# Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2022-08973 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** May 4, 2022 - **Citation:** 87 FR 26504 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM21-17-000] Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection AGENCY: Federal Energy Regulatory Commission. ACTION: Notice of proposed rulemaking. SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes to reform both the pro forma Open Access Transmission Tariff and the pro forma Large Generator Interconnection Agreement to remedy deficiencies in the Commission's existing regional transmission planning and cost allocation requirements. Specifically, the proposal would require public utility transmission providers to; conduct long-term regional transmission planning on a sufficiently forward-looking basis to meet transmission needs driven by changes in the resource mix and demand; more fully consider dynamic line ratings and advanced power flow control devices in regional transmission planning processes; seek the agreement of relevant state entities within the transmission planning region regarding the cost allocation method or methods that will apply to transmission facilities selected in the regional transmission plan for purposes of cost allocation through long-term regional transmission planning; 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; and revise their existing interregional transmission coordination procedures to reflect the long-term regional transmission planning reforms proposed in this NOPR. In addition, the proposal would not permit public utility transmission providers to take advantage of the construction-work-in-progress incentive for regional transmission facilities selected for purposes of cost allocation through long-term regional transmission planning and would permit the exercise of federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider with the federal right of first refusal for such regional transmission facilities establishing joint ownership of the transmission facilities. DATES: Comments are due July 18, 2022 and Reply Comments are due August 17, 2022. ADDRESSES: Comments, identified by docket number, may be filed in the following ways. Electronic filing through https://www.ferc.gov, is preferred. • Electronic Filing: Documents must be filed in acceptable native applications and print-to-PDF, but not in scanned or picture format. • For those unable to file electronically, comments may be filed by USPS mail or by hand (including courier) delivery. ○ Mail via U.S. Postal Service Only: Addressed to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. ○ Hand (including courier) delivery: Deliver to: Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852. The Comment Procedures Section of this document contains more detailed filing procedures. FOR FURTHER INFORMATION CONTACT: David Borden (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734, david.borden@ferc.gov Noah Lichtenstein (Technical Information), Office of Energy Market Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696, noah.lichtenstein@ferc.gov Lina Naik (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8882, lina.naik@ferc.gov SUPPLEMENTARY INFORMATION: Table of Contents Paragraph Nos. I. Introduction 1 II. Background 12 A. Historical Framework: Order Nos. 888, 890, and 1000 12 B. ANOPR and Technical Conference 18 C. Joint Federal-State Task Force on Electric Transmission 20 D. High-Level Overview of ANOPR Comments 23 III. Need for Reform 24 A. Potential Benefits of Long-Term Regional Transmission Planning and Cost Allocation to Identify and Plan for Transmission Needs Driven by Changes in the Resource Mix and Demand 28 B. Unjust and Unreasonable and Unduly Discriminatory and Preferential Commission-Jurisdictional Rates 34 1. The Transmission Investment Landscape Today 36 2. Deficiencies in the Commission's Existing Regional Transmission Planning and Cost Allocation Requirements 47 IV. Regional Transmission Planning 56 A. Overview of Existing Regional Transmission Planning Processes 57 1. Reliability Needs 58 2. Economic Needs 59 3. Transmission Needs Driven by Public Policy Requirements 60 B. Comments 61 C. Proposed Reforms 64 1. Long-Term Regional Transmission Planning 64 a. Need for Reform 64 b. Proposed Reform 68 i. Development of Long-Term Scenarios For Use In Long-Term Regional Transmission Planning 79 (a) Comments 80 (b) Proposed Reform 84 (1) Long-Term Scenarios Requirements 91 (i) Transmission Planning Horizon and Frequency 92 (01) Comments 95 (02) Proposed Requirement 97 (ii) Factors 101 (01) Comments 103 (02) Proposed Requirement 104 (iii) Number and Range of Long-Term Scenarios 113 (01) Comments 118 (02) Proposed Requirement 121 (iv) Specificity of Data Inputs 127 (01) Comments 129 (02) Proposed Requirement 130 (v) Identification of Geographic Zones 135 (01) Comments 136 (02) Proposed Requirement 145 ii. Coordination of Regional