# Building for the Future Through Electric Regional Transmission Planning and Cost Allocation > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2024-10872 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** June 11, 2024 - **Citation:** 89 FR 49280 ## Text 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 1 A. Historical Framework: Order Nos. 888, 890, and 1000 14 B. ANOPR and Technical Conference 20 C. Joint Federal-State Task Force on Electric Transmission 22 D. Notice of Proposed Rulemaking 26 E. High-Level Overview of NOPR Comments 36 F. Use of Terms 37 II. The Overall Need for Reform 47 A. NOPR Proposal 47 B. Comments 49 C. Commission Determination 85 1. The Transmission Investment Landscape Today 90 2. Unjust, Unreasonable, and Unduly 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. 1 The reforms herein will remedy deficiencies in the Commission's existing regional and local transmission planning and cost allocation requirements to ensure that the rates, terms, and conditions for transmission service provided by public utility transmission providers (transmission providers) 2 remain just and reasonable and not unduly discriminatory or preferential. This final order builds upon Order No. 888, Order No. 890, 3 and Order No. 1000, 4 in which the Commission incrementally developed the requirements that govern regional transmission planning and cost allocation processes to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. Specifically, in this final order, we find that there is substantial evidence to support the conclusion that the existing regional transmission planning and cost allocation processes are unjust, unreasonable, and unduly discriminatory or preferential because the Commission's existing transmission planning and cost allocation requirements do not require transmission providers to: (1) perform a sufficiently long-term assessment of transmission needs that identifies Long-Term Transmission Needs; 5 (2) adequately account on a forward-looking basis for known determinants of Long-Term Transmission Needs; and (3) consider the broader set of benefits of regional transmission facilities planned to meet those Long-Term Transmission Needs. Accordingly, we believe that it is necessary to revisit existing transmission planning and cost allocation requirements. We conclude that adopting the reforms of this final order, as previously contemplated in the notice of proposed rulemaking (NOPR), 6 will remedy the identified deficiencies in existing regional and local transmission planning and cost allocation requirements, as discussed below, and will ensure the identification, evaluation, and selection, as well as the allocation of the costs, of more efficient or cost-effective regional transmission solutions to address Long-Term Transmission Needs. 1 16 U.S.C. 824e. 2 Section 201(e) of the FPA, 16 U.S.C. 824(e), defines “public utility” to mean “any person who owns or operates facilities subject to the jurisdiction of the Commission under this subchapter.” As stated in the Order No. 888 pro forma Open Access Transmission Tariff (OATT), “transmission provider” is a “public utility (or its Designated Agent) that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce and provides transmission service under the Tariff.” Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Servs. by Pub. Utils.; Recovery of Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996) (cross-referenced at 75 FERC ¶ 61,080), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002); Pro forma OATT section I.1 (Definitions). The term “transmission provider” includes a public utility transmission owner when the transmission owner is separate from the transmission provider, as is the case in regional transmission organizations (RTO) and independent system operators (ISO). 3 Preventing Undue Discrimination & Preference in Transmission Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, 118 FERC ¶ 61,119 (2007), order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007) (cross-referenced at 118 FERC ¶ 61,119), order on reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ¶ 61,126 (2009). 4 Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 FERC ¶ 61,051 (2011), Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132 (2012), order on reh'g & clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014). 5 All capitalized terms are defined below. Infra Use of Terms section. 6 Bldg. for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation & Generator Interconnection, 87 FR 26504 (May 4, 2022), 179 FERC ¶ 61,028 (2022) (NOPR); see also Bldg. for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation & Generator Interconnection, 86 FR 40266 (July 27, 2021), 176 FERC ¶ 61,024 (2021) (advanced notice of proposed rulemaking (ANOPR)). 2. Specifically, the reforms adopted in this final order require transmission providers in each transmission planning region to participate in a regional transmission planning process that includes Long-Term Regional Transmission Planning. 7 This final order adopts specific requirements regarding how transmission providers must conduct Long-Term Regional Transmission Planning, including, among other things, the use of scenarios to identify Long-Term Transmission Needs and Long-Term Regional Transmission Facilities to meet those needs. 7 For purposes of this final order, and consistent with Order No. 1000, a transmission planning region is one in which transmission providers, in consultation with stakeholders and affected states, have agreed to participate for purposes of regional transmission planning and development of a single regional transmission plan. See Order No. 1000, 136 FERC ¶ 61,051 at P 160. 3. This final order also requires transmission providers to measure and use at least the seven specified benefits to evaluate Long-Term Regional Transmission Facilities as part of Long-Term Regional Transmission Planning. In addition, this final order requires transmission providers to calculate the benefits of Long-Term Regional Transmission Facilities over a time horizon that covers, at a minimum, 20 years starting from the estimated in-service date of the transmission facilities and requires that this minimum 20-year benefit horizon be used both for the evaluation and selection of Long-Term Regional Transmission Facilities in the regional transmission plan for purposes of cost allocation. 8 8 We recognize that some transmission planning regions may include Long-Term Regional Transmission Facilities, or a portfolio of such Facilities, in a regional transmission plan, but may not necessarily include these Facilities for purposes of cost allocation. See Order No. 1000, 136 FERC ¶ 61,051 at P 63. For purposes of this final order, unless otherwise noted, when referencing Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) that are selected, we intend “selected” to mean that those Facilities are selected in the regional transmission plan for purposes of cost allocation. 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 9 originally identified through the generator interconnection process. 9 The Commission's pro forma Large Generator Interconnection Procedures (LGIP) and pro forma Large Generator Interconnection Agreement (LGIA) provide that, “Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission Provider's Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission Provider's Transmission System to accommodate the interconnection of the Large Generating Facility to the Transmission Provider's Transmission System.” See Improvements to Generator Interconnection Procedures & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC ¶ 61,054, at P 13 n.23, order on reh'g, 185 FERC ¶ 61,063 (2023), order on reh'g, Order No. 2023-A, 89 FR 27006 (Apr. 16, 2024), 186 FERC ¶ 61,199 (2024). In this final order, we refer to network upgrades developed through the generator interconnection process as interconnection-related network upgrades. 8. This final order requires transmission providers in each transmission planning region to consider more fully the alternative transmission technologies of dynamic line ratings, advanced power flow control devices, advanced conductors, and transmission switching in Long-Term Regional Transmission Planning and existing Order No. 1000 regional transmission planning and cost allocation processes. 9. This final order does not finalize the NOPR proposal to not permit transmission providers to take advantage of the recovery of 100% of construction work in progress for Long-Term Regional Transmission Facilities, and the Commission will instead continue to consider transmission incentives issues in other proceedings. This final order similarly does not finalize the NOPR proposal with respect to permitting the exercise of Federal rights of first refusal for selected transmission facilities, conditioned on the incumbent transmission provider with the Federal right of first refusal establishing joint ownership of the transmission facilities, and the Commission will instead continue considering the NOPR proposal and potential Federal right of first refusal issues in other proceedings. 10. This final order adopts the NOPR proposal to require transmission providers to adopt enhanced transparency requirements for local transmission planning processes and improve coordination between regional and local transmission planning with the aim of identifying potential opportunities to “right-size” replacement transmission facilities. 11. This final order requires transmission providers to revise their interregional transmission coordination processes to reflect the Long-Term Regional Transmission Planning reforms adopted in this final order. This final order also requires that transmission providers meet additional information sharing and transparency requirements with respect to their interregional transmission coordination processes. 12. This final order requires that each transmission provider submit a compliance filing within ten months of the effective date of this final order revising its OATT and other document(s) subject to the Commission's jurisdiction to demonstrate that it meets the requirements of this final order, with the exception of those requirements adopted in the Interregional Transmission Coordination section in this final order. This final order requires that each transmission provider submit a compliance filing within 12 months of the effective date of this final order revising its OATT and other document(s) subject to the Commission's jurisdiction as necessary to demonstrate that it meets the interregional transmission coordination requirements adopted in this final order. 