# 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%3A2024-27982 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** December 6, 2024 - **Citation:** 89 FR 97174 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM21-17-001; Order No. 1920-A] Building for the Future Through Electric Regional Transmission Planning and Cost Allocation AGENCY: Federal Energy Regulatory Commission, Department of Energy (DOE). ACTION: Order on rehearing and clarification. SUMMARY: In this order, the Federal Energy Regulatory Commission addresses arguments raised on rehearing, sets aside, in part, and clarifies Order No. 1920, which required transmission providers to conduct Long-Term Regional Transmission Planning to 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. Order No. 1920 also directed 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. DATES: The changes to Order No. 1920 made in this order on rehearing and clarification will be effective on January 6, 2025. FOR FURTHER INFORMATION CONTACT: Michael Kellermann (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8491, michael.kellermann@ferc.gov. Patrick T. Metz (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8197, patrick.metz@ferc.gov. David Tobenkin (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6445, david.tobenkin@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. SUPPLEMENTARY INFORMATION: Paragraph Nos. I. Executive Summary 1 II. Introduction and Background 20 III. The Overall Need for Reform 34 A. Order No. 1920 34 1. The Transmission Investment Landscape Today 38 2. Unjust, Unreasonable, and Unduly Discriminatory or Preferential Commission-Jurisdictional Transmission Planning and Cost Allocation Processes 46 3. Benefits of Long-Term Regional Transmission Planning and Cost Allocation To Identify and Plan for Long-Term Transmission Needs 59 B. The Commission Adequately Demonstrated That Existing Rates, or Practices Affecting Rates, Are Unjust and Unreasonable 61 1. The Commission Correctly Characterized Its Statutory Burden 62 2. The Commission Adequately Supported Its Determination on Step One of Section 206 70 3. The Commission Identified Deficiencies That Exist Beyond Isolated Pockets 87 4. The Commission Has the Authority To Conduct a Generic Rulemaking 98 C. The Commission Demonstrated That the Replacement Rate is Just and Reasonable 104 1. Requests for Rehearing 104 2. Commission Determination 107 D. The Commission's Section 206 Findings Were Not Circular 115 1. Requests for Rehearing 115 2. Commission Determination 119 IV. Statutory Authority 125 A. Order No. 1920 Determination 125 B. Federal/State Division of Authority 132 1. Requests for Rehearing 132 2. Commission Determination 135 C. Major Questions Doctrine 166 1. Requests for Rehearing 166 2. Commission Determination 171 D. Other Issues 186 1. Requests for Rehearing 186 2. Commission Determination 192 V. Long-Term Regional Transmission Planning 200 A. Requirement To Participate in Long-Term Regional Transmission Planning 200 1. Order No. 1920 Requirements 200 2. Requests for Rehearing and Clarification 205 3. Commission Determination 210 B. Long-Term Scenarios Requirements 218 1. Requirement for Transmission Providers To Use the Seven Required Benefits To Help To Inform Their Identification of Long-Term Transmission Needs 218 2. Transmission Planning Horizon 227 3. Frequency of Long-Term Scenario Revisions 248 4. Categories of Factors 263 5. Requests for Additional Flexibility Regarding Long-Term Scenarios Requirements 351 C. Evaluation of the Benefits of Regional Transmission Facilities 369 1. Requirement for Transmission Providers To Use and Measure a Set of Seven Required Benefits 369 2. Measurement and Use of Other Benefits 411 3. Identification, Measurement, and Evaluation of Benefits 417 4. Benefits Horizon 421 5. Evaluation of the Benefits of Portfolios of Transmission Facilities 428 D. Evaluation and Selection of Long-Term Regional Transmission Facilities 434 1. Minimum Requirements 434 2. Role of Relevant State Entities 452 3. Voluntary Funding 461 4. No Selection Requirement 466 5. Reevaluation 469 E. Implementation of Long-Term Regional Transmission Planning 502 1. Order No. 1920 Requirements 502 2. Requests for Rehearing and Clarification 505 3. Commission Determination 507 VI. Coordination of Regional Transmission Planning and Generator Interconnection Processes 511 A. Need for Reform and Overall Requirement 511 1. Order No. 1920 Requirements 511 2. Requests for Rehearing 513 3. Commission Determination 516 B. Qualifying Criteria 525 1. Order No. 1920 Requirements 525 2. Requests for Rehearing and Clarification 532 3. Commission Determination 538 C. Cost Allocation 557 1. Order No. 1920 Requirements 557 2. Requests for Rehearing and Clarification 558 3. Commission Determination 562 D. Gaming 566 1. Order No. 1920 Requirements 566 2. Requests for Rehearing and Clarification 567 3. Commission Determination 570 E. Transmission Planning Process Evaluation 572 1. Order No. 1920 Requirements 572 2. Requests for Rehearing and Clarification 574 3. Commission Determination 582 VII. Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices 594 A. Order No. 1920 Requirements 594 B. Requests for Rehearing and Clarification 596 1. General Requests for Rehearing and Clarification 596 2. Technology Specific Requests for Rehearing and Clarification 601 VIII. Regional Transmission Cost Allocation 610 A. Obligation To File an Ex Ante Long-Term Regional Transmission Cost Allocation Method and Its Use as a Backstop 610 1. Logical Outgrowth 610 2. Substantive Issues 618 B. Requirements Concerning Relevant State Entities 635 1. Requested Requirement To Obtain the Agreement of Relevant State Entities 635 2. Requirements Concerning Relevant State Entities' Preferred Cost Allocation Methods 642 C. Design and Operation of the Engagement Period 663 1. Logical Outgrowth 663 2. Requests Arguing the Engagement Period is Inferior to a Requirement That Transmission Providers Seek the Agreement of Relevant State Entities 669 3. Duration of the Engagement Period 674 4. Content of the Engagement Period 679 5. Consultation With Relevant State Entities After the Engagement Period 687 D. Design and Operation of State Agreement Processes 693 1. Definition of Relevant State Entities 693 2. Extensions of Time for Negotiation of Cost Allocation Methods Under State Agreement Processes 705 E. Use of Existing Cost Allocation Methods in Long-Term Regional Transmission Planning or Existing Regional Processes 709 1. Order No. 1920 Requirements 709 2. Requests for Rehearing and Clarification 710 3. Commission Determination 712 F. Regional Cost Allocation Principles for Long-Term Regional Transmission Facilities 718 1. Logical Outgrowth 718 2. Omission of Regional Cost Allocation Principle No. 6 and Ability To Allocate Costs by Type of Project 728 3. Concerns Regarding Cost Causation 753 G. General Benefits Requirements Related to Cost Allocation 769 1. Logical Outgrowth 769 2. Substantive Issues 775 H. Additional Cost Allocation Issues 781 1. Order No. 1920 Requirements 781 2. Requests for Rehearing and Clarification 784 3. Commission Determination 789 IX. Construction Work in Progress Incentive 794 A. CWIP 794 1. Order No. 1920 794 2. Requests for Rehearing and Clarification 795 3. Commission Determination 799 X. Exercise of a Federal Right of First Refusal in Commission-Jurisdictional Tariffs and Agreements 801 A. Order No. 1920 Requirements 801 B. Request for Rehearing 802 C. Commission Determination 803 XI. Local Transmission Planning Inputs in the Regional Transmission Planning Process 804 A. Need for Reform 804 1. Order No. 1920 804 2. Analysis Under FPA Section 206 813 3. Departure From Commission Precedent 824 4. Commission Authority Under the FPA 828 5. Policy Against Anticompetitive Practices 840 6. Other Arguments 843 B. Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process 847 1. Order No. 1920 847 2. Requests for Additional Reforms 851 3. Stakeholder Meeting Clarifications 859 C. Identifying Potential Opportunities to Right-Size Replacement Transmission Facilities 863 1. Eligibility 863 2. Right of First Refusal for Right-Sized Replacement Transmission Facilities Selected To Meet Long-Term Transmission Needs 882 3. Confidentiality of In-Kind Replacement Estimates 895 XII. Interregional Transmission Coordination 899 A. Order No. 1920 899 B. Comments 901 C. Commission Determination 902 XIII. Compliance Procedures 903 A. Order No. 1920 903 B. Requests for Rehearing and Clarification 907 C. Commission Determination 914 XIV. Overarching Logical Outgrowth Challenges 927 A. Requests for Rehearing 927 B. Commission Determination 930 XV. Information Collection Statement 932 XVI. Environmental Analysis 950 XVII. Regulatory Flexibility Act 951 XVIII. Document Availability 953 XIX. Effective Date 956 Appendix A: Abbreviated Names of Parties Appendix B: Pro Forma Open Access Transmission Tariff Attachment K I. Executive Summary 1. In Order No. 1920, 1 the Federal Energy Regulatory Commission (Commission) revised the pro forma Open Access Transmission Tariff (OATT) to adopt reforms to its existing electric transmission planning and cost allocation requirements pursuant to section 206 of the Federal Power Act (FPA). 2 The Commission found that existing regional transmission planning and cost allocation processes are unjust, unreasonable, and unduly discriminatory or preferential because, inter alia, 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; 3 (2) adequately account on a forward-looking basis for known determinants of Long-Term Transmission Needs; and (3) consider a set of benefits of regional transmission facilities planned to meet those Long-Term Transmission Needs. 4 Order No. 1920 addressed these deficiencies by establishing requirements to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential including, inter alia, requiring transmission providers to conduct Long-Term Regional Transmission Planning 5 that will ensure the identification, evaluation, and selection of more efficient or cost-effective regional transmission facilities to address Long-Term Transmission Needs, as well as the just and reasonable allocation of the costs of those facilities. By expanding the time horizon and scope of Commission-jurisdictional regional transmission planning processes, Order No. 1920 reflected an evolutionary step in the Commission's ongoing commitment 6 to ensure that those processes remain just and reasonable and meet the needs of the American people. 1 Bldg. for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation, Order No. 1920, 89 FR 49280 (June 11, 2024), 187 FERC ¶ 61,068 (2024). 2 16 U.S.C. 824e. 3 See infra Introduction and Background section (defining “Long-Term Transmission Needs”). 4 Order No. 1920, 187 FERC ¶ 61,068 at P 1. 5 See infra Introduction and Background section (defining “Long-Term Regional Transmission Planning). 6 See Preventing Undue Discrimination & Preference in Transmission Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, 118 FERC ¶ 61,119 (2007), order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007) (cross-referenced at 118 FERC ¶ 61,119), order on reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ¶ 61,126 (2009); Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 FERC ¶ 61,051 (2011), Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132 (2012), order on reh'g & clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) (per curiam). 2. In this order, we refine and improve Long-Term Regional Transmission Planning by building on the reforms adopted in Order No. 1920, with a particular focus on ensuring that states have a robust role in Long-Term Regional Transmission Planning and cost allocation processes established in this rule. We continue to find, as the Commission did in the final rule, that the key components of Order No. 1920 together ensure that transmission providers will conduct sufficiently long-term, forward-looking, and comprehensive transmission planning and cost allocation processes. At least once every five years, transmission providers are required to conduct Long-Term Regional Transmission Planning, a process that includes looking ahead over a 20-year transmission planning horizon. This process further requires developing at least three plausible and diverse Long-Term Scenarios 7 that are based upon known drivers of transmission needs and informed by best available data; analyzing the impacts of events like extreme weather under each Long-Term Scenario; and evaluating potential Long-Term Regional Transmission Facilities. 8 This evaluation includes assessing whether these facilities would yield reliability and economic benefits to transmission customers and, if so, identifying those benefits. Together, these reforms ensure that transmission providers, state regulators, and stakeholders possess the information necessary for each transmission planning region to identify, evaluate, and select ( i.e., determine whether to pursue the development of facilities) more efficient or cost-effective transmission facilities that provide significant benefits for customers. 7 See infra Introduction and Background section (defining “Long-Term Scenario”). 8 See infra Introduction and Background section (defining “Long-Term Regional Transmission Facility”). 