Transmission Planning and Generator Interconnection Processes 154 (a) ANOPR 155 (b) Comments 157 (c) Need for Reform 161 (d) Proposed Reform 166 iii. Evaluation of the Benefits of Regional Transmission Facilities 175 (a) Evaluations of Long-Term Regional Transmission Benefits 176 (1) Comments 178 (2) Proposed Reform 183 (3) Description of Long-Term Regional Transmission Benefits 189 (b) Evaluation of Transmission Benefits Over Longer Time Horizon 226 (1) Comments 226 (2) Proposed Reform 227 (c) Evaluation of the Benefits of Portfolios of Transmission Facilities 231 (1) Comments 232 (2) Proposed Reform 233 iv. Selection of Regional Transmission Facilities 236 (a) Comments 238 (b) Proposed Reform 241 c. Implementation of Long-Term Regional Transmission Planning 253 2. Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices in Long-Term Regional Transmission Planning 256 a. ANOPR 256 b. Comments 257 c. Need for Reform 267 d. Proposed Reform 272 V. Regional Transmission Cost Allocation 278 A. Background 280 B. ANOPR 286 C. Comments 288 D. Need for Reform 297 E. Proposed Reform 302 1. State Involvement in Cost Allocation for Long-Term Regional Transmission Facilities 302 a. Agreement of Relevant State Entities 304 b. State Agreement Process 311 2. Time Period in Long-Term Regional Transmission Planning Cost Allocation Processes for State-Negotiated Alternate Cost Allocation Method 319 3. Identification of Benefits Considered in Cost Allocation for Long-Term Regional Transmission Facilities 325 VI. Construction Work in Progress Incentive 328 A. Background 328 B. Need for Reform 330 C. Proposed Reform 333 VII. Exercise of a Federal Right of First Refusal in Commission-Jurisdictional Tariffs and Agreements 335 A. Background 337 1. Order No. 1000's Nonincumbent Transmission Developer Reforms and Federal Right of First Refusal Elimination Mandate 337 2. Experience Since Order No. 1000 343 3. ANOPR 345 4. Comments 346 B. Need for Reform 349 C. Proposed Reform 351 1. Approach to Reform 351 2. Conditional Federal Rights of First Refusal for Certain Jointly-Owned Transmission Facilities 358 a. Background 359 b. Comments 360 c. Proposed Reform 365 VIII. Enhanced Transparency of Local Transmission Planning Inputs In the Regional Transmission Planning Process and Identifying Potential Opportunities to Right-Size Replacement Transmission Facilities 383 A. Background 383 B. ANOPR 387 C. Comments 390 D. Need for Reform 398 E. Proposed Reform 400 IX. Interregional Transmission Coordination and Cost Allocation 416 A. Background 417 B. ANOPR 422 C. Comments 423 D. Need for Reform 424 E. Proposed Reform 426 X. Proposed Compliance Procedures 430 XI. Information Collection Statement 434 XII. Environmental Analysis 451 XIII. Regulatory Flexibility Act [Analysis or Certification] 452 XIV. Comment Procedures 460 XV. Document Availability 463 Appendix A: Abbreviated Names of Commenters Appendix B: Pro Forma Open Access Transmission Tariff Attachment K Appendix C: Pro forma Large Generator Interconnection Procedures (LGIP) I. Introduction 1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) is proposing, pursuant to its authority under section 206 of the Federal Power Act (FPA), 1 to reform its electric regional transmission planning and cost allocation requirements. The proposed reforms are intended to remedy deficiencies in the Commission's existing regional transmission planning and cost allocation requirements to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. 1 16 U.S.C. 824e. Section 206 requires that Commission-jurisdictional rates, terms, and conditions, including those for transmission services, be just and reasonable and not unduly discriminatory or preferential. The phrase “Commission-jurisdictional rates,” as used in this NOPR, includes rates, terms, and conditions. 2. This NOPR builds on Order Nos. 888, 2 890, 3 and 1000, 4 in which the Commission incrementally developed the requirements that govern regional transmission planning and cost allocation processes to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. 2 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Pub. Utils.; Recovery of Stranded Costs by Publ. 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 Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. N. Y. v. FERC, 535 U.S. 1 (2002). 3 Preventing Undue Discrimination & Preference in Transmission Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), 118 FERC ¶ 61,119, order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), 121 FERC ¶ 61,297 (2007), order on reh'g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009). 4 Transmission Planning & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 FERC ¶ 61,051 (2011), order on reh'g, Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132, order on reh'g and clarification, Order No. 1000 -B, 141 FERC ¶ 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014). 