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Rule2024-10872

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

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Published

June 11, 2024

Effective

August 12, 2024

Issuing agencies

Energy DepartmentFederal Energy Regulatory Commission

Abstract

The Federal Energy Regulatory Commission (Commission) revises the pro forma Open Access Transmission Tariff (OATT) to remedy deficiencies in the Commission's existing regional and local transmission planning and cost allocation requirements. In this final order, the Commission requires transmission providers to conduct Long- Term Regional Transmission Planning that will ensure the identification, evaluation, and selection, as well as the allocation of the costs, of more efficient or cost-effective regional transmission solutions to address Long-Term Transmission Needs. The Commission also directs other reforms to improve coordination of regional transmission planning and generator interconnection processes, require consideration of certain alternative transmission technologies in regional transmission planning processes, and improve transparency of local transmission planning processes and coordination between regional and local transmission planning processes. These reforms are intended to ensure that existing regional and local transmission planning and cost allocation requirements are just, reasonable, and not unduly discriminatory or preferential.

Full Text

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[Federal Register Volume 89, Number 113 (Tuesday, June 11, 2024)]
[Rules and Regulations]
[Pages 49280-49586]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-10872]

[[Page 49279]]

Vol. 89

Tuesday,

No. 113

June 11, 2024

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation; Final Rule

Federal Register / Vol. 89, No. 113 / Tuesday, June 11, 2024 / Rules
and Regulations

[[Page 49280]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM21-17-000; Order No. 1920]

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

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final order.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) revises
the pro forma Open Access Transmission Tariff (OATT) to remedy
deficiencies in the Commission's existing regional and local
transmission planning and cost allocation requirements. In this final
order, the Commission requires transmission providers to conduct Long-
Term Regional Transmission Planning that will ensure the
identification, evaluation, and selection, as well as the allocation of
the costs, of more efficient or cost-effective regional transmission
solutions to address Long-Term Transmission Needs. The Commission also
directs other reforms to improve coordination of regional transmission
planning and generator interconnection processes, require consideration
of certain alternative transmission technologies in regional
transmission planning processes, and improve transparency of local
transmission planning processes and coordination between regional and
local transmission planning processes. These reforms are intended to
ensure that existing regional and local transmission planning and cost
allocation requirements are just, reasonable, and not unduly
discriminatory or preferential.

DATES: This final order is effective August 12, 2024.

FOR FURTHER INFORMATION CONTACT:
David Borden (Technical Information), Office of Energy Policy and
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734,
<a href="/cdn-cgi/l/email-protection#2b4f4a5d424f054944594f4e456b4d4e5948054c445d">[email&#160;protected]</a>.
Noah Lichtenstein (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696,
<a href="/cdn-cgi/l/email-protection#214f4e40490f4d48424955444f525544484f61474453420f464e57">[email&#160;protected]</a>.
Michael Kellermann (Legal Information), Office of the General
Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8491,
<a href="/cdn-cgi/l/email-protection#bad7d3d9d2dbdfd694d1dfd6d6dfc8d7dbd4d4fadcdfc8d994ddd5cc">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.

I. Introduction and Background.......................... 1
A. Historical Framework: Order Nos. 888, 890, and 14
1000...............................................
B. ANOPR and Technical Conference................... 20
C. Joint Federal-State Task Force on Electric 22
Transmission.......................................
D. Notice of Proposed Rulemaking.................... 26
E. High-Level Overview of NOPR Comments............. 36
F. Use of Terms..................................... 37
II. The Overall Need for Reform......................... 47
A. NOPR Proposal.................................... 47
B. Comments......................................... 49
C. Commission Determination......................... 85
1. The Transmission Investment Landscape Today.. 90
2. Unjust, Unreasonable, and Unduly 112
Discriminatory or Preferential Commission-
Jurisdictional Transmission Planning and Cost
Allocation Processes...........................
3. Benefits of Long-Term Regional Transmission 134
Planning and Cost Allocation To Identify and
Plan for Long-Term Transmission Needs..........
4. Conclusion................................... 139
III. Long-Term Regional Transmission Planning........... 140
A. Requirement To Participate in Long-Term Regional 140
Transmission Planning..............................
1. NOPR Proposal................................ 140
2. Comments..................................... 145
a. General Comments......................... 145
b. Requests for Flexibility in Transmission 151
Planning...................................
c. Comments Regarding More Comprehensive 163
Transmission Planning......................
d. Concerns Regarding Favoring Renewable 172
Resources..................................
e. Concerns Regarding Uncertainty, Over- 176
Building, and Costs........................
f. Concerns Regarding Incentives for 187
Resource Development.......................
g. Comments Regarding Definition of Long- 189
Term Regional Transmission Facility........
h. Challenges to Commission Jurisdiction or 190
Authority..................................
i. Other Issues............................. 215
j. Miscellaneous Concerns................... 217
3. Commission Determination..................... 224
a. Participation in Long-Term Regional 224
Transmission Planning......................
b. Definition of Long-Term Regional 250
Transmission Facility......................
c. Legal Authority To Adopt Reforms for Long- 253
Term Regional Transmission Planning........
B. Development of Long-Term Scenarios............... 284
1. NOPR Proposal................................ 284
2. Comments..................................... 286
a. General Comments......................... 286
b. Applying Scenario Planning to Reliability 296
and Economic Planning......................
3. Commission Determination..................... 298
C. Long-Term Scenarios Requirements................. 307
1. Transmission Planning Horizon................ 307
a. NOPR Proposal............................ 307
b. Comments................................. 309
c. Commission Determination................. 344
2. Frequency of Long-Term Scenario Revisions.... 352

[[Page 49281]]

a. NOPR Proposal............................ 352
b. Comments................................. 354
c. Commission Determination................. 377
3. Categories of Factors........................ 387
a. Requirement To Incorporate Categories of 387
Factors....................................
b. Specific Categories of Factors........... 422
c. Treatment of Specific Categories of 495
Factors....................................
d. Stakeholder Process and Transparency..... 519
4. Number and Development of Long-Term Scenarios 538
a. NOPR Proposal............................ 538
b. Comments................................. 541
c. Commission Determination................. 559
5. Types of Long-Term Scenarios................. 564
a. NOPR Proposal............................ 564
b. Comments................................. 566
c. Commission Determination................. 575
6. Sensitivities for High-Impact, Low-Frequency 578
Events.........................................
a. NOPR Proposal............................ 578
b. Comments................................. 580
c. Commission Determination................. 593
7. Specificity of Data Inputs................... 602
a. NOPR Proposal............................ 602
b. Comments................................. 606
c. Commission Determination................. 633
8. Identification of Geographic Zones........... 645
a. NOPR Proposal............................ 645
b. Comments................................. 650
c. Commission Determination................. 665
D. Evaluation of the Benefits of Regional 667
Transmission Facilities............................
1. Requirement for Transmission Providers To Use 669
a Set of Seven Required Benefits...............
a. NOPR Proposal............................ 669
b. Comments................................. 673
c. Commission Determination................. 719
2. Required Benefits............................ 740
a. The Seven Required Benefits.............. 740
3. Identification, Measurement, and Evaluation 823
of the Benefits of Long-Term Regional
Transmission Facilities........................
a. NOPR Proposal............................ 823
b. Comments................................. 824
c. Commission Determination................. 837
4. Evaluation of Transmission Benefits Over a 843
Longer Time Horizon............................
a. NOPR Proposal............................ 843
b. Comments................................. 845
c. Commission Determination................. 859
5. Evaluation of the Benefits of Portfolios of 871
Transmission Facilities........................
a. NOPR Proposal............................ 871
b. Comments................................. 872
c. Commission Determination................. 889
6. Issues Related to Use of Benefits............ 891
a. NOPR Proposal............................ 891
b. Comments................................. 892
c. Commission Determination................. 902
E. Evaluation and Selection of Long-Term Regional 904
Transmission Facilities............................
1. Requirement To Adopt an Evaluation Process 904
and Selection Criteria.........................
a. NOPR Proposal............................ 904
b. Comments................................. 906
c. Commission Determination................. 911
2. Flexibility.................................. 919
a. NOPR Proposal............................ 919
b. Comments................................. 920
c. Commission Determination................. 924
3. Minimum Requirements......................... 927
a. NOPR Proposal............................ 927
b. Comments................................. 930
c. Commission Determination................. 954
4. Role of Relevant State Entities.............. 972
a. NOPR Proposal............................ 972
b. Comments................................. 973
c. Commission Determination................. 994
5. Voluntary Funding Opportunities.............. 1003
a. NOPR Proposal............................ 1003
b. Comments................................. 1004
c. Commission Determination................. 1012
6. No Selection Requirement..................... 1019

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a. NOPR Proposal............................ 1019
b. Comments................................. 1020
c. Commission Determination................. 1026
7. Other Issues................................. 1029
a. Comments................................. 1029
b. Commission Determination................. 1031
8. Reevaluation................................. 1033
a. NOPR Proposal............................ 1033
b. Comments................................. 1035
c. Commission Determination................. 1048
F. Implementation of Long-Term Regional Transmission 1062
Planning...........................................
1. NOPR Proposal................................ 1062
2. Comments..................................... 1064
a. Comments on the Initial Timing Sequence.. 1064
b. Comments on Periodic Forums.............. 1067
3. Commission Determination..................... 1071
a. Initial Timing Sequence Implementation... 1071
b. Periodic Forums.......................... 1075
IV. Coordination of Regional Transmission Planning and 1076
Generator Interconnection Processes....................
A. Need for Reform and Overall Reform............... 1076
1. NOPR Proposal................................ 1076
2. Comments..................................... 1079
a. On the Overall Reform.................... 1079
b. Requesting Additional Reform............. 1081
c. Concerns With the Overall Reform......... 1085
d. Cost Allocation.......................... 1093
e. Interconnection Queue Gaming 1095
Considerations.............................
f. Miscellaneous............................ 1098
3. Need for Reform.............................. 1100
4. Commission Determination..................... 1106
B. Transmission Planning Process Evaluation......... 1122
1. NOPR Proposal................................ 1122
2. Comments..................................... 1123
3. Commission Determination..................... 1126
C. Qualifying Criteria.............................. 1130
1. NOPR Proposal................................ 1130
2. Comments..................................... 1134
3. Commission Determination..................... 1145
V. Consideration of Dynamic Line Ratings and Advanced 1163
Power Flow Control Devices.............................
A. General Proposal................................. 1163
1. NOPR Proposal................................ 1163
2. Comments on General Proposal................. 1167
3. Need for Reform.............................. 1194
4. Commission Determination..................... 1198
B. Specific Alternative Transmission Technologies... 1217
1. NOPR Proposal................................ 1217
2. Comments on Specific Technologies............ 1218
3. Commission Determination..................... 1239
VI. Regional Transmission Cost Allocation............... 1248
A. Cost Allocation for Long-Term Regional 1248
Transmission Facilities............................
1. Cost Allocation Methods for Long-Term 1248
Regional Transmission Facilities...............
a. NOPR Proposal............................ 1248
b. Comments................................. 1252
c. Commission Determination................. 1291
2. Requirement that Transmission Providers Seek 1308
the Agreement of Relevant State Entities
Regarding the Cost Allocation Method or Methods
for Long-Term Regional Transmission Facilities.
a. NOPR Proposal............................ 1308
b. Comments................................. 1313
c. Commission Determination................. 1354
3. Proposals Relating to the Design and 1369
Operation of State Agreement Processes.........
a. NOPR Proposal............................ 1369
b. Comments................................. 1371
c. Commission Determination................. 1402
4. Filing Rights Under the FPA.................. 1422
a. Comments................................. 1422
b. Commission Determination................. 1428
5. Time Period and Related Issues in the Long- 1432
Term Regional Transmission Planning Cost
Allocation Processes for State-Negotiated
Alternate Cost Allocation Method...............
a. NOPR Proposal............................ 1432
b. Comments................................. 1436
c. Commission Determination................. 1456
B. Long-Term Regional Transmission Facility Cost 1458
Allocation Compliance With the Existing Six Order
No. 1000 Regional Cost Allocation Principles.......

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1. NOPR Proposal................................ 1458
2. Comments..................................... 1459
a. General Proposal......................... 1459
b. Comments Specific to a State Agreement 1467
Process....................................
3. Commission Determination................. 1469
C. Identification of Benefits Considered in Cost 1480
Allocation for Long-Term Regional Transmission
Facilities.........................................
1. NOPR Proposal................................ 1480
2. Comments..................................... 1482
a. Agree With Proposal...................... 1482
b. Requests To Reflect the Full Breadth of 1491
Benefits in Cost Allocation Methods While
Maintaining Flexibility....................
c. Disagree With Proposal, Mostly Require 1492
Benefits...................................
d. Alignment of Benefits Between 1497
Transmission Planning and Cost Allocation..
e. Additional Benefits or Suggestions for 1502
Refinement.................................
3. Commission Determination..................... 1505
D. Miscellaneous Cost Allocation Comments and 1516
Proposals..........................................
1. Comments..................................... 1516
2. Commission Determination..................... 1521
VII. Construction Work in Progress Incentive............ 1524
A. NOPR Proposal.................................... 1524
B. Comments......................................... 1525
1. Interest in the NOPR Proposal................ 1525
2. Concerns With the NOPR Proposal.............. 1532
3. Interaction of the CWIP Incentive With the 1545
Abandoned Plant Incentive......................
C. Commission Determination......................... 1547
VIII. Exercise of a Federal Right of First Refusal in 1548
Commission-Jurisdictional Tariffs and Agreements.......
A. NOPR Proposal.................................... 1548
B. Comments......................................... 1553
1. General Perspectives and Approach to Reform.. 1553
2. Comments on the NOPR's Joint Ownership 1560
Proposal.......................................
C. Commission Determination......................... 1563
IX. Local Transmission Planning Inputs in the Regional 1565
Transmission Planning Process..........................
A. Need for Reform.................................. 1565
1. NOPR......................................... 1565
2. Comments..................................... 1567
3. Commission Determination..................... 1569
B. Enhanced Transparency of Local Transmission 1578
Planning Inputs in the Regional Transmission
Planning Process...................................
1. NOPR Proposal................................ 1578
2. Comments..................................... 1581
a. Interest in Enhanced Transparency of 1581
Local Transmission Planning Inputs.........
b. Suggested Modifications to the NOPR 1586
Proposal...................................
c. Concern With the NOPR Proposal........... 1591
d. Specific Stakeholder Meeting Requirements 1601
e. Additional Issues........................ 1613
3. Commission Determination..................... 1625
a. Specific Stakeholder Meeting Requirements 1638
b. Additional Issues........................ 1647
C. Identifying Potential Opportunities to Right-Size 1649
Replacement Transmission Facilities................
1. Eligibility.................................. 1649
a. NOPR Proposal............................ 1649
b. Comments................................. 1652
c. Commission Determination................. 1677
2. Right of First Refusal....................... 1693
a. NOPR Proposal............................ 1693
b. Comments................................. 1694
c. Commission Determination................. 1702
3. Cost Allocation.............................. 1710
a. NOPR Proposal............................ 1710
b. Comments................................. 1712
c. Commission Determination................. 1716
4. Miscellaneous................................ 1723
a. Comments................................. 1723
b. Commission Determination................. 1735
X. Interregional Transmission Coordination.............. 1740
A. NOPR Proposal.................................... 1740
B. Comments......................................... 1744
C. Commission Determination......................... 1751
XI. Compliance Procedures............................... 1759
A. NOPR Proposal.................................... 1759
B. Comments......................................... 1761
C. Commission Determination......................... 1768
XII. Information Collection Statement................... 1775
XIII. Environmental Analysis............................ 1784
XIV. Regulatory Flexibility Act......................... 1785

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XV. Document Availability............................... 1789
XVI. Effective Date and Congressional Notification...... 1792

I. Introduction and Background

1. In this final order, the Commission acts under section 206 of
the Federal Power Act (FPA) to adopt reforms to its electric
transmission planning and cost allocation requirements.\1\ The reforms
herein will remedy deficiencies in the Commission's existing regional
and local transmission planning and cost allocation requirements to
ensure that the rates, terms, and conditions for transmission service
provided by public utility transmission providers (transmission
providers) \2\ remain just and reasonable and not unduly discriminatory
or preferential. This final order builds upon Order No. 888, Order No.
890,\3\ and Order No. 1000,\4\ in which the Commission incrementally
developed the requirements that govern regional transmission planning
and cost allocation processes to ensure that Commission-jurisdictional
rates remain just and reasonable and not unduly discriminatory or
preferential. Specifically, in this final order, we find that there is
substantial evidence to support the conclusion that the existing
regional transmission planning and cost allocation processes are
unjust, unreasonable, and unduly discriminatory or preferential because
the Commission's existing transmission planning and cost allocation
requirements do not require transmission providers to: (1) perform a
sufficiently long-term assessment of transmission needs that identifies
Long-Term Transmission Needs; \5\ (2) adequately account on a forward-
looking basis for known determinants of Long-Term Transmission Needs;
and (3) consider the broader set of benefits of regional transmission
facilities planned to meet those Long-Term Transmission Needs.
Accordingly, we believe that it is necessary to revisit existing
transmission planning and cost allocation requirements. We conclude
that adopting the reforms of this final order, as previously
contemplated in the notice of proposed rulemaking (NOPR),\6\ will
remedy the identified deficiencies in existing regional and local
transmission planning and cost allocation requirements, as discussed
below, and will ensure the identification, evaluation, and selection,
as well as the allocation of the costs, of more efficient or cost-
effective regional transmission solutions to address Long-Term
Transmission Needs.
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\1\ 16 U.S.C. 824e.
\2\ Section 201(e) of the FPA, 16 U.S.C. 824(e), defines
``public utility'' to mean ``any person who owns or operates
facilities subject to the jurisdiction of the Commission under this
subchapter.'' As stated in the Order No. 888 pro forma Open Access
Transmission Tariff (OATT), ``transmission provider'' is a ``public
utility (or its Designated Agent) that owns, controls, or operates
facilities used for the transmission of electric energy in
interstate commerce and provides transmission service under the
Tariff.'' Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Servs. by Pub. Utils.; Recovery of
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888,
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036 (1996)
(cross-referenced at 75 FERC ] 61,080), order on reh'g, Order No.
888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048
(cross-referenced at 78 FERC ] 61,220), order on reh'g, Order No.
888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 82
FERC ] 61,046 (1998), aff'd in relevant part sub nom. Transmission
Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000),
aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002); Pro forma OATT
section I.1 (Definitions). The term ``transmission provider''
includes a public utility transmission owner when the transmission
owner is separate from the transmission provider, as is the case in
regional transmission organizations (RTO) and independent system
operators (ISO).
\3\ Preventing Undue Discrimination & Preference in Transmission
Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. &
Regs. ] 31,241, 118 FERC ] 61,119 (2007), order on reh'g, Order No.
890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261
(2007) (cross-referenced at 118 FERC ] 61,119), order on reh'g and
clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC
] 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar.
25, 2009), 126 FERC ] 61,228 (2009), order on clarification, Order
No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ] 61,126 (2009).
\4\ Transmission Plan. & Cost Allocation by Transmission Owning
& Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11,
2011), 136 FERC ] 61,051 (2011), Order No. 1000-A, 77 FR 32184 (May
31, 2012), 139 FERC ] 61,132 (2012), order on reh'g & 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).
\5\ All capitalized terms are defined below. Infra Use of Terms
section.
\6\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, 87 FR 26504
(May 4, 2022), 179 FERC ] 61,028 (2022) (NOPR); see also Bldg. for
the Future Through Elec. Reg'l Transmission Planning & Cost
Allocation & Generator Interconnection, 86 FR 40266 (July 27, 2021),
176 FERC ] 61,024 (2021) (advanced notice of proposed rulemaking
(ANOPR)).
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2. Specifically, the reforms adopted in this final order require
transmission providers in each transmission planning region to
participate in a regional transmission planning process that includes
Long-Term Regional Transmission Planning.\7\ This final order adopts
specific requirements regarding how transmission providers must conduct
Long-Term Regional Transmission Planning, including, among other
things, the use of scenarios to identify Long-Term Transmission Needs
and Long-Term Regional Transmission Facilities to meet those needs.
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\7\ For purposes of this final order, and consistent with Order
No. 1000, a transmission planning region is one in which
transmission providers, in consultation with stakeholders and
affected states, have agreed to participate for purposes of regional
transmission planning and development of a single regional
transmission plan. See Order No. 1000, 136 FERC ] 61,051 at P 160.
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3. This final order also requires transmission providers to measure
and use at least the seven specified benefits to evaluate Long-Term
Regional Transmission Facilities as part of Long-Term Regional
Transmission Planning. In addition, this final order requires
transmission providers to calculate the benefits of Long-Term Regional
Transmission Facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the
transmission facilities and requires that this minimum 20-year benefit
horizon be used both for the evaluation and selection of Long-Term
Regional Transmission Facilities in the regional transmission plan for
purposes of cost allocation.\8\
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\8\ We recognize that some transmission planning regions may
include Long-Term Regional Transmission Facilities, or a portfolio
of such Facilities, in a regional transmission plan, but may not
necessarily include these Facilities for purposes of cost
allocation. See Order No. 1000, 136 FERC ] 61,051 at P 63. For
purposes of this final order, unless otherwise noted, when
referencing Long-Term Regional Transmission Facilities (or a
portfolio of such Facilities) that are selected, we intend
``selected'' to mean that those Facilities are selected in the
regional transmission plan for purposes of cost allocation.
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4. This final order requires transmission providers to include in
their OATTs an evaluation process, including selection criteria, that
they will use to identify and evaluate Long-Term Regional Transmission
Facilities for potential selection to address Long-Term Transmission
Needs.
5. Further, this final order requires transmission providers to
file one or more ex ante Long-Term Regional Transmission Cost
Allocation Methods to allocate the costs of Long-Term Regional
Transmission Facilities (or a portfolio of such Facilities) that are
selected. This final order further permits, but does not require,