13. We recognize that transmission providers have ongoing efforts to address transmission planning and cost allocation. This final order is not intended to interfere with the potential progress represented by those efforts, and we encourage transmission providers to continue to innovate to improve their transmission planning and cost allocation processes. A. Historical Framework: Order Nos. 888, 890, and 1000 14. Over the last several decades, the Commission has taken multiple significant actions on transmission planning and cost allocation, including issuing Order Nos. 888, 890, and 1000. In 1996, the Commission issued Order No. 888, which implemented open access to transmission facilities owned, operated, or controlled by a public utility and included certain minimum requirements for transmission planning. In 2007, the Commission issued Order No. 890 to address identified deficiencies in the pro forma OATT after more than 10 years of experience since Order No. 888. Among other OATT reforms, the Commission required all public utility transmission providers' local transmission planning processes to satisfy nine transmission planning principles: (1) coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; (7) regional participation; (8) economic planning studies; and (9) cost allocation for new projects. 10 10 Order No. 890, 118 FERC ¶ 61,119 at PP 418-601. 15. In 2011, the Commission recognized the need for further transmission planning reforms with its issuance of Order No. 1000. The Commission based the reforms it adopted in Order No. 1000 on changes in the energy industry, its experience implementing Order No. 890, and a robust record developed through technical conferences and comments from a diverse range of stakeholders. 11 The Commission stated in Order No. 1000 that “the electric industry is currently facing the possibility of substantial investment in future transmission facilities to meet the challenge of maintaining reliable service at a reasonable cost.” 12 In establishing the requirements of Order No. 1000, the Commission found that the existing requirements of Order No. 890 were not adequate, noting that Order No. 1000 “expands upon the reforms begun in Order No. 890 by addressing new concerns that have become apparent in the Commission's ongoing monitoring of these matters.” 13 The Commission then enumerated multiple concerns that it had regarding existing transmission planning practices, including concerns about: (1) the lack of an affirmative obligation to develop a transmission plan evaluating if a regional transmission facility “may be more efficient or cost-effective than solutions identified in local transmission planning processes”; (2) the lack of a requirement to address Public Policy Requirements; 14 (3) the Federal right of first refusal for incumbent transmission developers to build upgrades to their existing transmission facilities; (4) the lack of procedures to identify and evaluate the benefits of interregional transmission facilities; and (5) cost allocation for regional and interregional transmission facilities. 15 11 For purposes of this final order, and consistent with Order No. 1000, a stakeholder includes any party interested in the transmission planning processes. See Order No. 1000, 136 FERC ¶ 61,051 at P 151 n.143. 12 Id. P 2. 13 Id. P 21. 14 Public Policy Requirements are requirements established by local, state, or Federal laws or regulations ( i.e., enacted statutes passed by the legislature and signed by the executive and regulations promulgated by a relevant jurisdiction, whether within a state or at the Federal level). Id. P 2. Order No. 1000-A clarified that Public Policy Requirements include local laws or regulations passed by a local governmental entity, such as a municipal or county government. Order No. 1000-A, 139 FERC ¶ 61,132 at P 319. 15 Order No. 1000, 136 FERC ¶ 61,051 at P 3. 16. Order No. 1000 included reforms intended to ensure that the transmission planning and cost allocation requirements embodied in the pro forma OATT could support the development of more efficient or cost-effective transmission facilities. 16 The reforms in Order No. 1000 included: (1) regional transmission planning; (2) transmission needs driven by Public Policy Requirements; (3) nonincumbent transmission developer reforms; (4) regional and interregional cost allocation, including a set of principles for each category of cost allocation; and (5) interregional transmission coordination. The reforms focused on the process by which transmission providers engage in regional transmission planning and the associated cost allocation rather than on the outcomes of the process. 17 16 Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ¶ 61,132 at PP 3, 4-6. 17 Order No. 1000, 136 FERC ¶ 61,051 at P 12. 17. Among other regional transmission planning reforms in Order No. 1000, the Commission required that the following Order No. 890 transmission planning principles apply to regional transmission planning processes: (1) coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; and (7) economic planning studies. 18 18 The Commission did not include the regional participation or cost allocation transmission planning principles with respect to regional transmission planning processes because those issues were addressed by other reforms in Order No. 1000. Id. P 151. 18. In addition, with respect to the Order No. 1000 reforms, the Commission made a distinction between a transmission facility “included” in a regional transmission plan and a transmission facility “selected.” A transmission facility selected in a regional transmission plan for purposes of cost allocation is a transmission facility that has been selected pursuant to a transmission planning region's Commission-approved regional transmission planning process for inclusion in a regional transmission plan for purposes of cost allocation because it is a more efficient or cost-effective transmission facility needed to meet regional transmission needs. Both regional transmission facilities and interregional transmission facilities are eligible for potential “selection” in a regional transmission plan for purposes of cost allocation. 19 19 Id. P 63. A regional transmission facility and an interregional transmission facility are defined below. Infra Use of Terms section. 19. Selected transmission facilities often will not comprise all of the transmission facilities that are included in a regional transmission plan. 20 Some transmission facilities are merely “rolled up” and listed in a regional transmission plan without going through an analysis at the regional level, and/or are merely considered for reliability implications upon a transmission system, and therefore, are not eligible for selection and regional cost allocation. 21 For example, a local transmission facility is a transmission facility located solely within a transmission provider's retail distribution service territory or footprint that is not selected. 22 Thus, a local transmission facility may be rolled up and “included” in a regional transmission plan for informational purposes, but it is not “selected.” 20 Order No. 1000, 136 FERC ¶ 61,051 at P 63. 21 Id. PP 7, 226, 318. 22 Id. P 63. The Commission clarified in Order No. 1000-A that a local transmission facility is one that is located within the geographical boundaries of a public utility transmission provider's retail distribution service territory, if it has one; otherwise, the area is defined by the public utility transmission provider's footprint. In the case of an RTO/ISO whose footprint covers the entire region, a local transmission facility is defined by reference to the retail distribution service territories or footprints of its underlying transmission owing members. Order No. 1000-A, 139 FERC ¶ 61,132 at P 429. B. ANOPR and Technical Conference 20. In July 2021, the Commission issued the ANOPR 23 presenting potential reforms to improve the regional transmission planning and cost allocation and generator interconnection processes. In issuing the ANOPR, the Commission noted that, in part because more than a decade had passed since Order No. 1000, it was now an appropriate time to review its regulations governing regional transmission planning and cost allocation to determine whether reforms are needed to ensure Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. 24 The Commission noted that the electricity sector is transforming as the generation fleet shifts from resources located close to population centers toward resources that may often be located far from load centers. The Commission also highlighted the growth of new resources seeking to interconnect to the transmission system and that the differing characteristics of those resources are creating new demands on the transmission system. The Commission explained that ensuring just and reasonable Commission-jurisdictional rates during these changes, while maintaining grid reliability, remains the Commission's priority in adopting requirements for the regional transmission planning and cost allocation and generator interconnection processes. As a result, the Commission issued the ANOPR to consider whether there should be changes in the regional transmission planning and cost allocation and generator interconnection processes and, if so, which changes are necessary to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential and that reliability is maintained. 23 ANOPR, 176 FERC ¶ 61,024. 24 Id. P 3. 21. On November 15, 2021, the Commission convened a staff-led technical conference (November 2021 Technical Conference or Technical Conference) to examine in detail issues and potential reforms related to regional transmission planning as described in the ANOPR. Specifically, the Technical Conference included three panels covering issues to consider in long-term scenarios, consideration of long-term scenarios in regional transmission planning processes, and identifying geographic zones with high renewable resource potential for use in regional transmission planning processes. 25 Following the Technical Conference, the Commission invited all interested persons to file comments to address issues raised during the Technical Conference. 25 Bldg. for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation & Generator Interconnection, Further Supplemental Notice of Technical Conference, Docket No. RM21-17-000 (issued Nov. 12, 2021) (attaching agenda). C. Joint Federal-State Task Force on Electric Transmission 22. On June 17, 2021, the Commission established a Joint Federal-State Task Force on Electric Transmission (Task Force) to formally explore broad categories of transmission-related topics. 26 The Commission explained that the development of new transmission infrastructure implicates a host of different issues, including how to plan and pay for these facilities. Given that Federal and state regulators each have authority over transmission-related issues and given the impact of transmission infrastructure development on numerous different priorities of Federal and state regulators, the Commission determined that the topic was ripe for greater Federal-state coordination and cooperation. 27 The Task Force was composed of all sitting FERC Commissioners as well as representatives from 10 state commissions nominated by the National Association of Regulatory Utility Commissioners (NARUC), with two originating from each NARUC region. 28 26 Joint Fed.-State Task Force on Elec. Transmission, 175 FERC ¶ 61,224, at PP 1, 6 (2021). 27 Id. P 2. 28 An up-to-date list of Task Force members, as well as additional information on the Task Force, is available on the Commission's website at: 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. 