3. With respect to regional transmission planning, as discussed in more detail below, the reforms proposed in this NOPR would require public utility transmission providers to conduct long-term regional transmission planning on a sufficiently forward-looking basis to meet transmission needs driven by changes in the resource mix and demand. 5 As part of this long-term regional transmission planning, public utility transmission providers would be required to: (1) Identify transmission needs driven by changes in the resource mix and demand through the development of long-term scenarios that satisfy the requirements set forth in this NOPR, including accounting for low-frequency, high-impact events such as extreme weather events; (2) evaluate the benefits of regional transmission facilities to meet these needs over a time horizon that covers, at a minimum, 20 years starting from the estimated in-service date of the transmission facilities; and (3) establish transparent and not unduly discriminatory criteria to select transmission facilities in the regional transmission plan for purposes of cost allocation that more efficiently or cost-effectively address these transmission needs in collaboration with states and other stakeholders. We do not propose in this NOPR to change Order No. 1000's requirements for public utility transmission providers with respect to existing reliability and economic planning requirements. Additionally, we propose to require that public utility transmission providers more fully consider dynamic line ratings and advanced power flow control devices in regional transmission planning processes. 5 A public utility transmission provider means a public utility that owns, controls, or operates transmission facilities. The term public utility transmission provider should be read to include 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). The term “public utility” means “any person who owns or operates facilities subject to the jurisdiction of the Commission . . . .” 16 U.S.C. 824(e). 4. With respect to transmission cost allocation, the reforms proposed in this NOPR would require that public utility transmission providers in each transmission planning region seek the agreement of relevant state entities within the transmission planning region regarding the cost allocation method or methods that will apply to transmission facilities selected in the regional transmission plan for purposes of cost allocation through long-term regional transmission planning 6 and revise their OATTs to include those method or methods. 6 This NOPR refers to such facilities as “Long-Term Regional Transmission Facilities”. 5. We also propose to not permit public utility transmission providers to take advantage of the construction-work-in-progress (CWIP) incentive for regional transmission facilities selected for purposes of cost allocation through long-term regional transmission planning. 6. With respect to federal rights of first refusal, the reforms proposed in this NOPR would amend Order No. 1000's requirements, in part, to permit the exercise of federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider with the federal right of first refusal for such regional transmission facilities establishing joint ownership of the transmission facilities consistent with the proposal below. 7. With respect to transparency and coordination, we propose to require public utility 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. 8. With respect to interregional transmission coordination and cost allocation, the reforms proposed in this NOPR would require that public utility transmission providers revise their existing interregional transmission coordination procedures to reflect the long-term regional transmission planning reforms proposed in this NOPR. 9. The proposed reforms in this NOPR related to regional transmission planning and cost allocation requirements, like those of Order Nos. 890 and 1000, are focused on the transmission planning process, and not on any substantive outcomes that may result from this process. Taken together, these proposed reforms would work together to remedy deficiencies in the Commission's existing regional transmission planning and cost allocation requirements. This, in turn, would fulfill our statutory obligation to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. 10. The Advance Notice of Proposed Rulemaking (ANOPR), 7 the Commission also sought comment on reforms related to cost allocation for interconnection-related network upgrades, interconnection queue processes, interregional transmission coordination and planning, and oversight of transmission planning and costs. While this NOPR does not propose broad or comprehensive reforms directly related to these topics, we will continue to review the record developed to date and expect to address possible inadequacies through subsequent proceedings that propose reforms, as warranted, related to these topics. In addition, concurrent with the issuance of this NOPR, we notice a technical conference on Transmission Planning and Cost Management. 