[[Page 49285]]

transmission providers to adopt a State Agreement Process, wherein
Relevant State Entities agree to such a State Agreement Process that
would provide up to six months after selection for its participants to
determine, and transmission providers to file, a cost allocation method
for specific Long-Term Regional Transmission Facilities. This final
order establishes a six-month time period (Engagement Period), during
which transmission providers must: (1) provide notice of the starting
and end dates for the six-month time period; (2) post contact
information that Relevant State Entities may use to communicate with
transmission providers about any agreement among Relevant State
Entities on a Long-Term Regional Transmission Cost Allocation Method(s)
and/or a State Agreement Process, as well as a deadline for
communicating such agreement; and (3) provide a forum for negotiation
of a Long-Term Regional Transmission Cost Allocation Method(s) and/or a
State Agreement Process that enables robust participation by Relevant
State Entities.
6. This final order also requires transmission providers to include
in their OATTs a process to provide Relevant State Entities and
interconnection customers the opportunity to voluntarily fund the cost
of, or a portion of the cost of, a Long-Term Regional Transmission
Facility that otherwise would not meet the transmission providers'
selection criteria. This final order requires transmission providers to
include in their OATTs provisions that require transmission providers--
in certain circumstances--to reevaluate Long-Term Regional Transmission
Facilities that previously were selected.
7. In addition, this final order requires that transmission
providers evaluate for potential selection in their existing Order No.
1000 regional transmission planning processes regional transmission
facilities that will address certain identified interconnection-related
transmission needs associated with certain interconnection-related
network upgrades \9\ originally identified through the generator
interconnection process.
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\9\ The Commission's pro forma Large Generator Interconnection
Procedures (LGIP) and pro forma Large Generator Interconnection
Agreement (LGIA) provide that, ``Network Upgrades shall mean the
additions, modifications, and upgrades to the Transmission
Provider's Transmission System required at or beyond the point at
which the Interconnection Facilities connect to the Transmission
Provider's Transmission System to accommodate the interconnection of
the Large Generating Facility to the Transmission Provider's
Transmission System.'' See Improvements to Generator Interconnection
Procedures & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6,
2023), 184 FERC ] 61,054, at P 13 n.23, order on reh'g, 185 FERC ]
61,063 (2023), order on reh'g, Order No. 2023-A, 89 FR 27006 (Apr.
16, 2024), 186 FERC ] 61,199 (2024). In this final order, we refer
to network upgrades developed through the generator interconnection
process as interconnection-related network upgrades.
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8. This final order requires transmission providers in each
transmission planning region to consider more fully the alternative
transmission technologies of dynamic line ratings, advanced power flow
control devices, advanced conductors, and transmission switching in
Long-Term Regional Transmission Planning and existing Order No. 1000
regional transmission planning and cost allocation processes.
9. This final order does not finalize the NOPR proposal to not
permit transmission providers to take advantage of the recovery of 100%
of construction work in progress for Long-Term Regional Transmission
Facilities, and the Commission will instead continue to consider
transmission incentives issues in other proceedings. This final order
similarly does not finalize the NOPR proposal with respect to
permitting the exercise of Federal rights of first refusal for selected
transmission facilities, conditioned on the incumbent transmission
provider with the Federal right of first refusal establishing joint
ownership of the transmission facilities, and the Commission will
instead continue considering the NOPR proposal and potential Federal
right of first refusal issues in other proceedings.
10. This final order adopts the NOPR proposal to require
transmission providers to adopt enhanced transparency requirements for
local transmission planning processes and improve coordination between
regional and local transmission planning with the aim of identifying
potential opportunities to ``right-size'' replacement transmission
facilities.
11. This final order requires transmission providers to revise
their interregional transmission coordination processes to reflect the
Long-Term Regional Transmission Planning reforms adopted in this final
order. This final order also requires that transmission providers meet
additional information sharing and transparency requirements with
respect to their interregional transmission coordination processes.
12. This final order requires that each transmission provider
submit a compliance filing within ten months of the effective date of
this final order revising its OATT and other document(s) subject to the
Commission's jurisdiction to demonstrate that it meets the requirements
of this final order, with the exception of those requirements adopted
in the Interregional Transmission Coordination section in this final
order. This final order requires that each transmission provider submit
a compliance filing within 12 months of the effective date of this
final order revising its OATT and other document(s) subject to the
Commission's jurisdiction as necessary to demonstrate that it meets the
interregional transmission coordination requirements adopted in this
final order.
13. We recognize that transmission providers have ongoing efforts
to address transmission planning and cost allocation. This final order
is not intended to interfere with the potential progress represented by
those efforts, and we encourage transmission providers to continue to
innovate to improve their transmission planning and cost allocation
processes.

A. Historical Framework: Order Nos. 888, 890, and 1000

14. Over the last several decades, the Commission has taken
multiple significant actions on transmission planning and cost
allocation, including issuing Order Nos. 888, 890, and 1000. In 1996,
the Commission issued Order No. 888, which implemented open access to
transmission facilities owned, operated, or controlled by a public
utility and included certain minimum requirements for transmission
planning. In 2007, the Commission issued Order No. 890 to address
identified deficiencies in the pro forma OATT after more than 10 years
of experience since Order No. 888. Among other OATT reforms, the
Commission required all public utility transmission providers' local
transmission planning processes to 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.\10\
---------------------------------------------------------------------------

\10\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
---------------------------------------------------------------------------

15. In 2011, the Commission recognized the need for further
transmission planning reforms with its issuance of Order No. 1000. The
Commission based the reforms it adopted in Order No. 1000 on changes in
the energy industry, its experience implementing Order No. 890, and a
robust record developed through technical conferences and comments

[[Page 49286]]

from a diverse range of stakeholders.\11\ The Commission stated in
Order No. 1000 that ``the electric industry is currently facing the
possibility of substantial investment in future transmission facilities
to meet the challenge of maintaining reliable service at a reasonable
cost.'' \12\ In establishing the requirements of Order No. 1000, the
Commission found that the existing requirements of Order No. 890 were
not adequate, noting that Order No. 1000 ``expands upon the reforms
begun in Order No. 890 by addressing new concerns that have become
apparent in the Commission's ongoing monitoring of these matters.''
\13\ The Commission then enumerated multiple concerns that it had
regarding existing transmission planning practices, including concerns
about: (1) the lack of an affirmative obligation to develop a
transmission plan evaluating if a regional transmission facility ``may
be more efficient or cost-effective than solutions identified in local
transmission planning processes''; (2) the lack of a requirement to
address Public Policy Requirements; \14\ (3) the Federal right of first
refusal for incumbent transmission developers to build upgrades to
their existing transmission facilities; (4) the lack of procedures to
identify and evaluate the benefits of interregional transmission
facilities; and (5) cost allocation for regional and interregional
transmission facilities.\15\
---------------------------------------------------------------------------

\11\ For purposes of this final order, and consistent with Order
No. 1000, a stakeholder includes any party interested in the
transmission planning processes. See Order No. 1000, 136 FERC ]
61,051 at P 151 n.143.
\12\ Id. P 2.
\13\ Id. P 21.
\14\ 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). Id. P 2. Order No. 1000-A clarified
that Public Policy Requirements include local laws or regulations
passed by a local governmental entity, such as a municipal or county
government. Order No. 1000-A, 139 FERC ] 61,132 at P 319.
\15\ Order No. 1000, 136 FERC ] 61,051 at P 3.
---------------------------------------------------------------------------

16. Order No. 1000 included reforms intended to ensure that the
transmission planning and cost allocation requirements embodied in the
pro forma OATT could support the development of more efficient or cost-
effective transmission facilities.\16\ The reforms in Order No. 1000
included: (1) regional transmission planning; (2) transmission needs
driven by Public Policy Requirements; (3) nonincumbent transmission
developer reforms; (4) regional and interregional cost allocation,
including a set of principles for each category of cost allocation; and
(5) interregional transmission coordination. The reforms focused on the
process by which transmission providers engage in regional transmission
planning and the associated cost allocation rather than on the outcomes
of the process.\17\
---------------------------------------------------------------------------

\16\ Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ] 61,132 at
PP 3, 4-6.
\17\ Order No. 1000, 136 FERC ] 61,051 at P 12.
---------------------------------------------------------------------------

17. Among other regional transmission planning reforms in Order No.
1000, the Commission required that the following Order No. 890
transmission planning principles apply to regional transmission
planning processes: (1) coordination; (2) openness; (3) transparency;
(4) information exchange; (5) comparability; (6) dispute resolution;
and (7) economic planning studies.\18\
---------------------------------------------------------------------------

\18\ The Commission did not include the regional participation
or cost allocation transmission planning principles with respect to
regional transmission planning processes because those issues were
addressed by other reforms in Order No. 1000. Id. P 151.
---------------------------------------------------------------------------

18. In addition, with respect to the Order No. 1000 reforms, the
Commission made a distinction between a transmission facility
``included'' in a regional transmission plan and a transmission
facility ``selected.'' A transmission facility selected in a regional
transmission plan for purposes of cost allocation is a transmission
facility that has been selected pursuant to a transmission planning
region's Commission-approved regional transmission planning process for
inclusion in a regional transmission plan for purposes of cost
allocation because it is a more efficient or cost-effective
transmission facility needed to meet regional transmission needs. Both
regional transmission facilities and interregional transmission
facilities are eligible for potential ``selection'' in a regional
transmission plan for purposes of cost allocation.\19\
---------------------------------------------------------------------------

\19\ Id. P 63. A regional transmission facility and an
interregional transmission facility are defined below. Infra Use of
Terms section.
---------------------------------------------------------------------------

19. Selected transmission facilities often will not comprise all of
the transmission facilities that are included in a regional
transmission plan.\20\ Some transmission facilities are merely ``rolled
up'' and listed in a regional transmission plan without going through
an analysis at the regional level, and/or are merely considered for
reliability implications upon a transmission system, and therefore, are
not eligible for selection and regional cost allocation.\21\ For
example, a local transmission facility is a transmission facility
located solely within a transmission provider's retail distribution
service territory or footprint that is not selected.\22\ Thus, a local
transmission facility may be rolled up and ``included'' in a regional
transmission plan for informational purposes, but it is not
``selected.''
---------------------------------------------------------------------------

\20\ Order No. 1000, 136 FERC ] 61,051 at P 63.
\21\ Id. PP 7, 226, 318.
\22\ Id. P 63. The Commission clarified in Order No. 1000-A that
a local transmission facility is one that is located within the
geographical boundaries of a public utility transmission provider's
retail distribution service territory, if it has one; otherwise, the
area is defined by the public utility transmission provider's
footprint. In the case of an RTO/ISO whose footprint covers the
entire region, a local transmission facility is defined by reference
to the retail distribution service territories or footprints of its
underlying transmission owing members. Order No. 1000-A, 139 FERC ]
61,132 at P 429.
---------------------------------------------------------------------------

B. ANOPR and Technical Conference

20. In July 2021, the Commission issued the ANOPR \23\ presenting
potential reforms to improve the regional transmission planning and
cost allocation and generator interconnection processes. In issuing the
ANOPR, the Commission noted that, in part because more than a decade
had passed since Order No. 1000, it was now an appropriate time to
review its regulations governing regional transmission planning and
cost allocation to determine whether reforms are needed to ensure
Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.\24\ The Commission noted that
the electricity sector is transforming as the generation fleet shifts
from resources located close to population centers toward resources
that may often be located far from load centers. The Commission also
highlighted the growth of new resources seeking to interconnect to the
transmission system and that the differing characteristics of those
resources are creating new demands on the transmission system. The
Commission explained that ensuring just and reasonable Commission-
jurisdictional rates during these changes, while maintaining grid
reliability, remains the Commission's priority in adopting requirements
for the regional transmission planning and cost allocation and
generator interconnection processes. As a result, the Commission issued
the ANOPR 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
Commission-jurisdictional rates remain just and reasonable and not
unduly

[[Page 49287]]

discriminatory or preferential and that reliability is maintained.
---------------------------------------------------------------------------

\23\ ANOPR, 176 FERC ] 61,024.
\24\ Id. P 3.
---------------------------------------------------------------------------

21. On November 15, 2021, the Commission convened a staff-led
technical conference (November 2021 Technical Conference or Technical
Conference) to examine in detail issues and potential reforms related
to regional transmission planning as described in the ANOPR.
Specifically, the Technical Conference included three panels covering
issues to consider in long-term scenarios, consideration of long-term
scenarios in regional transmission planning processes, and identifying
geographic zones with high renewable resource potential for use in
regional transmission planning processes.\25\ Following the Technical
Conference, the Commission invited all interested persons to file
comments to address issues raised during the Technical Conference.
---------------------------------------------------------------------------

\25\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, Further
Supplemental Notice of Technical Conference, Docket No. RM21-17-000
(issued Nov. 12, 2021) (attaching agenda).
---------------------------------------------------------------------------

C. Joint Federal-State Task Force on Electric Transmission

22. On June 17, 2021, the Commission established a Joint Federal-
State Task Force on Electric Transmission (Task Force) to formally
explore broad categories of transmission-related topics.\26\ The
Commission explained that the development of new transmission
infrastructure implicates a host of different issues, including how to
plan and pay for these facilities. Given that Federal and state
regulators each have authority over transmission-related issues and
given the impact of transmission infrastructure development on numerous
different priorities of Federal and state regulators, the Commission
determined that the topic was ripe for greater Federal-state
coordination and cooperation.\27\ The Task Force was composed of all
sitting FERC Commissioners as well as representatives from 10 state
commissions nominated by the National Association of Regulatory Utility
Commissioners (NARUC), with two originating from each NARUC region.\28\
---------------------------------------------------------------------------

\26\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC
] 61,224, at PP 1, 6 (2021).
\27\ Id. P 2.
\28\ An up-to-date list of Task Force members, as well as
additional information on the Task Force, is available on the
Commission's website at: <a href="https://www.ferc.gov/TFSOET">https://www.ferc.gov/TFSOET</a>. Public
materials related to the Task Force, including transcripts from
public meetings, are available in the Commission's eLibrary in
Docket No. AD21-15-000.
---------------------------------------------------------------------------

23. The Task Force has convened multiple formal meetings with eight
meetings held thus far to discuss regional transmission planning and
cost allocation issues, convening on November 10, 2021, February 16,
2022, May 6, 2022, July 20, 2022, November 15, 2022, February 15, 2023,
July 16, 2023, and February 28, 2024.
24. The discussion at the November 2021 meeting was focused on
incorporating state perspectives into regional transmission
planning.\29\ The February 2022 meeting included discussion of specific
categories and types of transmission benefits that transmission
providers should consider for the purposes of transmission planning and
cost allocation.\30\ The May 2022 meeting focused on barriers to the
efficient, expeditious, and reliable interconnection of new
resources.\31\ The July 2022 meeting focused on interregional
transmission planning and transmission project development and the
NOPR.\32\ The November 2022 meeting focused on regulatory gaps and
challenges in oversight of transmission development.\33\ The February
2023 meeting focused on the physical security of the Nation's
transmission system, and featured guest speakers from the North
American Electric Reliability Corporation and US DOE.\34\ The July 2023
meeting focused on grid enhancing technologies, featuring a guest
speaker from the Electric Power Research Institute.\35\ The February
2024 meeting focused on transmission siting, featuring guest speakers
from US DOE.\36\
---------------------------------------------------------------------------

\29\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching
agenda).
\30\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching
agenda).
\31\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022) (attaching
agenda).
\32\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued June 30, 2022) (attaching
agenda).
\33\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Nov. 1, 2022) (attaching
agenda).
\34\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 1, 2023) (attaching
agenda).
\35\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued June 30, 2023) (attaching
agenda).
\36\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 13, 2024) (attaching
agenda).
---------------------------------------------------------------------------

25. In light of the Task Force expiring three years from its first
public meeting, i.e., on November 10, 2024,\37\ on March 21, 2024, the
Commission established the Federal and State Current Issues
Collaborative (Collaborative).\38\ The Collaborative will be comprised
of all Commissioners, as well as representative from 10 state
commissions. The Collaborative will provide a venue for Federal and
state regulators to share perspectives, increase understanding, and
where appropriate, identify potential solutions regarding challenges
and coordination on matters that impact specific state and Federal
regulatory jurisdiction.\39\
---------------------------------------------------------------------------

\37\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC
] 61,224 at P 4.
\38\ Joint Fed.-State Task Force on Elec. Transmission, 186 FERC
] 61,189 (2024).
\39\ Id. PP 5-6.
---------------------------------------------------------------------------