3. Here, we adopt a number of modifications and clarifications to address the concerns raised in response to Order No. 1920. Order No. 1920 recognized the important role that states will play in Long-Term Regional Transmission Planning and established various requirements to facilitate their participation in those processes, including requiring transmission providers to engage with states in developing cost allocation approaches for Long-Term Regional Transmission Facilities. With this order, we reaffirm and enhance that finding by recognizing that meaningful engagement with states is critical to the success of the Long-Term Regional Transmission Planning reforms established in Order No. 1920. Specifically, in response to rehearing and clarification requests, we better integrate states' input into regional transmission planning and cost allocation processes, both in the transmission providers' development of Order No. 1920 compliance filings and the ongoing implementation of these reforms in the future. These modifications and clarifications address many of the concerns raised in the rehearing requests submitted in response to Order No. 1920, and they will increase the likelihood that Long-Term Regional Transmission Planning results in efficient and cost-effective transmission investment. 4. In this order, we also clarify what this rule does, and does not, require. Because Order No. 1920 mandates only improvements to transmission planning processes which, in turn, ensures foundational transparency about potential transmission development, Order No. 1920 does not force or mandate the development of certain transmission facilities. A requirement to develop a structured process to analyze whether building certain transmission facilities would yield benefits greater than their costs, over the long term and based upon various future scenarios, will help transmission providers and states to assess the value that those projects could bring. However, such process-based requirements are not the same as a requirement to build any particular transmission facilities. More precisely, Order No. 1920 does not require transmission providers to select any particular transmission facility; does not automatically authorize transmission developers to develop or construct any specific facilities; and does not mandate any specific set of transmission customers to pay for any particular transmission facilities. Instead, Order No. 1920 and this order together set out processes that direct transmission planning regions to systematically consider various drivers of transmission needs and develop cost allocation approaches that yield the development of cost-effective transmission projects and thereby yield just and reasonable rates for customers. 5. As such, Long-Term Regional Transmission Planning as required by Order No. 1920 is a significant step forward in the Commission's responsibility to ensure just and reasonable and not unduly discriminatory or preferential rates. By establishing minimum standards based on transmission planning best practices observed around the country for forecasting future scenarios and managing the uncertainty inherent in forward-looking planning, the Long-Term Regional Transmission Planning requirements established in this proceeding will lead transmission providers to re-direct investment toward more efficient or cost-effective regional transmission facilities, and ultimately produce greater benefits for transmission customers. 6. Moreover, improving regional transmission planning practices is an urgent concern in light of the uncontroverted, rapidly changing circumstances on the grid, including load growth; the increased impacts of extreme weather; affordability concerns; and changing economics and policies that shape the resource mix and demand, which are increasing the need for transmission across the country. To cost-effectively meet these needs, Order No. 1920 and this order set out systematic processes that transmission providers will use to identify and analyze transmission projects that bring benefits to consumers, while recognizing the need for flexibility to account for regional differences. 7. Order No. 1920 follows in the footsteps of Order Nos. 890 and 1000 when it comes to the requirements governing the selection of potential regional transmission facilities identified through Long-Term Regional Transmission Planning. Consistent with the core theory of Order Nos. 890 and 1000, even though Order No. 1920 does not require the buildout of specific transmission facilities, it will reveal the benefits of designing and developing transmission projects and enable investment in those that yield great benefits for electricity customers across the country. Ultimately, we expect Order No. 1920 to lead to the development of more efficient or cost-effective transmission facilities through improved analysis and transparency that empower the transmission planning regions with the information needed to make prudent investments in beneficial transmission infrastructure for customers. 8. Order No. 1920's requirements for regional cost allocation practices are similarly well grounded in Commission and court precedent. If more efficient or cost-effective Long-Term Regional Transmission Facilities are identified and determined to be worth developing as a result of the enhanced regional transmission planning required by Order No. 1920, customers will pay for these facilities only to the extent that they benefit from them. That is because Order No. 1920 requires, consistent with well-established law and Orders No. 890 and 1000, that any cost allocation must comply with cost causation and the “beneficiary pays” principle. 9 Thus, Order No. 1920 will not lead one group of customers to pay for more than their fair share of the costs of transmission development because any proposal to charge customers for costs that are not “roughly commensurate” with the benefits they are expected to receive from Long-Term Regional Transmission Facilities would contravene the final rule. 10 9 See PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ¶ 61,063, at P 66 (2007) (requiring PJM to set forth a “beneficiary pays” method in its tariff and consistently apply that approach each time a new regionally-planned transmission facility is approved), on reh'g, Opinion No. 494-A, 122 FERC ¶ 61,082 (2008), remanded Ill. Com. Comm'n v. FERC, 576 F.3d 470, 474-78 (7th Cir. 2009) ( ICC v. FERC I ) (remanding Commission order for further proceedings in light of Commission's failure to provide substantial evidence supporting Commission's approval of cost allocation method as complying with “beneficiary pays” principle). 10 See ICC v. FERC I, 576 F.3d at 477 (holding that, if the Commission cannot quantify the benefits of particular transmission facilities to a particular class of transmission customers, it must have “an articulable and plausible reason to believe that the benefits [of those facilities] are at least roughly commensurate with” the costs to be paid by those customers). 9. Order No. 1920 builds on Order No. 1000's cost allocation requirements. Order No. 1000 required transmission providers to incorporate into their tariffs a default (“ ex ante” ) cost allocation approach that, if transmission facilities are determined to be worth investing in based upon the results of the regional transmission planning process, would provide a mechanism for those transmission customers that benefit to pay for those projects. Prior to Order No. 1000, transmission providers did not necessarily have the means to charge transmission customers located within a particular transmission planning region, but outside their individual service territories, for the costs of regional transmission facilities that benefit customers throughout the region. Thus, the requirement to establish an ex ante cost allocation method in each OATT that would apply if a regional transmission planning process resulted in the selection of more efficient or cost-effective transmission facilities was central to ensuring that those facilities could actually be developed. Like Order No. 1000, Order No. 1920 requires each transmission provider to establish at least one ex ante cost allocation method through which the costs of Long-Term Regional Transmission Facilities will be allocated in a manner consistent with the “beneficiary pays” principle. Just like in Order No. 1000, the requirement to establish a mechanism by which the costs of selected transmission facilities may be allocated to relevant benefitting transmission customers does not mandate any particular method that transmission providers or planning regions must adopt. 10. Importantly, Order No. 1920 provides additional flexibility to transmission providers and states regarding cost allocation. While transmission providers under Order No. 1000 must adopt a cost allocation method for each type of transmission facility, Order No. 1920 relaxes this requirement. Furthermore, the modifications and clarifications granted on rehearing expand states' critical role in determining the cost allocation approach most suitable for each transmission planning region. These modifications and clarifications are necessary because the Commission recognizes that states play a critical role in the successful planning of, the decision about how to pay for, and ultimately, the deployment of beneficial regional transmission facilities. 11. For example, under Order No. 1920 as modified in this order, Relevant State Entities have an opportunity to negotiate their preferred ex ante cost allocation method(s) in the first instance, including being able to secure an extension of time if needed to continue those negotiations. Upon reaching agreement, Relevant State Entities can present their preferred approach to the transmission provider, which then will either propose that approach to the Commission in its compliance filing for this rule, or if the transmission provider submits a different proposal, will include in its compliance filing the states' preferred approach for the Commission to consider. 12. This order further improves states' ability to negotiate cost allocation methods. Under Order No. 1920, states, through Relevant State Entities, 11 have an opportunity to secure the right to negotiate alternate cost allocation methods in the future, for either an individual transmission facility or a group of them, instead of using the ex ante cost allocation method on file in transmission providers' OATTs. This State Agreement Process 12 allows Relevant State Entities to consider, for example, whether certain Long-Term Regional Transmission Facilities largely provide a unique set of benefits such that the costs of those facilities are appropriately paid for in a different manner than under the ex ante cost allocation method. And, going forward, we require transmission providers to consult with Relevant State Entities regarding potential future changes to ex ante cost allocation methods and State Agreement Processes used in Long-Term Regional Transmission Planning. 11 See infra Introduction and Background section (defining “Relevant State Entity”). 12 See infra Introduction and Background section (defining “State Agreement Process”). 13. Order No. 1920 provides greater flexibility than Order No. 1000 to deviate from the ex ante cost allocation method or to establish more than one ex ante cost allocation method. We also provide new opportunities for states to influence each of these choices because better enabling state input into cost allocation choices helps to ensure that more efficient or cost-effective Long-Term Regional Transmission Facilities that are likely to be sited and constructed only with state regulatory approval are ultimately developed successfully. Given that Order No. 1920 continues to afford considerable flexibility to transmission providers and Relevant State Entities to determine the cost allocation methods appropriate for their transmission planning region and retains the core obligation that any cost allocation method filed must be consistent with cost causation, the beneficiary pays principle, and other statutory requirements, we believe that cost allocation under this rule will result in just and reasonable rates. Order No. 1920 requires no more than Order No. 1000—that some mechanism for charging customers for more efficient or cost-effective transmission facilities be available in case such facilities are determined, after evaluation through Long-Term Regional Transmission Planning, to be worth developing. In fact, Order No. 1920 expands the opportunities for transmission providers, state regulators, and stakeholders to ensure that the costs of Long-Term Regional Transmission Facilities are allocated only “roughly commensurate” with the benefits expected to result from those facilities. 14. As noted above, we agree with certain arguments raised on rehearing and/or clarification of Order No. 1920. The instances where we modify the discussion in Order No. 1920 and set aside the result of Order No. 1920 generally fall into three categories. First, as discussed above, we further enhance the role of Relevant State Entities in Long-Term Regional Transmission Planning, especially their role in shaping the development of Long-Term Scenarios and cost allocation methods. Second, we clarify that, when Relevant State Entities request, transmission providers must develop a reasonable number of additional scenarios to help inform the development or application of cost allocation methods. And third, we remove the requirement that transmission providers include corporate commitments in Factor Category Seven. 