7 Building for the Future Through Electric Regional Transmission Planning & Cost Allocation & Generator Interconnection, 86 FR 40266 (July 15, 2021), 176 FERC ¶ 61,024 (2021) (ANOPR); see infra P 18 (briefly summarizing the ANOPR). 11. We seek comment on the reforms proposed herein and encourage commenters to identify enhancements to those reforms that could better support development of more efficient or cost-effective transmission facilities than is the case under the Commission's existing regional transmission planning and cost allocation requirements. II. Background A. Historical Framework: Order Nos. 888, 890, and 1000 12. Over the last several decades, the Commission has taken multiple significant actions on transmission planning and cost allocation, including issuing Order Nos. 888, 890, and 1000. In 1996, the Commission issued Order No. 888, which implemented open access to transmission facilities owned, operated, or controlled by a public utility and included certain minimum requirements for transmission planning. In 2007, the Commission issued Order No. 890 to address deficiencies in the pro forma OATT that it identified after more than 10 years of experience since Order No. 888. Among other OATT reforms, the Commission required all public utility transmission providers' local transmission planning processes to satisfy nine transmission planning principles: (1) Coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; (7) regional participation; (8) economic planning studies; and (9) cost allocation for new projects. 8 8 Order No. 890, 118 FERC ¶ 61,119 at PP 418-601. 13. Then, in 2011, the Commission recognized the need for further transmission planning reforms with its issuance of Order No. 1000. The Commission based the reforms it adopted in Order No. 1000 on changes in the energy industry, its experience implementing Order No. 890, and a robust record developed through technical conferences and comments from a diverse range of stakeholders. 9 The Commission stated in Order No. 1000 that “the electric industry is currently facing the possibility of substantial investment in future transmission facilities to meet the challenge of maintaining reliable service at a reasonable cost.” 10 In establishing the requirements of Order No. 1000, the Commission found that the existing requirements of Order No. 890 were not adequate, noting that Order No. 1000 “expands upon the reforms begun in Order No. 890 by addressing new concerns that have become apparent in the Commission's ongoing monitoring of these matters.” 11 The Commission then enumerated multiple concerns that it had regarding existing transmission planning practices, including concerns about: (1) The lack of an affirmative obligation to develop a transmission plan evaluating if a regional transmission facility “may be more efficient or cost-effective than solutions identified in local transmission planning processes;” (2) the lack of a requirement to address Public Policy Requirements; 12 (3) the federal right of first refusal for incumbent transmission developers to build upgrades to their existing transmission facilities; (4) the lack of procedures to identify and evaluate the benefits of interregional transmission facilities; and (5) cost allocation for regional and interregional transmission facilities. 13 9 Order No. 1000, 136 FERC ¶ 61,051 at P 3. The term “stakeholder” means any interested party. Id. P 151 n.143. 10 Id. P 2. 11 Id. P 22. 12 Public Policy Requirements are requirements established by local, state or federal laws or regulations ( i.e., enacted statutes passed by the legislature and signed by the executive and regulations promulgated by a relevant jurisdiction, whether within a state or at the federal level). Id. P 2. Order No. 1000-A clarified that Public Policy Requirements include local laws or regulations passed by a local governmental entity, such as a municipal or county government. Order No. 1000-A, 139 FERC ¶ 61,132 at P 319. 13 Order No. 1000, 136 FERC ¶ 61,051 at P 3. 14. Order No. 1000 included a package of reforms to ensure that the transmission planning and cost allocation requirements embodied in the pro forma OATT were adequate to support the development of more efficient or cost-effective transmission facilities. 14 The reforms in Order No. 1000 fell into the following categories: Regional transmission planning; transmission needs driven by Public Policy Requirements; nonincumbent transmission developer reforms; regional and interregional cost allocation, including a set of principles for each category of cost allocation; and interregional transmission coordination. The reforms focused on the process by which public utility transmission providers engage in regional transmission planning and associated cost allocation rather than on the outcomes of the process. 