D. Notice of Proposed Rulemaking

26. On April 21, 2022, the Commission issued the NOPR, proposing
reforms focused on long-term regional transmission planning and cost
allocation processes. In particular, the Commission proposed in the
NOPR that transmission providers in each transmission planning region
participate in a regional transmission planning process that includes
Long-Term Regional Transmission Planning.\40\ The Commission also
proposed to require that transmission providers develop Long-Term
Scenarios as part of Long-Term Regional Transmission Planning.\41\
---------------------------------------------------------------------------

\40\ NOPR, 179 FERC ] 61,028 at PP 64, 68.
\41\ Id. P 84.
---------------------------------------------------------------------------

27. The Commission proposed that transmission providers consider,
as part of their Long-Term Regional Transmission Planning, regional
transmission facilities that address certain interconnection-related
transmission needs that the transmission provider has identified
multiple times in the generator interconnection process but that have
never been constructed due to the withdrawal of the relevant
interconnection request(s).\42\
---------------------------------------------------------------------------

\42\ Id. P 166.
---------------------------------------------------------------------------

28. The Commission proposed 12 benefits that transmission providers
may consider in Long-Term Regional Transmission Planning and cost
allocation processes.\43\ The Commission stated that the list of
potential benefits was neither mandatory nor exhaustive, and that
pursuant to the proposal, transmission providers would have flexibility
to propose which benefits to use as part of their Long-Term Regional
Transmission Planning.\44\
---------------------------------------------------------------------------

\43\ Id. P 185.
\44\ Id. P 184.
---------------------------------------------------------------------------

29. The Commission proposed, with regard to the selection of Long-
Term Regional Transmission Facilities in the regional transmission plan
for purposes of cost allocation, to require that transmission
providers, as part of their Long-Term Regional Transmission Planning,
include in their OATTs: (1) transparent and not unduly

[[Page 49288]]

discriminatory criteria, which seek to maximize benefits to consumers
over time without over-building transmission facilities, to identify
and evaluate transmission facilities for potential selection that
address transmission needs driven by changes in the resource mix and
demand; and (2) a process to coordinate with the Relevant State
Entities in developing such criteria.\45\
---------------------------------------------------------------------------

\45\ Id. P 241.
---------------------------------------------------------------------------

30. The Commission proposed to require transmission providers to
more fully consider the incorporation into transmission facilities of
dynamic line ratings and advanced power flow control devices in
regional transmission planning and cost allocation processes.\46\
---------------------------------------------------------------------------

\46\ Id. P 272.
---------------------------------------------------------------------------

31. The Commission proposed to require, with regard to allocating
the costs of Long-Term Regional Transmission Facilities, transmission
providers to revise their OATTs to include: (1) a Long-Term Regional
Transmission Cost Allocation Method to allocate the costs of Long-Term
Regional Transmission Facilities; (2) a State Agreement Process by
which one or more Relevant State Entities may voluntarily agree to a
cost allocation method; or (3) a combination thereof.\47\ The
Commission proposed to require transmission providers to seek the
agreement of Relevant State Entities within the transmission planning
region regarding the Long-Term Regional Transmission Cost Allocation
Method, State Agreement Process, or combination thereof.\48\ The
Commission proposed to require transmission providers to identify on
compliance the benefits they will use in ex ante Long-Term Regional
Transmission Cost Allocation Methods associated with Long-Term Regional
Transmission Planning, how they will calculate those benefits, and how
the benefits will reasonably reflect the benefits of regional
transmission facilities to meet identified transmission needs driven by
changes in the resource mix and demand.\49\
---------------------------------------------------------------------------

\47\ Id. P 302.
\48\ Id. P 303.
\49\ Id. P 326.
---------------------------------------------------------------------------

32. The Commission further proposed to not permit transmission
providers to take advantage of the allowance for inclusion of 100% of
construction work in progress costs in rate base in certain
circumstances for Long-Term Regional Transmission Facilities.\50\
---------------------------------------------------------------------------

\50\ Id. P 333.
---------------------------------------------------------------------------

33. Finally, the Commission proposed to permit the exercise of
Federal rights of first refusal for selected transmission facilities,
conditioned on the incumbent transmission provider with the Federal
right of first refusal for such regional transmission facilities
establishing joint ownership of the transmission facilities consistent
with certain proposed requirements described in the NOPR.\51\
---------------------------------------------------------------------------

\51\ Id. P 351.
---------------------------------------------------------------------------

34. The Commission also proposed to require transmission providers
to revise the regional transmission planning process in their OATTs
with additional provisions to enhance transparency of: (1) the
criteria, models, and assumptions that they use in their local
transmission planning process; (2) the local transmission needs that
they identify through that process; and (3) the potential local or
regional transmission facilities that they will evaluate to address
those local transmission needs.\52\ The Commission proposed to require
transmission providers to evaluate whether transmission facilities
operating at or above 230 kV that an individual transmission provider
that owns the transmission facility anticipates replacing in-kind with
a new transmission facility during the next 10 years can be ``right-
sized'' to more efficiently or cost-effectively address regional
transmission needs identified in Long-Term Regional Transmission
Planning.\53\
---------------------------------------------------------------------------

\52\ Id. P 400.
\53\ Id. P 403.
---------------------------------------------------------------------------

35. The Commission further proposed to require transmission
providers in neighboring transmission planning regions to revise their
existing interregional transmission coordination procedures (and
regional transmission planning processes as needed) to provide for: (1)
the sharing of information regarding their respective transmission
needs identified in Long-Term Regional Transmission Planning, as well
as potential transmission facilities to meet those needs; and (2) the
identification and joint evaluation of interregional transmission
facilities that may be more efficient or cost-effective transmission
facilities to address transmission needs identified through Long-Term
Regional Transmission Planning.\54\ Finally, the Commission proposed to
require transmission providers in neighboring transmission planning
regions to revise their interregional transmission coordination
procedures (and regional transmission planning processes as needed) to
allow an entity to propose an interregional transmission facility in
the regional transmission planning process as a potential solution to
transmission needs identified through Long-Term Regional Transmission
Planning.\55\
---------------------------------------------------------------------------

\54\ Id. P 427.
\55\ Id. P 428.
---------------------------------------------------------------------------

E. High-Level Overview of NOPR Comments

36. The Commission received a great many comments from a diverse
set of parties in response to the NOPR.\56\ One hundred and ninety-six
parties, including Federal agencies, state regulatory commissions,
state policy makers and other state representatives, ratepayer
advocates, municipalities, RTOs/ISOs, RTO/ISO market monitors,
transmission providers, transmission-dependent utilities, electric
cooperatives, municipal power providers, independent power producers,
transmission developers, generation trade associations, transmission
trade associations, industry interest groups, consumer interest groups,
energy policy and law interest groups, individual businesses,
landowners, and individuals, filed initial comments that totaled over
15,000 pages with attachments. A similarly diverse set of 92 parties
filed reply comments that totaled nearly 1,900 pages.
---------------------------------------------------------------------------

\56\ See appendix A for a list of commenters and the abbreviated
names of commenters that are used in this final order.
---------------------------------------------------------------------------

F. Use of Terms

37. Before turning to the detailed requirements of this final
order, we note several of the key terms used herein. We further address
the definitions of these terms, including any modifications to
definitions proposed in the NOPR, in the relevant later sections of
this final order.
38. For purposes of this final order, Long-Term Regional
Transmission Planning means regional transmission planning on a
sufficiently long-term, forward-looking, and comprehensive basis to
identify Long-Term Transmission Needs, identify transmission facilities
that meet such needs, measure the benefits of those transmission
facilities, and evaluate those transmission facilities for potential
selection in the regional transmission plan for purposes of cost
allocation as the more efficient or cost-effective regional
transmission facilities to meet Long-Term Transmission Needs.
39. For purposes of this final order, Long-Term Transmission Needs
are transmission needs identified through Long-Term Regional
Transmission Planning by, among other things and as discussed in this
final order, running

[[Page 49289]]

scenarios and considering the enumerated categories of factors.\57\
---------------------------------------------------------------------------

\57\ Further discussion on Long-Term Transmission Needs can be
found below. Infra Development of Long-Term Scenarios subsection
under the Long-Term Regional Transmission Planning section.
---------------------------------------------------------------------------

40. For purposes of this final order, Long-Term Scenarios are
scenarios that incorporate various assumptions using best available
data inputs about the future electric power system over a sufficiently
long-term, forward-looking transmission planning horizon to identify
Long-Term Transmission Needs and enable the identification and
evaluation of transmission facilities to meet such transmission needs.
41. For purposes of this final order, a Long-Term Regional
Transmission Facility is a regional transmission facility \58\ that is
identified as part of Long-Term Regional Transmission Planning to
address Long-Term Transmission Needs.
---------------------------------------------------------------------------

\58\ For purposes of this final order, and consistent with Order
No. 1000, a regional transmission facility is a transmission
facility located entirely in one transmission planning region. An
interregional transmission facility is a transmission facility that
is located in two or more transmission planning regions. A local
transmission facility is 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. Order No. 1000,
136 FERC ] 61,051 at PP 63, 482 n.374.
---------------------------------------------------------------------------

42. For purposes of this final order, best available data inputs
are data inputs that are timely, developed using best practices and
diverse and expert perspectives, and adopted via a process that
satisfies the transmission planning principles of Order Nos. 890 and
1000, and reflect the list of factors that transmission providers
account for in their Long-Term Scenarios.
43. For purposes of this final order, a Long-Term Regional
Transmission Cost Allocation Method is an ex ante regional cost
allocation method for one or more selected Long-Term Regional
Transmission Facilities (or a portfolio of such Facilities) that are
selected in the regional transmission plan for purposes of cost
allocation.
44. For purposes of this final order, a Relevant State Entity is
any state entity responsible for electric utility regulation or siting
electric transmission facilities within the state or portion of a state
located in the transmission planning region, including any state entity
as may be designated for that purpose by the law of such state.
45. For purposes of this final order, a State Agreement Process is
a process by which one or more Relevant State Entities may voluntarily
agree to a cost allocation method for Long-Term Regional Transmission
Facilities (or a portfolio of such Facilities) before or no later than
six months after they are selected.
46. For purposes of this final order, federally-recognized Tribes
are those Tribes listed in the most recent notice provided by the
Bureau of Indian Affairs and published in the Federal Register.\59\
---------------------------------------------------------------------------

\59\ See, e.g., Indian Entities Recognized by and Eligible to
Receive Servs. from the U.S. Bureau of Indian Affairs, Federal
Register, 89 FR 944 (Jan. 8, 2024).
---------------------------------------------------------------------------

II. The Overall Need for Reform

A. NOPR Proposal

47. The Commission issued the NOPR on April 21, 2022, proposing to
reform the pro forma OATT and the pro forma LGIA to remedy deficiencies
in the Commission's existing regional transmission planning and cost
allocation requirements. The Commission stated that, over the last 25
years, it has undertaken a series of significant reforms to ensure that
transmission planning and cost allocation processes result in
Commission-jurisdictional rates that are just and reasonable and not
unduly discriminatory or preferential.\60\ The Commission noted that it
has now been more than a decade since Order No. 1000--its last
significant regional transmission planning and cost allocation rule--
and that there is mounting evidence that its regional transmission
planning and cost allocation requirements may be inadequate to ensure
that Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.\61\
---------------------------------------------------------------------------

\60\ NOPR, 179 FERC ] 61,028 at P 24.
\61\ Id.
---------------------------------------------------------------------------

48. The Commission found that, in particular, although transmission
providers are required to participate in regional transmission planning
and cost allocation processes under Order No. 1000, it was concerned
that those processes may not be planning transmission on a sufficiently
long-term, forward-looking basis to meet transmission needs driven by
changes in the resource mix and demand. The Commission stated that, as
a result, the regional transmission planning and cost allocation
processes that transmission providers adopted to comply with Order No.
1000 may not be identifying the more efficient or cost-effective
transmission facilities.\62\ The Commission stated that it was
concerned that the absence of sufficiently long-term, forward-looking,
comprehensive transmission planning processes appears to be resulting
in piecemeal transmission expansion to address relatively near-term
transmission needs, and that continuing with the status quo approach
may cause transmission providers to undertake relatively inefficient
investments in transmission infrastructure, the costs of which are
ultimately recovered through Commission-jurisdictional rates. The
Commission stated that this dynamic may result in transmission
customers paying more than necessary to meet their transmission needs,
customers forgoing benefits that outweigh their costs, or some
combination thereof--either or both of which could potentially render
Commission-jurisdictional rates unjust and unreasonable or unduly
discriminatory or preferential. Based on the evidence, the Commission
preliminarily concluded that revisions to its existing transmission
planning and cost allocation requirements established in Order Nos. 890
and 1000 are necessary to ensure that Commission-jurisdictional
services are provided at rates, terms, and conditions that are just and
reasonable and not unduly discriminatory and preferential.\63\
---------------------------------------------------------------------------

\62\ Id. PP 24-25.
\63\ Id. PP 25, 27, 34-35.
---------------------------------------------------------------------------

B. Comments

49. A significant majority of commenters, including transmission
providers, transmission developers, transmission customers, members of
Congress, states, state commissions, consumer advocates, trade
associations, and public interest organizations, among others, agree
that existing regional transmission planning and cost allocation
processes need to be reformed.\64\ Advanced Energy Buyers

[[Page 49290]]

note that the electric system is presently undergoing one of the most
significant transformations in a century.\65\ Other commenters agree
that electric energy supply and demand is evolving quickly.\66\ Clean
Energy Buyers agree with the Commission that there is a need for reform
to meet these drastic changes in the resource mix and load and to
ensure continued reliability and cost-effective transmission
service.\67\
---------------------------------------------------------------------------

\64\ See, e.g., Acadia Center and CLF Initial Comments at 1-2;
ACEG Initial Comments at 11-12, 21-22; ACORE Initial Comments at 2-
5; ACORE Supplemental Comments at 1; Advanced Energy Buyers Initial
Comments at 2-3; AEE Initial Comments at 7-8; AEP Initial Comments
at 1-3; Amazon Initial Comments at 1-2; Ameren Initial Comments at
1-2; American Municipal Power Initial Comments at 4; Anbaric Initial
Comments at 1; Arizona Commission Initial Comments at 3-4; Avangrid
Initial Comments at 5-6; BP Initial Comments at 3; Breakthrough
Energy Initial Comments at 5-6; Breakthrough Energy Supplemental
Comments at 1; Business Council for Sustainable Energy Initial
Comments at 2-3; California Commission Initial Comments at 1-2;
California Energy Commission Initial Comments at 1; CAISO Initial
Comments at 1; City of New Orleans Council Initial Comments at 4, 7-
9; Cross Sector Representatives Supplemental Comments at 1; DC and
MD Offices of People's Counsel Initial Comments at 4-5; US Senators
Supplemental Comments at 1; EEI Initial Comments at 4-5; ELCON
Initial Comments at 4; Enel Initial Comments at 2, 7; ENGIE Initial
Comments at 1-2; Entergy Initial Comments at 2-3; Environmental
Legislators Caucus Supplemental Comments at 1; Evergreen Action
Initial Comments at 1-3; Eversource Initial Comments at 1-2, 5-9;
Exelon Initial Comments at 1-2; Grid United Initial Comments at 1-2;
Handy Law Initial Comments at 1-7; Harvard ELI Initial Comments at
1; Illinois Commission Initial Comments at 3; Indicted PJM TOs
Initial Comments at 1-2; Indicated US Senators and Representatives
Initial Comments at 1; Interwest Initial Comments at 2-3; Invenergy
Initial Comments at 2, 5; ISO-NE Initial Comments at 2, 8-9; ISO/RTO
Council Initial Comments at 2; Kansas Commission Initial Comments at
10-11; Massachusetts Attorney General Initial Comments at 3-6;
Michigan Commission Initial Comments at 2, 4; Michigan State
Entities Initial Comments at 3-4; Minnesota State Entities Initial
Comments at 2-3; National Grid Initial Comments at 1, 6; National
and State Conservation Organizations Initial Comments at 1; NESCOE
Initial Comments at 2, 7, 14-15; New Jersey Commission Initial
Comments at 1-2; New York Commission and NYSERDA Initial Comments at
1-3; NextEra Reply Comments at 1; Non-RTO NASUCA Initial Comments at
4-5; NYISO Initial Comments at 2-3; Onward Energy Initial Comments
at 1-2; [Oslash]rsted Initial Comments at 2-3; Pattern Energy
Initial Comments at 1; PacifiCorp and NV Energy Initial Comments at
2, 7-8; Pacific Northwest State Agencies Initial Comments at 1, 8;
PG&E Initial Comments at 1; PIOs Initial Comments at 6-7; Policy
Integrity Initial Comments at 1-2; Renewable Northwest Initial
Comments at 3-4; RMI Supplemental Comments at 1-2; SPP Market
Monitor Initial Comments at 3-4; SEIA Initial Comments at 2; Shell
Initial Comments at 1, 9; US Senator Barrasso Supplemental Comments
at 2; Senator Whitehouse Supplemental Comments at 2; Southeast PIOs
Initial Comments at 1; SREA Initial Comments at 1; State Officials
Supplemental Comments at 1; TAPS Initial Comments at 1-2; US DOE
Initial Comments at 1-4; US DOJ and FTC Initial Comments 1, 5;
Vermont State Entities Initial Comments at 2; Western State
Representatives Initial Comments at 3-4; WIRES Initial Comments at
2, 5.
\65\ Advanced Energy Buyers Initial Comments at 2.
\66\ See, e.g., AEE Initial Comments at 1; Cross Sector
Representatives Supplemental Comments at 1; Eversource Initial
Comments at 5-8 (citing ISO-NE, 2020 Regional Electricity Outlook,
at 35 (2020)); Indicated PJM TOs Initial Comments at 1-2; Kansas
Commission Initial Comments at 2; Pattern Energy Initial Comments at
1; PG&E Initial Comments at 1; Policy Integrity Initial Comments at
2; Renewable Northwest Initial Comments at 5; State Agencies Initial
Comments at 12-13; WIRES Initial Comments at 3.
\67\ Clean Energy Buyers Initial Comments at 7.
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50. Many commenters argue that current regional transmission
planning and cost allocation processes across the country are not
ensuring efficient and cost-effective transmission development, are not
satisfying the purposes of Order Nos. 890 and 1000, and are not meeting
transmission needs at a reasonable cost. For example, several
commenters assert that Order Nos. 890 and 1000 have not solved
longstanding problems with regional transmission planning and cost
allocation.\68\ Northwest and Intermountain claim that Order No. 1000
has been inadequate to meet transmission needs, particularly in the
non-RTO/ISO West.\69\ Michigan State Entities assert that the current
lack of long-term transmission planning has led to significantly higher
costs for residential ratepayers, costs that will increase without
reforms.\70\ SREA argues that reform is needed to correct the
unintended consequences of Order No. 1000 in the Southeast, where
transmission planning ``has grown into an enormously elaborate and
extremely expensive black box,'' without any meaningful review by state
regulatory bodies.\71\
---------------------------------------------------------------------------

