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

Federal RegisterJun 11, 2024

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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.

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,

david.borden@ferc.gov

Noah Lichtenstein (Technical Information), Office of Energy Market Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696,

noah.lichtenstein@ferc.gov

Michael Kellermann (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8491,

michael.kellermann@ferc.gov

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.

I. Introduction and Background

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

B. ANOPR and Technical Conference

C. Joint Federal-State Task Force on Electric Transmission

D. Notice of Proposed Rulemaking

E. High-Level Overview of NOPR Comments

F. Use of Terms

II. The Overall Need for Reform

A. NOPR Proposal

B. Comments

C. Commission Determination

1. The Transmission Investment Landscape Today

2. Unjust, Unreasonable, and Unduly Discriminatory or Preferential Commission-Jurisdictional Transmission Planning and Cost Allocation Processes

112

3. Benefits of Long-Term Regional Transmission Planning and Cost Allocation To Identify and Plan for Long-Term Transmission Needs

134

4. Conclusion

139

III. Long-Term Regional Transmission Planning

140

A. Requirement To Participate in Long-Term Regional Transmission Planning

140

1. NOPR Proposal

140

2. Comments

145

a. General Comments

145

b. Requests for Flexibility in Transmission Planning

151

c. Comments Regarding More Comprehensive Transmission Planning

163

d. Concerns Regarding Favoring Renewable Resources

172

e. Concerns Regarding Uncertainty, Over-Building, and Costs

176

f. Concerns Regarding Incentives for Resource Development

187

g. Comments Regarding Definition of Long-Term Regional Transmission Facility

189

h. Challenges to Commission Jurisdiction or Authority

190

i. Other Issues

215

j. Miscellaneous Concerns

217

3. Commission Determination

224

a. Participation in Long-Term Regional Transmission Planning

224

b. Definition of Long-Term Regional Transmission Facility

250

c. Legal Authority To Adopt Reforms for Long-Term Regional Transmission Planning

253

B. Development of Long-Term Scenarios

284

1. NOPR Proposal

284

2. Comments

286

a. General Comments

286

b. Applying Scenario Planning to Reliability and Economic Planning

296

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

a. NOPR Proposal

352

b. Comments

354

c. Commission Determination

377

3. Categories of Factors

387

a. Requirement To Incorporate Categories of Factors

387

b. Specific Categories of Factors

422

c. Treatment of Specific Categories of Factors

495

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 Events

578

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 Transmission Facilities

667

1. Requirement for Transmission Providers To Use a Set of Seven Required Benefits

669

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 of the Benefits of Long-Term Regional Transmission Facilities

823

a. NOPR Proposal

823

b. Comments

824

c. Commission Determination

837

4. Evaluation of Transmission Benefits Over a Longer Time Horizon

843

a. NOPR Proposal

843

b. Comments

845

c. Commission Determination

859

5. Evaluation of the Benefits of Portfolios of Transmission Facilities

871

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 Transmission Facilities

904

1. Requirement To Adopt an Evaluation Process and Selection Criteria

904

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

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 Planning

1062

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 Generator Interconnection Processes

1076

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 Considerations

1095

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 Power Flow Control Devices

1163

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 Transmission Facilities

1248

1. Cost Allocation Methods for Long-Term Regional Transmission Facilities

1248

a. NOPR Proposal

1248

b. Comments

1252

c. Commission Determination

1291

2. Requirement that Transmission Providers Seek the Agreement of Relevant State Entities Regarding the Cost Allocation Method or Methods for Long-Term Regional Transmission Facilities

1308

a. NOPR Proposal

1308

b. Comments

1313

c. Commission Determination

1354

3. Proposals Relating to the Design and Operation of State Agreement Processes

1369

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-Term Regional Transmission Planning Cost Allocation Processes for State-Negotiated Alternate Cost Allocation Method

1432

a. NOPR Proposal

1432

b. Comments

1436

c. Commission Determination

1456

B. Long-Term Regional Transmission Facility Cost Allocation Compliance With the Existing Six Order No. 1000 Regional Cost Allocation Principles