15 14 Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ¶ 61,132 at PP 3, 4-6. 15 Order No. 1000, 136 FERC ¶ 61,051 at P 12. 15. Among other regional transmission planning reforms in Order No. 1000, the Commission required that the following Order No. 890 transmission planning principles apply to regional transmission planning processes: (1) Coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; and (7) economic planning studies. 16 16 The Commission did not include the regional participation or cost allocation transmission planning principles with respect to regional transmission planning processes because those issues were addressed by other reforms in Order No. 1000. Id. P 151. 16. In addition, with respect to the Order No. 1000 reforms, there is a distinction between a transmission facility “included” in a regional transmission plan and a transmission facility “selected” in a regional transmission plan for purposes of cost allocation. A transmission facility selected in a regional transmission plan for purposes of cost allocation is a transmission facility that has been selected pursuant to a transmission planning region's 17 Commission-approved regional transmission planning process for inclusion in a regional transmission plan for purposes of cost allocation because it is a more efficient or cost-effective transmission facility needed to meet regional transmission needs. Both regional transmission facilities and interregional transmission facilities are eligible for potential “selection” in a regional transmission plan for purposes of cost allocation. 18 A regional transmission facility is a transmission facility located entirely in one transmission planning region. 19 An interregional transmission facility is one that is located in two or more transmission planning regions. 20 17 A transmission planning region is one in which public utility 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 160. 18 Id. P 63. 19 Id. n.374. 20 Id. 17. Transmission facilities selected in a regional transmission plan for purposes of cost allocation often will not comprise all of the transmission facilities that are included in a regional transmission plan. 21 Some transmission facilities are merely “rolled up” and listed in a regional transmission plan without going through an analysis at the regional level, and therefore, are not eligible for selection and regional cost allocation. 22 For example, a local transmission facility is a transmission facility located solely within a public utility transmission provider's retail distribution service territory or footprint that is not selected in the regional transmission plan for purposes of cost allocation. 23 Thus, a local transmission facility may be rolled up and “included” in a regional transmission plan for informational purposes, but it is not “selected” in a regional transmission plan for purposes of cost allocation. 21 Id. P 63. 22 Id. PP 7, 226, 318. 23 Id. P 63. The Commission clarified in Order No. 1000-A that a local transmission facility is one that is located within the geographical boundaries of a public utility transmission provider's retail distribution service territory, if it has one; otherwise the area is defined by the public utility transmission provider's footprint. In the case of an RTO/ISO whose footprint covers the entire region, a local transmission facility is defined by reference to the retail distribution service territories or footprints of its underlying transmission owing members. Order No. 1000-A, 139 FERC ¶ 61,132 at P 429. B. ANOPR and Technical Conference 18. In July 2021, the Commission issued an ANOPR presenting potential reforms to improve the regional transmission planning and cost allocation and generator interconnection processes. In issuing the ANOPR, the Commission noted that, more than a decade after Order No. 1000, it was time to review its regulations governing regional transmission planning and cost allocation and generator interconnection processes to determine whether reforms are needed to ensure Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. 24 The Commission noted that the electricity sector is transforming as the generation fleet shifts from resources located close to population centers toward resources that may often be located far from load centers. The Commission also highlighted the growth of new resources seeking to interconnect to the transmission system and that the differing characteristics of those resources are creating new demands on the transmission system. The Commission explained that ensuring just and reasonable Commission-jurisdictional rates as the resource mix changes, while maintaining grid reliability, remains the Commission's priority in adopting requirements for the regional transmission planning and cost allocation and generator interconnection processes. As a result, the Commission issued the ANOPR to consider whether there should be changes in the regional transmission planning and cost allocation and generator interconnection processes and, if so, which changes are necessary to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential and that reliability is maintained. 