\68\ See, e.g., Acadia Center and CLF Initial Comments at 1;
ACEG Initial Comments at 17-18, 20 (citing Order No. 1000, 136 FERC
] 61,051 at P 3; NOPR, 179 FERC ] 61,028 at PP 24-25); AEE Initial
Comments at 1-2; CARE Coalition Initial Comments at 3; NERC Initial
Comments at 5; Massachusetts Attorney General Initial Comments at 5-
6; Northwest and Intermountain Initial Comments at 6-7; Pine Gate
Initial Comments at 8-10; PIOs Initial Comments at 2-3; Southeast
PIOs Initial Comments at 7-9, 11, 16-17, 43-44; SPP Market Monitor
Initial Comments at 3-4; SREA Reply Comments at 4; US DOE Initial
Comments at 3-4, 7-8.
\69\ Northwest and Intermountain Initial Comments at 6-7.
\70\ Michigan State Entities Initial Comments at 1-2.
\71\ SREA Reply Comments at 4.
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51. PIOs assert that transmission owners can evade Order No. 1000
requirements through investments in local transmission projects, which
has led to billions of dollars in excessive costs.\72\ PIOs explain
that financial incentives drive utilities to upgrade their own systems
at the expense of building a more integrated and robust transmission
system to meet the needs and demands of the future.\73\ PIOs observe
that, between 2013 and 2017, about one-half of the approximately $70
billion in aggregate transmission investments by Commission-
jurisdictional transmission owners in RTO/ISO regions were approved
outside of regional transmission planning processes or with limited
stakeholder engagement.\74\ Ohio Consumers add that since 2017, less
than 25% of new transmission investments in Ohio have been associated
with large regional transmission projects needed for reliability or
economic efficiency.\75\ Competition Coalition argues that incumbent
transmission owners have used reliability designations to justify
projects with higher costs.\76\
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\72\ PIOs Initial Comments at 8 (citing Johannes P.
Pfeifenberger et al., The Brattle Group, Cost Savings Offered by
Competition in Electric Transmission: Experience to Date and the
Potential for Additional Customer Value, at 19-20, and Section I
(Apr. 2019) (Brattle Apr. 2019 Competition Report), <a href="https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf">https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf</a>).
\73\ Id. at 6-7.
\74\ Id. at 9 (citing Brattle Apr. 2019 Competition Report at
4).
\75\ Ohio Consumers Initial Comments at 5.
\76\ Competition Coalition Initial Comments at 15-16.
---------------------------------------------------------------------------

52. Citing to a report from Lawrence Berkeley National Laboratory,
US DOE concludes that many existing regional transmission planning
approaches are likely understating the economic value of new
transmission. US DOE suggests that the need for increased transmission
capacity to address persistent and worsening transmission congestion
demonstrates that these processes may not fully anticipate present and
future transmission needs.\77\ In addition, US DOE notes the unfair
burden on interconnection customers that must bear increasing costs,
especially for interconnection-related network upgrades that provide
system-wide benefits.\78\ US DOJ and FTC agree that reforms are
necessary to encourage needed regional and interregional transmission
investment and that a larger, more integrated transmission system would
improve resilience, promote competition, and lower costs for
consumers.\79\
---------------------------------------------------------------------------

\77\ US DOE Initial Comments at 3-4.
\78\ Id. at 7-8.
\79\ US DOJ and FTC Initial Comments at 1, 5 (citing NOPR, 179
FERC ] 61,028 at P 6; P. R. Brown & A. Botterud, The Value of Inter-
Regional Coordination and Transmission in Decarbonizing the US
Electricity System, 5 Joule 115, 115-134 (2021); Eric Larson et al.,
Princeton Univ., Net-Zero America: Potential Pathways,
Infrastructure, and Impacts, at 108 (Oct. 2021), <a href="https://netzeroamerica.princeton.edu/the-report">https://netzeroamerica.princeton.edu/the-report</a>).
---------------------------------------------------------------------------

53. Many commenters contend that inadequate regional transmission
planning and cost allocation processes have resulted in, or are
threatening to cause, unjust, unreasonable, and unduly discriminatory
or preferential rates.\80\ Michigan State Entities cite renewable
energy curtailments, which limit the supply of energy that customers
can access, and the lack of regional and interregional transmission
lines, which limit the transfer of lower-priced power.\81\ New Jersey
Commission asserts that better transmission planning

[[Page 49291]]

can reduce overall system costs by billions of dollars.\82\ Certain
TDUs add that Commission action is essential now to ensure that
necessary transmission expansion occurs in a way that protects
customers from excessive costs and that results in just and reasonable
transmission rates.\83\ CARE Coalition argues that the Commission's
current failure to require transmission planners to internalize siting-
related costs and risks results in unjust, unreasonable, and unduly
discriminatory or preferential rates.\84\ In a similar vein,
[Oslash]rsted and Massachusetts Attorney General claim that failure to
proactively plan for offshore wind generation buildout could lead to
transmission rates that are unjust, unreasonable, and unduly
discriminatory or preferential.\85\
---------------------------------------------------------------------------

\80\ See, e.g., ACORE Initial Comments at 3, AEE Initial
Comments at 27 (citing NOPR, 179 FERC ] 61,028 at PP 47, 55, 78;
S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56); CARE Coalition
Initial Comments at 17; Certain TDUs Initial Comments at 2; Clean
Energy Associations Initial Comments at 3, 7; Clean Energy Buyers
Initial Comments at 10; Harvard ELI Initial Comments at 1;
Massachusetts Attorney General Initial Comments at 5-6; New Jersey
Commission Initial Comments at 1-2; PIOs Initial Comments at 6; SEIA
Initial Comments at 2-3; Southeast PIOs Reply Comments at 2; US DOE
Initial Comments at 2, 6-7.
\81\ Michigan State Entities Initial Comments at 3.
\82\ New Jersey Commission Initial Comments at 3-9.
\83\ Certain TDUs Initial Comments at 2.
\84\ CARE Coalition Initial Comments at 17.
\85\ Massachusetts Attorney General Initial Comments at 5;
[Oslash]rsted Initial Comments at 3-5.
---------------------------------------------------------------------------

54. Several commenters agree with the Commission's concerns that
the expansion of the high-voltage transmission system is increasingly
occurring outside of the regional transmission planning process through
other mechanisms such as the generator interconnection process, which
results in piecemeal transmission development.\86\ AEE agrees that
limited development of regional transmission facilities, increased
spending on local transmission projects, and backlogged interconnection
queues all show that the existing regional transmission planning
requirements are not sufficient to meet customers' transmission
needs.\87\ Likewise, Exelon argues that relying on interconnection
studies as the primary transmission planning method results in
piecemeal and inefficient transmission investment.\88\ PIOs add that
many generation developers have to bear the full costs of transmission
upgrades, which leads to interconnection request withdrawals,
inefficiencies, and higher system-wide costs.\89\ In addition, Clean
Energy States note that interconnection queues are extremely large and
that the current one-plant-at-a-time approach to transmission upgrades
drives up costs and misses opportunities for improvements to the system
as a whole.\90\
---------------------------------------------------------------------------

\86\ See, e.g., Acadia Center and CLF Initial Comments at 3-4;
Anbaric Initial Comments at 5; Clean Energy Associations Initial
Comments at 4-7; Exelon Initial Comments at 1-2, 5; Joint Consumer
Advocates Initial Comments at 5; Non-RTO NASUCA Initial Comments at
4; [Oslash]rsted Initial Comments at 4-5; Pine Gate Initial Comments
at 8-10; SEIA Initial Comments at 2; see also AEP Initial Comments
at 8.
\87\ AEE Initial Comments at 1-2 (citing NOPR, 179 FERC ] 61,028
at PP 47-55).
\88\ Exelon Initial Comments at 5.
\89\ PIOs Initial Comments at 9-10.
\90\ Clean Energy States Initial Comments at 2.
---------------------------------------------------------------------------

55. Non-RTO NASUCA agrees with the Commission that Long-Term
Regional Transmission Planning is necessary to help alleviate
generation interconnection issues.\91\ According to Harvard ELI,
current transmission planning processes have failed to address
backlogged interconnection queues and operational challenges that are
best addressed at the regional level, as well as to include inexpensive
technologies that can increase transmission capacity.\92\
---------------------------------------------------------------------------

\91\ Non-RTO NASUCA Initial Comments at 4.
\92\ Harvard ELI Initial Comments at 1.
---------------------------------------------------------------------------

56. ACEG argues that there is no evidence that any regional
reliability or economic transmission planning performed in non-RTO/ISO
regions, like the Southeastern Regional Transmission Planning region
(SERTP), is equal to or superior to the techniques or outcomes in the
NOPR.\93\ ACEG further contends that, instead, most new transmission
facilities built since Order No. 1000 have been built for local
transmission needs, thereby resulting in less efficient and cost-
effective transmission development that does not address the larger
needs of the transmission system for reliability and resilience.\94\
Relatedly, SREA states that no state fully participates in SERTP, and
that instead, each state in the Southeast uses its own state planning
process, with no platform for states to collaborate. As a result, SREA
argues that ``transmission planning in the Southeast has many holes and
is threadbare.'' \95\ SREA catalogs deficiencies in many Southeastern
states' planning processes, including a lack of transparency.\96\
---------------------------------------------------------------------------

\93\ ACEG Reply Comments at 9 (citing Alabama Commission Initial
Comments at 2-3; Southern Initial Comments at 5-6, Ex. 2 at 2-3).
\94\ Id. at 9-10 (citing PIOs Initial Comments at 7).
\95\ SREA Reply Comments at 4.
\96\ Id. at 5-18.
---------------------------------------------------------------------------

57. Western PIOs argue that, outside of CAISO, transmission
planning in the West is ineffective.\97\ Specifically, Western PIOs
assert that Western transmission planning groups have not developed new
transmission projects using their Order No. 1000 transmission planning
processes, but have instead built transmission projects that their
utility members have already proposed.\98\ Relatedly, SEIA argues that
``non-RTO areas do not engage in sufficient or transparent transmission
planning,'' and that transmission planning in non-RTO/ISO regions is
exclusionary, based on inconsistent and inaccurate data, and
disjointed.\99\ More broadly, NRECA contends that incumbent investor-
owned utilities control transmission planning, and that some incumbent
investor-owned utilities develop transmission without transparency,
leading to disparities in transmission rates in different RTO/ISO local
zones.\100\
---------------------------------------------------------------------------

\97\ Western PIOs Initial Comments at 4-28.
\98\ Id. at 28.
\99\ SEIA Reply Comments at 5-6 (citing Southern Initial
Comments at 13-14).
\100\ NRECA Initial Comments at 15-16.
---------------------------------------------------------------------------

58. Several commenters specify other reasons that transmission
planning reforms are needed.\101\ Americans for Fair Energy Prices
agree with PIOs that there is a need for regional transmission planning
instead of the balkanized process that currently exists.\102\ DC and MD
Offices of People's Counsel assert that the NOPR provides a once-in-a-
generation opportunity to meet the energy transition in a just,
equitable, efficient, reliable, and resilient fashion by recognizing
the benefits of long-term transmission planning and developing rules
that incorporate those broad benefits. DC and MD Offices of People's
Counsel state that current transmission planning processes do not fully
consider all of the benefits of transmission development, including
enhanced reliability and resilience that will serve as a necessary
bulwark against disruptions caused by extreme weather.\103\ ACEG argues
that current transmission planning processes have not led to investment
in interregional transmission capacity, and that more interregional
transmission capacity could have avoided some of the $25 billion to $70
billion in yearly costs caused by severe weather events.\104\ EEI
states that robust transmission development will provide a host of
benefits for customers, including greater resilience, enhanced system
reliability, and cost-savings from greater access to low-cost
resources.\105\ Some commenters emphasize the importance of the
Commission taking prudent action to remedy deficiencies in the
Commission's existing regional transmission planning and cost

[[Page 49292]]

allocation requirements,\106\ and to strengthen electric reliability
and resilience, while controlling costs.\107\
---------------------------------------------------------------------------

\101\ See, e.g., Americans for Fair Energy Prices Reply Comments
at 5; SREA Reply Comments at 4.
\102\ Americans for Fair Energy Prices Reply Comments at 5
(citing PIOs Initial Comments at 34).
\103\ DC and MD Offices of People's Counsel Reply Comments at 1-
2.
\104\ ACEG Initial Comments at 21-22 (citing Grid Strategies,
LLC, Transmission Makes the Power System Resilient to Extreme
Weather, at 1-3, 12 (July 2021) (Grid Strategies July 2021 Extreme
Weather Report)).
\105\ EEI Supplemental Comments at 1.
\106\ US Senators Supplemental Comments at 1; Senator Whitehouse
Supplemental Comments at 2.
\107\ US Senator Barrasso Supplemental Comments at 1-2.
---------------------------------------------------------------------------

59. Several commenters argue that the need to reform transmission
planning includes addressing environmental justice and equity
issues.\108\ Center for Biological Diversity states that energy justice
and environmental justice considerations are appropriately included in
transmission planning.\109\ Center for Biological Diversity further
asserts that it is within the Commission's authority to consider these
costs and benefits, as the benefits of decarbonization and related
energy justice objectives will be far greater than the costs.\110\
Grand Rapids NAACP, CARE Coalition, and PIOs argue that to ensure just,
reasonable, and nondiscriminatory rates, transmission planning must
consider energy equity and environmental justice.\111\ Grand Rapids
NAACP further argues that high energy burdens can be unjust,
unreasonable, and unduly discriminatory or preferential.\112\ Grand
Rapids NAACP argues that the Commission's duty under the FPA to promote
the public interest requires it to ensure that energy justice and
equity considerations are included in transmission planning
processes.\113\ WE ACT relatedly argues that, due to under-investment,
the transmission system is unreliable and vulnerable to extreme weather
events, which is both a reliability and environmental justice issue
because communities of color and low-income communities are more
susceptible to power outages during extreme weather.\114\
---------------------------------------------------------------------------

\108\ See, e.g., CARE Coalition Initial Comments at 2; Center
for Biological Diversity Initial Comments at 20-24; Environmental
Groups Supplemental Comments at 2; Environmental Legislators Caucus
Supplemental Comments at 1; Grand Rapids NAACP Initial Comments at
20-21; Massachusetts Attorney General Initial Comments at 53-54
(citing Massachusetts Attorney General ANOPR Initial Comments at 32-
34); Montclair Congregation Supplemental Comments at 1; NESCOE Reply
Comments at 8-9; New England for Offshore Wind Initial Comments at
5; PIOs Reply Comments at 11-17; US DOE Initial Comments at 9; WE
ACT Initial Comments at 1-2.
\109\ Center for Biological Diversity Initial Comments at 20-24
(citing Pacific Northwest National Laboratory & Sandia National
Laboratories, Advancing Energy Equity in Grid Planning (Apr. 2022),
<a href="https://netl.doe.gov/sites/default/files/netl-file/Advancing%20Energy%20Equity%20in%20Grid%20Planning.pdf">https://netl.doe.gov/sites/default/files/netl-file/Advancing%20Energy%20Equity%20in%20Grid%20Planning.pdf</a>; Office of
Energy Justice and Equity, US DOE, Justice40 Initiative, <a href="https://www.energy.gov/diversity/justice40-initiative">https://www.energy.gov/diversity/justice40-initiative</a>).
\110\ Id. at 23 (citing Neb. Pub. Power Dist. v. FERC, 957 F.3d
932, 942 (8th Cir. 2020)).
\111\ Grand Rapids NAACP Reply Comments at 4 (citing 16 U.S.C.
824(a); Re Nat'l Ass'n for the Advancement of Colored People, Inc.,
95 P.U.R.3d 357 (F.P.C. 1972), vacated and remanded sub nom. NAACP
v. FPC, 520 F.2d 432 (D.C. Cir. 1975), aff'd, 425 U.S. 662 (1976));
CARE Coalition Initial Comments at 2; PIOs Reply Comments at 14.
\112\ Id. at 20-21.
\113\ Id. at 17-19.
\114\ WE ACT Initial Comments at 1-2.
---------------------------------------------------------------------------

60. Advanced Energy Buyers state that failure to prepare the grid
for the energy transition would be problematic for three primary
reasons: (1) insufficient transmission investment will leave customer
cost savings on the table; (2) lack of available transmission capacity
will constrain its members' ability to meet decarbonization and clean
energy goals; and (3) failure to plan and build adequate transmission
will hamper the transition to a cleaner and more reliable electric
grid.\115\ New Jersey Commission contends that the lack of holistic
multi-driver transmission planning is inflating consumers' electricity
costs by billions of dollars every year.\116\ Northwest and
Intermountain explain that due to insufficient transmission capacity
from renewable rich zones, utilities must attempt to meet their
renewable energy policy targets with new resources that are close to
load but more expensive, less reliable, and less efficient than more
distant alternatives, even considering the potential costs of
transmission expansion.\117\ Clean Energy Associations add that the
lack of transmission capacity imposes real and demonstrable costs
today, as evidenced by geographic differences in real-time power
prices, and that the lack of robust and proactive transmission planning
rules renders current rates unjust, unreasonable, and unduly
discriminatory or preferential.\118\
---------------------------------------------------------------------------

\115\ Advanced Energy Buyers Initial Comments at 3.
\116\ New Jersey Commission Initial Comments at 2-9.
\117\ Northwest and Intermountain Initial Comments at 6.
\118\ Clean Energy Associations Initial Comments at 5 (citing
Dev Millstein et al., Lawrence Berkeley National Laboratory,
Empirical Estimates of Transmission Value Using Locational Marginal
Prices, at 3 (Aug. 2022), <a href="https://eta-publications.lbl.gov/sites/default/files/lbnlempirical_transmission_value_study-august_2022.pdf">https://eta-publications.lbl.gov/sites/default/files/lbnlempirical_transmission_value_study-august_2022.pdf</a>
(LBNL Aug. 2022 Transmission Value Study)).
---------------------------------------------------------------------------

61. Southeast PIOs contend that the ``snowballing'' inefficiencies
created by numerous small-scale transmission ``band-aids'' result in
unjust, unreasonable, and unduly discriminatory or preferential rates,
and that reforms are particularly needed in the Southeast, where there
is minimal utility coordination and a balkanized transmission
system.\119\ According to ACEG, short-term, piecemeal transmission
planning is unlikely to identify the more efficient or cost-effective
solutions to transmission needs and thus will result in unjust,
unreasonable, and unduly discriminatory or preferential rates.\120\
---------------------------------------------------------------------------

\119\ Southeast PIOs Reply Comments at 1-2.
\120\ ACEG Initial Comments at 21.
---------------------------------------------------------------------------

62. Many commenters argue that reforms are necessary to meet state
policy goals \121\ and that greater state involvement or consideration
of state policies is needed to avoid transmission planning
inefficiencies.\122\ For example, ACORE cites a recent National
Renewable Energy Laboratory (NREL) report highlighting the need for new
transmission to aid in achieving zero carbon goals.\123\ NextEra opines
that the passage of the Inflation Reduction Act of 2022 will increase
the demand for renewables and drive corresponding demands on the
transmission system.\124\ Pacific Northwest State Agencies argue that
reforms are critical to successfully achieving their respective state
clean energy laws and policies and to ensuring that there is sufficient
clean, safe, reliable, and affordable energy.\125\ Michigan State
Entities note that some states may pursue aggressive renewable energy
portfolio standards, and others may have no such requirements, but
these policy choices will inevitably affect the price and reliability
of energy for all customers across the states in question and that not
planning for that reality imposes costs on unwilling customers.\126\
---------------------------------------------------------------------------

\121\ See, e.g., Acadia Center and CLF Initial Comments at 1;
ACORE Reply Comments at 1; Breakthrough Energy Initial Comments at
5-6; Business Council for Sustainable Energy Initial Comments 2-3;
Illinois Commission Initial Comments at 3-4; ISO-NE Initial Comments
at 2; Michigan State Entities Initial Comments at 2-3; National Grid
Initial Comments at 6-7; NESCOE Initial Comments at 9-10, 15-16;
NextEra Reply Comments at 5, 25; Northwest and Intermountain Initial
Comments at 5-6; [Oslash]rsted Initial Comments at 1-3; Pacific
Northwest State Agencies Initial Comments at 1; PacifiCorp and NV
Energy Initial Comments at 10-11; State Agencies Initial Comments at
16-17; Vermont Electric and Vermont Transco Initial Comments at 2;
Western State Representatives Initial Comments at 3.
\122\ See, e.g., AEE Reply Comments at 3-4; California
Democratic Representatives Supplemental Comments at 1-2; US Senators
Supplemental Comments at 1 (citing to National Academies of
Sciences, Engineering, and Medicine, Accelerating Decarbonization in
the United States: Technology, Policy, and Societal Dimensions
(2023)); Maryland Energy Admin Initial Comments at 1; North Carolina
Commission and Staff Initial Comments at 2, 4; PJM States Initial
Comments at 1; SREA Reply Comments at 4.
\123\ ACORE Reply Comments at 1 (citing Paul Denholm, et al.,
NREL, Examining Supply-Side Options to Achieve 100% Clean
Electricity by 2035 (Sept. 2022), <a href="https://www.nrel.gov/docs/fy22osti/81644.pdf">https://www.nrel.gov/docs/fy22osti/81644.pdf</a>).
\124\ NextEra Reply Comments at 5, 25.
\125\ Pacific Northwest State Agencies at 1.
\126\ Michigan State Entities Initial Comments at 2-3.