29 The February 2022 meeting included discussion of specific categories and types of transmission benefits that transmission providers should consider for the purposes of transmission planning and cost allocation. 30 The May 2022 meeting focused on barriers to the efficient, expeditious, and reliable interconnection of new resources. 31 The July 2022 meeting focused on interregional transmission planning and transmission project development and the NOPR. 32 The November 2022 meeting focused on regulatory gaps and challenges in oversight of transmission development. 33 The February 2023 meeting focused on the physical security of the Nation's transmission system, and featured guest speakers from the North American Electric Reliability Corporation and US DOE. 34 The July 2023 meeting focused on grid enhancing technologies, featuring a guest speaker from the Electric Power Research Institute. 35 The February 2024 meeting focused on transmission siting, featuring guest speakers from US DOE. 36 29 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching agenda). 30 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching agenda). 31 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022) (attaching agenda). 32 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued June 30, 2022) (attaching agenda). 33 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Nov. 1, 2022) (attaching agenda). 34 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Feb. 1, 2023) (attaching agenda). 35 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued June 30, 2023) (attaching agenda). 36 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Feb. 13, 2024) (attaching agenda). 25. In light of the Task Force expiring three years from its first public meeting, i.e., on November 10, 2024, 37 on March 21, 2024, the Commission established the Federal and State Current Issues Collaborative (Collaborative). 38 The Collaborative will be comprised of all Commissioners, as well as representative from 10 state commissions. The Collaborative will provide a venue for Federal and state regulators to share perspectives, increase understanding, and where appropriate, identify potential solutions regarding challenges and coordination on matters that impact specific state and Federal regulatory jurisdiction. 39 37 Joint Fed.-State Task Force on Elec. Transmission, 175 FERC ¶ 61,224 at P 4. 38 Joint Fed.-State Task Force on Elec. Transmission, 186 FERC ¶ 61,189 (2024). 39 Id. PP 5-6. D. Notice of Proposed Rulemaking 26. On April 21, 2022, the Commission issued the NOPR, proposing reforms focused on long-term regional transmission planning and cost allocation processes. In particular, the Commission proposed in the NOPR that transmission providers in each transmission planning region participate in a regional transmission planning process that includes Long-Term Regional Transmission Planning. 40 The Commission also proposed to require that transmission providers develop Long-Term Scenarios as part of Long-Term Regional Transmission Planning. 41 40 NOPR, 179 FERC ¶ 61,028 at PP 64, 68. 41 Id. P 84. 27. The Commission proposed that transmission providers consider, as part of their Long-Term Regional Transmission Planning, regional transmission facilities that address certain interconnection-related transmission needs that the transmission provider has identified multiple times in the generator interconnection process but that have never been constructed due to the withdrawal of the relevant interconnection request(s). 42 42 Id. P 166. 28. The Commission proposed 12 benefits that transmission providers may consider in Long-Term Regional Transmission Planning and cost allocation processes. 43 The Commission stated that the list of potential benefits was neither mandatory nor exhaustive, and that pursuant to the proposal, transmission providers would have flexibility to propose which benefits to use as part of their Long-Term Regional Transmission Planning. 44 43 Id. P 185. 44 Id. P 184. 29. The Commission proposed, with regard to the selection of Long-Term Regional Transmission Facilities in the regional transmission plan for purposes of cost allocation, to require that transmission providers, as part of their Long-Term Regional Transmission Planning, include in their OATTs: (1) transparent and not unduly discriminatory criteria, which seek to maximize benefits to consumers over time without over-building transmission facilities, to identify and evaluate transmission facilities for potential selection that address transmission needs driven by changes in the resource mix and demand; and (2) a process to coordinate with the Relevant State Entities in developing such criteria. 45 45 Id. P 241. 30. The Commission proposed to require transmission providers to more fully consider the incorporation into transmission facilities of dynamic line ratings and advanced power flow control devices in regional transmission planning and cost allocation processes. 46 46 Id. P 272. 31. The Commission proposed to require, with regard to allocating the costs of Long-Term Regional Transmission Facilities, transmission providers to revise their OATTs to include: (1) a Long-Term Regional Transmission Cost Allocation Method to allocate the costs of Long-Term Regional Transmission Facilities; (2) a State Agreement Process by which one or more Relevant State Entities may voluntarily agree to a cost allocation method; or (3) a combination thereof. 47 The Commission proposed to require transmission providers to seek the agreement of Relevant State Entities within the transmission planning region regarding the Long-Term Regional Transmission Cost Allocation Method, State Agreement Process, or combination thereof. 48 The Commission proposed to require transmission providers to identify on compliance the benefits they will use in ex ante Long-Term Regional Transmission Cost Allocation Methods associated with Long-Term Regional Transmission Planning, how they will calculate those benefits, and how the benefits will reasonably reflect the benefits of regional transmission facilities to meet identified transmission needs driven by changes in the resource mix and demand. 49 47 Id. P 302. 48 Id. P 303. 49 Id. P 326. 32. The Commission further proposed to not permit transmission providers to take advantage of the allowance for inclusion of 100% of construction work in progress costs in rate base in certain circumstances for Long-Term Regional Transmission Facilities. 50 50 Id. P 333. 33. Finally, the Commission proposed to permit the exercise of Federal rights of first refusal for selected transmission facilities, conditioned on the incumbent transmission provider with the Federal right of first refusal for such regional transmission facilities establishing joint ownership of the transmission facilities consistent with certain proposed requirements described in the NOPR. 51 51 Id. P 351. 34. The Commission also proposed to require transmission providers to revise the regional transmission planning process in their OATTs with additional provisions to enhance transparency of: (1) the criteria, models, and assumptions that they use in their local transmission planning process; (2) the local transmission needs that they identify through that process; and (3) the potential local or regional transmission facilities that they will evaluate to address those local transmission needs. 52 The Commission proposed to require transmission providers to evaluate whether transmission facilities operating at or above 230 kV that an individual transmission provider that owns the transmission facility anticipates replacing in-kind with a new transmission facility during the next 10 years can be “right-sized” to more efficiently or cost-effectively address regional transmission needs identified in Long-Term Regional Transmission Planning. 53 52 Id. P 400. 53 Id. P 403. 35. The Commission further proposed to require transmission providers in neighboring transmission planning regions to revise their existing interregional transmission coordination procedures (and regional transmission planning processes as needed) to provide for: (1) the sharing of information regarding their respective transmission needs identified in Long-Term Regional Transmission Planning, as well as potential transmission facilities to meet those needs; and (2) the identification and joint evaluation of interregional transmission facilities that may be more efficient or cost-effective transmission facilities to address transmission needs identified through Long-Term Regional Transmission Planning. 54 Finally, the Commission proposed to require transmission providers in neighboring transmission planning regions to revise their interregional transmission coordination procedures (and regional transmission planning processes as needed) to allow an entity to propose an interregional transmission facility in the regional transmission planning process as a potential solution to transmission needs identified through Long-Term Regional Transmission Planning. 55 54 Id. P 427. 55 Id. P 428. E. High-Level Overview of NOPR Comments 36. The Commission received a great many comments from a diverse set of parties in response to the NOPR. 56 One hundred and ninety-six parties, including Federal agencies, state regulatory commissions, state policy makers and other state representatives, ratepayer advocates, municipalities, RTOs/ISOs, RTO/ISO market monitors, transmission providers, transmission-dependent utilities, electric cooperatives, municipal power providers, independent power producers, transmission developers, generation trade associations, transmission trade associations, industry interest groups, consumer interest groups, energy policy and law interest groups, individual businesses, landowners, and individuals, filed initial comments that totaled over 15,000 pages with attachments. A similarly diverse set of 92 parties filed reply comments that totaled nearly 1,900 pages. 56 See appendix A for a list of commenters and the abbreviated names of commenters that are used in this final order. F. Use of Terms 37. Before turning to the detailed requirements of this final order, we note several of the key terms used herein. We further address the definitions of these terms, including any modifications to definitions proposed in the NOPR, in the relevant later sections of this final order. 38. For purposes of this final order, Long-Term Regional Transmission Planning means regional transmission planning on a sufficiently long-term, forward-looking, and comprehensive basis to identify Long-Term Transmission Needs, identify transmission facilities that meet such needs, measure the benefits of those transmission facilities, and evaluate those transmission facilities for potential selection in the regional transmission plan for purposes of cost allocation as the more efficient or cost-effective regional transmission facilities to meet Long-Term Transmission Needs. 39. For purposes of this final order, Long-Term Transmission Needs are transmission needs identified through Long-Term Regional Transmission Planning by, among other things and as discussed in this final order, running scenarios and considering the enumerated categories of factors. 