15. In the first category, Order No. 1920 provided an opportunity for states to influence how transmission is planned and ultimately paid for. This order goes even farther by agreeing with the rehearing arguments advanced by several states seeking additional and expanded opportunities for states to engage. Specifically, we require transmission providers to incorporate input from states about how Long-Term Scenarios used in Long-Term Regional Transmission Planning will be developed, particularly given that these scenarios will necessarily reflect how the states plan to meet their laws, policies, and regulations. In addition, we require transmission providers to include in the transmittal or as an attachment to their Order No. 1920 compliance filings any ex ante cost allocation method and/or State Agreement Process agreed to by the Relevant State Entities (to the extent the transmission provider does not adopt such an agreed-to cost allocation method and/or process as its own proposal), along with any information related to the Engagement Period 13 requested by a Relevant State Entity to be included. We are further persuaded by arguments on rehearing that Relevant State Entities may, in some cases, need time beyond the six-month Engagement Period allowed under Order No. 1920. We therefore clarify that the Commission will grant extensions of time requested by Relevant State Entities where there is a showing that additional time is needed to resolve cost allocation discussions, up to a period of an additional six months. We believe this clarification ensures states who are engaged in working toward agreed-upon cost allocation methods and/or a State Agreement Process will have the time they need to resolve those discussions. 13 See infra Introduction and Background section (defining “Engagement Period”). 16. Furthermore, to ensure that Relevant State Entities have a role in cost allocation for Long-Term Regional Transmission Facilities going forward, we require that transmission providers consult with Relevant State Entities (1) prior to amending the Long-Term Regional Transmission Cost Allocation Method(s) and/or State Agreement Process(es), or (2) if Relevant State Entities seek, consistent with their chosen method to reach agreement, to amend that method or process. Finally, we clarify that the flexibility Order No. 1920 affords to transmission providers and Relevant State Entities to determine cost allocation methods appropriate for their region does not preclude proposed methods that allocate costs commensurate with reliability and economic benefits region-wide, while allocating costs commensurate with additional benefits to a subset of states that agree to such cost allocation, e.g., based on the incremental costs and benefits of transmission needed to achieve state laws, policies, and regulations beyond the cost of transmission needed in the absence of those laws, policies, and regulations. 17. In the second category, we clarify in response to requests for rehearing that, while transmission providers are obligated to develop three Long-Term Scenarios that meet all of the requirements of the rule, Order No. 1920 permits transmission providers to develop additional analyses, including other scenarios, to help inform who pays for those selected facilities. We further modify Order No. 1920 on rehearing to now require that transmission providers develop a reasonable number of additional scenarios at Relevant State Entities' request. The aim of Order No. 1920 is to ensure that transmission providers engage in the sufficiently long-term, forward-looking, and comprehensive transmission planning that is essential to have the information necessary to determine which investments are worth making. As long as transmission providers engage in that robust planning process and achieve the transparency required through that process, transmission providers can develop and consider additional information beyond that required as part of Long-Term Regional Transmission Planning. 18. In the third category of changes, on rehearing we modify, in one respect, the requirement to use seven categories of factors in the development of the three Long-Term Scenarios that are used to identify Long-Term Transmission Needs, and potential solutions to those needs. Several parties raise concerns regarding the inclusion of corporate commitments in Factor Category Seven, which they argue may elevate the needs of particular transmission customers above those of others. Upon further consideration, we eliminate the requirement to incorporate corporate commitments from Factor Category Seven into each Long-Term Scenario and thus we eliminate the potential for confusion around the treatment of particular transmission customers, while enabling transmission providers to give appropriate weight to corporate commitments as an indicator of customer preference in a region where those preferences are known. 19. Taken together, we believe the requirements of Order No. 1920 with the modifications and clarifications we make on rehearing will remedy the deficiencies of current regional transmission planning processes, establish sufficiently long-term, forward-looking, and comprehensive transmission planning, and ensure that transmission providers and Relevant State Entities in each region have the flexibility to devise cost allocation methods that reasonably and fairly assign the costs of Long-Term Regional Transmission Facilities to those that benefit from such facilities. II. Introduction and Background 20. In Order No. 1920, the Commission found that 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: 14 (1) perform a sufficiently long-term assessment of transmission needs that identifies Long-Term Transmission Needs; 15 (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. 16 14 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) ( TAPS ), 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). 15 For purposes of Order No. 1920, Long-Term Transmission Needs are transmission needs identified through Long-Term Regional Transmission Planning by, among other things and as discussed in Order No. 1920, running scenarios and considering the enumerated categories of factors. Order No. 1920, 187 FERC ¶ 61,068 at P 299. 16 Order No. 1920, 187 FERC ¶ 61,068 at P 1. 21. Order No. 1920 therefore established requirements to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. First, Order No. 1920 required transmission providers in each transmission planning region to participate in a regional transmission planning process that includes Long-Term Regional Transmission Planning. 17 Order No. 1920 established specific requirements regarding how transmission providers must conduct Long-Term Regional Transmission Planning, including, among other things, the use of Long-Term Scenarios to identify Long-Term Transmission Needs and Long-Term Regional Transmission Facilities 18 to meet those needs. 19 17 Id. P 224. 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. Id. For purposes of Order No. 1920, 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. Id. P 2 n.7; see Order No. 1000, 136 FERC ¶ 61,051 at P 160. 18 For purposes of Order No. 1920, a Long-Term Regional Transmission Facility is a regional transmission facility that is identified as part of Long-Term Regional Transmission Planning to address Long-Term Transmission Needs. Order No. 1920, 187 FERC ¶ 61,068 at P 250. For the purposes of Order No. 1920, 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. Id. P 41 n.58 (citing Order No. 1000, 136 FERC ¶ 61,051 at PP 63, 482 n.374). 19 Id. P 298. For purposes of Order No. 1920, 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. Id. P 302. 22. Order No. 1920 required transmission providers to measure and use at least seven specified benefits to evaluate Long-Term Regional Transmission Facilities as part of Long-Term Regional Transmission Planning. 20 Order No. 1920 required 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 required 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. 21 20 Id. P 719. 21 Id. P 859. The Commission recognized 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. Id. P 3 n.8 (citing Order No. 1000, 136 FERC ¶ 61,051 at P 63). For purposes of Order No. 1920, unless otherwise noted, when referencing Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) that are selected, we intend that the word “selected” mean that those Facilities are selected in the regional transmission plan for purposes of cost allocation. Id. 23. Order No. 1920 required 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. 22 Further, Order No. 1920 required transmission providers to include in their OATTs a process to provide Relevant State Entities 23 and interconnection customers with 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 transmission providers' selection criteria. 24 Order No. 1920 also required 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. 25 22 Id. P 911. 23 For the purposes of Order No. 1920, 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. Id. P 1355. 24 Id. P 1012. 25 Id. P 1048. 24. Order No. 1920 required transmission providers to file one or more ex ante Long-Term Regional Transmission Cost Allocation Methods 26 to allocate the costs of Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) that are selected. 27 Order No. 1920 further allowed, but did not require, transmission providers to adopt a State Agreement Process for allocating the costs of all, or a subset of, Long-Term Regional Transmission Facilities. 28 Where Relevant State Entities agree to such a State Agreement Process, and transmission providers choose to file such a process, a State Agreement Process would provide Relevant State Entities 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. 29 Order No. 1920 also established 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. 30 26 For purposes of Order No. 1920, a Long-Term Regional Transmission Cost Allocation Method is an ex ante regional cost allocation method for one or more Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) that are selected in the regional transmission plan for purposes of cost allocation. Id. P 1291. 27 Id. 28 Id. P 1402. For purposes of Order No. 1920, 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. Id. 29 Id. 30 Id. P 1354. 25. Order No. 1920 required transmission providers to evaluate for potential selection in their existing Order No. 1000 regional transmission planning processes regional transmission facilities that will address certain identified interconnection-related transmission needs associated with certain interconnection-related network upgrades originally identified through the generator interconnection process. 31 31 Id. PP 1106-1107. 26. Order No. 1920 required transmission providers 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. 32 32 Id. P 1198. 27. Order No. 1920 required 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. 33 33 Id. PP 1625, 1677. 28. Order No. 1920 required transmission providers to revise their interregional transmission coordination procedures to reflect the Long-Term Regional Transmission Planning reforms adopted in Order No. 1920. 34 Order No. 1920 also required transmission providers to meet additional information sharing and transparency requirements with respect to their interregional transmission coordination processes. 35 34 Id. P 1751. 35 Id. 29. The Commission received 49 timely filed requests for rehearing and/or clarification 36 and several additional filings. 37 The rehearing requests raise issues related to nearly all reforms adopted in Order No. 1920. 36 Appendix A provides the short names of the entities that filed requests for rehearing or clarification. To the extent that they intend to seek rehearing, the pleadings filed by Grid United, PJM States, Vermont Commission, and Virginia and North Carolina Commissions are deficient because they fail to include a separate section entitled “Statement of Issues” listing each issue presented to the Commission in a separately enumerated paragraph that includes representative precedent on which the participant is relying, as required by Rule 713(c)(2) of the Commission's Rules of Practice and Procedure (18 CFR 385.713(c)(2)). Consistent with Rule 713, we deem these petitioners to have waived the issues for which they seek rehearing. We consider petitioners' requests for clarification and, to provide clarity, address their arguments on rehearing below. EEI, PJM States, and PJM Utilities filed answers to certain requests for rehearing. Rule 713(d)(1) (18 CFR 385.713(d)(1)) prohibits an answer to a request for rehearing. Accordingly, we deny EEI's, PJM States', and PJM Utilities' motions to answer and reject their answers. Although PJM States style their July 3, 2024 pleading as comments, we treat the pleading as an answer to PJM's request for rehearing. See, e.g., San Diego Gas & Elec. Co., 133 FERC ¶ 61,014, at P 15 (2010) (“[W]e are not obligated to accept a filing solely on the basis of its party-bestowed title. Instead, we examine the substance of the pleading.”). 37 Susann Rizzo, Gary Andrews, and Cher Gilmore filed letters supporting Order No. 1920. They also urged the Commission to require interregional transmission planning and establish environmental justice liaisons. In addition, E. Andrews, Illinois Commission, and Minnesota Commission each submitted late-filed pleadings that are generally supportive of Order No. 1920. Further, on June 12, 2024, Missouri Commission filed a letter addressing Order No. 1920. On September 3, 2024, Chairman Willie Phillips responded to the Missouri Commission letter. On July 22, 2024, State Regulatory Commissioners filed a letter expressing views on Order No. 1920. On October 9, 2024, Chairman Willie Phillips responded to the State Regulatory Commissioners' letter. 30. Pursuant to Allegheny Defense Project v. FERC, 38 the rehearing requests filed in this proceeding may be deemed denied by operation of law. However, as permitted by section 313(a) of the FPA, 39 we are modifying the discussion in Order No. 1920, setting aside the order, in part, and clarifying the order, as discussed below. 