24 ANOPR, 176 FERC ¶ 61,024 at P 3. 19. On November 15, 2021, the Commission convened a staff-led technical conference (November 2021 Technical Conference or Technical Conference) to examine in detail issues and potential reforms related to regional transmission planning as described in ANOPR. Specifically, the Technical Conference included three panels covering issues related to factors to consider in long-term scenarios, consideration of longer-term scenarios in regional transmission planning processes, and identifying geographic zones with high renewable resource potential for use in regional transmission planning processes. 25 After the Technical Conference, the Commission invited all interested persons to file comments after the Technical Conference to address issues raised during the Technical Conference. 25 Building for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation & Generator Interconnection, Further Supplemental Notice of Technical Conference, Docket No. RM21-17-000 (issued Nov. 12, 2021) (attaching agenda). C. Joint Federal-State Task Force on Electric Transmission 20. On June 17, 2021, the Commission established a Joint Federal-State Task Force on Electric Transmission (Task Force) to formally explore broad categories of transmission-related topics. 26 The Commission explained that the development of new transmission infrastructure implicates a host of different issues, including how to plan and pay for these facilities. Given that federal and state regulators each have authority over transmission-related issues and the impact of transmission infrastructure development on numerous different priorities of federal and state regulators, the Commission determined that the area is ripe for greater federal-state coordination and cooperation. 27 The Task Force is comprised of all FERC Commissioners as well as representatives from 10 state commissions nominated by the National Association of Regulatory Utility Commissioners (NARUC), with two originating from each NARUC region. 28 26 Joint Fed.-State Task Force on Elec. Transmission, 175 FERC ¶ 61,224, at PP 1, 6 (2021). 27 Id. P 2. 28 An up-to-date list of Task Force members, as well as additional information on the Task Force, is available on the Commission's website at: https://www.ferc.gov/TFSOET. Public materials related to the Task Force, including transcripts from public meetings, are available in the Commission's eLibrary in Docket No. AD21-15-000. 21. The Task Force will convene for multiple formal meetings and has thus far met twice—on November 10, 2021, and on February 16, 2022. The discussion at the November meeting was focused on incorporating state perspectives into regional transmission planning. The Task Force members discussed: Whether the existing regional transmission planning processes adequately plan for future transmission needs, including those of states in meeting their energy-related goals; what methods are currently employed to provide states a role in regional transmission planning processes and whether reforms are needed to increase consideration and incorporation of state perspectives and energy-related goals in those processes; transparency in existing regional transmission planning processes; and criteria for use in selecting transmission facilities, including the proper role for states in selection of transmission facilities identified during regional transmission planning processes. 29 29 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching agenda). 22. The February meeting included discussion of specific categories and types of transmission benefits that transmission providers should consider for the purposes of transmission planning and cost allocation. The Task Force Members discussed: Whether and how the three categories and types of transmission (to address transmission needs driven by reliability, economic considerations, and Public Policy Requirements) that are considered for the purposes of transmission planning and cost allocation should be expanded or changed; whether these categories are being adequately considered or can be improved upon; if there any specific benefits being considered by public utility transmission providers today that should be more widely adopted by other public utility transmission providers and whether certain benefits are unique to specific regions; and how the certainty of benefits should be addressed, such as whether and how benefits need to be quantified. The Task Force Members also discussed at the February meeting cost allocation principles, methodologies, and decision processes, such as whether the current cost allocation methodologies used by public utility transmission providers allocate costs roughly commensurate with estimated benefits, and if not, how should this be improved; under what set of benefits—both existing and expanded—would states be amenable to bearing the costs of transmission that is expected to deliver those estimated benefits to ratepayers; and whether there is sufficient opportunity for stakeholders, including states, to collaborate in the development and approval of cost allocation methodologies to build consensus among and increase buy-in from stakeholders within a transmission planning region, and if not, how this can be improved. 