that, largely due to the 
potential shortcomings with the current regional transmission planning 
and cost allocation processes, transmission infrastructure is 
increasingly being

[[Page 40297]]

developed through the generator interconnection process. That means 
that infrastructure with potentially significant benefits for a broad 
range of entities may be developed through a process that focuses 
exclusively on the needs of a comparatively small number of 
interconnection customers--a dynamic that is almost sure to result in 
comparatively inefficient investment decisions. The participant funding 
approach to financing interconnection-related network upgrades will 
often mean that the interconnection customer(s) alone must pay for 
all--or the vast majority--of the costs of that transmission 
infrastructure, even where it provides significant benefits to other 
entities. That, in turn, may cause those interconnection customers to 
withdraw projects from the queue, causing considerable uncertainty and 
delay, and may mean that net beneficial transmission infrastructure is 
never developed due to a misalignment in how that infrastructure would 
be paid for.
    11. Finally, we are also concerned that the Commission's current 
approach to overseeing transmission investment may not adequately 
protect consumers. While transmission infrastructure can provide a 
broad spectrum of benefits, it is itself a significant investment that 
represents a major component of customers' electric bills. The 
Commission must vigorously oversee the rules governing how transmission 
projects are planned and paid for if we are to satisfy our 
responsibility to protect customers from excessive rates and 
charges.\17\ The potential bases for invigorating our oversight of 
transmission spending contemplated in today's order have the potential 
to go a long way toward ensuring that we fulfill that function.
---------------------------------------------------------------------------

    \17\ Cf., e.g., California ex rel. Lockyer v. FERC, 383 F.3d 
1006, 1017 (9th Cir. 2004) (rejecting ``an interpretation [that] 
comports neither with the statutory text nor with the Act's `primary 
purpose' of protecting consumers''); City of Chicago v. FPC, 458 
F.2d 731, 751 (D.C. Cir. 1971) (``[T]he primary purpose of the 
Natural Gas Act is to protect consumers.'' (citing, inter alia, City 
of Detroit v. FPC, 230 F.2d 810, 815 (D.C. Cir. 1955)).
---------------------------------------------------------------------------

    12. Today's action plants the seeds for addressing the concerns 
outlined above. A forward-looking, holistic approach to transmission 
planning has the potential to identify the more efficient or cost-
effective solutions for meeting the transmission needs of the changing 
resource mix, including those resources that are not yet under 
development. Such an approach would allow transmission planners to 
proactively identify the areas of the transmission grid that will have 
significant transmission needs and select the more efficient or cost-
effective solution to meet those needs, including needs driven by 
resources that are not yet in operation or even under development. 
Doing so has the potential to address the transmission needs of the 
future generation mix while costing customers considerably less than 
they would pay to meet those same needs under the status quo. That, in 
our view, is what is necessary to ensure that the rates for 
transmission service remain just and reasonable as the resource mix 
changes.
    13. We anticipate that this effort will be the Commission's 
principal focus in the months to come. In addition to reviewing the 
record assembled in response to today's order, we intend to explore 
technical conferences and other avenues for augmenting that record--
including through the joint federal-state task force \18\--before 
proceeding to reform our rules and regulations. We recognize that the 
issues addressed herein are highly technical, complex problems that do 
not lend themselves to easy solutions. That being said, we also 
recognize the urgent need to address the transmission needs of the 
changing resource mix and appreciate that we do not have the luxury of 
sitting back and debating these issues ad nauseum.
---------------------------------------------------------------------------

    \18\ See supra n.2.
---------------------------------------------------------------------------

* * * * *
    14. The electricity sector is at a pivotal moment. With the clean 
energy transition gaining steam, we can either continue with the status 
quo, trying to meet the transmission needs of the future by building 
out the grid in a myopic, piecemeal fashion, or we can start 
holistically and proactively planning for those future transmission 
needs. We believe that today's advance notice of proposed rulemaking 
represents an important and essential first step in the right direction 
and toward the type of transmission planning and cost allocation 
paradigm that is necessary to protect customers, support reliability, 
and ensure just and reasonable rates.
    For these reasons, we respectfully concur.

-----------------------------------------------------------------------
Richard Glick,

Chairman.

-----------------------------------------------------------------------
Allison Clements,

Commissioner.