40 38 964 F.3d 1 (D.C. Cir. 2020) (en banc). 39 16 U.S.C. 825 l (a) (“Until the record in a proceeding shall have been filed in a court of appeals, as provided in subsection (b), the Commission may at any time, upon reasonable notice and in such manner as it shall deem proper, modify or set aside, in whole or in part, any finding or order made or issued by it under the provisions of this chapter.”). 40 Allegheny Def. Project, 964 F.3d at 16-17. In Appendix B, we provide the revisions to the provisions of Attachment K to the pro forma OATT made in this order on rehearing and clarification. 31. Specifically, we set aside the order, in part, to specify that: (1) transmission providers are not required to use the set of seven required benefits to help inform their identification of Long-Term Transmission Needs; 41 (2) Factor Category Seven no longer includes corporate commitments; 42 (3) transmission providers must propose an effective date for the OATT revisions necessary to comply with Order No. 1920 that is no later than two years from the date on which they will commence the first Long-Term Regional Transmission Planning cycle; 43 (4) when Relevant State Entities agree on a Long-Term Regional Transmission Cost Allocation Method or State Agreement Process resulting from the Engagement Period, transmission providers must include that method or process in the transmittal or as an attachment to their compliance filing, even if transmission providers propose a different Long-Term Regional Transmission Cost Allocation method or do not propose to adopt a State Agreement Process along with any information that Relevant State Entities provide to transmission providers regarding the state negotiations during the Engagement Period; 44 and (5) transmission providers shall consult with Relevant State Entities prior to amending the Long-Term Regional Transmission Cost Allocation Method(s) and/or State Agreement Process(es), or if Relevant State Entities seek, consistent with their chosen method to reach agreement, for the transmission provider to amend that method or process. 41 See Order No. 1920, 187 FERC ¶ 61,068 at P 301 (“Transmission providers must use [the set of seven required benefits] to help to inform their identification of Long-Term Transmission Needs.”). 42 See id. P 481 (“We adopt the NOPR proposal, with modification, to require transmission providers in each transmission planning region to incorporate Factor Category Seven: utility and corporate commitments and federal, federally-recognized Tribal, state, and local policy goals that affect Long-Term Transmission Needs, in the development of Long-Term Scenarios.”). 43 See id. P 1072 (“Thus, we require transmission providers in each transmission planning region to propose on compliance a date, no later than one year from the date on which initial filings to comply with this final rule are due, on which they will commence the first Long-Term Regional Transmission Planning cycle.”). 44 See id. P 1359 (“We note, however, that the ultimate decision as to whether to file a Long-Term Regional Transmission Cost Allocation Method(s) and/or State Agreement Process to which Relevant State Entities have agreed will continue to lie with the transmission providers.”). 32. Additionally, we grant multiple clarifications on most elements of Order No. 1920, as further discussed below. For example, among other clarifications, we clarify that transmission providers may develop additional scenarios, beyond the three Long-Term Scenarios that Order No. 1920 requires, to provide Relevant State Entities with information that they can use to inform the application of Long-Term Regional Cost Allocation Method(s) or the development of cost allocation methods through the State Agreement Process(es), and that Order No. 1920 does not prevent transmission providers from recognizing different types of benefits and using them to allocate costs in proportion to those benefits. 33. Finally, we specify that the Commission will grant an extension of the required Engagement Period for up to an additional six months when Relevant State Entities request an extension and represent to the Commission that they agree, consistent with their chosen method to reach agreement, that they need additional time to finish cost allocation discussions. If the Commission grants such an extension request, it will also, as appropriate, extend, sua sponte, the relevant Order No. 1920 compliance deadlines to ensure that any extension of the Engagement Period would not conflict with the required compliance deadlines. III. The Overall Need for Reform A. Order No. 1920 34. In Order No. 1920, the Commission found 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. Specifically, the Commission explained that the absence of sufficiently long-term, forward-looking, and comprehensive transmission planning requirements causes transmission providers to fail to adequately anticipate and plan for future system conditions and to fail to appropriately evaluate the benefits of transmission infrastructure. 45 The Commission found that this status quo results in piecemeal transmission expansion to address relatively near-term needs and causes transmission providers to make relatively inefficient investments in transmission infrastructure, the costs of which are ultimately recovered through Commission-jurisdictional rates. One result of this dynamic, the Commission explained, is that transmission customers overpay to meet their transmission needs and forgo benefits that outweigh their costs, which results in less efficient or cost-effective transmission investments. Such deficiencies, the Commission found, render Commission-jurisdictional regional transmission planning and cost allocation processes unjust, unreasonable, and unduly discriminatory or preferential. 46 45 Order No. 1920, 187 FERC ¶ 61,068 at P 85. 46 Id. 35. The Commission explained that it has the authority to issue Order No. 1920 under FPA section 206, which “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.' ” 47 The Commission concluded that the D.C. Circuit has recognized that regional transmission planning and cost allocation processes are practices affecting rates subject to the Commission's exclusive jurisdiction 48 and that 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. 49 The Commission found that, because these processes identify, evaluate, and select the regional transmission facilities whose costs will be recovered through transmission rates, they directly affect those rates. 50 The Commission found that, because such regional transmission facilities lead to a more robust transmission system, regional transmission planning and cost allocation processes, as well as “the rules and practices that determine how those [processes] operate,” 51 directly affect rates that customers pay for both transmission and sale of electric energy in interstate commerce. 52 The Commission noted that it may act pursuant to FPA section 206 if the Commission first establishes, through substantial evidence, 53 that existing practices are unjust, unreasonable, or unduly discriminatory or preferential and, second, establishes that the replacement practices are just and reasonable. 54 47 Id. P 86 (citation omitted) (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55). 48 Id. (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-59, 84). 49 Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56). 50 Id.; see also id. P 86 n.186 (citing Conn. Dep't of Pub. Util. Control v. FERC, 569 F.3d 477, 485 (D.C. Cir. 2009)). 51 Id. P 86 (quoting FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 279 (2016) ( EPSA )). 52 Id. (citing 16 U.S.C. 824e(a)). 53 Id. (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 54). The Commission explained that FPA section 206 empowers the Commission to address the mere threat of unjust and unreasonable rates and, in this context the Commission need not necessarily provide empirical evidence for every proposition to satisfy the substantial evidence standard. Order No. 1920, 187 FERC ¶ 61,068 at P 86 n.189 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64-65, 85). 54 Id. (citing 16 U.S.C. 824e(a); EPSA, 577 U.S. at 277). 36. Addressing whether existing rates, or practices affecting rates, remain just and reasonable— i.e., the first prong under FPA section 206 55 —the Commission found that existing Order No. 890 and Order No. 1000 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, and transmission providers therefore often do not identify, evaluate, or select more efficient or cost-effective regional transmission solutions to meet Long-Term Transmission Needs. 56 The Commission determined that this results in piecemeal, inefficient, and less cost-effective transmission planning, which imposes real costs on customers 57 and renders the Commission's existing transmission planning and cost allocation requirements unjust, unreasonable, and unduly discriminatory or preferential in violation of FPA section 206. 58 55 See Pub. Serv. Elec. & Gas Co. v. FERC, 989 F.3d 10, 13 (D.C. Cir. 2021) (explaining that section 206 “mandates a two-step procedure” whereby the Commission, on the first step, must make an explicit finding that the existing rate is unlawful and then, on the second step, must set a new rate. (quotation omitted)). 56 Order No. 1920, 187 FERC ¶ 61,068 at P 87. 57 Id. 58 Id. P 88. 37. The Commission also found that existing transmission planning and cost allocation requirements are insufficient to ensure just and reasonable and not unduly discriminatory or preferential rates. Thus, pursuant to FPA section 206, the Commission stated that it is now requiring transmission providers to 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. The Commission found that such 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. 59 59 Id. P 89. 1. The Transmission Investment Landscape Today 38. The Commission explained that due to continuing changes in the industry, ongoing investment in transmission facilities is necessary to ensure the transmission system remains reliable, affordable, and economically efficient. More comprehensive transmission planning can enable transmission providers to proactively identify potential reliability problems and economic constraints and evaluate potential transmission solutions, which can facilitate the selection of more efficient or cost-effective transmission facilities to meet Long-Term Transmission Needs. 60 Transmission infrastructure can also increase competition among generators, which results in a host of benefits for customers, including cost savings from greater access to low-cost power. 61 60 Id. P 90 (citations omitted). 61 Id. P 91. 39. The Commission cited evidence demonstrating a nationwide increase in transmission spending since the issuance of Order No. 1000 and explained that, unsurprisingly, transmission costs have become an increasing share of customers' overall electricity bills in regions that saw a significant increase in transmission expenditures. 62 Further, the Commission highlighted several studies in the record demonstrating that transmission investment is likely to increase substantially in coming years. 63 62 Id. P 92 (citations omitted). 63 Id. P 93 (citations omitted). 40. The Commission found that a number of factors are driving the growing need for new transmission infrastructure. 64 First, the Commission found that longer-term reliability needs are changing and driving a significant shift in the demands placed on the transmission system, and transmission system operators are increasingly depending on regional transmission facilities to ensure operational stability and system reliability, particularly due to the growing frequency of extreme weather events and increasing share of variable resources entering the resource mix. 65 Second, after many years of flat or minimal load growth in regions across the country, the Commission found that both regional and national demand is projected to increase significantly in the coming decades, which will require an increasingly robust transmission system to serve this growing load reliably. Third, the Commission found that supply is changing, driven by federal, federally-recognized Tribal, state, and local policies, customer demands, utility commitments, and the shifting economics of resources that comprise the resource mix. 66 64 Id. P 94 (citations omitted). 65 Id. (citations omitted). 66 Id. PP 96-99 (citations omitted). 41. The Commission also found that the record in this proceeding affirms the Commission's longstanding recognition that regional transmission planning that identifies more efficient or cost-effective transmission solutions helps to ensure cost-effective transmission development for customers and can yield better returns for every dollar spent than localized or piecemeal transmission solutions, while inadequate or poorly designed transmission planning processes can cause customers to foot the bill for piecemeal, inefficient, and less cost-effective transmission solutions. 67 67 Id. P 100 (citations omitted). 42. Based on its experience implementing Order No. 1000, the Commission found that existing regional transmission planning processes are not of sufficient scope and duration to adequately or consistently identify transmission needs and associated opportunities to evaluate and select, on a more comprehensive basis, more efficient or cost-effective transmission solutions to those needs. 