57 57 Further discussion on Long-Term Transmission Needs can be found below. Infra Development of Long-Term Scenarios subsection under the Long-Term Regional Transmission Planning section. 40. For purposes of this final order, Long-Term Scenarios are scenarios that incorporate various assumptions using best available data inputs about the future electric power system over a sufficiently long-term, forward-looking transmission planning horizon to identify Long-Term Transmission Needs and enable the identification and evaluation of transmission facilities to meet such transmission needs. 41. For purposes of this final order, a Long-Term Regional Transmission Facility is a regional transmission facility 58 that is identified as part of Long-Term Regional Transmission Planning to address Long-Term Transmission Needs. 58 For purposes of this final order, and consistent with Order No. 1000, a regional transmission facility is a transmission facility located entirely in one transmission planning region. An interregional transmission facility is a transmission facility that is located in two or more transmission planning regions. A local transmission facility is a transmission facility located solely within a transmission provider's retail distribution service territory or footprint that is not selected in the regional transmission plan for purposes of cost allocation. Order No. 1000, 136 FERC ¶ 61,051 at PP 63, 482 n.374. 42. For purposes of this final order, best available data inputs are data inputs that are timely, developed using best practices and diverse and expert perspectives, and adopted via a process that satisfies the transmission planning principles of Order Nos. 890 and 1000, and reflect the list of factors that transmission providers account for in their Long-Term Scenarios. 43. For purposes of this final order, a Long-Term Regional Transmission Cost Allocation Method is an ex ante regional cost allocation method for one or more selected Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) that are selected in the regional transmission plan for purposes of cost allocation. 44. For purposes of this final order, a Relevant State Entity is any state entity responsible for electric utility regulation or siting electric transmission facilities within the state or portion of a state located in the transmission planning region, including any state entity as may be designated for that purpose by the law of such state. 45. For purposes of this final order, a State Agreement Process is a process by which one or more Relevant State Entities may voluntarily agree to a cost allocation method for Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) before or no later than six months after they are selected. 46. For purposes of this final order, federally-recognized Tribes are those Tribes listed in the most recent notice provided by the Bureau of Indian Affairs and published in the Federal Register . 59 59 See, e.g., Indian Entities Recognized by and Eligible to Receive Servs. from the U.S. Bureau of Indian Affairs, Federal Register , 89 FR 944 (Jan. 8, 2024). II. The Overall Need for Reform A. NOPR Proposal 47. The Commission issued the NOPR on April 21, 2022, proposing to reform the pro forma OATT and the pro forma LGIA to remedy deficiencies in the Commission's existing regional transmission planning and cost allocation requirements. The Commission stated that, over the last 25 years, it has undertaken a series of significant reforms to ensure that transmission planning and cost allocation processes result in Commission-jurisdictional rates that are just and reasonable and not unduly discriminatory or preferential. 60 The Commission noted that it has now been more than a decade since Order No. 1000—its last significant regional transmission planning and cost allocation rule—and that there is mounting evidence that its regional transmission planning and cost allocation requirements may be inadequate to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. 61 60 NOPR, 179 FERC ¶ 61,028 at P 24. 61 Id. 48. The Commission found that, in particular, although transmission providers are required to participate in regional transmission planning and cost allocation processes under Order No. 1000, it was concerned that those processes may not be planning transmission on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand. The Commission stated that, as a result, the regional transmission planning and cost allocation processes that transmission providers adopted to comply with Order No. 1000 may not be identifying the more efficient or cost-effective transmission facilities. 62 The Commission stated that it was concerned that the absence of sufficiently long-term, forward-looking, comprehensive transmission planning processes appears to be resulting in piecemeal transmission expansion to address relatively near-term transmission needs, and that continuing with the status quo approach may cause transmission providers to undertake relatively inefficient investments in transmission infrastructure, the costs of which are ultimately recovered through Commission-jurisdictional rates. The Commission stated that this dynamic may result in transmission customers paying more than necessary to meet their transmission needs, customers forgoing benefits that outweigh their costs, or some combination thereof—either or both of which could potentially render Commission-jurisdictional rates unjust and unreasonable or unduly discriminatory or preferential. Based on the evidence, the Commission preliminarily concluded that revisions to its existing transmission planning and cost allocation requirements established in Order Nos. 890 and 1000 are necessary to ensure that Commission-jurisdictional services are provided at rates, terms, and conditions that are just and reasonable and not unduly discriminatory and preferential. 63 62 Id. PP 24-25. 63 Id. PP 25, 27, 34-35. B. Comments 49. A significant majority of commenters, including transmission providers, transmission developers, transmission customers, members of Congress, states, state commissions, consumer advocates, trade associations, and public interest organizations, among others, agree that existing regional transmission planning and cost allocation processes need to be reformed. 64 Advanced Energy Buyers note that the electric system is presently undergoing one of the most significant transformations in a century. 65 Other commenters agree that electric energy supply and demand is evolving quickly. 66 Clean Energy Buyers agree with the Commission that there is a need for reform to meet these drastic changes in the resource mix and load and to ensure continued reliability and cost-effective transmission service. 67 64 See, e.g., Acadia Center and CLF Initial Comments at 1-2; ACEG Initial Comments at 11-12, 21-22; ACORE Initial Comments at 2-5; ACORE Supplemental Comments at 1; Advanced Energy Buyers Initial Comments at 2-3; AEE Initial Comments at 7-8; AEP Initial Comments at 1-3; Amazon Initial Comments at 1-2; Ameren Initial Comments at 1-2; American Municipal Power Initial Comments at 4; Anbaric Initial Comments at 1; Arizona Commission Initial Comments at 3-4; Avangrid Initial Comments at 5-6; BP Initial Comments at 3; Breakthrough Energy Initial Comments at 5-6; Breakthrough Energy Supplemental Comments at 1; Business Council for Sustainable Energy Initial Comments at 2-3; California Commission Initial Comments at 1-2; California Energy Commission Initial Comments at 1; CAISO Initial Comments at 1; City of New Orleans Council Initial Comments at 4, 7-9; Cross Sector Representatives Supplemental Comments at 1; DC and MD Offices of People's Counsel Initial Comments at 4-5; US Senators Supplemental Comments at 1; EEI Initial Comments at 4-5; ELCON Initial Comments at 4; Enel Initial Comments at 2, 7; ENGIE Initial Comments at 1-2; Entergy Initial Comments at 2-3; Environmental Legislators Caucus Supplemental Comments at 1; Evergreen Action Initial Comments at 1-3; Eversource Initial Comments at 1-2, 5-9; Exelon Initial Comments at 1-2; Grid United Initial Comments at 1-2; Handy Law Initial Comments at 1-7; Harvard ELI Initial Comments at 1; Illinois Commission Initial Comments at 3; Indicted PJM TOs Initial Comments at 1-2; Indicated US Senators and Representatives Initial Comments at 1; Interwest Initial Comments at 2-3; Invenergy Initial Comments at 2, 5; ISO-NE Initial Comments at 2, 8-9; ISO/RTO Council Initial Comments at 2; Kansas Commission Initial Comments at 10-11; Massachusetts Attorney General Initial Comments at 3-6; Michigan Commission Initial Comments at 2, 4; Michigan State Entities Initial Comments at 3-4; Minnesota State Entities Initial Comments at 2-3; National Grid Initial Comments at 1, 6; National and State Conservation Organizations Initial Comments at 1; NESCOE Initial Comments at 2, 7, 14-15; New Jersey Commission Initial Comments at 1-2; New York Commission and NYSERDA Initial Comments at 1-3; NextEra Reply Comments at 1; Non-RTO NASUCA Initial Comments at 4-5; NYISO Initial Comments at 2-3; Onward Energy Initial Comments at 1-2; 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. 65 Advanced Energy Buyers Initial Comments at 2. 66 See, e.g., AEE Initial Comments at 1; Cross Sector Representatives Supplemental Comments at 1; Eversource Initial Comments at 5-8 (citing ISO-NE, 2020 Regional Electricity Outlook, at 35 (2020)); Indicated PJM TOs Initial Comments at 1-2; Kansas Commission Initial Comments at 2; Pattern Energy Initial Comments at 1; PG&E Initial Comments at 1; Policy Integrity Initial Comments at 2; Renewable Northwest Initial Comments at 5; State Agencies Initial Comments at 12-13; WIRES Initial Comments at 3. 67 Clean Energy Buyers Initial Comments at 7. 50. Many commenters argue that current regional transmission planning and cost allocation processes across the country are not ensuring efficient and cost-effective transmission development, are not satisfying the purposes of Order Nos. 890 and 1000, and are not meeting transmission needs at a reasonable cost. For example, several commenters assert that Order Nos. 890 and 1000 have not solved longstanding problems with regional transmission planning and cost allocation. 68 Northwest and Intermountain claim that Order No. 1000 has been inadequate to meet transmission needs, particularly in the non-RTO/ISO West. 69 Michigan State Entities assert that the current lack of long-term transmission planning has led to significantly higher costs for residential ratepayers, costs that will increase without reforms. 70 SREA argues that reform is needed to correct the unintended consequences of Order No. 1000 in the Southeast, where transmission planning “has grown into an enormously elaborate and extremely expensive black box,” without any meaningful review by state regulatory bodies. 71 68 See, e.g., Acadia Center and CLF Initial Comments at 1; ACEG Initial Comments at 17-18, 20 (citing Order No. 1000, 136 FERC ¶ 61,051 at P 3; NOPR, 179 FERC ¶ 61,028 at PP 24-25); AEE Initial Comments at 1-2; CARE Coalition Initial Comments at 3; NERC Initial Comments at 5; Massachusetts Attorney General Initial Comments at 5-6; Northwest and Intermountain Initial Comments at 6-7; Pine Gate Initial Comments at 8-10; PIOs Initial Comments at 2-3; Southeast PIOs Initial Comments at 7-9, 11, 16-17, 43-44; SPP Market Monitor Initial Comments at 3-4; SREA Reply Comments at 4; US DOE Initial Comments at 3-4, 7-8. 