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[[Page 49293]]

63. PacifiCorp and NV Energy similarly assert that the need for
reform in the West is driven by the diverse policy priorities in its
six-state transmission system, and they note that decisions are subject
to state oversight and the participation of disparately situated
transmission providers without inclination or authority to accept any
cost allocation.\127\ National Grid asserts that ISO New England's
(ISO-NE) 2050 Transmission Study demonstrates a direct connection
between state laws and requirements to meet clean energy goals and the
need for new and expanded transmission facilities.\128\ Indicated PJM
TOs add that maintaining a reliable and resilient transmission system
requires forward-looking assessments informed by evolving public
policy, changing generation mix and demand patterns, and stakeholder
input.\129\
---------------------------------------------------------------------------

\127\ PacifiCorp and NV Energy Initial Comments at 10-11.
\128\ National Grid Initial Comments at 6-7 (citing the then-
preliminary findings from the ISO-NE 2050 Transmission Study).
\129\ Indicated PJM TOs Initial Comments at 1.
---------------------------------------------------------------------------

64. Maryland Energy Administration contends that Maryland has
experienced unfair and costly consequences of inadequate consultation
with state authorities in regional transmission planning
processes.\130\ AEE argues that if current transmission planning
processes fail to incorporate factors such as state laws, corporate
targets, and retail demand, then transmission needs will be unmet,
risking unjust, unreasonable, and unduly discriminatory or preferential
rates.\131\
---------------------------------------------------------------------------

\130\ Maryland Energy Administration Initial Comments at 1
(citing Maryland Energy Administration ANOPR Initial Comments at 2).
\131\ AEE Reply Comments at 3-4.
---------------------------------------------------------------------------

65. Many commenters argue that, based on the record, the Commission
has an obligation under the FPA to take action to ensure that
transmission planning and cost allocation results in rates that are
just and reasonable and not unduly discriminatory.\132\ ACEG states
that the Commission's broad authority to remedy unduly discriminatory
behavior pursuant to FPA section 206 applies to transmission planning
and cost allocation, as the U.S. Court of Appeals for the District of
Columbia Circuit held in South Carolina Public Service Authority v.
FERC.\133\ PIOs contend that the Commission is required by the FPA to
use its authority to address market abuses and undue discrimination
that have led to unjust, unreasonable, and unduly discriminatory or
preferential rates for consumers, who bear the costs of inefficiencies
in the current transmission planning process.\134\
---------------------------------------------------------------------------

\132\ See, e.g., ACEG Initial Comments at 11; Clean Energy
Associations Initial Comments at 7-10; Grand Rapids NAACP Initial
Comments at 17; Massachusetts Attorney General Initial Comments at
3-4; Pine Gate Initial Comments at 10-14; PIOs Initial Comments at
8.
\133\ 762 F.3d at 57. See also ACEG Initial Comments at 13-14;
Harvard ELI Initial Comments at 1-2; SEIA Initial Comments at 3.
\134\ PIOs Initial Comments at 8.
---------------------------------------------------------------------------

66. Southeast PIOs assert that the NOPR adequately demonstrated
that existing regional transmission planning processes have intrinsic
flaws, making the integrated resource planning and request for proposal
processes ill-equipped to efficiently address changes in the resource
mix and demand.\135\ Specifically, Southeast PIOs cite the following
preliminary findings from the NOPR: (1) existing transmission planning
processes utilize a limited planning horizon; (2) many transmission
planning processes provide an inaccurate portrayal of the comparative
benefits of different transmission facilities; and (3) rapid changes to
the generation fleet and demand are creating increasingly urgent
transmission needs.\136\
---------------------------------------------------------------------------

\135\ Southeast PIOs Reply Comments at 4 (citing Duke Initial
Comments at 6-9; SERTP Sponsors Initial Comments at 31-36; Southern
Initial Comments at 36-40).
\136\ Id. at 5-6 (citing NOPR, 179 FERC ] 61,028 at PP 45, 47,
49, 53).
---------------------------------------------------------------------------

67. Southeast PIOs cite the finding in South Carolina Public
Service Authority v. FERC that the threshold of substantial evidence
could be met without ``empirical evidence'' as long as the Commission
provides evidence based on ``reasonable economic propositions.'' \137\
Southeast PIOs also note that South Carolina Public Service Authority
v. FERC upheld the Commission's findings in Order No. 1000, which were
based on (1) a threat to just and reasonable rates from existing
regional transmission planning and cost allocation practices, (2)
significant changes in the industry driven by increases in renewable
energy resources, and (3) recent increases in transmission
investment.\138\ Moreover, Southeast PIOs note that findings need not
be region-specific, as the ``Commission may rely on generic or general
findings of a systemic problem to support imposition of an industry-
wide solution.'' \139\
---------------------------------------------------------------------------

\137\ Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 65).
\138\ Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 65-66).
\139\ Id. at 7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 67).
---------------------------------------------------------------------------

68. ACEG similarly asserts that the Commission has shown the need
for transmission planning reform based on findings that existing
transmission planning requirements do not adequately identify
transmission needs driven by changes in the resource mix and demand,
and that failure to identify such needs causes customers to pay for
less efficient or cost-effective transmission investments.\140\
Relatedly, ACEG argues that pursuing region-specific solutions will
lead to siloed and disjunctive transmission planning policies that will
not solve the problems facing the Nation's electric transmission
system.\141\
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\140\ ACEG Reply Comments at 7-8 (citing Alabama Commission
Initial Comments at 2-3; Duke Initial Comments at 6-9; Idaho Power
Initial Comments at 2-3; NRECA Initial Comments at 11; North
Carolina Commission and Staff Initial Comments at 14; Pacific
Northwest Utilities Initial Comments at 9-10; Utah Commission
Initial Comments at 9-12).
\141\ Id. at 17.
---------------------------------------------------------------------------

69. Colorado Consumer Advocate and Joint Consumer Advocates aver
that the Commission has a statutory duty under the FPA to reform
current regional transmission planning processes because they lack
transparency, coordination, and openness, and because they create
opportunities for monopoly transmission developers to exert dominant
influence and promote their own economic self-interest at customers'
and other stakeholders' expense.\142\ According to New Jersey
Commission, current transmission planning processes are inefficient and
unnecessarily burden ratepayers with excessive costs without providing
additional benefits. New Jersey Commission contends that those
processes are therefore per se unjust and unreasonable, and that the
Commission thus has FPA section 206 authority to require that
transmission providers employ practices like long-term, holistic,
multi-driver transmission planning.\143\
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\142\ Colorado Consumer Advocate Initial Comments at 21-23;
Joint Consumer Advocates Initial Comments at 18-20.
\143\ New Jersey Commission Initial Comments at 3-4.
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70. Similarly, Harvard ELI states that deficient transmission
planning threatens the justness and reasonableness of transmission
rates, and therefore the Commission has legal authority and
jurisdiction to order changes to transmission planning to remedy that
deficiency.\144\ Harvard ELI further asserts that the Commission must
remedy undue discrimination due to incumbent transmission owners'
unduly discriminatory influence in regional transmission planning.\145\
Massachusetts Attorney General also

[[Page 49294]]

argues that the Commission's proposed reforms are necessary to fulfill
the Commission's statutory obligation to ensure that transmission rates
are just and reasonable.\146\
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\144\ Harvard ELI Initial Comments at 1-2 (citing S.C. Pub.
Serv. Auth. v. FERC, 762 F.3d 41; Order No.1000-A, 139 FERC ] 61,132
at PP 56-75).
\145\ Id. at 3.
\146\ Massachusetts Attorney General Initial Comments at 3-6.
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71. Some commenters argue that there is insufficient evidence for
the Commission to find that existing jurisdictional rates are unjust,
unreasonable, and unduly discriminatory or preferential.\147\ For
example, while Idaho Commission recognizes that there are deficiencies
in existing transmission planning and cost allocation processes, Idaho
Commission disagrees with the NOPR's claim that their failure to
identify and plan for transmission needs driven by changes in the
resource mix and demand is resulting in unjust, unreasonable, and
unduly discriminatory or preferential Commission-jurisdictional
rates.\148\ Mississippi Commission also disagrees that the lack of
long-term regional transmission planning will result in unjust,
unreasonable, and unduly discriminatory or preferential rates.\149\
ELCON questions a finding of unjust, unreasonable, and unduly
discriminatory or preferential rates, and it states that the NOPR's
focus on Long-Term Regional Transmission Planning solely to address
changes in resource mix and demand, if adopted, could fail to produce
better outcomes for customers and may exceed the Commission's authority
under the FPA.\150\
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\147\ See, e.g., ELCON Initial Comments at 7; Idaho Commission
Initial Comments at 2; Mississippi Commission Initial Comments at 2,
9; NRECA Initial Comments at 14-16; Undersigned States Reply
Comments at 6-7.
\148\ Idaho Commission Initial Comments at 2 (citing NOPR, 179
FERC ] 61,028 at P 34).
\149\ Mississippi Commission Initial Comments at 2.
\150\ ELCON Initial Comments at 7.
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72. Louisiana Commission states that the Commission's finding that,
absent reforms, transmission rates universally are not just and
reasonable and are discriminatory is not based on individual analysis
of each RTO or region, is not supported, and should be retracted.\151\
Mississippi Commission also states that the Commission should, instead,
initiate region-specific investigations pursuant to FPA section
206.\152\ Southern argues that the Commission has failed to satisfy the
first prong of its FPA section 206 burden of proof, noting that the
NOPR's preliminary conclusion, that existing regional transmission
planning processes are not sufficient to address changes in the
resource mix and demand, cannot reasonably be made of Southern or
SERTP.\153\
---------------------------------------------------------------------------

\151\ Louisiana Commission Reply Comments at 5-6.
\152\ Mississippi Commission Reply Comments at 7-9.
\153\ Southern Initial Comments at 40; Southern Reply Comments
at 1-3.
---------------------------------------------------------------------------

73. Similarly, Industrial Customers argue that the Commission has
not satisfied the first prong of FPA section 206, which requires the
Commission to find, and provide substantial evidence supporting its
finding, that existing rates are unjust, unreasonable, and unduly
discriminatory or preferential.\154\ Industrial Customers claim that
demand growth should be the primary factor in identifying transmission
needs, and that demand is growing more slowly than in previous periods.
Industrial Customers add that, in contrast, investment in transmission
is rising relative to demand, which is the opposite of the
circumstances that prevailed in 2007 when the Commission issued Order
No. 890.\155\ According to Industrial Customers, changes in demand are
not significant enough in historical terms to warrant major changes in
transmission planning. Moreover, Industrial Customers state that
changes in demand are unpredictable because technological changes are
inherently difficult to forecast and the risks to consumers of making
mistakes are too high. Industrial Customers argue that, if anything,
the rapid growth of renewables indicates that current processes are
already facilitating changes in the resource mix.\156\ Similarly, NRG
argues that long-term forecasts of important factors are often wrong,
which has real-world impacts on customers.\157\
---------------------------------------------------------------------------

\154\ Industrial Customers Initial Comments at 6-7.
\155\ Id. at 8-10.
\156\ Id. at 10-11.
\157\ NRG Initial Comments at 10-12 (noting, for example, that
``[p]redictions for the future price of natural gas and thus the
economics of gas generation in long-term forecasts have been
notoriously inaccurate.'' (citing Lawrence Berkeley National
Laboratory, Comparison of AEO 2008 Natural Gas Price Forecast to
NYMEX Futures Prices (Jan. 2008)).
---------------------------------------------------------------------------

74. Further, Industrial Customers contend that the NOPR does not
clearly define the term ``changes in the resource mix and demand,''
despite using such changes as the justification for the proposals.
Industrial Customers argue that transmission should only be planned in
order to maintain reliability and should not be based on the demand for
certain fuel sources or the fuel type of the generation fleet.\158\
Industrial Customers argue that current transmission planning is based
on known and measurable factors, and that any attempt to plan for
potential future changes in the resource mix without determining
precisely what these changes will be would result in the overbuilding
of the system for generation that may not be built. Industrial
Customers argue that this outcome would be unjust and unreasonable and
would force transmission customers to pay for generation that is non-
existent.\159\
---------------------------------------------------------------------------

\158\ Industrial Customers Initial Comments at 7-8.
\159\ Id. at 15.
---------------------------------------------------------------------------

75. Other commenters agree that the Commission lacks a specific
record to support the need for reform.\160\ For example, former Kansas
Commission Chair Keen avers that there is no analytical or evidentiary
basis in the NOPR for a complete and thorough overhaul or revision of
transmission planning processes.\161\
---------------------------------------------------------------------------

\160\ See, e.g., Alabama Commission Initial Comments at 4-5;
Duke Initial Comments 6-9; Idaho Commission Initial Comments at 2;
Industrial Customers Initial Comments at 1, 6-11, 15; Kansas
Commission Chair Keen Initial Comments at 1-2; Nebraska Commission
Initial Comments at 1-2; NRECA Initial Comments at 14-16; NRG
Initial Comments at 3; Ohio Commission Federal Advocate Initial
Comments at 5-6; Potomac Economics Initial Comments at 3-4; Southern
Initial Comments at 40.
\161\ Kansas Commission Chair Keen Initial Comments at 2.
---------------------------------------------------------------------------

76. Duke asserts that the NOPR does not provide robust and specific
support as to how and why current regional transmission planning
processes are failing to plan for transmission needs driven by changes
in the resource mix and demand, leading to inefficient investment.\162\
Duke asserts that the NOPR does not support the presumption that the
absence of significant regional transmission investment is evidence of
inefficient transmission planning.\163\ Duke also asserts that, to
ensure legal durability, the Commission should identify evidence that
justifies a nationwide finding that current transmission planning
processes are failing to plan for transmission needs driven by changes
in the resource mix and demand, leading to inefficient investment and
unjust, unreasonable, and unduly discriminatory or preferential
rates.\164\
---------------------------------------------------------------------------

\162\ Duke Initial Comments at 6-7.
\163\ Id. at 7-8.
\164\ Id. at 9 (citing Emera Me. v. FERC, 854 F.3d 9, 24 (D.C.
Cir. 2017)).
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77. Undersigned States argue that the Commission does not have
evidence in the record that current rates are unjust, unreasonable, or
unduly discriminatory or preferential, which FPA section 206
requires.\165\ Undersigned States argue

[[Page 49295]]

that, contrary to the preliminary findings in the NOPR, the Southeast
has developed significant and sufficient transmission infrastructure
and renewable energy from 2015-2020. Undersigned States further argue
that the Commission is supposed to enhance reliability, and that,
because renewables are intermittent and inherently less reliable,
forcing ratepayers to subsidize their use through financing the
construction of additional transmission infrastructure is not
consistent with the Commission's mission. Undersigned States also argue
that the Commission has not justified replacing existing transmission
planning processes with a new approach, so the NOPR is arbitrary and
capricious.\166\ Further, Undersigned States argue that the Commission
has not offered a detailed justification for countering prior precedent
in Order No. 1000 that ``the regional transmission planning process is
not the vehicle by which integrated resource planning is conducted.''
\167\
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\165\ Undersigned States Reply Comments at 6-7. The Undersigned
States that submitted reply comments include the States of Texas,
Utah, Alabama, Alaska, Arkansas, Florida, Georgia, Kansas, Kentucky,
Louisiana, Mississippi, Montana, Nebraska, Ohio, Oklahoma, South
Carolina, and West Virginia. Id. at 1. The Undersigned States that
submitted initial comments include the States of Utah, Alaska,
Georgia, Idaho, Indiana, Kansas, Kentucky, Louisiana, Mississippi,
Montana, Nebraska, North Dakota, Ohio, Oklahoma, South Carolina,
Texas, West Virginia, and Wyoming. Undersigned States Initial
Comments at 5-6.
\166\ Undersigned States Reply Comments at 6-8.
\167\ Id. at 8 (citing Order No. 1000, 136 FERC ] 61,051 at P
154).
---------------------------------------------------------------------------

78. Some commenters assert that the intention of the NOPR is to
improperly favor certain energy resources.\168\ Consumer Organizations
argue that solutions that allow for an equitable transition and make
space for advancing technology and smaller energy systems are
preferrable to a rushed plan that favors certain resources, such as
wind, solar, and battery storage, that have already proven to be
inadequate.\169\ ELCON adds that Congress did not give the Commission
express authority to balance the FPA's just and reasonable rates
requirement with the policy goal of connecting renewable resources to
the transmission system.\170\ SERTP Sponsors argue that Congress has
not clearly provided the Commission with jurisdiction to presuppose
generation decisions and thereby effect particular, substantive
transmission outcomes; rather, SERTP Sponsors continue, Congress has
expressly and unequivocally reserved generation authority to the
states.\171\ Louisiana Commission argues that the FPA does not confer
on the Commission authority to engage in wide-scale public policymaking
by enacting sweeping energy policy changes with far-reaching,
nationwide effects.\172\
---------------------------------------------------------------------------

\168\ See, e.g., Consumers Organizations Initial Comments at 1-
3; ELCON Initial Comments at 9-10.
\169\ Consumers Organizations Initial Comments at 1-3.
\170\ ELCON Initial Comments at 9-10 (citing 16 U.S.C.
824q(b)(4)).
\171\ SERTP Sponsors Initial Comments at 18.
\172\ Louisiana Commission Initial Comments at 6 (citing West
Virginia v. EPA, 597 U.S. 697 (2022)).
---------------------------------------------------------------------------