68 The Commission explained that, in some regions, investment in regional transmission facilities has declined as compared to prior to Order No. 1000 and that, across all non-RTO/ISO regions, not a single transmission facility has been selected pursuant to the regional planning processes since implementation of Order No. 1000. The Commission noted that, within some RTO/ISO regional transmission planning processes, even where investments through the regional transmission planning process occur, much of that investment has been in transmission projects that only address immediate reliability needs. 69 The Commission also cited evidence showing that, in the limited instances in which transmission providers have followed processes that share many of the elements that Order No. 1920 requires, customers have seen clear and quantifiable benefits. 70 68 Id. P 101. 69 Id. (citations omitted). 70 Id. P 102. 43. Further, the Commission explained that a substantial amount of new transmission investment is occurring in generator interconnection processes and local transmission planning processes, which, unlike regional transmission planning processes, do not comprehensively assess either broader transmission needs or solutions to those needs. The Commission concluded that overreliance on those processes can result in relatively inefficient or less cost-effective transmission development for customers, which contributes to rates for transmission that are unjust and unreasonable. 71 71 Id. P 103 (citations omitted). 44. The Commission cited evidence showing a sharp growth in both the total cost of interconnection-related network upgrades and in the cost of such upgrades relative to generation project costs, as well as evidence showing that increases in interconnection costs are being driven, in many cases, by an expansion in the scope and complexity of interconnection-related network upgrades. 72 The Commission noted that, unlike regional transmission planning processes, the generator interconnection process is not designed to consider how to address transmission needs more efficiently or cost-effectively beyond the discrete interconnection request (or requests) being studied. 73 The Commission found that increasingly relying on interconnection customers' interconnection-related network upgrades to expand the capacity of the transmission system is inefficient and leads to less cost-effective transmission development than would result from long-term, forward-looking, and more comprehensive regional transmission planning, to the detriment of customers. 74 72 Id. PP 104-105 (citations omitted). 73 Id. P 106. 74 Id. P 108. 45. The Commission also cited evidence that, since the issuance of Order No. 1000, the majority of investment in transmission facilities has been in local transmission facilities, a trend that is accelerating across multiple regions. 75 The Commission noted evidence that transmission expansion through local transmission planning and in-kind replacement processes is incremental and misses the potential to identify, evaluate, and select more efficient or cost-effective transmission facilities to solve transmission needs, as well as to afford system-wide benefits that may not be achieved through piecemeal, one-off local transmission facilities. 76 Such transmission planning, the Commission stated, results in relatively inefficient or less cost-effective transmission development for customers, which contributes to rates for transmission that are unjust and unreasonable. 77 75 Id. P 109. 76 Id. P 110 (citations omitted). 77 Id. The Commission acknowledged the important roles played by generator interconnection processes and local transmission planning processes and underscored that the Commission's findings were not intended to call into question the justness and reasonableness of either process. Id. P 111. 2. Unjust, Unreasonable, and Unduly Discriminatory or Preferential Commission-Jurisdictional Transmission Planning and Cost Allocation Processes 46. The Commission concluded that there is substantial evidence in the record to support the determination that sufficiently long-term, forward-looking, and comprehensive regional transmission planning and cost allocation to meet Long-Term Transmission Needs is not occurring on a consistent and sufficient basis. 78 The Commission found that the absence of a sufficiently long-term, forward-looking, and comprehensive regional transmission planning process results in relatively unfavorable outcomes, including: piecemeal transmission expansion to address relatively near-term transmission needs, transmission providers undertaking investments in relatively inefficient or less cost-effective transmission infrastructure, and transmission customers paying more than is necessary or appropriate to meet their transmission needs and/or forgoing benefits that outweigh their costs. 79 78 Id. P 112. 79 Id. 47. The Commission determined that there is substantial evidence in the record to support the conclusion that the Commission's regional transmission planning and cost allocation requirements are deficient, thus rendering Commission-jurisdictional regional transmission planning and cost allocation processes unjust and unreasonable. Specifically, the Commission found that existing regional transmission planning and cost allocation requirements fail to require transmission providers to: (1) perform a sufficiently long-term assessment of transmission needs that identifies Long-Term Transmission Needs; (2) adequately account on a forward-looking basis for known determinants of Long-Term Transmission Needs; and (3) consider the broader set of benefits of regional transmission facilities planned to meet those Long-Term Transmission Needs. 80 80 Id. P 114. 48. As to the first deficiency—the lack of sufficiently long-term planning—the Commission cited evidence in the record demonstrating that, under the status quo, most transmission planning regions do not plan beyond a 10-year transmission planning horizon. 81 The Commission stated that the absence of any consistent and sufficient longer-term assessment of transmission needs prevents transmission providers from identifying Long-Term Transmission Needs and considering regional transmission facilities that may be more efficient or cost-effective solutions to address those needs. 82 The Commission added that short-term transmission planning fails to take advantage of the potential for efficiencies or economies of scale that regional transmission facilities can provide and fails to create opportunities to “right size” the replacement of aging transmission facilities to address multiple transmission needs over the longer term. Further, the Commission stated that the time horizon over which much transmission planning is often occurring is shorter than the time needed to plan and construct large ( e.g., high voltage or long distance) transmission facilities 83 and much too short to capture all of the benefits that regional transmission facilities can provide. 84 81 Id. P 115. 82 Id. (citations omitted). 83 Id. P 116 (citations omitted). 84 Id. (citations omitted). 49. The Commission noted that the likelihood that near-term assessments will fail to identify Long-Term Transmission Needs and more efficient or cost-effective regional transmission facilities to meet those needs is higher during periods of rapid change, as the electric sector is now experiencing, during which the need for transmission infrastructure is expected to grow considerably. 85 85 Id. P 117 (citations omitted). 50. The second deficiency the Commission discussed is that the Commission's existing regional transmission planning and cost allocation requirements fail to require transmission providers to account adequately on a forward-looking basis for known determinants of Long-Term Transmission Needs; moreover, the Commission stated, transmission providers are not consistently or sufficiently doing so. 86 The Commission further stated that the record demonstrates that there are numerous factors that increasingly shape Long-Term Transmission Needs, are known and identifiable, and have reasonably predictable effects, especially in the aggregate, such as reliability needs driven by the impact of extreme weather; trends in future generation additions and retirements; load growth; federal, federally-recognized Tribal, state, and local laws and regulations; and utility goals. 87 The Commission determined, however, that existing regional transmission planning processes frequently undervalue or do not consider some or all of these factors, and that the Commission's existing regional transmission planning requirements do not ensure that such factors will be sufficiently accounted for in that planning. 88 The Commission noted that the failure to adequately consider such factors delays planning for the transmission system's changing operational needs until shortly before those transmission needs manifest. As a result, the Commission stated, existing regional transmission planning processes are piecemeal and fail to take advantage of economies of scale in transmission investment or opportunities to address multiple transmission needs over multiple time horizons, which leads to transmission investment that is not more efficient or cost-effective and renders Commission-jurisdictional regional transmission planning and cost allocation processes unjust and unreasonable. 89 86 Id. P 118. 87 Id. P 119. 88 Id. P 120. 89 Id. P 121 (citations omitted). 51. The third deficiency that the Commission identified is that the Commission's regional transmission planning and cost allocation requirements fail to require transmission providers to adequately consider the broader set of benefits of regional transmission facilities planned to meet Long-Term Transmission Needs. The Commission pointed to evidence demonstrating that many regional transmission planning processes focus too narrowly only on some benefits, while other regional transmission planning processes fail entirely to consider cost savings associated with certain transmission facilities. 90 The Commission also explained that the cost-benefit analyses that transmission providers often use provide an inaccurate portrayal of the comparative benefits of different transmission facilities, which results in transmission customers forgoing benefits that may significantly outweigh their costs and in less efficient or cost-effective transmission investments, and ultimately contributes to Commission-jurisdictional rates that are unjust and unreasonable. 91 90 Id. P 122 & n.312. 91 Id. P 123. 52. The Commission determined that, given its findings concerning the deficiencies in existing transmission planning requirements, and its conclusion that long-term, forward-looking, and more comprehensive regional transmission planning is needed, existing cost allocation requirements are also deficient and must be modified to properly account for Long-Term Regional Transmission Planning. 92 92 Id. P 124. 53. The Commission determined that its current cost allocation requirements, which were designed in the context of the Order No. 1000 regional transmission planning process, are insufficient to appropriately allocate costs associated with regional transmission facilities selected in accordance with Order No. 1920's Long-Term Regional Transmission Planning requirements. 93 The Commission's existing Order No. 1000 cost allocation requirements contemplate the application of differing cost allocation methods to different types of transmission facilities, but Order No. 1920's approach to Long-Term Regional Transmission Planning accounts for multiple drivers of Long-Term Transmission Needs and results in Long-Term Regional Transmission Facilities that produce a broader set of benefits and therefore warrants a different approach to cost allocation. 94 The Commission also explained that existing Order No. 1000 regional transmission planning processes do not mandate the consideration of specific benefits and that information concerning these benefits may be relevant when allocating the costs of Long-Term Regional Transmission Facilities in a manner that is at least roughly commensurate with their benefits. 95 Further, the Commission noted that under existing cost allocation requirements, there is no dedicated process to engage states in the development of regional cost allocation methods. The Commission explained that engaging states in cost allocation is particularly relevant to Long-Term Regional Transmission Planning given the long lead times for construction of transmission projects, which create uncertainty for Long-Term Regional Transmission Facilities and increase the importance of ensuring that such facilities will obtain needed siting approvals from the states and are thus timely and cost-effectively developed. The Commission therefore concluded that it is both necessary and appropriate to establish specific cost allocation requirements tailored to the Long-Term Regional Transmission Planning reforms. 96 93 Id. P 126. 94 Id. 95 Id. (citing ICC v. FERC I, 576 F.3d at 477; Order No. 1000, 136 FERC ¶ 61,051 at PP 622, 639). 96 Id. 54. The Commission found that there is substantial evidence in the record demonstrating that Long-Term Regional Transmission Planning and cost allocation to identify and plan for Long-Term Transmission Needs does not occur on a consistent and sufficient basis. 97 The Commission added that this is largely due to the deficiencies it identified regarding existing regional transmission planning and cost allocation requirements. 98 The Commission also found that, under the status quo, transmission providers are meeting many transmission needs by identifying transmission solutions and developing transmission facilities outside of the regional transmission planning and cost allocation processes or in response to near-term reliability needs. 