Department of Energy

Federal Energy Regulatory Commission

Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation and Generator Interconnection

Docket No. RM21-17-000
(Issued July 15, 2021)
DANLY, Commissioner, concurring:

    1. I concur with the issuance of this Advance Notice of Proposed 
Rulemaking (ANOPR) because the Commission is always entitled to solicit 
comments on possible changes to existing rules and a number of the 
questions raised here are worthy of consideration.
    2. I write separately to highlight one overarching concern. The 
ANOPR poses several questions where the answer is ``no.'' Many of the 
contemplated proposals would exceed or cede our jurisdictional 
authority, violate cost causation principles, create stifling layers of 
oversight and ``coordination,'' trample transmission owners' rights, 
force neighboring states' ratepayers to shoulder the costs of other 
states' public policy choices, treat renewables as a new favored class 
of generation with line-jumping privileges, and perhaps inadvertently 
lead to much less transmission being built and at much greater all-in 
cost to ratepayers.
    3. There are obviously problems with the existing transmission 
regime. I, for example, have long been troubled by interconnection 
logjams and have wondered whether we are needlessly propping up fantasy 
projects while viable projects get lost in the crowd.\1\ This is but 
one example; there are any number of other critical transmission 
planning reforms that bear investigation.
---------------------------------------------------------------------------

    \1\ See, e.g., PacifiCorp, 171 FERC ] 61,112 (2020) (Danly, 
Comm'r, concurring).
---------------------------------------------------------------------------

    4. My hope therefore is that commenters will supply us with a full 
record on each issue raised in the ANOPR: Whether and why the existing 
rule works or not, and whether and why the possible reform may work or 
not. With every proposed change, I specifically solicit comments on two 
subjects. First: Is the contemplated reform a proper exercise of the 
Commission's authority, i.e., is it within our jurisdiction? That is 
always the threshold question before we turn to policy. Second: what 
will be the ultimate effect on ratepayers? I fear that in the 
enthusiasm to build transmission, many may tout the benefits of new 
transmission while overlooking the costs that will eventually be borne 
by ratepayers. No proposed policy,

[[Page 40298]]

however worthy, can evade our statutory duty to ensure that rates are 
just and reasonable.
    5. I encourage everyone with an interest to file. I look forward to 
learning from the parties that submit comments and to engaging with my 
colleagues to consider whether there are legally durable, economically 
sound reforms that we might consider to improve the reliability of the 
transmission system at just and reasonable rates.
    For these reasons, I respectfully concur.

-----------------------------------------------------------------------
James P. Danly,

Commissioner.

Department of Energy

Federal Energy Regulatory Commission

Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation and Generator Interconnection

Docket No. RM21-17-000
(Issued July 15, 2021)
CHRISTIE, Commissioner, concurring:

    1. I concur with today's ANOPR because approximately ten years 
after the Commission issued Order No. 1000, it is appropriate to review 
the implementation of that order, assess the successes and problems 
that have become evident over the past decade, and consider reforms and 
revisions to existing regulations governing regional transmission 
planning and cost allocation. This consideration of potential reforms 
is especially timely as the transmission system faces the challenge of 
maintaining reliability through the changing generation mix and efforts 
to reduce carbon emissions.
    2. The broad goal of the Commission's regulation of our nation's 
power grid under the Federal Power Act (FPA) is to ensure a reliable 
power supply to consumers, which includes residential customers as well 
as the businesses providing jobs for tens of millions of Americans, at 
just and reasonable rates. Transmission is one of the three essential 
elements of a reliable power system, along with generation and 
distribution, so continually working to make America's transmission 
system more reliable, more efficient, and more cost-effective is our 
job at FERC.
    3. As with Order No. 1000, the statutory framework governing our 
potential actions in this proceeding remains section 206 of the FPA, 
which requires us to ensure that all transmission planning processes 
and cost allocation mechanisms subject to our jurisdiction result in 
jurisdictional services being provided at rates, terms and conditions 
that are just, reasonable, and not unduly discriminatory or 
preferential. Any proposals ultimately adopted by this Commission for 
reforms or revisions to existing regulations must be consistent with 
this authority.
    4. As Paragraph 4 of the ANOPR makes clear,\1\ we have not 
predetermined that any specific proposal in this ANOPR has already been 
or will ultimately be approved. Rather, we seek comment from all 
interested persons and organizations on the wide range of proposals 
contained herein, as well as the submission of alternative proposals. 
Today is the beginning of a long process and I look forward to hearing 
from all concerned.
---------------------------------------------------------------------------

    \1\ ANOPR at P 4 (``We note that the Commission has not 
predetermined that any specific proposal discussed herein shall or 
should be made or in what final form; rather, we seek comment from 
the public on those proposals and welcome commenters to offer 
additional or alternative proposals for consideration.'').
---------------------------------------------------------------------------

    5. Similarly, my concurrence to issue today's ANOPR does not 
represent an endorsement at this point in the process of any one or 
more of the proposals included in the order. This ANOPR contains a 
number of good proposals, some potentially good proposals (depending on 
how they are fleshed out), and frankly, some proposals that are not--
and may never be--ready for prime time, or could potentially cause 
massive increases in consumers' bills for little to no commensurate 
benefit or inappropriately expand the role of federal regulation over 
local utility regulation. Given the early stage of this process, 
however, I agree it is worthwhile to submit a broad range of proposals 
to the public for comment in the hope that the final result will be a 
more reliable, more efficient, and more cost-effective transmission 
system.
    For these reasons, I respectfully concur.

-----------------------------------------------------------------------
Mark C. Christie,

Commissioner.

[FR Doc. 2021-15512 Filed 7-26-21; 8:45 am]
BILLING CODE 6717-01-P