1458

1. NOPR Proposal

1458

2. Comments

1459

a. General Proposal

1459

b. Comments Specific to a State Agreement Process

1467

3. Commission Determination

1469

C. Identification of Benefits Considered in Cost Allocation for Long-Term Regional Transmission Facilities

1480

1. NOPR Proposal

1480

2. Comments

1482

a. Agree With Proposal

1482

b. Requests To Reflect the Full Breadth of Benefits in Cost Allocation Methods While Maintaining Flexibility

1491

c. Disagree With Proposal, Mostly Require Benefits

1492

d. Alignment of Benefits Between Transmission Planning and Cost Allocation

1497

e. Additional Benefits or Suggestions for Refinement

1502

3. Commission Determination

1505

D. Miscellaneous Cost Allocation Comments and Proposals

1516

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 Abandoned Plant Incentive

1545

C. Commission Determination

1547

VIII. Exercise of a Federal Right of First Refusal in Commission-Jurisdictional Tariffs and Agreements

1548

A. NOPR Proposal

1548

B. Comments

1553

1. General Perspectives and Approach to Reform

1553

2. Comments on the NOPR's Joint Ownership Proposal

1560

C. Commission Determination

1563

IX. Local Transmission Planning Inputs in the Regional Transmission Planning Process

1565

A. Need for Reform

1565

1. NOPR

1565

2. Comments

1567

3. Commission Determination

1569

B. Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process

1578

1. NOPR Proposal

1578

2. Comments

1581

a. Interest in Enhanced Transparency of Local Transmission Planning Inputs

1581

b. Suggested Modifications to the NOPR Proposal

1586

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 Replacement Transmission Facilities

1649

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

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.

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)

remain just and reasonable and not unduly discriminatory or preferential. This final order builds upon Order No. 888, Order No. 890,

and Order No. 1000,

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;

(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),

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.

16 U.S.C. 824e.

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.

FERC,

225 F.3d 667 (D.C. Cir. 2000),

aff'd sub nom. N.Y.

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).

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).

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.

FERC,

762 F.3d 41 (D.C. Cir. 2014).

All capitalized terms are defined below.

Infra

Use of Terms section.

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)).

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.

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.

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.

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.

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.

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,

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

originally identified through the generator interconnection process.

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.

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.

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

from a diverse range of stakeholders.

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.”

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.”

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;

(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.

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.

Id.

P 2.

Id.

P 21.

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.

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.

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.

Id.

PP 11-12, 42-44; Order No. 1000-A, 139 FERC ¶ 61,132 at PP 3, 4-6.

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.

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.

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.

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.

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.

Thus, a local transmission facility may be rolled up and “included” in a regional transmission plan for informational purposes, but it is not “selected.”

Order No. 1000, 136 FERC ¶ 61,051 at P 63.

Id.

PP 7, 226, 318.

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

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.

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

discriminatory or preferential and that reliability is maintained.

ANOPR, 176 FERC ¶ 61,024.

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.

Following the Technical Conference, the Commission invited all interested persons to file comments to address issues raised during the Technical Conference.

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.

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.

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.

Joint Fed.-State Task Force on Elec. Transmission,

175 FERC ¶ 61,224, at PP 1, 6 (2021).

Id.

P 2.

An up-to-date list of Task Force members, as well as additional information on the Task Force, is available on the Commission's website at:

https://www.ferc.gov/TFSOET

. Public materials related to the Task Force, including transcripts from public meetings, are available in the Commission's eLibrary in Docket No. AD21-15-000.

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.

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.

The May 2022 meeting focused on barriers to the efficient, expeditious, and reliable interconnection of new resources.

The July 2022 meeting focused on interregional transmission planning and transmission project development and the NOPR.

The November 2022 meeting focused on regulatory gaps and challenges in oversight of transmission development.

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.

The July 2023 meeting focused on grid enhancing technologies, featuring a guest speaker from the Electric Power Research Institute.

The February 2024 meeting focused on transmission siting, featuring guest speakers from US DOE.

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching agenda).