79. Ohio Commission Federal Advocate states that the NOPR may be
intended ``to establish policies designed to encourage the massive
transmission build-out that will doubtless be required to transition to
an aspirational renewable future'' and ``to achieve narrow
environmental policy objectives, not to address legitimate requirements
under the Federal Power Act like ensuring just and reasonable rates or
reliability.'' \173\ Former Kansas Commission Chair Keen claims that
the NOPR encourages an extensive and expensive transmission build-out
without considering the impact on state-jurisdictional generation
mixes. He also claims that some of the NOPR proposals impose an
accelerated pace for the transition from dispatchable to renewable
resources, which could hasten the premature retirement of dispatchable
generation and compromise regional and state power reliability. He also
expresses concern that the NOPR proposals would force ratepayers in
some states to pay for neighboring states' transmission projects to
advance public policy goals that they do not share.\174\
---------------------------------------------------------------------------

\173\ Ohio Commission Federal Advocate Initial Comments at 4-5
(citing NOPR, 179 FERC ] 61,028, Danly, Comm'r, dissenting, at PP 2-
3).
\174\ Kansas Commission Chair Keen Initial Comments at 3.
---------------------------------------------------------------------------

80. Some commenters challenge aspects of the need for reform. For
example, Nebraska Commission believes that the established structures
in RTO/ISO regions are generally working and that many aspects of the
NOPR are thus unnecessary there.\175\ Potomac Economics disagrees with
some of the Commission's arguments for requiring Long-Term Regional
Transmission Planning, contending that the Commission's proposals are
based on anticipated future generation and other speculative factors
and seem to be incorrectly premised on a presumption that congestion
should not exist or may limit investment in economic generation.
Potomac Economics states that investment should occur only to the
extent that the savings of reducing congestion are larger than the
investment costs. According to Potomac Economics, congestion that is
caused by generators' siting decisions should be borne by the
generation developers, as it will incent them to propose the lowest-
cost projects taking transmission costs into account. Potomac Economics
argues that, if transmission is expanded preemptively to facilitate
generation investment in a particular location, such costs are
equivalent to subsidies for the developer.\176\
---------------------------------------------------------------------------

\175\ Nebraska Commission Initial Comments at 1-2.
\176\ Potomac Economics Initial Comments at 3-4.
---------------------------------------------------------------------------

81. Mississippi Commission disagrees that too much expansion of
high-voltage transmission has occurred through the generator
interconnection process instead of through regional transmission
planning.\177\ Similarly, North Carolina Commission and Staff disagree
with the Commission's conclusion that the growth in interconnection-
related network upgrades demonstrates a failure of regional
transmission planning as it relates to North Carolina.\178\ Southern
adds that, contrary to statements in the NOPR, it is not significantly
expanding its transmission system through the generator interconnection
process.\179\
---------------------------------------------------------------------------

\177\ Mississippi Commission Initial Comments at 9.
\178\ North Carolina Commission and Staff Initial Comments at 5.
\179\ Southern Initial Comments at 38-40.
---------------------------------------------------------------------------

82. Alabama Commission asserts that Alabama has a resource planning
process that accounts for needed transmission buildout to maintain
reliable service, and thus, Alabama Power plans its transmission system
proactively both to maintain deliveries from existing resources and to
accommodate Alabama Commission-certified generation additions. Alabama
Commission claims that the SERTP process builds on the integrated
resource planning efforts of its sponsor states, ensuring that there
are no regional transmission solutions that are more efficient or cost-
effective than solutions identified through the underlying state-
jurisdictional processes.\180\
---------------------------------------------------------------------------

\180\ Alabama Commission Initial Comments at 4.
---------------------------------------------------------------------------

83. Duke argues that, for certain transmission providers, the local
transmission planning process may more effectively meet transmission
needs, especially when combined with state-regulated integrated
resource planning and a bottom-up regional transmission planning
process. Duke contends that a regional transmission facility may not
fully address local transmission needs such that a local transmission
facility would still be needed, and thus, the regional transmission
facility is not necessarily more efficient or cost-effective than the
local transmission facility.\181\
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\181\ Duke Initial Comments at 7-9.

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[[Page 49296]]

84. NRECA states that certain of its members in RTOs/ISOs believe
that regional transmission planning is working well to meet long-term
needs (e.g., those in MISO) and that the NOPR proposals would burden
transmission providers' limited resources. NRECA states that other
NRECA members in RTOs/ISOs believe that existing RTO/ISO transmission
planning processes contain discrete deficiencies that the NOPR
proposals will not remedy. According to NRECA, these electric
cooperatives believe that some incumbent investor-owned transmission
owners develop local transmission projects without transparency
concerning need or costs, leading to disparities in transmission rates
across RTO/ISO transmission zones, and that incumbent transmission
owners control the transmission planning process such that no regional
transmission planning occurs. NRECA states that, in these cooperatives'
view, the criteria to determine the eligibility of a regional
transmission project is the barrier, and that requiring Long-Term
Regional Transmission Planning, by itself, will not solve the
problem.\182\
---------------------------------------------------------------------------

\182\ NRECA Initial Comments at 14-16.
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C. Commission Determination

85. Based on the record, we find that there is substantial evidence
to support the conclusion that the Commission's existing regional
transmission planning and cost allocation requirements are unjust,
unreasonable, and unduly discriminatory or preferential. We therefore
adopt the preliminary findings in the NOPR concerning the need for
reform. Specifically, we find that the absence of sufficiently long-
term, forward-looking, and comprehensive transmission planning
requirements is causing transmission providers to fail to adequately
anticipate and plan for future system conditions. It causes
transmission providers to fail to appropriately evaluate the benefits
of transmission infrastructure, and results in piecemeal transmission
expansion to address relatively near-term transmission needs. We find
that this status quo causes transmission providers to undertake
relatively inefficient investments in transmission infrastructure, the
costs of which are ultimately recovered through Commission-
jurisdictional rates. This dynamic results in, among other things,
transmission customers paying more than necessary or appropriate to
meet their transmission needs and forgoing benefits that outweigh their
costs, which results in less efficient or cost-effective transmission
investments. As explained below, we find that these deficiencies render
Commission-jurisdictional regional transmission planning and cost
allocation processes unjust, unreasonable, and unduly discriminatory or
preferential.
86. The Commission has authority under FPA section 206 to issue
this final order. Specifically, FPA section 206 ``instructs the
Commission to remedy `any . . . practice' that `affect[s]' a rate for
interstate electricity service `demanded' or `charged' by `any public
utility' if such practice is `unjust, unreasonable, unduly
discriminatory or preferential.''' \183\ As the D.C. Circuit has
recognized, regional transmission planning and cost allocation
processes are practices affecting rates subject to the Commission's
exclusive jurisdiction.\184\ As the Court explained in South Carolina
Public Service Authority v. FERC, transmission providers use those
processes to ``determine which transmission facilities will more
efficiently or cost-effectively meet'' transmission needs, the
development of which directly impacts the rates, terms, and conditions
of Commission-jurisdictional service.\185\ In particular, because these
processes identify, evaluate, and select the regional transmission
facilities whose costs will be recovered through transmission rates, we
find that they directly affect those rates.\186\ In addition, as
discussed below, such transmission facilities contribute to the
development of a more robust transmission system, supporting continuity
of service in the face of growing reliability challenges and providing
wholesale electric customers greater access to lower-cost generation
supplied by a wider range of resources. Accordingly, regional
transmission planning and cost allocation processes, as well as ``the
rules and practices that determine how those [processes]
operate,''\187\ have a direct effect on the rates that customers pay
for both the transmission and sale of electric energy in interstate
commerce.\188\ The Commission may act pursuant to FPA section 206 if
the Commission first establishes, through substantial evidence,\189\
that the existing practices are unjust, unreasonable, or unduly
discriminatory or preferential and, second, establishes that the
replacement practices are just and reasonable.\190\
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\183\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55 (quoting 16
U.S.C. 824e(a)).
\184\ Id. at 55-59, 84 (affirming the Commission's authority to
regulate transmission planning and cost allocation as practices
affecting rates); see also Order No. 1000-A, 139 FERC ] 61,132 at P
577 (holding that ``requirements regarding transmission planning and
cost allocation . . . are practices affecting rates.'').
\185\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56 (citing
Order No. 1000, 136 FERC ] 61,051 at PP 112, 116); see also Emera
Me. v. FERC, 854 F.3d at 674.
\186\ That is true even if regional transmission planning and
cost allocation processes do not result in the development, siting,
and construction of every regional transmission facility that
transmission providers select to more efficiently or cost-
effectively meet transmission needs. See, e.g., Conn. Dep't of Pub.
Util. Control v. FERC, 569 F.3d 477, 485 (D.C. Cir. 2009) (holding
that ``even if all [that] the I[nstalled] C[apacity] R[equirement]
did was help to find the right [capacity] price,'' rather than
result in the construction or procurement of any new capacity, ``it
would still amount to a `practice . . . affecting' rates.'' (citing
16 U.S.C. 824e(a) (omission in original))).
\187\ FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 279 (2016)
(EPSA).
\188\ 16 U.S.C. 824e(a).
\189\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 54 (``The
Commission's factual findings are conclusive if supported by
substantial evidence.''). Courts have held that substantial evidence
in this context does not necessarily require the Commission to
provide empirical evidence for every proposition. Rather, FPA
section 206 empowers the Commission to address a mere threat of
unjust and unreasonable rates. See S.C. Pub. Serv. Auth. v. FERC,
762 F.3d at 64-65, 85.
\190\ 16 U.S.C. 824e(a); see also EPSA, 577 U.S. at 277
(affirming the Commission ``has the authority--and indeed, the
duty--to ensure that rules or practices `affecting' wholesale rates
are just and reasonable'').
---------------------------------------------------------------------------

87. With regard to the first showing under FPA section 206, we find
that, while Order No. 890 requires transmission providers to satisfy
certain principles in their local transmission planning processes and
Order No. 1000 requires transmission providers to participate in
regional transmission planning and cost allocation processes that
satisfy the requirements set forth therein, these existing transmission
planning and cost allocation requirements do not result in regional
transmission planning that is conducted on a sufficiently long-term,
forward-looking, and comprehensive basis to plan for Long-Term
Transmission Needs. As a result, we find that transmission providers
are often not identifying, evaluating, or selecting more efficient or
cost-effective regional transmission solutions to meet Long-Term
Transmission Needs. This gap in existing regional transmission planning
processes results in piecemeal, inefficient, and less cost-effective
transmission planning that imposes real costs on customers, who pay
Commission-jurisdictional transmission rates for less efficient or
cost-effective transmission facilities and do not realize the benefits
that would result from long-term, forward-looking, and more
comprehensive regional transmission planning and cost allocation
processes that identify, evaluate, and select more efficient or cost-
effective transmission

[[Page 49297]]

solutions to Long-Term Transmission Needs.
88. We find that these deficiencies in the Commission's existing
transmission planning and cost allocation requirements render those
requirements unjust, unreasonable, and unduly discriminatory or
preferential in violation of FPA section 206.
89. We also find that the Commission's existing transmission
planning and cost allocation requirements are insufficient to ensure
just and reasonable and not unduly discriminatory or preferential
rates. Given these findings, we are now requiring, pursuant to FPA
section 206, that transmission providers engage in and conduct
sufficiently long-term, forward-looking, and comprehensive transmission
planning and cost allocation processes to identify and plan for Long-
Term Transmission Needs. We find that these reforms will facilitate a
process by which transmission providers can better identify, evaluate,
and select more efficient or cost-effective transmission solutions to
meet Long-Term Transmission Needs, which will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly
discriminatory or preferential.
1. The Transmission Investment Landscape Today
90. As the Commission explained in the NOPR, a robust, well-planned
transmission system is foundational to ensuring an affordable, reliable
supply of electricity.\191\ Due to continuing changes in the industry,
ongoing investment in transmission facilities is necessary to ensure
the transmission system continues to serve load in a reliable,\192\
affordable, and economically efficient fashion. Such investments
support enhanced reliability, as larger, more integrated transmission
systems result in a diversity of supply and demand conditions and a
certain degree of redundancy that allows the system to better withstand
failures during extreme events.\193\ Proactive, forward-looking
transmission planning that considers both evolving reliability needs
and other drivers of transmission needs more comprehensively can enable
transmission providers to identify potential reliability problems and
economic constraints, as well as to evaluate potential transmission
solutions, well in advance of these issues affecting the transmission
system,\194\ which can facilitate the selection of more efficient or
cost-effective transmission facilities to meet Long-Term Transmission
Needs.
---------------------------------------------------------------------------

\191\ NOPR, 179 FERC ] 61,028 at P 28 (citing 16 U.S.C. 824,
824d, 824e); see also US DOE ANOPR Initial Comments at 2 (stating
that ``strengthening and expanding existing transmission
infrastructure, particularly the development of regional and inter-
regional transmission projects, is key to continued access to
reliable, resilient, lower-cost, and clean electricity for all'').
\192\ See, e.g., MISO ANOPR Initial Comments at 40; Testimony of
James B. Robb Before the U.S. Senate Energy and Natural Resources
Committee, Reliability, Resiliency, and Affordability of Electric
Service in the United States Amid the Changing Energy Mix and
Extreme Weather Events, at 8-9 (Mar. 11, 2021), <a href="https://www.energy.senate.gov/services/files/D47C2B83-A0A7-4E0B-ABF2-9574D9990C11">https://www.energy.senate.gov/services/files/D47C2B83-A0A7-4E0B-ABF2-9574D9990C11</a> (testifying that more transmission infrastructure is
required to ensure the reliability and resilience of the bulk power
system in light of changing conditions).
\193\ ACORE ANOPR Initial Comments Ex. 4, Grid Strategies July
2021 Extreme Weather Report; Mark Chupka & Pearl Donohoo-Vallett,
Recognizing the Role of Transmission in Electric System Resilience
(May 2018), <a href="https://wiresgroup.com/wp-content/uploads/2020/06/2018-05-09-Brattle-Group-Recognizing-the-Role-of-Transmission-in-Electric-System-Resilience-.pdf">https://wiresgroup.com/wp-content/uploads/2020/06/2018-05-09-Brattle-Group-Recognizing-the-Role-of-Transmission-in-Electric-System-Resilience-.pdf</a>; NERC ANOPR Initial Comments at 17-
18; US DOE ANOPR Initial Comments at 18.
\194\ MISO's Multi-Value Project (MVP) regional transmission
planning process, for example, eliminated the need for approximately
$300 million in reliability transmission facilities, resolving
reliability violations and mitigating system instability conditions,
through a forward-looking approach. Midcontinent Independent System
Operator, MTEP17 MVP Triennial Review: A 2017 review of the public
policy, economic, and qualitative benefits of the Multi-Value
Project Portfolio, at 11, 33 (Sept. 2017) (MTEP2017 Review).
---------------------------------------------------------------------------

91. In addition, transmission infrastructure can unlock the forces
of competition, changing who can sell to whom, eliminating barriers to
entry, and mitigating market power.\195\ Increased competition, in
turn, can provide a host of benefits for customers, including cost-
savings from greater access to low-cost power and a wider range of
resources.\196\ Transmission infrastructure can also serve as a form of
insurance against future uncertainties because a more robust,
integrated transmission system has the potential to provide consumers
with the benefits of competition and enhanced reliability even if
supply and demand fundamentals change over time.\197\
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\195\ Policy Integrity ANOPR Initial Comments at 13 n.40 (``A
new transmission project can enhance competition by both increasing
the total supply that can be delivered to consumers and the number
of suppliers that are available to serve load.'' (citing Mohamed
Awad et al., The California ISO Transmission Economic Assessment
Methodology (TEAM): Principles and Applications to Path 26, at 3
(2006)); PIOs ANOPR Initial Comments Ex. A, Johannes Pfeifenberger
et al., The Brattle Group and Grid Strategies, Transmission Planning
for the 21st Century: Proven Practices that Increase Value and
Reduce Costs, at 48-49 (Oct. 2021) (Brattle-Grid Strategies Oct.
2021 Report), <a href="https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf">https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf</a> (``Expansion of the transmission network typically
increases the number of independent wholesale electricity suppliers
that are able to compete to supply electricity at locations in the
transmission network served by the upgrade . . . .'' (quoting F.A.
Wolak, World Bank, Managing Unilateral Market Power in Electricity,
Policy Research Working Paper No. 3691, at 8 (2005))).
\196\ See, e.g., PJM Interconnection, L.L.C., PJM Value
Proposition, at 1-2 (2019), https://www.pjm.com/about-pjm/~/media/
about-pjm/pjm-value-proposition.ashx (PJM's planning of resource
adequacy over a large region is estimated to result in savings of
$1.2-1.8 billion.); Midcontinent Independent System Operator, MISO
Value Proposition (2020), <a href="https://www.misoenergy.org/meet-miso/MISO_Strategy/miso-value-proposition/">https://www.misoenergy.org/meet-miso/MISO_Strategy/miso-value-proposition/</a> (MISO estimated $517-572
million in savings from more efficient use of existing assets and
$2.5-3.2 billion from reduced need for additional assets.); SPP
Transmission Planning, Southwest Power Pool, SPP's Value of
Transmission: 2021 Report and Update (Mar. 31, 2022) (SPP estimated
$382.7 million in adjusted product costs savings in 2020 due to
transmission investment.); see also ACEG Initial Comments at 3-4
(``The benefits generated by MISO's MVPs and SPP's Priority Projects
exceeded the costs by 2.2 to 3.5 times and means that every dollar
spent on transmission will enable access to generation that is $3 to
$4 cheaper than would otherwise be available.'').
\197\ US DOE, National Electric Transmission Congestion Study,
at 11 (Sept. 2015), <a href="https://www.energy.gov/sites/prod/files/2015/09/f26/2015%20National%20Electric%20Transmission%20Congestion%20Study_0.pdf">https://www.energy.gov/sites/prod/files/2015/09/f26/2015%20National%20Electric%20Transmission%20Congestion%20Study_0.pdf</a>
(stating transmission expansion can strengthen and increase the
flexibility of the overall network and ``create real options to use
the transmission system in ways that were not originally
envisioned''); Vikram S. Budhraja et al., Improving Electricity
Resource Planning Processes by Considering the Strategic Benefits of
Transmission, 22 ELEC. J. 54 (Mar. 2009) (high voltage transmission
affords ``mitigation of risks as a form of insurance against extreme
events'').
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92. With that overview, we again begin with the key facts on the
ground.\198\ Since the issuance of Order No. 1000, transmission
spending has continued to increase nationwide. A study by US DOE found
that ``annual investment [in transmission] first exceeded $5 billion
per year in 2006 . . . and has increased consistently since that time.
Annual investment [] doubled to more than $10 billion per year by 2010
and then [] doubled again by 2016. Annual investment has been between
$18 billion and $22 billion annually since 2014.'' \199\ A separate
study, noted by the Commission in the NOPR, estimated that transmission
developers in the United States invested $20 to $25 billion annually in
transmission facilities from 2013 to 2020.\200\ Unsurprisingly, in
regions that saw a significant increase in transmission expenditures,
transmission costs have also become an increasing