99 The Commission stated that this approach may not identify more efficient or cost-effective transmission solutions and will saddle consumers with the costs of relatively inefficient or less cost-effective piecemeal transmission investment and expansion. 100 97 Id. P 127 (citations omitted). 98 Id. 99 Id. (citations omitted). 100 Id. P 128 (citations omitted). 55. Moreover, the Commission found that transmission needs in most transmission planning regions are rapidly changing and exacerbating concerns arising from the absence of sufficiently long-term, forward-looking, and comprehensive regional transmission planning and cost allocation processes and the corresponding failure by transmission providers to identify and evaluate more efficient or cost-effective transmission solutions to Long-Term Transmission Needs. 101 The Commission emphasized that it is reacting to well-documented factors, which the record demonstrates are driven by exogenous forces beyond the Commission's jurisdiction or control, including, but not limited to, the increasing frequency of extreme weather events, customer preferences, demand growth, economic and technological trends, and federal, federally-recognized Tribal, state, and local policies. 102 101 Id. P 129. 102 Id. (citation omitted). 56. The Commission stated that Order No. 1920 does not aim to affect—either facilitate or hinder—any changes or decisions that occur outside of the Commission's jurisdiction. 103 Instead, the Commission explained, Order No. 1920 focuses on ensuring that Commission-jurisdictional processes associated with regional transmission planning and cost allocation result in rates that are just and reasonable and not unduly discriminatory or preferential; Order No. 1920 seeks to ensure that such regional transmission planning processes are adequately “ accounting for” changes occurring outside of the Commission's jurisdiction, including the resource decisions that are the exclusive jurisdiction of states. 104 103 Id. P 130 (emphasis in original). 104 Id. (citing PJM Power Providers Grp. v. FERC, 88 F.4th 250, 275 (3d Cir. 2023); Elec. Power Supply Ass'n v. Star, 904 F.3d 518, 524 (7th Cir. 2018)). 57. The Commission disagreed with arguments that it could not rely on general findings, rather than individualized analyses of each, specific transmission planning region, as the basis for Order No. 1920. 105 The Commission explained that it was acting pursuant to relevant precedent, which makes clear that the Commission need not make findings that are region-specific in every case and is instead empowered to “rely on `generic' or `general' findings of a systemic problem to support imposition of an industry-wide solution,” 106 notwithstanding regional variation among regional transmission planning processes. Moreover, the Commission acknowledged that, while transmission planning practices vary considerably between transmission planning regions, the record demonstrates that deficiencies in transmission planning processes “reach well beyond `isolated pockets' ” 107 and instead pervade large swathes of the country, including RTO/ISO and non-RTO/ISO planning regions. 108 Thus, the Commission added, Order No. 1920 does not present an “extreme `disproportion of remedy to ailment.' ” 109 The Commission also noted that it has discretion to decide the most efficient approach for resolving industry-wide problems. 110 Further, the Commission reasoned, “region-specific solutions will lead to `siloed and disjunctive transmission planning policies [that] will not solve the problems facing the nation's electric grid.' ” 111 105 Id. P 132 (citations omitted). 106 Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67 (quoting Interstate Nat. Gas Ass'n of Am. v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002))). 107 Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67) (alteration omitted). 108 Id. (citations omitted). 109 Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67) (alteration omitted). 110 Id. (citing Order No. 1000, 136 FERC ¶ 61,051 at P 60). 111 Id. (quoting ACEG NOPR Reply Comments at 17). 58. The Commission stated that the record shows that significant changes in transmission needs are well underway nationwide and that failing to account for Long-Term Transmission Needs threatens just and reasonable rates across the country. 112 The Commission also noted that significant investments in new transmission facilities are expected to occur and substantially affect Commission-jurisdictional rates that customers pay, which underscores the importance of addressing deficiencies in its regional transmission planning and cost allocation requirements now. 113 112 Id. P 133 (citation omitted). 113 Id. (citing Order No. 1000, 136 FERC ¶ 61,051 at PP 46, 50). 3. Benefits of Long-Term Regional Transmission Planning and Cost Allocation To Identify and Plan for Long-Term Transmission Needs 59. Based on the record, the Commission found that Order No. 1920's requirements will help to ensure just and reasonable Commission-jurisdictional rates by addressing deficiencies in the existing regional transmission planning and cost allocation requirements and promoting enhanced reliability and more efficient or cost-effective transmission solutions. 114 The Commission noted evidence in the record demonstrating that the kind of regional transmission planning required by Order No. 1920 will help transmission providers to identify, evaluate, and select more efficient or cost-effective transmission solutions to Long-Term Transmission Needs. 115 114 Id. P 134. 115 Id. P 135. 60. The Commission found that Long-Term Regional Transmission Planning that expands the transmission planning horizon and considers factors affecting Long-Term Transmission Needs as well as a broader list of benefits will: (1) reduce reliance on transmission solutions that are relatively inefficient or less cost-effective because they address only short-term transmission needs; (2) unlock the benefits of economies of scale in transmission investment; 116 (3) enable opportunities to “right size” replacement transmission facilities; 117 (4) facilitate the selection of regional transmission facilities that could address multiple transmission needs over different time horizons; and (5) provide states, utilities, customers, and other stakeholders with greater insight and transparency into the costs and benefits of particular transmission solutions to address Long-Term Transmission Needs. The Commission concluded that these regional transmission planning and cost allocation reforms will help to ensure just and reasonable rates. 118 The Commission added that sufficiently long-term, forward-looking, and comprehensive regional transmission planning and cost allocation processes will also enhance reliability because a robust, well-planned transmission system is foundational to ensuring an affordable, reliable supply of electricity. 119 Additionally, the Commission cited evidence demonstrating how long-term, forward-looking, and more comprehensive regional transmission planning can better identify reliability needs and resolve those needs with more efficient or cost-effective transmission solutions. 120 116 Id. P 136 (citation omitted). 117 Id. (citations omitted). 118 Id. (citations omitted). 119 Id. P 137. 120 Id. P 138 (citations omitted). B. The Commission Adequately Demonstrated That Existing Rates, or Practices Affecting Rates, Are Unjust and Unreasonable 61. We sustain the Commission's determination in Order No. 1920 that existing regional transmission planning and cost allocation processes are unjust and unreasonable, and unduly discriminatory or preferential. We conclude that this finding, as well as the Commission's finding that the identified deficiencies in transmission planning and cost allocation processes render existing Commission-jurisdictional rates unjust and unreasonable, was based on substantial record evidence, reflecting significant input from nearly 200 stakeholders across the country, third-party reports and studies, and the Commission's extensive knowledge of the industry and expert predictions regarding the transmission planning processes and cost allocation requirements that the Commission itself has established and oversees in carrying out its statutory responsibilities. We disagree with several rehearing parties who argue that the Commission failed to satisfy its burden under the first prong of FPA section 206 to show that Order No. 1000 regional transmission planning and cost allocation processes are unjust, unreasonable, or unduly discriminatory and preferential. 121 First, we disagree with certain rehearing parties as to the nature of the Commission's evidentiary burden under FPA section 206. Second, we conclude that the Commission's factual findings and the substantial evidence supporting those findings satisfies, and exceeds, the Commission's burden under FPA section 206. Third, we find that the “deficiencies identified by the Commission” in Order No. 1920 do not “`exist[ ] only in isolated pockets' ” and such evidence is supported by the record. Finally, we conclude that the Commission has authority to conduct a nationwide rulemaking. We address these points in turn. 121 Alabama Commission Rehearing Request at 3-4; Designated Retail Regulators Rehearing Request at 3, 7-8, 19-22; Industrial Customers Rehearing Request at 3-4, 6, 11-18; SERTP Sponsors Rehearing Request at 28-29, 31-37; Undersigned States Rehearing Request at 7, 19-21; Arizona Commission Rehearing Request at 19-20. 1. The Commission Correctly Characterized Its Statutory Burden a. Requests for Rehearing 62. SERTP Sponsors contend that the Commission must demonstrate more than theoretical deficiencies to support nationwide policies and that systemic problems must be demonstrated beyond isolated issues. 122 SERTP Sponsors argue that Order No. 1920's findings, which are based on theory and supposition, are insufficient to carry the applicable burden and are contradicted by substantial specific evidence about SERTP. 123 SERTP Sponsors argue that South Carolina Public Service Authority v. FERC “does not stand for the proposition that any assertion of any theoretical problem by FERC is enough to satisfy the first step of the analysis under [s]ection 206.” 124 SERTP Sponsors contend that except in limited circumstances— e.g., when there is a lack of empirical evidence—the D.C. Circuit requires more than theoretical deficiencies to support nationwide policies. 125 122 SERTP Sponsors Rehearing Request at 34 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 71). 123 Id. 124 Id. at 31 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65). 125 Id. at 29, 31, 34. 63. Relatedly, Industrial Customers claim that Order No. 1920 is “legally infirm” because it does not make specific findings that rates and practices are unjust, unreasonable, or unduly discriminatory or preferential and instead “proposes to amend Order No. 1000 based upon mere concerns that Order No. 1000 may not be planning transmission in a manner that comports with the FPA.” 126 126 Industrial Customers Rehearing Request at 16-17 (emphasis in original). b. Commission Determination 64. We sustain our determination under the first prong of FPA section 206 and find that the Commission relied on sufficient and appropriate evidence to support its determination that existing rates are unjust and unreasonable. We disagree with SERTP Sponsors' and Industrial Customers' arguments that the Commission did not satisfy its section 206 burden because its analysis under the first prong of FPA section 206 was predicated “entirely on theory and supposition” 127 or on “mere concerns” that Order No. 1000 processes “ may not be planning transmission in a manner that comports with the FPA.” 128 Setting aside that in making this determination the Commission did not rely solely on “supposition” or “mere concerns” about deficiencies in the Order No. 1000 regional transmission planning and cost allocation processes, 129 SERTP Sponsors' and Industrial Customers' arguments disregard well-established principles regarding the findings and type of evidence sufficient to support a conclusion that the Commission's burden under the first prong of FPA section 206 has been satisfied, as established by longstanding authority, including the D.C. Circuit's opinion in South Carolina Public Service Authority v. FERC. 127 SERTP Sponsors Rehearing Request at 31. 128 Industrial Customers Rehearing Request at 16-17. 129 See, e.g., Order No. 1920, 187 FERC ¶ 61,068 at PP 93-97, 114-123 (discussed below in The Commission Adequately Supported Its Determination on Step One of Section 206 section). 65. In South Carolina Public Service Authority v. FERC, the D.C. Circuit—reviewing Order No. 1000, which the Commission adopted to address the “theoretical threat” of unjust or unreasonable rates “stemm[ing] from the absence of [transmission] planning processes that take a sufficiently broad view of both the tasks involved and the means of addressing them”—rejected arguments similar to those made here by Industrial Customers. 130 In particular, petitioners there, similar to Industrial Customers here, argued that the “`theoretical threat' described by the Commission fail[ed] to satisfy its evidentiary burden under [s]ection 206 . . . .” 131 130 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64 (alteration omitted) (quoting Order No. 1000, 136 FERC ¶ 61,051 at P 52). 131 Id. 66. The court squarely rejected that contention. 132 It explained that the substantial evidence required to support a finding that an existing practice affecting rates is “unjust, unreasonable, unduly discriminatory or preferential” pursuant to FPA section 206 “requires `more than a scintilla' but `less than a preponderance' of evidence.” 