30 30 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching agenda). D. High-Level Overview of ANOPR Comments 23. The Commission received many comments from a diverse set of parties in response to the ANOPR. 31 One hundred and seventy five parties, including federal agencies, state regulatory commissions, state policy makers and other state representatives, ratepayer advocates, municipalities, RTOs/ISOs, RTO/ISO market monitors, public utility transmission providers, transmission-dependent utilities, electric cooperatives, municipal power providers, independent power producers, transmission developers, generation trade associations, transmission trade associations, industry interest groups, consumer interest groups, energy policy and law interest groups, individual businesses, landowners, and individuals, filed initial comments that totaled over 4,000 pages without attachments. A similarly diverse set of 95 parties filed reply comments that totaled nearly 2,000 pages. 31 See Appendix A for a list of commenters and the abbreviated names of commenters that are used in this NOPR. III. Need for Reform 24. Over the last 25 years, the Commission has undertaken a series of significant reforms to ensure that transmission planning and cost allocation processes result in Commission-jurisdictional rates that are just and reasonable and not unduly discriminatory or preferential. 32 It has now been more than a decade since Order No. 1000—the Commission's last significant regional transmission planning and cost allocation rule—and there is mounting evidence that the Commission's regional transmission planning and cost allocation requirements may be inadequate to ensure Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. In particular, although public utility transmission providers are required to participate in regional transmission planning and cost allocation processes under Order No. 1000, we are concerned that those processes may not be planning transmission on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand. 32 See supra PP 12-14. 25. As a result, the regional transmission planning and cost allocation processes that public utility transmission providers adopted to comply with Order No. 1000 may not be identifying the more efficient or cost-effective transmission facilities. We are concerned that the absence of sufficiently long-term, comprehensive transmission planning processes appears to be resulting in piecemeal transmission expansion to address relatively near-term transmission needs. We are concerned that continuing with the status quo approach may cause public utility transmission providers to undertake relatively inefficient investments in transmission infrastructure, the costs of which are ultimately recovered through Commission-jurisdictional rates. 33 That dynamic may result in transmission customers paying more than necessary to meet their transmission needs, customers forgoing benefits that outweigh their costs, or some combination thereof—either or both of which could potentially render Commission-jurisdictional rates unjust and unreasonable or unduly discriminatory or preferential. As the Commission has an obligation under the FPA to ensure that those rates are just and reasonable and not unduly discriminatory or preferential, we are proposing reforms to remedy these potential deficiencies in the Commission's existing regional transmission planning and cost allocation requirements. 33 S.C. Pub. Serv. Auth., 762 F.3d at 56-59. 26. As explained in the next section, we believe that there are substantial potential benefits of long-term regional transmission planning and cost allocation to identify and plan for transmission needs driven by changes in the resource mix and demand. But, as explained below, expansion of the high voltage transmission system is apparently increasingly occurring outside of the regional transmission planning process, and in a piecemeal fashion through other avenues, such as the generator interconnection process primarily in response to individual (or a small cluster of) interconnection requests rather than through regional transmission planning and cost allocation processes. 