[[Page 49298]]

share of customers' overall electricity bills, underscoring the
importance of ensuring that transmission investments are efficient and
cost-effective.\201\
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\198\ NOPR, 179 FERC ] 61,028 at P 36.
\199\ California Commission Reply Comments at 9 n.27 (quoting US
DOE, National Electric Transmission Congestion Study, at 9-10 (Sept.
2020), <a href="https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf">https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf</a>).
\200\ NOPR, 179 FERC ] 61,028 at P 39 (citing Brattle-Grid
Strategies Oct. 2021 Report at 2); Brattle Apr. 2019 Competition
Report at 2-3 & fig.1.
\201\ Resale Iowa Initial Comments at 3 (``[T]ransmission costs
have comprised an increasing percentage of [] total wholesale
electric costs [for Resale Iowa's members]. Currently, transmission
and ancillary services constitute approximately 43% of such costs,
as compared to 18.1% in 2009.''); Industrial Customers Initial
Comments at 5 (showing that transmission costs made up just 7% of
the total PJM electricity bill in 2011 but 27% by 2020); Rob
Gramlich and Jay Caspary, Americans for a Clean Energy Grid,
Planning for the Future: FERC's Opportunity to Spur More Cost-
Effective Transmission Infrastructure, at 26-28 (Jan. 2021), <a href="https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf">https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf</a> (ACEG Jan. 2021 Planning Report) (stating that the
current approach to transmission planning ``results in higher total
energy bills for customers than would result from more forward-
looking, holistic transmission planning''); see also California
Municipal Utilities Initial Comments at 10 (projecting that between
2022 and 2040, total high and low-voltage transmission access
charges will nearly double and noting that ``[g]one are the days
when transmission was a de minimis portion of the overall bill and
increases had little impact on the end consumer''); Public Systems
Initial Comments at 5 (noting that ``New England's Regional Network
Service transmission rate has grown nine-fold, from $15.60 per kW-
year (in 2003) to $140.98 per kW-year (in 2021)'').
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93. Furthermore, the record demonstrates that transmission
investment is likely to substantially increase in coming years. A
number of studies project significant and sustained transmission
spending through at least 2050. For example, one projection cited by
the US DOJ and FTC states that ``high voltage transmission capacity
must expand by 60 percent by 2030 at a capital cost of $330 billion,
and must triple by 2050 at a capital cost of $2.2 trillion.'' \202\
TAPS cites a separate study projecting $750 billion of new transmission
investment between 2023 and 2050.\203\ SoCal Edison ``estimates that
grid investments of up to $75 billion, including transmission upgrades,
will be required from 2030 to 2045 in California alone to integrate
bulk renewable generation and storage and serve load growth associated
with electrification.'' \204\ And ISO-NE's recently-completed 2050
Transmission Study estimates that transmission investment in New
England will range from $16 billion to $26 billion between 2024 and
2050, depending on the amount of load growth realized in the
region.\205\
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\202\ US DOJ and FTC Initial Comments at 3 (citing Eric Larson
et al., Net-Zero America: Potential Pathways, Infrastructure, and
Impacts, Princeton Univ., 108 (Oct. 2021), <a href="https://netzeroamerica.princeton.edu/the-report">https://netzeroamerica.princeton.edu/the-report</a>).
\203\ TAPS Initial Comments at 46 & n.133 (citing J[uuml]rgen
Weiss et al., The Brattle Group, The Coming Electrification of the
North American Economy, at iii (2019), <a href="https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf">https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf</a>)).
\204\ SoCal Edison Initial Comments at 2 (citing Southern
California Edison, Pathway 2045: Update to the Clean Power and
Electrification Pathway (2019), <a href="https://download.newsroom.edison.com/create_memory_file/?f_id=5dc0be0b2cfac24b300fe4ca&content_verified=True">https://download.newsroom.edison.com/create_memory_file/?f_id=5dc0be0b2cfac24b300fe4ca&content_verified=True</a>) (emphasis
added)).
\205\ ISO-NE, 2050 Transmission Study, at 55-56 (Feb. 12, 2024),
<a href="https://www.iso-ne.com/static-assets/documents/100008/2024_02_14_pac_2050_transmission_study_final.pdf">https://www.iso-ne.com/static-assets/documents/100008/2024_02_14_pac_2050_transmission_study_final.pdf</a>.
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94. The growing need for new transmission infrastructure,
particularly over a longer time horizon, is being driven by a number of
factors. First, longer-term reliability needs are changing. The NOPR
explained that transmission system operators are increasing their
reliance on regional transmission facilities to ensure operational
stability, particularly because of the growing frequency of extreme
weather events and increasing share of variable resources entering the
resource mix.\206\ The comments submitted in response to the NOPR
support that preliminary finding. The record shows that changing
reliability needs are driving a significant shift in demands placed on
the transmission system,\207\ and that because extreme weather events
are occurring with greater frequency, transmission is increasingly
critical to ensuring system reliability.\208\ For example, Winter Storm
Uri demonstrated that transmission infrastructure can make critical
contributions to system reliability during extreme weather events,\209\
as well as how transmission constraints can prevent operational
generation resources from being able to serve load during tight supply
conditions.\210\ Consistent with experience from Winter Storm Uri, US
DOE's Lawrence Berkeley National Laboratory provides further evidence
of the significant value of transmission during unanticipated events,
with research suggesting that 50% of the value created by alleviating
transmission system congestion occurs during only 5% of the hours
during which the transmission system is used.\211\ Thus, transmission
investment is likely to be more critical, and produce more reliability
benefits, for customers as extreme weather and other system
contingencies become more frequent.\212\ For some communities who can
be more susceptible to the impacts of extreme weather, like communities
of color and

[[Page 49299]]

low-income communities, transmission investment has the potential to be
even more critical.\213\ Conversely, failure to adequately plan the
transmission system to meet such changing reliability needs will forgo
many of those potential benefits, jeopardize system reliability, and
force customers to pay for transmission facilities that may not
efficiently or cost-effectively address urgent reliability needs.
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\206\ NOPR, 179 FERC ] 61,028 at P 45.
\207\ ACEG Initial Comments at 5 (noting that weather-related
power outages cost Americans $25-70 billion annually (citing Grid
Strategies July 2021 Extreme Weather Report at 1)); id. at 52
(explaining that ``[c]hanges to the transmission planning processes
that would allow for certain transmission upgrades identified in the
interconnection process to be addressed and ultimately constructed
through the transmission planning process will only serve to
increase the resiliency and reliability of the transmission
system.''); ACEG Reply Comments at 5-6 (``[R]eliability requires
long term transmission planning that incorporates known and knowable
information about the future resource mix.''); NERC Initial Comments
at 6 (``Transmission will be the key to support the resource
transformation enabling delivery of energy from areas that have
surplus energy to areas which are deficient. The frequency of such
occurrences are increasing as extreme weather conditions resulting
from climate change impact the fuel sources for variable energy
resources. Regional transmission planning can ensure that sufficient
amounts of transmission capacity will be needed to address these
more frequent extreme weather conditions.'').
\208\ See DC and Maryland Offices of People's Counsel Reply
Comments at 2 (noting that new transmission development has benefits
including enhanced reliability and resilience that will serve as a
necessary bulwark against disruptions caused by extreme weather);
Indicated PJM TOs Initial Comments at 1 (explaining that maintaining
a ``reliable and resilient'' transmission system requires holistic
planning); NESCOE Initial Comments at 32-33 (``ISO-NE explains that
energy-security risks in New England are well documented,
highlighting the importance of conducting comprehensive energy
security assessments covering a wide range of operating conditions,
including low-probability, high-impact reliability risks (tail
risks) related to extreme weather'' (internal quotations omitted));
NYISO Initial Comments at 16 (expressing a desire to engage in
actionable scenario planning to plan for future reliability
challenges that may arise due to extreme weather, including the loss
of all generation connected to a pipeline or other fuel sources,
loss of an entire transmission line, and impacts from weather events
like hurricanes or wildfires).
\209\ ACEG Initial Comments at 22 n.63 (During Winter Storm Uri,
``[a]n additional 1 gigawatt (GW) of transmission ties between ERCOT
and the Southeastern U.S. could have saved nearly $1 billion and
kept power flowing to hundreds of thousands of Texans.'' (citing
Grid Strategies July 2021 Extreme Weather Report at 1-3, 12)); Grid
Strategies July 2021 Extreme Weather Report at 7-8 (``The value of
transmission for resilience can be seen in the drastically different
outcomes of MISO and SPP relative to ERCOT during [Winter Storm
Uri]. . . . In contrast to the 13,000 MW MISO was importing during
the peak of [the] event, ERCOT was only able to import about 800 MW
of power throughout the event.''); NARUC Initial Comments at 67
n.192 (During Winter Storm Uri, SPP's `` `relationships and
interconnections with neighboring systems were critical. Usually a
net exporter of energy, SPP relied significantly on imported energy
to serve load during the winter event, with net amounts exceeding
6,000 megawatts (MW) at times. This emphasizes the value these
relationships and robust transmission interconnections provide
during emergency events and the opportunity to further strengthen
them.' '' (quoting Southwest Power Pool, A Comprehensive Review of
Southwest Power Pool's Response to the February 2021 Winter Storm:
Analysis and Recommendations, at 9 (July 2021), <a href="https://spp.org/documents/65037/comprehensive%20review%20of%20spp%27s%20response%20to%20the%20feb.%202021%20winter%20storm%202021%2007%2019.pdf">https://spp.org/documents/65037/comprehensive%20review%20of%20spp%27s%20response%20to%20the%20feb.%202021%20winter%20storm%202021%2007%2019.pdf</a> (brackets omitted))).
\210\ See Advanced Energy Buyers Initial Comments at 3.
\211\ ACORE Initial Comments at 10-11 (citing LBNL Aug. 2022
Transmission Value Study at 33); US DOE Initial Comments at 5-6 &
n.13.
\212\ ACORE Initial Comments at 11 (citing LBNL Aug. 2022
Transmission Value Study at 33; see also Clean Energy Associations
Initial Comments at 5.
\213\ See, e.g., WE ACT Initial Comments at 1-2 & n.3 (citing
Jeff Turrentine, NRDC, A Roadmap for Frontline Communities (Dec.
2019)); see also Grand Rapids NAACP Initial Comments at 8 n.20
(``[P]ower outages uniquely burden low-income communities of color
`given that they are unable to `bounce back' as quickly from events
that damage food and medicine supplies' '' (citing Shalanda Baker et
al., The Energy Justice Workbook 20 (2019), <a href="https://iejusa.org/wp-content/uploads/2019/12/The-Energy-Justice-Workbook-2019-web.pdf">https://iejusa.org/wp-content/uploads/2019/12/The-Energy-Justice-Workbook-2019-web.pdf</a>)).
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95. Second, demand is changing. After many years of flat or minimal
load growth in regions across the country, demand, on both a national
and a regional basis, is projected to significantly increase in the
coming decades, and it will require an increasingly robust transmission
system to reliably serve this load growth. As stated in the NOPR,
changes in electric demand and associated load profiles are occurring
as load-serving entities work to meet increasing needs due to
electrification trends, as well as new large loads associated with
evolving industrial and commercial needs, such as growth in data
centers.\214\ The comments submitted in this record demonstrate that,
in regions across the country, customers are electrifying everything
from household appliances to vehicles.\215\ Comments also substantiate
the fact that, in many regions, large loads associated with new and
emerging industrial needs, like data centers, are driving rapid load
growth.\216\ Estimates quantifying the magnitude of this shift show
that it is significant, with nationwide demand for electricity
projected to increase by 5% to 15% (200 to 600 TWh) by 2030.\217\ That
trend is projected not just to continue but to accelerate, with
nationwide demand for electricity projected to increase by 25% to 85%
(1,100 to 3,700 TWh) by 2050.\218\ Industrial customers in many regions
are driving much of this increase; industry executives have reported
that electrification initiatives, through which many of the Nation's
largest companies plan to electrify their manufacturing processes,
transportation, and heating operations, are well underway or soon to
begin.\219\ Importantly, the record shows that these increases in
aggregate demand for electricity will have significant consequences for
the transmission system. To serve more load, the capacity of the
already-oversubscribed transmission system will need to increase.\220\
Moreover, load growth driven primarily by electrification can create a
load profile that has a higher load factor and that is thus more
challenging to serve.\221\
---------------------------------------------------------------------------

\214\ NOPR, 179 FERC ] 61,028 at PP 45, 51. The continuation
and, in some instances, acceleration of these trends identified in
the ANOPR and NOPR counters certain commenters' concerns that
changes in demand are inherently unpredictable or that existing
regional transmission planning processes are adequately identifying
and addressing transmission needs. Compare infra notes 21515-2188
and accompanying discussion, with Potomac Economics Initial Comments
at 3-4 (arguing that Long-Term Regional Transmission Planning that
requires speculating about future uncertainty is not advisable), and
Industrial Customers Initial Comments at 10-11 (arguing that changes
in demand are unpredictable).
\215\ AEE Initial Comments at 1, 14 (noting that, as of 2022,
``[n]ine states have also taken steps directly to promote
electrification of transportation and buildings. Individuals and
governments are also adopting electric vehicles; for example, light-
duty electric vehicle sales have increased from 10,092 vehicles in
2011 to 459,426 vehicles in 2021, over a 4400% increase.'');
Renewable Northwest Initial Comments at 20 (explaining that heat
pumps installed as part of building electrification could add large
new weather-dependent loads, estimated at 20,000 to 40,000 MW of
incremental peak capacity by 2050 across the Pacific Northwest); see
also AMP Initial Comments at 4; ISO-NE, Operational Impact of
Extreme Weather Events: Final Report on the Probabilistic Energy
Adequacy Tool (PEAT) Framework and 2027/2032 Study Results, at 190-
94 (Nov. 2023) (providing sensitivity that included 15% and 10%
increases in peak load and average hourly loads, respectively,
driven by heating and vehicle electrification); U.S. Energy Info.
Admin. (EIA), Incentives and Lower Costs Drive Electric Vehicle
Adoption in Our Annual Energy Outlook, (May 15, 2023) (noting that,
per 2023 Annual Energy Outlook Projections, electric vehicles will
account for between 13% and 29% of new light-duty vehicle sales in
the United States, and between 11% and 26% of then on-road light
duty vehicle stocks, by 2050).
\216\ See, e.g., Transmission Dependent Utilities Initial
Comments at 4-5 (``For example, the PJM Interconnection, L.L.C.
Transmission Expansion Advisory Committee recently posted that
Dominion Energy Virginia will need over $603 million in transmission
upgrades through 2025--just three years from now--to accommodate
significant data center load growth in Northern Virginia.'' (citing
PJM Transmission Advisory Committee, Reliability Analysis Update, at
3, 5 (Aug. 9, 2022))). These trends are continuing and even
accelerating. See PJM Interconnection, L.L.C., PJM Load Forecast
Report, at 1 (Jan. 2024), <a href="https://www.pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx">https://www.pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx</a> (noting upward
adjustments in 2024 load forecasts for certain zones to account for
large, unanticipated load growth driven by data centers, a chip
processing plant, and port electrification, among other factors);
id. at 78 (projecting increase from 2,333 GWh in 2024 to 130,489 GWh
in 2039 due to plug-in electric vehicles); id. at 30 (showing 1.0%
higher load growth projection for 2024, 6% higher load growth
projection for 2029, and 10.4% higher load growth projection for
2034, as compared to 2023 Load Forecast Report).
\217\ National Grid Initial Comments at 8 (citing J[uuml]rgen
Weiss et al., The Brattle Group, The Coming Electrification of the
North American Economy (Mar. 2019), <a href="https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf">https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf</a>).
\218\ Id.; see also John D. Wilson and Zach Zimmerman, Grid
Strategies, The Era of Flat Power Demand is Over, at 3 (Dec. 2023),
<a href="https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf">https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf</a> (``Over [2023], grid planners nearly
doubled the 5-year load growth forecast. The nationwide forecast of
electricity demand shot up from 2.6% to 4.7% growth over the next
five years, as reflected in 2023 FERC [Form 714] filings. Grid
planners forecast peak demand growth of 38 gigawatts (GW) through
2028.''); N. Amer. Elec. Reliability Corp., 2023 Long-Term
Reliability Assessment, at 33 (Dec. 2023), <a href="https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf">https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf</a>
(``Electricity peak demand and energy growth forecasts over the 10-
year assessment period are higher than at any point in the past
decade. The aggregated assessment area summer peak demand forecast
is expected to rise by 79 GW, and aggregated winter peak demand
forecasts are increasing by nearly 91 GW. Furthermore, the growth
rates of forecasted peak demand and energy have risen sharply since
the 2022 [Long-Term Reliability Assessment], reversing a decades-
long trend of falling or flat growth rates.'').
\219\ Renewable Northwest Initial Comments at 20 (``A recent
study done by Deloitte showed that 70 percent of executives in
industrial manufacturing industries have plans for the
electrification of industrial processes, and 50 percent of the
executives who responded have goals to electrify vehicle fleets and
space and water heating within their companies by 2030.'' (citing
Stanley Porter et al., Deloitte, Electrification in Industrials
(Aug. 2020), <a href="https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/electrification-in-industrials.html">https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/electrification-in-industrials.html</a>)).
\220\ See, e.g., National Grid Initial Comments at 6 (discussing
preliminary findings of the ISO-NE 2050 Transmission Study, which
show ``significant new transmission will be needed to reliably
serve'' increased future loads assumed in the study (citing ISO-NE,
2050 Transmission Study (2023), <a href="https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf">https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf</a>));
Northwest and Intermountain Initial Comments at 5 n.12 (``For
example, Bonneville Power Administration (`BPA') owns about 75
percent of the transmission lines in the Pacific Northwest. In BPA's
2022 Transmission Service Expansion Plan cluster study, customers
submitted 153 separate transmission service requests totaling 11,831
MW of transmission capacity. BPA was able to offer service (without
requiring detailed studies and transmission upgrades) to only 275
MWs of those service requests.'' (citing BPA, TSR Study and
Expansion Process, at 12 (Dec. 2021), <a href="https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf">https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf</a>.)).
\221\ MISO Initial Comments at 54 (``In addition, a return to
load growth driven primarily by the electrification of
transportation, space heating and water heating is creating a load
profile that has a higher load factor and is more challenging to
serve.''). Load factor refers to ``[t]he ratio of the average load
to peak load during a specified time interval.'' U.S. Energy Info.
Admin. (EIA), Glossary (last visited Mar. 2024), <a href="https://www.eia.gov/tools/glossary/index.php?id=L">https://www.eia.gov/tools/glossary/index.php?id=L</a>.
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96. Third, supply is changing. As the NOPR explained, Federal,
state, and local policies are incentivizing various forms of generation
resources and other technologies,\222\ resulting in changes to the
Nation's resource mix. The comments in this record show that these
policies are widespread and now span