133 Substantial evidence, however, “does not necessarily mean empirical evidence,” 134 and, in satisfying the substantial evidence standard, the Commission may rely on its own predictions as long as they are “`at least likely enough to be within the Commission's authority' and [are] based on reasonable economic propositions.” 135 As the court recognized, “[a]gencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall.” 136 132 Id. 133 Id. at 54 (quoting Fla. Gas Transmission Co. v. FERC, 604 F.3d 636, 645 (D.C. Cir. 2010)), 64-65 (citing 16 U.S.C. 824e(a)), 5 U.S.C. 706(2)(E))). 134 Id. at 65 (citing 5 U.S.C. 706(2)(E)); see also Xcel Energy Servs. Inc. v. FERC, 41 F.4th 548, 560-61 (D.C. Cir. 2022) (“In making decisions, it is `perfectly legitimate for the Commission to base its findings on basic economic theory,' including relying on `generic factual predictions,' as long as the agency `explains and applies the relevant economic principles in a reasonable manner.'” (cleaned up) (quoting Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 531 (D.C. Cir. 2010) (per curiam))); id. (“Where the `promulgation of generic rate criteria clearly involves the determination of policy goals or objectives, and the selection of means to achieve them,' the `courts reviewing an agency's selection of means are not entitled to insist on empirical data for every proposition on which the selection depends.'” (alterations omitted) (quoting Associated Gas Distribs. v. FERC, 824 F.2d 981, 1008 (D.C. Cir. 1987) ( Associated Gas Distributors ))). 135 Id.; see also id. at 76 (“[A]t least in circumstances where it would be difficult or even impossible to marshal empirical evidence, the Commission is free to act based upon reasonable predictions rooted in basic economic principles.”). 136 Id. at 65 (quoting Associated Gas Distributors, 824 F.2d at 1008); see also Cent. Hudson Gas & Elec. Corp. v. FERC, 783 F.3d 92, 109 (2d Cir. 2015) (“FERC may permissibly rely on economic theory alone to support its conclusions so long as it has applied the relevant economic principles in a reasonable manner and adequately explained its reasoning.”). 67. The court in reviewing Order No. 1000 determined that the Commission had satisfied its evidentiary burden under section 206. In particular, the Commission had identified “significant changes in the nation's electric power industry” that presented “significant challenges to the development and cost allocation of interstate transmission projects” and highlighted five deficiencies in Order No. 890's transmission planning and cost allocation processes. 137 Ultimately, the court held that the Commission's determination that the then-current transmission planning and cost allocation practices were unjust or unreasonable was based on substantial evidence. 138 137 Id. at 66. 138 See id. at 67. 68. By insisting that the Commission was required to demonstrate that rates or practices are, in fact, unjust, unreasonable, or unduly discriminatory or preferential, 139 SERTP Sponsors and Industrial Customers overlook principles articulated in South Carolina Public Service Authority v. FERC, including that the Commission need not provide empirical evidence for every proposition and may instead rely upon the threat of unjust and unreasonable rates as a basis for taking action. 140 Their argument is predicated on a faulty premise that, in a rulemaking setting, the Commission must wait for a threat to result in actual harm, and may not act where it anticipates harmful consequences. 141 But in South Carolina Public Service Authority v. FERC, the court explicitly reached the opposite conclusion, holding that the Commission satisfied its evidentiary burden under section 206 by relying on the theoretical threat to just and reasonable rates even though the Commission acknowledged other evidence in the record. 142 SERTP Sponsors are thus incorrect to suggest that the South Carolina Public Service Authority v. FERC court allowed the Commission to rely on generic factual findings only because the record lacked empirical evidence. 143 139 Industrial Customers Rehearing Request at 16-17; SERTP Sponsors Rehearing Request at 34. 140 See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64-65; see also id. at 85 (“[W]hether a threat of unjust or unreasonable rates derives from a practice or the absence thereof, Section 206 empowers the Commission to address it.”); Nat'l Fuel Gas Supply Corp. v. FERC, 468 F.3d 831, 844 (D.C. Cir. 2006) (stating that the Commission could choose to “rely solely on a theoretical threat”). 141 See Industrial Customers Rehearing Request at 16-17. 142 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64, 67. 143 SERTP Sponsors Rehearing Request at 29. 69. South Carolina Public Service Authority v. FERC makes clear that, because “substantial evidence” is not limited to empirical evidence and may include generic factual predictions, the Commission could have satisfied its evidentiary burden under the first prong of FPA section 206 with analysis based on theoretical threats and predictions regarding such threats based on reasonable economic propositions within the Commission's expertise. 144 Here, however, the Commission established a theoretical threat and, as discussed below, also cited substantial empirical and other record evidence to support its finding that the existing regional transmission planning processes and cost allocation requirements—and the rates that have resulted from them—are unjust and unreasonable. 144 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65 (quoting Associated Gas Distributors, 824 F.2d at 1008). 2. The Commission Adequately Supported Its Determination on Step One of Section 206 a. Requests for Rehearing 70. Designated Retail Regulators argue that, in its analysis under the first prong of section 206 of the FPA, the Commission made conclusory, “blanket claims that are unsupported by evidence.” 145 Undersigned States similarly assert that the Commission does not “point to evidence in the record sufficient to support” a finding that existing regional transmission planning and cost allocation processes are resulting in unjust, unreasonable, unduly discriminatory, and preferential Commission-jurisdictional rates because “such evidence does not exist.” 146 Arizona Commission contends that the evidence in the record used to support Order No. 1920's section 206 finding consists largely of comments from special interest groups that will profit from Order No. 1920 and not evidence specific to the Arizona Commission. 147 145 Designated Retail Regulators Rehearing Request at 20-21. 146 Undersigned States Rehearing Request at 21. 147 Arizona Commission Rehearing Request at 19. 71. Industrial Customers claim that, rather than making specific findings that existing practices are unjust and unreasonable, the Commission made “several generic assertions . . . to reach very broad conclusions,” 148 and “generically assert[ed]” that the Commission satisfies its burden under the first prong of the FPA section 206 inquiry “based on the record.” 149 Industrial Customers assert that the failure to reach specific findings, supported by substantial evidence, under the first prong of FPA section 206 renders Order No. 1920 legally infirm. 150 Industrial Customers claim that the absence of detailed and substantiated findings makes it “difficult, if not impossible” for transmission providers to file compliance filings because it will be challenging to develop and propose solutions without an understanding of the root problem the Commission is trying to fix. 151 148 Industrial Customers Rehearing Request at 16. 149 Id. at 13 (alteration omitted). 150 Id. at 17. 151 Id. at 17-18. b. Commission Determination 72. We continue to find that the Commission made adequate findings under the first prong of FPA section 206 and marshalled substantial evidence to support those findings. We are therefore not persuaded by rehearing parties' arguments to the contrary. Below, we first summarize the empirical and other record evidence the Commission cited to support its findings that Commission-jurisdictional regional transmission planning and cost allocation processes are unjust and unreasonable because they result in transmission providers failing to identify Long-Term Transmission Needs, to evaluate and select more efficient or cost-effective transmission solutions to meet those transmission needs, and to allocate the costs of transmission facilities selected to meet those transmission needs in a manner that is at least roughly commensurate with benefits. 152 Next, we summarize the Commission's generic factual predictions. We conclude that this evidence is more than sufficient to meet the Commission's evidentiary burden under section 206. 152 Order No. 1920, 187 FERC ¶ 61,068 at PP 114-122. 73. Based on the robust record before it, the Commission concluded that transmission investment, which has increased nationwide since the Commission issued Order No. 1000, 153 is likely to grow substantially in coming years due to three factors that are driving a growing need for new transmission infrastructure. 154 First, reports and comments in the record demonstrated that longer-term reliability needs are changing as transmission providers increasingly rely on regional transmission facilities to ensure operational stability as extreme weather events become more frequent and variable resources increasingly enter the resource mix. 155 Based on evidence in the record, the Commission concluded that transmission investment is likely to be more critical, and produce more reliability benefits for customers, as extreme weather and other system contingencies become more frequent. 156 Second, the Commission noted evidence that electric demand is projected to increase significantly in the coming decades due to electrification trends and new large loads associated with evolving industrial and commercial needs. 157 Again, relying on record evidence, the Commission found that these increases in aggregate electricity demand will have significant consequences for the transmission system. 158 Third, the Commission found that the resource mix is changing due to federal, federally-recognized Tribal, state, and local policies, 159 customer demands for clean energy, 160 utility emission commitments, 161 and the changing economics of resources that comprise the resource mix. 162 153 Id. P 92 (referencing a study by the US DOE, which found that annual investment in transmission first exceeded $5 billion per year in 2006, doubled to more than $10 billion per year by 2010, doubled again by 2016, and has been between $18 billion and $22 billion annually since 2014 (quoting US DOE, National Electric Transmission Congestion Study, at 9-10 (Sept. 2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf )); id. (citing estimates from The Brattle Group and Grid Strategies that transmission developers in the United States invested $20 to $25 billion annually in transmission facilities from 2013 to 2020 (citing Brattle-Grid Strategies Oct. 2021 Report at 2); Brattle Apr. 2019 Competition Report at 2-3 & fig.1)). 154 Id. P 93 (citing a number of studies projecting sustained transmission spending through at least 2050, including one by Princeton University projecting that high voltage transmission capacity must expand by 60 percent by 2030 at a capital cost of $330 billion and must triple by 2050 at a capital cost of $2.2 trillion, as well as another by The Brattle Group projecting $750 billion of new transmission investment between 2023 and 2050. (citing Eric Larson et al., Princeton Univ., Net-Zero America: Potential Pathways, Infrastructure, and Impacts, at 108 (Oct. 2021), https://netzeroamerica.princeton.edu/the-report; Jürgen Weiss et al., The Brattle Group, The Coming Electrification of the North American Economy, at iii (2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf )). 155 The Commission cited comments and reports demonstrating that transmission infrastructure can be critical to system reliability during extreme weather events such as Winter Storm Uri. Id. P 94 & n.209 (citing ACEG NOPR Initial Comments at 22 n.63 (stating that during Winter Storm Uri, “[a]n additional 1 gigawatt (GW) of transmission ties between ERCOT and the Southeastern U.S. could have saved nearly $1 billion and kept power flowing to hundreds of thousands of Texans.”); Grid Strategies July 2021 Extreme Weather Report at 7-8 (“The value of transmission for resilience can be seen in the drastically different outcomes of MISO and SPP relative to ERCOT during [Winter Storm Uri]. . . . In contrast to the 13,000 MW MISO was importing during the peak of [the] event, ERCOT was only able to import about 800 MW of power throughout the event.”)). The Commission also cited research from US DOE's Lawrence Berkeley National Laboratory suggesting that 50% of the value created by alleviating transmission system congestion occurs during only 5% of the hours during which the transmission system is used, further evidence of the significant value of transmission during unanticipated events. Id. P 94 (citing LBNL Aug. 2022 Transmission Value Study at 33). 156 Id. P 94 (citing LBNL Aug. 2022 Transmission Value Study at 33; Clean Energy Associations NOPR Initial Comments at 5). 