69 Northwest and Intermountain Initial Comments at 6-7. 70 Michigan State Entities Initial Comments at 1-2. 71 SREA Reply Comments at 4. 51. PIOs assert that transmission owners can evade Order No. 1000 requirements through investments in local transmission projects, which has led to billions of dollars in excessive costs. 72 PIOs explain that financial incentives drive utilities to upgrade their own systems at the expense of building a more integrated and robust transmission system to meet the needs and demands of the future. 73 PIOs observe that, between 2013 and 2017, about one-half of the approximately $70 billion in aggregate transmission investments by Commission-jurisdictional transmission owners in RTO/ISO regions were approved outside of regional transmission planning processes or with limited stakeholder engagement. 74 Ohio Consumers add that since 2017, less than 25% of new transmission investments in Ohio have been associated with large regional transmission projects needed for reliability or economic efficiency. 75 Competition Coalition argues that incumbent transmission owners have used reliability designations to justify projects with higher costs. 76 72 PIOs Initial Comments at 8 (citing Johannes P. Pfeifenberger et al., The Brattle Group, Cost Savings Offered by Competition in Electric Transmission: Experience to Date and the Potential for Additional Customer Value, at 19-20, and Section I (Apr. 2019) (Brattle Apr. 2019 Competition Report), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf ). 73 Id. at 6-7. 74 Id. at 9 (citing Brattle Apr. 2019 Competition Report at 4). 75 Ohio Consumers Initial Comments at 5. 76 Competition Coalition Initial Comments at 15-16. 52. Citing to a report from Lawrence Berkeley National Laboratory, US DOE concludes that many existing regional transmission planning approaches are likely understating the economic value of new transmission. US DOE suggests that the need for increased transmission capacity to address persistent and worsening transmission congestion demonstrates that these processes may not fully anticipate present and future transmission needs. 77 In addition, US DOE notes the unfair burden on interconnection customers that must bear increasing costs, especially for interconnection-related network upgrades that provide system-wide benefits. 78 US DOJ and FTC agree that reforms are necessary to encourage needed regional and interregional transmission investment and that a larger, more integrated transmission system would improve resilience, promote competition, and lower costs for consumers. 79 77 US DOE Initial Comments at 3-4. 78 Id. at 7-8. 79 US DOJ and FTC Initial Comments at 1, 5 (citing NOPR, 179 FERC ¶ 61,028 at P 6; P. R. Brown & A. Botterud, The Value of Inter-Regional Coordination and Transmission in Decarbonizing the US Electricity System, 5 Joule 115, 115-134 (2021); Eric Larson et al., Princeton Univ., Net-Zero America: Potential Pathways, Infrastructure, and Impacts, at 108 (Oct. 2021), 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. 80 Michigan State Entities cite renewable energy curtailments, which limit the supply of energy that customers can access, and the lack of regional and interregional transmission lines, which limit the transfer of lower-priced power. 81 New Jersey Commission asserts that better transmission planning can reduce overall system costs by billions of dollars. 82 Certain TDUs add that Commission action is essential now to ensure that necessary transmission expansion occurs in a way that protects customers from excessive costs and that results in just and reasonable transmission rates. 83 CARE Coalition argues that the Commission's current failure to require transmission planners to internalize siting-related costs and risks results in unjust, unreasonable, and unduly discriminatory or preferential rates. 84 In a similar vein, 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. 85 80 See, e.g., ACORE Initial Comments at 3, AEE Initial Comments at 27 (citing NOPR, 179 FERC ¶ 61,028 at PP 47, 55, 78; S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56); CARE Coalition Initial Comments at 17; Certain TDUs Initial Comments at 2; Clean Energy Associations Initial Comments at 3, 7; Clean Energy Buyers Initial Comments at 10; Harvard ELI Initial Comments at 1; Massachusetts Attorney General Initial Comments at 5-6; New Jersey Commission Initial Comments at 1-2; PIOs Initial Comments at 6; SEIA Initial Comments at 2-3; Southeast PIOs Reply Comments at 2; US DOE Initial Comments at 2, 6-7. 81 Michigan State Entities Initial Comments at 3. 82 New Jersey Commission Initial Comments at 3-9. 83 Certain TDUs Initial Comments at 2. 84 CARE Coalition Initial Comments at 17. 85 Massachusetts Attorney General Initial Comments at 5; 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. 86 AEE agrees that limited development of regional transmission facilities, increased spending on local transmission projects, and backlogged interconnection queues all show that the existing regional transmission planning requirements are not sufficient to meet customers' transmission needs. 87 Likewise, Exelon argues that relying on interconnection studies as the primary transmission planning method results in piecemeal and inefficient transmission investment. 88 PIOs add that many generation developers have to bear the full costs of transmission upgrades, which leads to interconnection request withdrawals, inefficiencies, and higher system-wide costs. 89 In addition, Clean Energy States note that interconnection queues are extremely large and that the current one-plant-at-a-time approach to transmission upgrades drives up costs and misses opportunities for improvements to the system as a whole. 90 86 See, e.g., Acadia Center and CLF Initial Comments at 3-4; Anbaric Initial Comments at 5; Clean Energy Associations Initial Comments at 4-7; Exelon Initial Comments at 1-2, 5; Joint Consumer Advocates Initial Comments at 5; Non-RTO NASUCA Initial Comments at 4; 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. 87 AEE Initial Comments at 1-2 (citing NOPR, 179 FERC ¶ 61,028 at PP 47-55). 88 Exelon Initial Comments at 5. 89 PIOs Initial Comments at 9-10. 90 Clean Energy States Initial Comments at 2. 55. Non-RTO NASUCA agrees with the Commission that Long-Term Regional Transmission Planning is necessary to help alleviate generation interconnection issues. 91 According to Harvard ELI, current transmission planning processes have failed to address backlogged interconnection queues and operational challenges that are best addressed at the regional level, as well as to include inexpensive technologies that can increase transmission capacity. 92 91 Non-RTO NASUCA Initial Comments at 4. 92 Harvard ELI Initial Comments at 1. 56. ACEG argues that there is no evidence that any regional reliability or economic transmission planning performed in non-RTO/ISO regions, like the Southeastern Regional Transmission Planning region (SERTP), is equal to or superior to the techniques or outcomes in the NOPR. 93 ACEG further contends that, instead, most new transmission facilities built since Order No. 1000 have been built for local transmission needs, thereby resulting in less efficient and cost-effective transmission development that does not address the larger needs of the transmission system for reliability and resilience. 94 Relatedly, SREA states that no state fully participates in SERTP, and that instead, each state in the Southeast uses its own state planning process, with no platform for states to collaborate. As a result, SREA argues that “transmission planning in the Southeast has many holes and is threadbare.” 95 SREA catalogs deficiencies in many Southeastern states' planning processes, including a lack of transparency. 96 93 ACEG Reply Comments at 9 (citing Alabama Commission Initial Comments at 2-3; Southern Initial Comments at 5-6, Ex. 2 at 2-3). 94 Id. at 9-10 (citing PIOs Initial Comments at 7). 95 SREA Reply Comments at 4. 96 Id. at 5-18. 57. Western PIOs argue that, outside of CAISO, transmission planning in the West is ineffective. 97 Specifically, Western PIOs assert that Western transmission planning groups have not developed new transmission projects using their Order No. 1000 transmission planning processes, but have instead built transmission projects that their utility members have already proposed. 98 Relatedly, SEIA argues that “non-RTO areas do not engage in sufficient or transparent transmission planning,” and that transmission planning in non-RTO/ISO regions is exclusionary, based on inconsistent and inaccurate data, and disjointed. 99 More broadly, NRECA contends that incumbent investor-owned utilities control transmission planning, and that some incumbent investor-owned utilities develop transmission without transparency, leading to disparities in transmission rates in different RTO/ISO local zones. 100 97 Western PIOs Initial Comments at 4-28. 98 Id. at 28. 99 SEIA Reply Comments at 5-6 (citing Southern Initial Comments at 13-14). 100 NRECA Initial Comments at 15-16. 58. Several commenters specify other reasons that transmission planning reforms are needed. 101 Americans for Fair Energy Prices agree with PIOs that there is a need for regional transmission planning instead of the balkanized process that currently exists. 102 DC and MD Offices of People's Counsel assert that the NOPR provides a once-in-a-generation opportunity to meet the energy transition in a just, equitable, efficient, reliable, and resilient fashion by recognizing the benefits of long-term transmission planning and developing rules that incorporate those broad benefits. DC and MD Offices of People's Counsel state that current transmission planning processes do not fully consider all of the benefits of transmission development, including enhanced reliability and resilience that will serve as a necessary bulwark against disruptions caused by extreme weather. 103 ACEG argues that current transmission planning processes have not led to investment in interregional transmission capacity, and that more interregional transmission capacity could have avoided some of the $25 billion to $70 billion in yearly costs caused by severe weather events. 104 EEI states that robust transmission development will provide a host of benefits for customers, including greater resilience, enhanced system reliability, and cost-savings from greater access to low-cost resources. 105 Some commenters emphasize the importance of the Commission taking prudent action to remedy deficiencies in the Commission's existing regional transmission planning and cost 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. v. FERC, 957 F.3d 932, 942 (8th Cir. 2020)). 111 Grand Rapids NAACP Reply Comments at 4 (citing 16 U.S.C. 824(a); Re Nat'l Ass'n for the Advancement of Colored People, Inc., 95 P.U.R.3d 357 (F.P.C. 1972), vacated and remanded sub nom. NAACP v. FPC, 520 F.2d 432 (D.C. Cir. 1975), aff'd, 425 U.S. 662 (1976)); CARE Coalition Initial Comments at 2; PIOs Reply Comments at 14. 112 Id. at 20-21. 