[[Page 49300]]

many regions of the country. States and cities in the Northeast,\223\
Mid-Atlantic,\224\ Midwest,\225\ West,\226\ and Southeast \227\ have
adopted binding state laws requiring emissions reductions. Moreover,
with the passage of the Inflation Reduction Act in 2022, Congress has
enacted legislation that will further spur investment nationwide in
renewable and non-emitting resources.\228\
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\222\ NOPR, 179 FERC ] 61,028 at P 45.
\223\ National Grid Initial Comments at 6-7 (explaining how all
six states in New England have renewable energy standards and how
ISO-NE's 2050 Transmission Study demonstrates the demands that
meeting those standards will place on New England's transmission
system); id. at 7 (explaining how the Climate Leadership and
Community Protection Act enacted in New York State requires 70%
renewable generation by 2030, zero-emissions by 2040, and 85%
economy-wide emissions reductions by 2050, and that transmission
infrastructure will be critical in meeting those goals); NESCOE
Initial Comments at 15 (``Achieving a decarbonized system is
required by laws and mandates in Connecticut, Maine, Massachusetts,
Rhode Island, and Vermont.'').
\224\ DC and MD Offices of People's Counsel Initial Comments at
18 (noting that ``both Maryland and the District have adopted
ambitious jurisdiction-wide decarbonization policies applicable to
the [electric distribution companies] regulated by their respective
public service commissions.'').
\225\ Illinois Commission Initial Comments at 5 (explaining that
``[i]n Illinois, the Climate and Equitable Jobs Act of 2021 . . .
will affect the future resource mix and demand and lead to
decarbonization and electrification. For example, [it] requires
Illinois to completely transition to clean energy by 2050 and
facilitates electrification through the promotion of electric
vehicles.'').
\226\ Renewable Northwest Initial Comments at 6 (explaining
that, ``[c]urrently, 80 percent of NorthernGrid's load is subject to
state clean energy laws, and by 2040 NorthernGrid will have 65
percent carbon-free energy.''); id. at 21 (explaining that
Washington state's ``SB 5974 sets a goal of all vehicles sold in
2030 and beyond to be [electric vehicles], with that goal becoming a
mandate in 2035[.]'').
\227\ SREA Initial Comments at 25 (noting that North Carolina
has adopted Renewable Energy and Energy Efficiency Portfolio
Standards and enacted the North Carolina Carbon Plan).
\228\ ACORE Initial Comments at 1-2 & n.2 (projecting that
``annual additions increasing from 15 GW of wind and 10 GW of
utility-scale solar PV in 2020 to an average of 39 GW/year of wind
additions in 2025-2026 (~2x the 2020 pace) and 49 GW/year of solar
(~5x the 2020 pace), with solar growth rates increasing
thereafter.'' (citing REPEAT Project, Preliminary Report: The
Climate and Energy Impacts of the Inflation Reduction Act of 2022,
at 15 (2022), <a href="https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf">https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf</a>)); CARE Coalition
Initial Comments at 17 (``Analysis suggests that the [Inflation
Reduction Act] could more than triple clean energy production in the
U.S. and lead to $600 billion in capital investment in clean energy
infrastructure.'' (citing American Clean Power Ass'n, It's a Big
Deal for Job Growth and for a Clean Energy Future (2022), <a href="https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future">https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future</a>)); Evergreen Action Initial Comments at 3-4
(discussing model showing that clean energy could comprise up to 81%
of all U.S. generation as a result of increased incentives in the
Inflation Reduction Act (citing John Larsen et al., Rhodium Group, A
Turning Point for US Climate Progress: Assessing the Climate and
Clean Energy Provisions in the Inflation Reduction Act (2022),
<a href="https://rhg.com/research/climate-clean-energy-inflation-reduction-act">https://rhg.com/research/climate-clean-energy-inflation-reduction-act</a>)); NextEra Reply Comments at 5 (``The signing of the Inflation
Reduction Act of 2022 . . . will only increase the demand for
renewables in the coming years and accelerate corresponding demands
on the transmission system.'').
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97. Customers are also driving changes in the resource mix. In
addition to increasing their aggregate demand for electricity, the NOPR
explained that customers, including major corporations, in many regions
are increasingly demanding that load be served by renewable or non-
emitting resources.\229\ Substantial evidence in the record supports
the existence of this trend. Since 2014, for example, ``commercial and
industrial customers have contracted for more than 52 GW of clean
energy[.]'' \230\ Furthermore, this trend is accelerating. In 2021
alone, energy customers voluntarily contracted for ``11.06 GW of clean
energy.'' \231\ The record demonstrates that, going forward, this shift
is projected to continue, as forecasts show that Fortune 1000 companies
will have up to 85 GW of new demand for renewable energy to meet their
public sustainability commitments for 2030.\232\ As also noted in the
NOPR, utilities in many regions have made commitments to procure most
or all of their electricity from renewable or non-emitting resources.
For example, Exelon,\233\ Dominion,\234\ AEP,\235\ and Southern \236\
have all committed to achieve net-zero emissions by 2050, and each has
set an interim goal to significantly reduce emissions by 2030. And,
although utility commitments vary by utility and by region, the record
shows that many utilities have announced some future emissions
target.\237\
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\229\ NOPR, 179 FERC ] 61,028 at P 45.
\230\ Advanced Energy Buyers Initial Comments at 5 (citing Clean
Energy Buyers Alliance, State of the Market 2022, <a href="https://cebuyers.org/state-of-the-market/">https://cebuyers.org/state-of-the-market/</a>).
\231\ Clean Energy Buyers Initial Comments at 7.
\232\ Clean Energy Buyers Initial Comments at 7 n.13 (citing
Clean Energy Buyers ANOPR Initial Comments at 21-22).
\233\ Exelon Initial Comments at 2 (``Exelon has established
ambitious targets and aims to be a leader in clean energy by
continuing to reduce its own greenhouse gas emissions, including
reducing operations-driven emissions 50 percent by 2030, relative to
a 2015 baseline, and achieving net-zero operations by 2050.''
(citing Calvin Butler, Exelon Corporation, We're on the Path to
Clean (Apr. 2021), <a href="https://www.exeloncorp.com/grid/were-on-the-path-to-clean">https://www.exeloncorp.com/grid/were-on-the-path-to-clean</a>)).
\234\ Dominion Initial Comments at 3-4 (``Dominion Energy has
committed to achieve net zero greenhouse gas emissions by 2050 and
is investing in clean energy resources such as solar and wind.'').
\235\ AEP Initial Comments at 4 n.12 (``AEP's goal is to reduce
carbon emissions from directly owned generation by 80% by 2030
compared to 2000 levels and to achieve net-zero emissions by 2050.''
(citing AEP, 2022 Corporate Sustainability Report, at 48 (2022),
<a href="https://www.aep.com/news/releases/read/8520/AEP-Releases-2022-Corporate-Sustainability-Report">https://www.aep.com/news/releases/read/8520/AEP-Releases-2022-Corporate-Sustainability-Report</a>)).
\236\ Southern Initial Comments at 14 (``By 2019, Southern
Companies had already achieved a 44% reduction in greenhouse gas
emissions in pursuit of its goals of a 50% reduction by 2030 and net
zero by 2050.'').
\237\ See, e.g., SREA Initial Comments at 41-42 (``Major
utilities in the South, including Entergy, Dominion Energy, Duke
Energy, NextEra, Tennessee Valley Authority, and Southern Company
have all announced some version of a net zero carbon emission plan
or commitment.'').
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98. Furthermore, as noted in the NOPR,\238\ the resource mix is
also being affected by the changing economics of the resources that
comprise the resource mix.\239\
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\238\ NOPR, 179 FERC ] 61,028 at P 45 & n.72 (noting the average
levelized cost of wind energy for commercial wind generation has
decreased from $90 per MWh in 2009, to $35 per MWh in 2019 (citing
Lawrence Berkeley National Laboratory, Wind Energy Technology Date
Update: 2020 Edition, at 66 (Nov. 2020))); id. (noting that the
average levelized power purchase agreement price for utility-scale
solar generation has decreased from approximately $160 per MWh in
2009, to approximately $40 MWh in 2020 (citing Lawrence Berkeley
National Laboratory, Utility-Scale Solar Data Update: 2020 Edition,
at 32 (Nov. 2020))).
\239\ See ACORE ANOPR Initial Comments at app. 1, p. 22 (ACEG
Jan. 2021 Planning Report) (``Wind and solar energy costs have
fallen 70 and 89 percent, respectively, in the last ten years, from
2009 through 2019.''); Dominion Initial Comments at 19 (noting how,
during the 2010s, the fracking revolution and advanced technology
for natural gas combined cycle generation lead to a shift away from
coal and nuclear as ``baseload'' fuels and how, today, renewable
energy resources are likewise undergoing a similar expansion);
Evergreen Action Initial Comments at 3 (``Rapid innovation has made
wind and solar power the lowest-cost resource in many areas of the
country[.]'' (citing Univ. of Tex. at Austin Energy Inst., Levelized
Cost of Electricity in the United States by County (2022), <a href="http://calculators.energy.utexas.edu/lcoe_map/#/county/tech">http://calculators.energy.utexas.edu/lcoe_map/#/county/tech</a>); see also
ACORE Reply Comments at 2 (``In all scenarios, building transmission
that enables low-cost wind and other energy resources is often
cheaper than the alternatives, such as use of higher-cost but local
resources (and potentially additional storage).'' (citing Paul
Denholm, et al., National Renewable Energy Laboratory, Examining
Supply-Side Options to Achieve 100% Clean Electricity by 2035, at
47-78 (Sept. 2022))).
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99. Together, trends in economics, growing demand, and Federal,
federally-recognized Tribal, state, and local policies are already
resulting in significant changes in the resource mix. The record shows
that as of 2021, nearly 70% of capacity additions across the country
were from new, utility-scale wind and solar resources.\240\ Meanwhile,
most of the capacity retirements are, and are projected to continue to
be, coal resources.\241\ Based

[[Page 49301]]

on the record, those trends are projected to continue, with over 1,300
GW of wind, solar, and storage resources in interconnection queues
across the country as of 2021.\242\ With the passage of the Inflation
Reduction Act in 2022, many analysts are predicting that the shift
toward renewable resources will accelerate.\243\
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\240\ SREA Initial Comments at 1-2 (citing US Energy Info.
Admin., Today in Energy (2021), <a href="https://www.eia.gov/todayinenergy/detail.php?id=46416#">https://www.eia.gov/todayinenergy/detail.php?id=46416#</a>); see also AEE Initial Comments at 13 (noting
that between 2011 and 2021, ``renewable generation nearly doubled,
from 12.5% to more than 20%.'').
\241\ AEE Initial Comments at 12-13 (``From 2011 to 2021, the
proportion of U.S. electricity generated by coal plants dropped by
almost half, from 42% to under 22%'' (citing U.S. Energy Info.
Admin., U.S. Electricity Generation by Major Energy Source, 1950-
2021 (2022), <a href="https://www.eia.gov/energyexplained//electricity/charts/generation-major-source.csv">https://www.eia.gov/energyexplained//electricity/charts/generation-major-source.csv</a>)); California Commission Initial
Comments at 65 (citing FERC, State of the Markets 2020 (Mar. 2021);
Renewable Northwest Initial Comments at 36 (using IRP data to show
that utilities in NorthernGrid plan to retire 6,573 MW of coal,
1,476 MW of natural gas, 10 MW of wind, and 18 MW of solar, by
2040). FERC's State of the Markets 2020 report stated that 9.6 GW of
coal capacity retired in 2020, which had a noticeable effect on
coal's operating capacity share in most RTOs/ISOs. FERC, State of
the Markets 2020, at 10, 12 (Mar. 2021). FERC's State of the Markets
2023 indicates that this trend is continuing, with coal generation
declining 18.8% in 2023. FERC, State of the Markets 2023, at 4 (Mar.
2024). See also US DOE Initial Comments at App. B, pp. 8-9 (Rand et
al., Lawrence Berkeley National Laboratory, Queued Up:
Characteristics of Power Plants Seeking Transmission Interconnection
as of the End of 2021 (Apr. 2021)).
\242\ See US DOE Initial Comments app. B, at p. 26 (Lawrence
Berkeley National Laboratory, Queued Up: Characteristics of Power
Plants Seeking Transmission Interconnection As of the End of 2021
(Apr. 2022)) (noting that 676 GW of solar, 246 GW of wind, 213 GW of
standalone battery capacity, and ~208 GW of hybrid battery capacity
wait in interconnection queues across the U.S.). On the other hand,
the number of coal and, relatedly, natural gas resources waiting to
interconnect is limited. See id.; Colorado Consumer Advocates
Initial Comments attach. 7, at p. 21 (``No new coal plants have been
built for domestic utility electricity production since 2014[.]'');
NESCOE Initial Comments at 15-16 (noting that new natural gas
generation represented nearly 48% of the queue in 2017, but just 3%
by March of 2022). Moreover, the updated version of the report to
which US DOE cites indicates that the capacity of wind, solar, and
storage in interconnection queues is still increasing. Lawrence
Berkeley National Laboratory, Queued Up: Characteristics of Power
Plants Seeking Transmission Interconnection As of the End of 2022
(Apr. 2023) (noting that 947 GW of solar, 300 GW of wind, 325 GW of
standalone battery capacity, and ~358 GW of hybrid storage capacity,
totaling over 1900 GW, wait in interconnection queues across the
country).
\243\ ACORE Initial Comments at 1-2 & n.2 (``[P]rojecting annual
additions increasing from 15 GW of wind and 10 GW of utility-scale
solar PV in 2020 to an average of 39 GW/year of wind additions in
2025-2026 (~2x the 2020 pace) and 49 GW/year of solar (~5x the 2020
pace), with solar growth rates increasing thereafter.'' (quoting
REPEAT Project, Preliminary Report: The Climate and Energy Impacts
of the Inflation Reduction Act of 2022, at 15 (2022), <a href="https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf">https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf</a>)).
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100. In light of these changing demands on the transmission system,
the record also affirms what the Commission has long recognized:
regional transmission planning that identifies more efficient or cost-
effective transmission solutions to needs helps to ensure cost-
effective transmission development for customers and can yield better
returns for every dollar spent than localized or piecemeal transmission
solutions.\244\ Conversely, inadequate or poorly designed transmission
planning processes can lead to relatively inefficient or less cost-
effective transmission investment, with customers footing the bill for
piecemeal, inefficient, and less cost-effective transmission solutions
designed to meet short-term or small-scale transmission needs. Given
the magnitude of transmission investment needed to meet customers'
changing needs, it is essential that regional transmission planning be
of sufficient scope and duration to help to ensure customers' money is
well-spent on transmission infrastructure that can efficiently and
cost-effectively meet those needs. Unfortunately, we conclude that this
is not the case today and that existing regional transmission planning
processes are inadequate to address the emerging Long-Term Transmission
Needs that are expected to increasingly drive transmission investment
in the coming decades.
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\244\ Order No. 1000, 136 FERC ] 61,051 at P 55 (``[T]he narrow
focus of current planning requirements and shortcomings of current
cost allocation practices create an environment that fails to
promote the more efficient and cost-effective development of new
transmission facilities.''); id. P 68 (concluding that reforms that
require transmission providers to engage in regional transmission
planning and evaluate proposed alternatives that ``may resolve the
region's needs more efficiently or cost-effectively than solutions
identified in the local transmission plans . . . will provide
assurance that rates for transmission services on these systems will
reflect more efficient or cost-effective solutions for the
region.''); Order No. 890, 118 FERC ] 61,119 at P 524
(``[C]oordination of planning on a regional basis will also increase
efficiency through the coordination of transmission upgrades that
have region-wide benefits, as opposed to pursuing transmission
expansion on a piecemeal basis.''); see also ACORE Initial Comments
at 6 (demonstrating that effective regional transmission planning
could significantly reduce total electric system costs compared to
electric system costs that result from intrastate planning (citing
Brattle-Grid Strategies Oct. 2021 Report at 12)); R Street Initial
Comments at 8 (``[H]olistic transmission planning could improve
economic efficiencies and save billions of dollars . . . . For
example, MISO's 2022 long-range transmission plan results include
$10 billion in transmission projects that support interconnection of
53,000 megawatts of new renewable generation and reduces other costs
by $37-$68 billion. PJM similarly identified $3 billion in
transmission upgrades that would save billions compared to the
current practice of incremental upgrades through the interconnection
process.'' (citing Johannes Pfeifenberger, Brattle Group, Planning
for Generation Interconnection, at 5 (May 31, 2022), <a href="https://www.esig.energy/event/special-topic-webinar-interconnection-study-criteria">https://www.esig.energy/event/special-topic-webinar-interconnection-study-criteria</a> (citation omitted))).
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101. Experience with the implementation of Order No. 1000 over the
last decade has highlighted a critical gap in the Commission's existing
transmission planning and cost allocation requirements. Notwithstanding
the broad recognition that additional transmission infrastructure is
needed to address the drivers noted above, regional transmission
planning processes across the country have yielded only limited
investments in regional transmission projects. As the Commission
observed in the NOPR, investment in regional transmission facilities in
some regions has declined compared to prior to Order No. 1000.\245\
Moreover, across all the non-RTO/ISO regions, there has not yet been a
single transmission facility selected since implementation of Order No.
1000.\246\ The record also demonstrates that within some RTO/ISO
regional transmission planning processes, even where investments
through the regional transmission planning process do occur, much of
that investment has been in transmission projects that only address
immediate reliability needs.\247\ We find that this evidence supports
our conclusion that existing regional transmission planning processes
are not of sufficient scope and duration to adequately or consistently
identify transmission needs and associated opportunities to more
comprehensively evaluate and select more efficient or cost-effective
transmission solutions to those needs.
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\245\ NOPR, 179 FERC ] 61,028 at P 39 (citing ACEG Jan. 2021
Planning Report at 25 & fig. 8); see also ACORE ANOPR Initial
Comments at 4 (``Despite the potential benefits, regional
transmission investment has not increased and in some regions even
has declined over the past decade.'') (citing ACEG Jan. 2021
Planning Report at 25)); State Agencies Initial Comments at 23
(``Regionally planned projects have [ ] declined in RTOs/ISOs . . .
.'' (citing John C. Gravan and Rob Gramlich, NRRI Insights, A New
State-Federal Cooperation Agenda for Regional and Interregional
Transmission, at 2 (Sept. 2021), <a href="https://pubs.naruc.org/pub/FF5D0E68-1866-DAAC-99FB-A31B360DC685">https://pubs.naruc.org/pub/FF5D0E68-1866-DAAC-99FB-A31B360DC685</a>)).
\246\ NOPR, 179 FERC ] 61,028 at P 39 (citing LS Power ANOPR
Initial Comments App. I at 18 & n.57); FERC, Staff Report, 2017
Transmission Metrics, at 19 (Oct. 6, 2017), <a href="https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf">https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf</a>);
see also Western PIOs Initial Comments at 28 (``The Western Regional
Planning Groups, with the exception of the CAISO, have not developed
new projects from their current Order 1000 transmission planning
process.'').
\247\ Southwestern Power Group Initial Comments at 15; PIOs
ANOPR Initial Comments at 93 & n.276; see also Ari Peskoe, Is the
Utility Syndicate Forever?, 42 Energy L.J. 1, 56-57 (2021)
(explaining, for example, that in ISO-NE, all but one of the
transmission projects approved through the regional transmission
planning process were immediate-need reliability projects).
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102. Indeed, in the limited instances in which transmission
providers have followed processes that share many of the elements of
the long-term, forward-looking, and more comprehensive regional
transmission planning this

[[Page 49302]]

order requires, customers have seen clear and quantifiable benefits.
For example, as the Commission observed in the NOPR,\248\ MISO's Multi-
Value Project (MVP) transmission planning process proactively planned
over a 20-year period for two key drivers of transmission needs: the
impacts of changing state laws on the resource mix, and a large
increase in the number of generator interconnection requests. To
mitigate the uncertainties associated with such long-term projections
of transmission needs, MISO relied on scenarios to consider a range of
potential future conditions \249\ and disclosed the assumptions and
inputs underlying each scenario.\250\ The MVP process then identified a
portfolio of transmission projects that were projected to provide
multiple kinds of reliability and economic benefits under all the
altern

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