157 Id. P 95 (citing Jürgen Weiss et al., The Brattle Group, The Coming Electrification of the North American Economy (Mar. 2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf ); John D. Wilson and Zach Zimmerman, Grid Strategies, The Era of Flat Power Demand is Over, at 3 (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (“Over [2023], grid planners nearly doubled the 5-year load growth forecast. The nationwide forecast of electricity demand shot up from 2.6% to 4.7% growth over the next five years, as reflected in 2023 FERC [Form 714] filings. Grid planners forecast peak demand growth of 38 gigawatts (GW) through 2028.”); N. Amer. Elec. Reliability Corp., 2023 Long-Term Reliability Assessment, at 33 (Dec. 2023), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf (“Electricity peak demand and energy growth forecasts over the 10-year assessment period are higher than at any point in the past decade. The aggregated assessment area summer peak demand forecast is expected to rise by 79 GW, and aggregated winter peak demand forecasts are increasing by nearly 91 GW. Furthermore, the growth rates of forecasted peak demand and energy have risen sharply since the 2022 [ Long-Term Reliability Assessment ], reversing a decades-long trend of falling or flat growth rates.”)). 158 See id. P 95 (citing National Grid NOPR Initial Comments at 6 (discussing preliminary findings of the ISO-NE 2050 Transmission Study, which show “significant new transmission will be needed to reliably serve” increased future loads assumed in the study (citing ISO-NE, 2050 Transmission Study (2023), https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf ))). 159 Id. P 96 & nn.223-227 (noting numerous jurisdictions that have adopted decarbonization, electrification, and renewable energy-related laws and policies); id. (citing ACORE NOPR Initial Comments at 1-2 & n.2; American Clean Power Ass'n, It's a Big Deal for Job Growth and for a Clean Energy Future (2022), https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future (“Analysis suggests that the [Inflation Reduction Act] could more than triple clean energy production in the U.S. and lead to $600 billion in capital investment in clean energy infrastructure.”); Evergreen Action NOPR Initial Comments at 3-4; NextEra NOPR Reply Comments at 5); id. P 99. 160 Id. P 97 (“Since 2014, for example, `commercial and industrial customers have contracted for more than 52 GW of clean energy.'” (alteration omitted) (quoting Advanced Energy Buyers NOPR Initial Comments at 5)). 161 Id. P 97 & nn.233-37 (noting that Exelon, Dominion, AEP, Southern, Entergy, Duke Energy, NextEra, and Tennessee Valley Authority have all announced some version of a net-zero carbon emission plan or commitment). 162 Id. P 97 & n.239 (citing ACORE ANOPR NOPR Initial Comments at app. 1, p. 22 (“Wind and solar energy costs have fallen 70 and 89 percent, respectively, in the last ten years, from 2009 through 2019.”)); Order No. 1920, 187 FERC ¶ 61,068 at P 99 (“[A]s of 2021, nearly 70% of capacity additions across the country were from new, utility-scale wind and solar resources[,] . . . [and] those trends are projected to continue, with over 1,300 GW of wind, solar, and storage resources in interconnection queues across the country as of 2021.” (citing SREA NOPR Initial Comments at 1-2; AEE NOPR Initial Comments at 12-13; California Commission NOPR Initial Comments at 65; Renewable Northwest NOPR Initial Comments at 36; FERC, State of the Markets 2020, at 10, 12 (Mar. 2021); FERC, State of the Markets 2023, at 4 (Mar. 2024); US DOE Initial Comments at app. B, PP. 8-9, 26). 74. Considering the changing transmission investment landscape, the Commission then relied on substantial record evidence to find that the Commission's existing regional transmission planning and cost allocation requirements are deficient in three ways and therefore fail to require transmission providers to adequately plan on a sufficiently long-term, forward-looking, and comprehensive basis. 163 163 Id. P 112. 75. The first deficiency that the Commission identified is the lack of a sufficiently long-term assessment of transmission needs. 164 The Commission explained that most transmission planning regions do not plan beyond a 10-year transmission planning horizon, 165 which is shorter than the time needed to plan and construct large ( e.g., high voltage or long distance) transmission facilities 166 or to capture all of the benefits that regional transmission facilities can provide. 167 According to comments and studies in the record, short-term transmission planning also fails to take advantage of the potential for efficiencies or economies of scale that regional transmission facilities can provide and does not create opportunities to “right size” the replacement of aging transmission facilities. 168 Based on this evidence, the Commission concluded that relying solely on shorter-term transmission planning and studies fails to identify Long-Term Transmission Needs and consequently undervalues or entirely ignores the benefits of transmission investments to meet those needs. 169 164 Order No. 1920, 187 FERC ¶ 61,068 at P 115 (citing MISO ANOPR Reply Comments at 5 (“[G]iven long-term needs of an evolving system, additional transmission is necessary to reliably serve customers now and into the future. These challenges require immediate action and further delay only increases the risk that system enhancements may not be in place in the timeframe needed.”); PIOs NOPR Initial Comments at 13 (“[A] short-term outlook under-forecasts longer-term transmission needs, preventing the development of more cost-effective transmission facilities, and fails to consider how the needs of the transmission system are shifting.”); US DOE ANOPR Initial Comments at 10 (stating that failure to plan transmission far enough ahead results in “adverse implications for system reliability, resilience, consumers' electricity rates, and the achievement of clean energy goals”)). 165 Id. (noting that commenters point out that ISO-NE, SERTP, and NorthernGrid use a 10-year transmission planning horizon, while PJM uses a 5-year transmission planning horizon for what it refers to as its short-term transmission planning process and a 6-to-15-year transmission planning horizon for what it refers to as its intermediate-term transmission planning process). 166 Id. P 116 (citing AEP NOPR Initial Comments at 11; Nevada Commission NOPR Initial Comments at 7 n.24; PIOs NOPR Initial Comments at 14; Renewable Northwest NOPR Initial Comments at 5; SEIA NOPR Initial Comments at 6). The Commission discussed MISO's MVP initiative, which took a decade to move from approval by the MISO Board of Directors in 2011 to completion of most of the projects by 2021, a 10-year period that does not even account for the significant transmission facility development efforts that occurred prior to the MISO Board of Directors' approval. Order No. 1920, 187 FERC ¶ 61,068 at P 116 (citing AESL Consulting, A Transmission Success Story: The MISO MVP Transmission Portfolio, at 39 (2021)). 167 Id. (citing SEIA NOPR Initial Comments at 6; US DOE NOPR Initial Comments at 33). 168 Id. (citing ACORE NOPR Initial Comments at 4 (“The narrowly focused current approaches [to transmission planning] do not identify opportunities to take advantage of the large economies of scale in transmission that come from `up-sizing' reliability projects to capture additional benefits, such as congestion relief, reduced transmission losses, and facilitating the more cost-effective interconnection of the renewable and storage resources needed to meet public policy goals.” (quoting Brattle-Grid Strategies Oct. 2021 Report at 3)); PIOs ANOPR Initial Comments at 10-11; SEIA ANOPR Initial Comments at 14). 169 Id. P 117 & n.290 (“Relying on successive small transmission expansion projects to meet foreseeable long-term needs may lead to the need for expensive retrofits (at customers' expense) at a later date. Economies of scale and network economies suggest that an initial larger-scale buildout will often represent a lower-cost solution.” (quoting US DOE ANOPR Initial Comments at 10)); id. (“While the Tranche 1 Portfolio is the result of MISO's long-range planning process being executed for only the second time, the rapid change within the industry will require that it become a more routine aspect of the MISO planning process going forward.” (quoting Midcontinent Independent System Operator, MTEP21 Report Addendum: Long Range Transmission Planning Tranche 1 Portfolio Report, at 6 (July 28, 2022), https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary625790.pdf )). 76. The second deficiency that the Commission identified is that transmission providers are not required to account adequately on a forward-looking basis for known determinants of Long-Term Transmission Needs or to account for such known determinants in a manner that ensures the identification and evaluation of more efficient or cost-effective regional transmission facilities to meet Long-Term Transmission Needs. 170 The Commission highlighted concrete evidence of this deficiency, including that some regional transmission planning processes ignore factors relevant to identifying transmission needs, 171 while others fail to account for factors that will shape future load. 172 The Commission added that, while forecasting necessarily involves uncertainty, the record demonstrates that there are numerous factors that increasingly shape Long-Term Transmission Needs, that are known and identifiable, and have reasonably predictable effects, especially in the aggregate. 173 These include, for example, reliability needs driven by the impact of extreme weather, 174 trends in future generation additions and retirements, 175 load growth, 176 federal, federally-recognized Tribal, state, and local laws and regulations, 177 and utility goals. 178 The Commission explained, however, that existing regional transmission planning processes frequently undervalue or do not consider some or all of these factors, and the Commission's existing regional transmission planning requirements do not ensure otherwise. 179 The Commission found that the failure to adequately consider such factors delays planning for the transmission system's changing operational needs until shortly before those transmission needs manifest, resulting in transmission planning processes that are piecemeal and fail to take advantage of economies of scale in transmission investment or opportunities to address multiple transmission needs over multiple time horizons. 180 170 Id. P 118. 171 Id. (discussing record evidence that some existing regional transmission planning processes ignore trends in future generation, the impact of extreme weather, state laws, and utility goals) (citing Acadia Center and CLF NOPR Initial Comments at 1; GridLab NOPR Initial Comments at 4-5; Brattle-Grid Strategies Oct. 2021 Report at 36; Grid Strategies July 2021 Extreme Weather Report at 5; SPP Market Monitor ANOPR Initial Comments at 3 & n.5; Renewable Northwest NOPR Initial Comments at 4, 8, 12; SREA NOPR Initial Comments at 25)). 172 Id. (discussing record evidence that existing regional transmission planning processes fail to account for factors shaping electrification trends like electric vehicles and data centers (citing AEE ANOPR Initial Comments at 18; Clean Energy Buyers NOPR Initial Comments at 7-8; National Grid NOPR Initial Comments at 8; AEE ANOPR Initial Comments at 18; Rocky Mountain Institute NOPR Supplemental Comments at 1; WIRES NOPR Supplemental Comments at attach. 1, p. 36)). 173 Id. P 119. 174 Id. P 120 (citing ACEG NOPR Initial Comments at 63; NERC NOPR Initial Comments at 6; Evergreen Action NOPR Initial Comments at 2 (“[A]dditional transmission built under improved planning procedures would [ ] create large reliability benefits. With increasing extreme weather events due to climate change—including wildfires, winter storms, hurricanes, and more—additional transmission infrastructure and grid improvements are increasingly necessary for resilience purposes.”); WE ACT NOPR Initial Comments at 2). 175 Id. P 120 (citing Pattern Energy NOPR Initial Comments at 26; SEIA NOPR Initial Comments at 9). 176 Id. (citing Northwest and Intermountain NOPR Initial Comments at 5 n.12; John Wilson and Zach Zimmerman, The Era of Flat Demand is Over, Grid Strategies, at 3, 6 (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (noting the 5-year load growth forecast has nearly doubled from 2.6% to 4.7% and “transmission investments need to increase just to keep up with demand”)). 177 Id. PP 119, 120 (citing Acadia Center and CLF NOPR Initial Comments at 8; AEE NOPR Initial Comments at 10 (noting that “[a]s of September 2020, 38 states and the District of Columbia had adopted renewable portfolio standards, and 21 states (plus the District of Columbia and Puerto Rico)—representing more than half of the U.S. population—include a target of 100% renewable energy by 2050 or sooner. Many of these requirements have been enacted in statute and are binding on utilities and retail energy providers.”)). 178 Id. P 120 (citing Renewable Northwest NOPR Initial Comments at 6; SREA NOPR Initial Comments at 41-46). 179 Id. 180 Id. P 121 (PIOs NOPR Initial Comments at 10-11; Renewable Northwest NOPR Initial Comments at 8). 77. The Commission explained that the third deficiency is that transmission providers are not required to adequately consider the broader set of benefits that accrue to regional transmission facilities planned to meet Long-Term Transmission Needs. 181 Relying on record evidence, the Commission found that many current regional transmission planning and cost allocation processes consider only a narrow subset of benefits that regional transmission facilities provide 182 or fail entirely to consider cost savings associated with certain transmission facilities. 183 181 Id. P 122 (citation omitted). 182 Id. (citing Brattle-Grid Strategies Oct. 2021 Report at 2 (“[M]ost of [the nation's recent transmission] [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%3A2024-27982. Public record. Not legal advice.