113 Id. at 17-19. 114 WE ACT Initial Comments at 1-2. 60. Advanced Energy Buyers state that failure to prepare the grid for the energy transition would be problematic for three primary reasons: (1) insufficient transmission investment will leave customer cost savings on the table; (2) lack of available transmission capacity will constrain its members' ability to meet decarbonization and clean energy goals; and (3) failure to plan and build adequate transmission will hamper the transition to a cleaner and more reliable electric grid. 115 New Jersey Commission contends that the lack of holistic multi-driver transmission planning is inflating consumers' electricity costs by billions of dollars every year. 116 Northwest and Intermountain explain that due to insufficient transmission capacity from renewable rich zones, utilities must attempt to meet their renewable energy policy targets with new resources that are close to load but more expensive, less reliable, and less efficient than more distant alternatives, even considering the potential costs of transmission expansion. 117 Clean Energy Associations add that the lack of transmission capacity imposes real and demonstrable costs today, as evidenced by geographic differences in real-time power prices, and that the lack of robust and proactive transmission planning rules renders current rates unjust, unreasonable, and unduly discriminatory or preferential. 118 115 Advanced Energy Buyers Initial Comments at 3. 116 New Jersey Commission Initial Comments at 2-9. 117 Northwest and Intermountain Initial Comments at 6. 118 Clean Energy Associations Initial Comments at 5 (citing Dev Millstein et al., Lawrence Berkeley National Laboratory, Empirical Estimates of Transmission Value Using Locational Marginal Prices, at 3 (Aug. 2022), 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 v. FERC. 133 PIOs contend that the Commission is required by the FPA to use its authority to address market abuses and undue discrimination that have led to unjust, unreasonable, and unduly discriminatory or preferential rates for consumers, who bear the costs of inefficiencies in the current transmission planning process. 134 132 See, e.g., ACEG Initial Comments at 11; Clean Energy Associations Initial Comments at 7-10; Grand Rapids NAACP Initial Comments at 17; Massachusetts Attorney General Initial Comments at 3-4; Pine Gate Initial Comments at 10-14; PIOs Initial Comments at 8. 133 762 F.3d at 57. See also ACEG Initial Comments at 13-14; Harvard ELI Initial Comments at 1-2; SEIA Initial Comments at 3. 134 PIOs Initial Comments at 8. 66. Southeast PIOs assert that the NOPR adequately demonstrated that existing regional transmission planning processes have intrinsic flaws, making the integrated resource planning and request for proposal processes ill-equipped to efficiently address changes in the resource mix and demand. 135 Specifically, Southeast PIOs cite the following preliminary findings from the NOPR: (1) existing transmission planning processes utilize a limited planning horizon; (2) many transmission planning processes provide an inaccurate portrayal of the comparative benefits of different transmission facilities; and (3) rapid changes to the generation fleet and demand are creating increasingly urgent transmission needs. 136 135 Southeast PIOs Reply Comments at 4 (citing Duke Initial Comments at 6-9; SERTP Sponsors Initial Comments at 31-36; Southern Initial Comments at 36-40). 136 Id. at 5-6 (citing NOPR, 179 FERC ¶ 61,028 at PP 45, 47, 49, 53). 67. Southeast PIOs cite the finding in South Carolina Public Service Authority v. FERC that the threshold of substantial evidence could be met without “empirical evidence” as long as the Commission provides evidence based on “reasonable economic propositions.” 137 Southeast PIOs also note that South Carolina Public Service Authority v. FERC upheld the Commission's findings in Order No. 1000, which were based on (1) a threat to just and reasonable rates from existing regional transmission planning and cost allocation practices, (2) significant changes in the industry driven by increases in renewable energy resources, and (3) recent increases in transmission investment. 138 Moreover, Southeast PIOs note that findings need not be region-specific, as the “Commission may rely on generic or general findings of a systemic problem to support imposition of an industry-wide solution.” 139 137 Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65). 138 Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65-66). 139 Id. at 7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67). 68. ACEG similarly asserts that the Commission has shown the need for transmission planning reform based on findings that existing transmission planning requirements do not adequately identify transmission needs driven by changes in the resource mix and demand, and that failure to identify such needs causes customers to pay for less efficient or cost-effective transmission investments. 140 Relatedly, ACEG argues that pursuing region-specific solutions will lead to siloed and disjunctive transmission planning policies that will not solve the problems facing the Nation's electric transmission system. 141 140 ACEG Reply Comments at 7-8 (citing Alabama Commission Initial Comments at 2-3; Duke Initial Comments at 6-9; Idaho Power Initial Comments at 2-3; NRECA Initial Comments at 11; North Carolina Commission and Staff Initial Comments at 14; Pacific Northwest Utilities Initial Comments at 9-10; Utah Commission Initial Comments at 9-12). 141 Id. at 17. 69. Colorado Consumer Advocate and Joint Consumer Advocates aver that the Commission has a statutory duty under the FPA to reform current regional transmission planning processes because they lack transparency, coordination, and openness, and because they create opportunities for monopoly transmission developers to exert dominant influence and promote their own economic self-interest at customers' and other stakeholders' expense. 142 According to New Jersey Commission, current transmission planning processes are inefficient and unnecessarily burden ratepayers with excessive costs without providing additional benefits. New Jersey Commission contends that those processes are therefore per se unjust and unreasonable, and that the Commission thus has FPA section 206 authority to require that transmission providers employ practices like long-term, holistic, multi-driver transmission planning. 143 142 Colorado Consumer Advocate Initial Comments at 21-23; Joint Consumer Advocates Initial Comments at 18-20. 143 New Jersey Commission Initial Comments at 3-4. 70. Similarly, Harvard ELI states that deficient transmission planning threatens the justness and reasonableness of transmission rates, and therefore the Commission has legal authority and jurisdiction to order changes to transmission planning to remedy that deficiency. 144 Harvard ELI further asserts that the Commission must remedy undue discrimination due to incumbent transmission owners' unduly discriminatory influence in regional transmission planning. 145 Massachusetts Attorney General also argues that the Commission's proposed reforms are necessary to fulfill the Commission's statutory obligation to ensure that transmission rates are just and reasonable. 146 144 Harvard ELI Initial Comments at 1-2 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41; Order No.1000-A, 139 FERC ¶ 61,132 at PP 56-75). 145 Id. at 3. 146 Massachusetts Attorney General Initial Comments at 3-6. 71. Some commenters argue that there is insufficient evidence for the Commission to find that existing jurisdictional rates are unjust, unreasonable, and unduly discriminatory or preferential. 147 For example, while Idaho Commission recognizes that there are deficiencies in existing transmission planning and cost allocation processes, Idaho Commission disagrees with the NOPR's claim that their failure to identify and plan for transmission needs driven by changes in the resource mix and demand is resulting in unjust, unreasonable, and unduly discriminatory or preferential Commission-jurisdictional rates. 148 Mississippi Commission also disagrees that the lack of long-term regional transmission planning will result in unjust, unreasonable, and unduly discriminatory or preferential rates. 149 ELCON questions a finding of unjust, unreasonable, and unduly discriminatory or preferential rates, and it states that the NOPR's focus on Long-Term Regional Transmission Planning solely to address changes in resource mix and demand, if adopted, could fail to produce better outcomes for customers and may exceed the Commission's authority under the FPA. 150 147 See, e.g., ELCON Initial Comments at 7; Idaho Commission Initial Comments at 2; Mississippi Commission Initial Comments at 2, 9; NRECA Initial Comments at 14-16; Undersigned States Reply Comments at 6-7. 148 Idaho Commission Initial Comments at 2 (citing NOPR, 179 FERC ¶ 61,028 at P 34). 149 Mississippi Commission Initial Comments at 2. 150 ELCON Initial Comments at 7. 72. Louisiana Commission states that the Commission's finding that, absent reforms, transmission rates universally are not just and reasonable and are discriminatory is not based on individual analysis of each RTO or region, is not supported, and should be retracted. 151 Mississippi Commission also states that the Commission should, instead, initiate region-specific investigations pursuant to FPA section 206. 152 Southern argues that the Commission has failed to satisfy the first prong of its FPA section 206 burden of proof, noting that the NOPR's preliminary conclusion, that existing regional transmission planning processes are not sufficient to address changes in the resource mix and demand, cannot reasonably be made of Southern or SERTP. 153 151 Louisiana Commission Reply Comments at 5-6. 152 Mississippi Commission Reply Comments at 7-9. 153 Southern Initial Comments at 40; Southern Reply Comments at 1-3. 73. Similarly, Industrial Customers argue that the Commission has not satisfied the first prong of FPA section 206, which requires the Commission to find, and provide substantial evidence supporting its finding, that existing rates are unjust, unreasonable, and unduly discriminatory or preferential. 154 Industrial Customers claim that demand growth should be the primary factor in identifying transmission needs, and that demand is growing more slowly than in previous periods. Industrial Customers add that, in contrast, investment in transmission is rising relative to demand, which is the opposite of the circumstances that prevailed in 2007 when the Commission issued Order No. 890. 155 According to Industrial Customers, changes in demand are not significant enough in historical terms to warrant major changes in transmission planning. Moreover, Industrial Customers state that changes in demand are unpredictable because technological changes are inherently difficult to forecast and the risks to consumers of making mistakes are too high. Industrial Customers argue that, if anything, the rapid growth of renewables indicates that current processes are already facilitating changes in the resource mix. 156 Similarly, NRG argues that long-term forecasts of important factors are often wrong, which has real-world impacts on customers. 