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching agenda).

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022) (attaching agenda).

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued June 30, 2022) (attaching agenda).

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued Nov. 1, 2022) (attaching agenda).

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued Feb. 1, 2023) (attaching agenda).

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued June 30, 2023) (attaching agenda).

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,

on March 21, 2024, the Commission established the Federal and State Current Issues Collaborative (Collaborative).

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.

Joint Fed.-State Task Force on Elec. Transmission,

175 FERC ¶ 61,224 at P 4.

Joint Fed.-State Task Force on Elec. Transmission,

186 FERC ¶ 61,189 (2024).

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.

The Commission also proposed to require that transmission providers develop Long-Term Scenarios as part of Long-Term Regional Transmission Planning.

NOPR, 179 FERC ¶ 61,028 at PP 64, 68.

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).

Id.

P 166.

28. The Commission proposed 12 benefits that transmission providers may consider in Long-Term Regional Transmission Planning and cost allocation processes.

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.

Id.

P 185.

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

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.

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.

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.

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.

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.

Id.

P 302.

Id.

P 303.

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.

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.

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.

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.

Id.

P 400.

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.

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.

Id.

P 427.

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.

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.

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

scenarios and considering the enumerated categories of factors.

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

that is identified as part of Long-Term Regional Transmission Planning to address Long-Term Transmission Needs.

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

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.

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.

NOPR, 179 FERC ¶ 61,028 at P 24.

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.

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.

Id.

PP 24-25.

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.

Advanced Energy Buyers

note that the electric system is presently undergoing one of the most significant transformations in a century.

Other commenters agree that electric energy supply and demand is evolving quickly.

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.

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; Ørsted 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.

Advanced Energy Buyers Initial Comments at 2.

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.

Clean Energy Buyers Initial Comments at 7.

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.

Northwest and Intermountain claim that Order No. 1000 has been inadequate to meet transmission needs, particularly in the non-RTO/ISO West.

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.

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.

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.

Northwest and Intermountain Initial Comments at 6-7.

Michigan State Entities Initial Comments at 1-2.

SREA Reply Comments at 4.

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.

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.

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.

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.

Competition Coalition argues that incumbent transmission owners have used reliability designations to justify projects with higher costs.

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),

https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf

Id.

at 6-7.

Id.

at 9 (citing Brattle Apr. 2019 Competition Report at 4).

Ohio Consumers Initial Comments at 5.

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.

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.

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.

US DOE Initial Comments at 3-4.

Id.

at 7-8.

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),

https://netzeroamerica.princeton.edu/the-report

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.

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.

New Jersey Commission asserts that better transmission planning

can reduce overall system costs by billions of dollars.

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.

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.

In a similar vein, Ørsted 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.

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.

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.

Michigan State Entities Initial Comments at 3.

New Jersey Commission Initial Comments at 3-9.

Certain TDUs Initial Comments at 2.

CARE Coalition Initial Comments at 17.

Massachusetts Attorney General Initial Comments at 5; Ørsted 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.

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.

Likewise, Exelon argues that relying on interconnection studies as the primary transmission planning method results in piecemeal and inefficient transmission investment.

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.

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.

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; Ørsted Initial Comments at 4-5; Pine Gate Initial Comments at 8-10; SEIA Initial Comments at 2;

see also

AEP Initial Comments at 8.

AEE Initial Comments at 1-2 (citing NOPR, 179 FERC ¶ 61,028 at PP 47-55).

Exelon Initial Comments at 5.

PIOs Initial Comments at 9-10.

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.

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.

Non-RTO NASUCA Initial Comments at 4.

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.

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.

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.”

SREA catalogs deficiencies in many Southeastern states' planning processes, including a lack of transparency.

ACEG Reply Comments at 9 (citing Alabama Commission Initial Comments at 2-3; Southern Initial Comments at 5-6, Ex. 2 at 2-3).

Id.

at 9-10 (citing PIOs Initial Comments at 7).

SREA Reply Comments at 4.

Id.

at 5-18.

57. Western PIOs argue that, outside of CAISO, transmission planning in the West is ineffective.

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.