157 154 Industrial Customers Initial Comments at 6-7. 155 Id. at 8-10. 156 Id. at 10-11. 157 NRG Initial Comments at 10-12 (noting, for example, that “[p]redictions for the future price of natural gas and thus the economics of gas generation in long-term forecasts have been notoriously inaccurate.” (citing Lawrence Berkeley National Laboratory, Comparison of AEO 2008 Natural Gas Price Forecast to NYMEX Futures Prices (Jan. 2008)). 74. Further, Industrial Customers contend that the NOPR does not clearly define the term “changes in the resource mix and demand,” despite using such changes as the justification for the proposals. Industrial Customers argue that transmission should only be planned in order to maintain reliability and should not be based on the demand for certain fuel sources or the fuel type of the generation fleet. 158 Industrial Customers argue that current transmission planning is based on known and measurable factors, and that any attempt to plan for potential future changes in the resource mix without determining precisely what these changes will be would result in the overbuilding of the system for generation that may not be built. Industrial Customers argue that this outcome would be unjust and unreasonable and would force transmission customers to pay for generation that is non-existent. 159 158 Industrial Customers Initial Comments at 7-8. 159 Id. at 15. 75. Other commenters agree that the Commission lacks a specific record to support the need for reform. 160 For example, former Kansas Commission Chair Keen avers that there is no analytical or evidentiary basis in the NOPR for a complete and thorough overhaul or revision of transmission planning processes. 161 160 See, e.g., Alabama Commission Initial Comments at 4-5; Duke Initial Comments 6-9; Idaho Commission Initial Comments at 2; Industrial Customers Initial Comments at 1, 6-11, 15; Kansas Commission Chair Keen Initial Comments at 1-2; Nebraska Commission Initial Comments at 1-2; NRECA Initial Comments at 14-16; NRG Initial Comments at 3; Ohio Commission Federal Advocate Initial Comments at 5-6; Potomac Economics Initial Comments at 3-4; Southern Initial Comments at 40. 161 Kansas Commission Chair Keen Initial Comments at 2. 76. Duke asserts that the NOPR does not provide robust and specific support as to how and why current regional transmission planning processes are failing to plan for transmission needs driven by changes in the resource mix and demand, leading to inefficient investment. 162 Duke asserts that the NOPR does not support the presumption that the absence of significant regional transmission investment is evidence of inefficient transmission planning. 163 Duke also asserts that, to ensure legal durability, the Commission should identify evidence that justifies a nationwide finding that current transmission planning processes are failing to plan for transmission needs driven by changes in the resource mix and demand, leading to inefficient investment and unjust, unreasonable, and unduly discriminatory or preferential rates. 164 162 Duke Initial Comments at 6-7. 163 Id. at 7-8. 164 Id. at 9 (citing Emera Me. v. FERC, 854 F.3d 9, 24 (D.C. Cir. 2017)). 77. Undersigned States argue that the Commission does not have evidence in the record that current rates are unjust, unreasonable, or unduly discriminatory or preferential, which FPA section 206 requires. 165 Undersigned States argue that, contrary to the preliminary findings in the NOPR, the Southeast has developed significant and sufficient transmission infrastructure and renewable energy from 2015-2020. Undersigned States further argue that the Commission is supposed to enhance reliability, and that, because renewables are intermittent and inherently less reliable, forcing ratepayers to subsidize their use through financing the construction of additional transmission infrastructure is not consistent with the Commission's mission. Undersigned States also argue that the Commission has not justified replacing existing transmission planning processes with a new approach, so the NOPR is arbitrary and capricious. 166 Further, Undersigned States argue that the Commission has not offered a detailed justification for countering prior precedent in Order No. 1000 that “the regional transmission planning process is not the vehicle by which integrated resource planning is conducted.” 167 165 Undersigned States Reply Comments at 6-7. The Undersigned States that submitted reply comments include the States of Texas, Utah, Alabama, Alaska, Arkansas, Florida, Georgia, Kansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, Ohio, Oklahoma, South Carolina, and West Virginia. Id. at 1. The Undersigned States that submitted initial comments include the States of Utah, Alaska, Georgia, Idaho, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, North Dakota, Ohio, Oklahoma, South Carolina, Texas, West Virginia, and Wyoming. Undersigned States Initial Comments at 5-6. 166 Undersigned States Reply Comments at 6-8. 167 Id. at 8 (citing Order No. 1000, 136 FERC ¶ 61,051 at P 154). 78. Some commenters assert that the intention of the NOPR is to improperly favor certain energy resources. 168 Consumer Organizations argue that solutions that allow for an equitable transition and make space for advancing technology and smaller energy systems are preferrable to a rushed plan that favors certain resources, such as wind, solar, and battery storage, that have already proven to be inadequate. 169 ELCON adds that Congress did not give the Commission express authority to balance the FPA's just and reasonable rates requirement with the policy goal of connecting renewable resources to the transmission system. 170 SERTP Sponsors argue that Congress has not clearly provided the Commission with jurisdiction to presuppose generation decisions and thereby effect particular, substantive transmission outcomes; rather, SERTP Sponsors continue, Congress has expressly and unequivocally reserved generation authority to the states. 171 Louisiana Commission argues that the FPA does not confer on the Commission authority to engage in wide-scale public policymaking by enacting sweeping energy policy changes with far-reaching, nationwide effects. 172 168 See, e.g., Consumers Organizations Initial Comments at 1-3; ELCON Initial Comments at 9-10. 169 Consumers Organizations Initial Comments at 1-3. 170 ELCON Initial Comments at 9-10 (citing 16 U.S.C. 824q(b)(4)). 171 SERTP Sponsors Initial Comments at 18. 172 Louisiana Commission Initial Comments at 6 (citing West Virginia v. EPA, 597 U.S. 697 (2022)). 79. Ohio Commission Federal Advocate states that the NOPR may be intended “to establish policies designed to encourage the massive transmission build-out that will doubtless be required to transition to an aspirational renewable future” and “to achieve narrow environmental policy objectives, not to address legitimate requirements under the Federal Power Act like ensuring just and reasonable rates or reliability.” 173 Former Kansas Commission Chair Keen claims that the NOPR encourages an extensive and expensive transmission build-out without considering the impact on state-jurisdictional generation mixes. He also claims that some of the NOPR proposals impose an accelerated pace for the transition from dispatchable to renewable resources, which could hasten the premature retirement of dispatchable generation and compromise regional and state power reliability. He also expresses concern that the NOPR proposals would force ratepayers in some states to pay for neighboring states' transmission projects to advance public policy goals that they do not share. 174 173 Ohio Commission Federal Advocate Initial Comments at 4-5 (citing NOPR, 179 FERC ¶ 61,028, Danly, Comm'r, dissenting, at PP 2-3). 174 Kansas Commission Chair Keen Initial Comments at 3. 80. Some commenters challenge aspects of the need for reform. For example, Nebraska Commission believes that the established structures in RTO/ISO regions are generally working and that many aspects of the NOPR are thus unnecessary there. 175 Potomac Economics disagrees with some of the Commission's arguments for requiring Long-Term Regional Transmission Planning, contending that the Commission's proposals are based on anticipated future generation and other speculative factors and seem to be incorrectly premised on a presumption that congestion should not exist or may limit investment in economic generation. Potomac Economics states that investment should occur only to the extent that the savings of reducing congestion are larger than the investment costs. According to Potomac Economics, congestion that is caused by generators' siting decisions should be borne by the generation developers, as it will incent them to propose the lowest-cost projects taking transmission costs into account. Potomac Economics argues that, if transmission is expanded preemptively to facilitate generation investment in a particular location, such costs are equivalent to subsidies for the developer. 176 175 Nebraska Commission Initial Comments at 1-2. 176 Potomac Economics Initial Comments at 3-4. 81. Mississippi Commission disagrees that too much expansion of high-voltage transmission has occurred through the generator interconnection process instead of through regional transmission planning. 177 Similarly, North Carolina Commission and Staff disagree with the Commission's conclusion that the growth in interconnection-related network upgrades demonstrates a failure of regional transmission planning as it relates to North Carolina. 178 Southern adds that, contrary to statements in the NOPR, it is not significantly expanding its transmission system through the generator interconnection process. 179 177 Mississippi Commission Initial Comments at 9. 178 North Carolina Commission and Staff Initial Comments at 5. 179 Southern Initial Comments at 38-40. 82. Alabama Commission asserts that Alabama has a resource planning process that accounts for needed transmission buildout to maintain reliable service, and thus, Alabama Power plans its transmission system proactively both to maintain deliveries from existing resources and to accommodate Alabama Commission-certified generation additions. Alabama Commission claims that the SERTP process builds on the integrated resource planning efforts of its sponsor states, ensuring that there are no regional transmission solutions that are more efficient or cost-effective than solutions identified through the underlying state-jurisdictional processes. 180 180 Alabama Commission Initial Comments at 4. 83. Duke argues that, for certain transmission providers, the local transmission planning process may more effectively meet transmission needs, especially when combined with state-regulated integrated resource planning and a bottom-up regional transmission planning process. Duke contends that a regional transmission facility may not fully address local transmission needs such that a local transmission facility would still be needed, and thus, the regional transmission facility is not necessarily more efficient or cost-effective than the local transmission facility. 181 181 Duke Initial Comments at 7-9. 84. NRECA states that certain of its members in RTOs/ISOs believe that regional transmission planning is working well to meet long-term needs ( e.g., those in MISO) and that the NOPR proposals would burden transmission providers' limited resources. NRECA states that other NRECA members in RTOs/ISOs believe that existing RTO/ISO transmission planning processes contain discrete deficiencies that the NOPR proposals will not remedy. According to NRECA, these electric cooperatives believe that some incumbent investor-owned transmission owners develop local transmission projects without transparency concerning need or costs, leading to disparities in transmission rates across RTO/ISO transmission zones, and that incumbent transmission owners control the transmission planning process such that no regional transmission planning occurs. NRECA states that, in these cooperatives' view, the criteria to determine the eligibility of a regional transmission project is the barrier, and that requiring Long-Term Regional Transmission Planning, by itself, will not solve the problem. 182 182 NRECA Initial Comments at 14-16. C. Commission Determination 85. Based on the record, we find that there is substantial evidence to support the conclusion that the Commission's existing regional transmission planning and cost allocation requirements are unjust, unreasonable, and unduly discriminatory or preferential. We therefore adopt the preliminary findings in the NOPR concerning the need for reform. Specifically, we find that the absence of sufficiently long-term, forward-looking, and comprehensive transmission planning requirements is causing transmission providers to fail to adequately anticipate and plan for future system conditions. It causes transmission providers to fail to appropriately evaluate the benefits of transmission infrastructure, and results in piecemeal transmission expansion to address relatively near-term transmission needs. We find that this status quo causes transmission providers to undertake relatively inefficient investments in transmission infrastructure, the costs of which are ultimately recovered through Commission-jurisdictional rates. This dynamic results in, among other things, transmission customers paying more than necessary or appropriate to meet their transmission needs and forgoing benefits that outweigh their costs, which results in less efficient or cost-effective transmission investments. As explained below, we find that these deficiencies render Commission-jurisdictional regional transmission planning and cost allocation processes unjust, unreasonable, and unduly discriminatory or preferential. 86. The Commission has authority under FPA section 206 to issue this final order. Specifically, FPA section 206 “instructs the Commission to remedy `any . . . practice' that `affect[s]' a rate for interstate electricity service `demanded' or `charged' by `any public utility' if such practice is `unjust, unreasonable, unduly discriminatory or preferential.'” 183 As the D.C. Circuit has recognized, regional transmission planning and cost allocation processes are practices affecting rates subject to the Commission's exclusive jurisdiction. 184 As the Court explained in South Carolina Public Service Authority v. FERC, transmission providers use those processes to “determine which transmission facilities will more efficiently or cost-effectively meet” transmission needs, the development of which directly impacts the rates, terms, and conditions of Commission-jurisdictional service. 185 In particular, because these processes identify, evaluate, and select the regional transmission facilities whose costs will be recovered through transmission rates, we find that they directly affect those rates. 186 In addition, as discussed below, such transmission facilities contribute to the development of a more robust transmission system, supporting continuity of service in the face of growing reliability challenges and providing wholesale electric customers greater access to lower-cost generation supplied by a wider range of resources. Accordingly, regional transmission planning and cost allocation processes, as well as “the rules and practices that determine how those [processes] operate,” 187 have a direct effect on the rates that customers pay for both the transmission and sale of electric energy in interstate commerce. 188 The Commission may act pursuant to FPA section 206 if the Commission first establishes, through substantial evidence, 189 that the existing practices are unjust, unreasonable, or unduly discriminatory or preferential and, second, establishes that the replacement practices are just and reasonable. 190 183 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55 (quoting 16 U.S.C. 824e(a)). 184 Id. at 55-59, 84 (affirming the Commission's authority to regulate transmission planning and cost allocation as practices affecting rates); see also Order No. 1000-A, 139 FERC ¶ 61,132 at P 577 (holding that “requirements regarding transmission planning and cost allocation . . . are practices affecting rates.”). 185 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56 (citing Order No. 1000, 136 FERC ¶ 61,051 at PP 112, 116); see also Emera Me. v. FERC, 854 F.3d at 674. 186 That is true even if regional transmission planning and cost allocation processes do not result in the development, siting, and construction of every regional transmission facility that transmission providers select to more efficiently or cost-effectively meet transmission needs. See, e.g., Conn. Dep't of Pub. Util. Control v. FERC, 569 F.3d 477, 485 (D.C. Cir. 2009) (holding that “even if all [that] the I[nstalled] C[apacity] R[equirement] did was help to find the right [capacity] price,” rather than result in the construction or procurement of any new capacity, “it would still amount to a `practice . . . affecting' rates.” (citing 16 U.S.C. 824e(a) (omission in original))). 187 FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 279 (2016) ( EPSA ). 188 16 U.S.C. 824e(a). 189 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 54 (“The Commission's factual findings are conclusive if supported by substantial evidence.”). Courts have held that substantial evidence in this context does not necessarily require the Commission to provide empirical evidence for every proposition. Rather, FPA section 206 empowers the Commission to address a mere threat of unjust and unreasonable rates. See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64-65, 85. 190 16 U.S.C. 824e(a); see also EPSA, 577 U.S. at 277 (affirming the Commission “has the authority—and indeed, the duty—to ensure that rules or practices `affecting' wholesale rates are just and reasonable”). 87. With regard to the first showing under FPA section 206, we find that, while Order No. 890 requires transmission providers to satisfy certain principles in their local transmission planning processes and Order No. 1000 requires transmission providers to participate in regional transmission planning and cost allocation processes that satisfy the requirements set forth therein, these existing transmission planning and cost allocation requirements do not result in regional transmission planning that is conducted on a sufficiently long-term, forward-looking, and comprehensive basis to plan for Long-Term Transmission Needs. As a result, we find that transmission providers are often not identifying, evaluating, or selecting more efficient or cost-effective regional transmission solutions to meet Long-Term Transmission Needs. This gap in existing regional transmission planning processes results in piecemeal, inefficient, and less cost-effective transmission planning that imposes real costs on customers, who pay Commission-jurisdictional transmission rates for less efficient or cost-effective transmission facilities and do not realize the benefits that would result from long-term, forward-looking, and more comprehensive regional transmission planning and cost allocation processes that identify, evaluate, and select more efficient or cost-effective transmission solutions to Long-Term Transmission Needs. 88. We find that these deficiencies in the Commission's existing transmission planning and cost allocation requirements render those requirements unjust, unreasonable, and unduly discriminatory or preferential in violation of FPA section 206. 89. We also find that the Commission's existing transmission planning and cost allocation requirements are insufficient to ensure just and reasonable and not unduly discriminatory or preferential rates. Given these findings, we are now requiring, pursuant to FPA section 206, that transmission providers engage in and conduct sufficiently long-term, forward-looking, and comprehensive transmission planning and cost allocation processes to identify and plan for Long-Term Transmission Needs. We find that these reforms will facilitate a process by which transmission providers can better identify, evaluate, and select more efficient or cost-effective transmission solutions to meet Long-Term Transmission Needs, which will ensure that Commission-jurisdictional rates are just and reasonable and not unduly discriminatory or preferential. 1. The Transmission Investment Landscape Today 90. As the Commission explained in the NOPR, a robust, well-planned transmission system is foundational to ensuring an affordable, reliable supply of electricity. 191 Due to continuing changes in the industry, ongoing investment in transmission facilities is necessary to ensure the transmission system continues to serve load in a reliable, 192 affordable, and economically efficient fashion. Such investments support enhanced reliability, as larger, more integrated transmission systems result in a diversity of supply and demand conditions and a certain degree of redundancy that allows the system to better withstand failures during extreme events. 193 Proactive, forward-looking transmission planning that considers both evolving reliability needs and other drivers of transmission needs more comprehensively can enable transmission providers to identify potential reliability problems and economic constraints, as well as to evaluate potential transmission solutions, well in advance of these issues affecting the transmission system, 194 which can facilitate the selection of more efficient or cost-effective transmission facilities to meet Long-Term Transmission Needs. 191 NOPR, 179 FERC ¶ 61,028 at P 28 (citing 16 U.S.C. 824, 824d, 824e); see also US DOE ANOPR Initial Comments at 2 (stating that “strengthening and expanding existing transmission infrastructure, particularly the development of regional and inter-regional transmission projects, is key to continued access to reliable, resilient, lower-cost, and clean electricity for all”). 192 See, e.g., MISO ANOPR Initial Comments at 40; Testimony of James B. Robb Before the U.S. Senate Energy and Natural Resources Committee, Reliability, Resiliency, and Affordability of Electric Service in the United States Amid the Changing Energy Mix and Extreme Weather Events, at 8-9 (Mar. 11, 2021), 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 [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2024-10872. Public record. Not legal advice.