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.

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

Western PIOs Initial Comments at 4-28.

Id.

at 28.

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

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),

https://netl.doe.gov/sites/default/files/netl-file/Advancing%20Energy%20Equity%20in%20Grid%20Planning.pdf

; Office of Energy Justice and Equity, US DOE,

Justice40 Initiative,

https://www.energy.gov/diversity/justice40-initiative

110

Id.

at 23 (citing

Neb. Pub. Power Dist.

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

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),

https://eta-publications.lbl.gov/sites/default/files/lbnlempirical_transmission_value_study-august_2022.pdf

(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; Ørsted 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),

https://www.nrel.gov/docs/fy22osti/81644.pdf

124

NextEra Reply Comments at 5, 25.

125

Pacific Northwest State Agencies at 1.

126

Michigan State Entities Initial Comments at 2-3.

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

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

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.

FERC,

762 F.3d at 56 (citing Order No. 1000, 136 FERC ¶ 61,051 at PP 112, 116);

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),

https://www.energy.senate.gov/services/files/D47C2B83-A0A7-4E0B-ABF2-9574D9990C11

(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),

https://wiresgroup.com/wp-content/uploads/2020/06/2018-05-09-Brattle-Group-Recognizing-the-Role-of-Transmission-in-Electric-System-Resilience-.pdf

; 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

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),

https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf

(“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),

https://www.misoenergy.org/meet-miso/MISO_Strategy/miso-value-proposition/

(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),

https://www.energy.gov/sites/prod/files/2015/09/f26/2015%20National%20Electric%20Transmission%20Congestion%20Study_0.pdf

(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”).

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

share of customers' overall electricity bills, underscoring the importance of ensuring that transmission investments are efficient and cost-effective.

201

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),

https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf

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),

https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf

(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)”).

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

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),

https://netzeroamerica.princeton.edu/the-report

203

TAPS Initial Comments at 46 & n.133 (citing Jürgen Weiss et al., The Brattle Group,

The Coming Electrification of the North American Economy,

at iii (2019),

https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf

)).

204

SoCal Edison Initial Comments at 2 (citing Southern California Edison,

Pathway 2045: Update to the Clean Power and Electrification Pathway

(2019),

https://download.newsroom.edison.com/create_memory_file/?f_id=5dc0be0b2cfac24b300fe4ca&content_verified=True

) (emphasis added)).

205

ISO-NE,

2050 Transmission Study,

at 55-56 (Feb. 12, 2024),

https://www.iso-ne.com/static-assets/documents/100008/2024_02_14_pac_2050_transmission_study_final.pdf

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

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.

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),

https://spp.org/documents/65037/comprehensive%20review%20of%20spp%27s%20response%20to%20the%20feb.%202021%20winter%20storm%202021%2007%2019.pdf

(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),

https://iejusa.org/wp-content/uploads/2019/12/The-Energy-Justice-Workbook-2019-web.pdf

)).

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),

https://www.pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx

(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 Jürgen Weiss et al., The Brattle Group,

The Coming Electrification of the North American Economy

(Mar. 2019),

https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf

218

Id.; see also

John D. Wilson and Zach Zimmerman, Grid Strategies,

The Era of Flat Power Demand is Over,

at 3 (Dec. 2023),

https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf

(“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),

https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf

(“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),

https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/electrification-in-industrials.html

)).

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),

https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf

)); 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),

https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf

.)).

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),

https://www.eia.gov/tools/glossary/index.php?id=L

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

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

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),

https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf

)); 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),

https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future

)); 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),

https://rhg.com/research/climate-clean-energy-inflation-reduction-act

)); 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.”).

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

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,

https://cebuyers.org/state-of-the-market/

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),

https://www.exeloncorp.com/grid/were-on-the-path-to-clean

)).

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),

https://www.aep.com/news/releases/read/8520/AEP-Releases-2022-Corporate-Sustainability-Report

)).

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.”).

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

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),

http://calculators.energy.utexas.edu/lcoe_map/#/county/tech

);

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