27. In light of those concerns, we propose reforms to require public utility transmission providers to conduct long-term regional transmission planning on a sufficiently long-term, forward-looking basis to identify and plan for transmission needs driven by changes in the resource mix and demand. Absent such reforms, we are concerned that meeting transmission needs driven by changes in the resource mix and demand through short-term, piecemeal transmission expansion will result in unjust and unreasonable and unduly discriminatory and preferential Commission-jurisdictional rates for customers. Specifically, without these reforms, we believe that regional transmission planning processes are unlikely to identify the more efficient or cost-effective solutions to transmission needs driven by changes in the resource mix and demand. Thus, we preliminarily find that these reforms are necessary to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential. A. Potential Benefits of Long-Term Regional Transmission Planning and Cost Allocation To Identify and Plan for Transmission Needs Driven by Changes in the Resource Mix and Demand 28. A robust, well-planned transmission system is foundational to ensuring an affordable, reliable supply of electricity. 34 Due to continuing changes in both supply and demand, ongoing investment in transmission facilities is necessary to ensure the transmission system continues to serve load in a reliable 35 and economically efficient fashion. Such investments also support enhanced reliability, as larger, more integrated transmission systems result in a diversity of supply and demand conditions and a certain degree of redundancy that allows the system to better withstand failures during unexpected events. 36 Proactive, forward-looking transmission planning that considers evolving supply and demand conditions more comprehensively can enable potential reliability problems and economic constraints to be identified and resolved before they affect the transmission system, 37 which can facilitate the selection of more efficient or cost-effective transmission facilities to meet transmission needs. 34 16 U.S.C. 824, 824d, 824e; see also U.S. DOE Comments at 2 (stating that “strengthening and expanding existing transmission infrastructure, particularly the development of regional and inter-regional transmission projects, is key to continued access to reliable, resilient, lower-cost, and clean electricity for all”). 35 See, e.g., Testimony of James B. Robb Before the U.S. Senate Energy and Natural Resources Committee, Reliability, Resiliency, and Affordability of Electric Service in the United States Amid the Changing Energy Mix and Extreme Weather Events, at 9 (Mar. 11, 2021), https://www.nerc.com/news/Headlines%20DL/NERC%20Reliability%20Hearing%20Testimony%203-11-21%20-%20Final.pdf (testifying that more transmission infrastructure is required to ensure reliability and resilience of the bulk power system in light of changing conditions); MISO Comments at 40. 36 U.S. DOE Comments at 18; NERC Comments at 16-17; ACORE Comments, Ex. 4, Transmission Makes the Power System Resilient to Extreme Weather; Mark Chupka & Pearl Donohoo-Vallett, Recognizing the Role of Transmission in Electric System Resilience (May 2018). 37 MISO's Multi-Value Project (MVP) regional transmission planning process, for example, eliminated the need for approximately $300 million in reliability transmission facilities, resolving reliability violations and mitigating system instability conditions, through a forward-looking approach. Midcontinent Independent System Operator, MTEP17 MVP Triennial Review: A 2017 review of the public policy, economic, and qualitative benefits of the Multi-Value Project Portfolio, at 11, 33 (Sept. 2017) (MTEP17 Review). 29. In addition, transmission can unlock the forces of competition, changing who can sell to whom, eliminating barriers to entry, and mitigating market power. 38 That, in turn, can provide a host of benefits for customers, including cost-savings from greater access to low-cost power and a wider range of resources. 39 Transmission infrastructure can also serve as a form of insurance for the uncertainties of the future, because a more robust, integrated transmission system has the potential to afford consumers the benefits of competition and enhanced reliability even if supply and demand fundamentals change over time. 40 38 Johannes Pfeifenberger et al., The Brattle Group and Grid Strategies, Transmission Planning for the 21st Century: Proven Practices that Increase Value and Reduce Costs, at 48-49 (Oct. 2021), https://gridprogress.files.wordpress.com/2021/10/transmission-planning-for-the-21st-century-proven-practices-that-increase-value-and-reduce-costs-7.pdf (Brattle-Grid Strategies Oct. 2021 Report); Policy Integrity Comments at 13 (citing Mohamed Awad et al., The California ISO Transmission Economic Assessment Methodology (TEAM): Principles and Applications to Path 26, at 3 (“A new transmission project can enhance competition by both increasing the total supply that can be delivered to consumers and the number of suppliers that are available to serve load.”)); PIOs Comments at 48 (quoting F.A. Wolak, World Bank, Managing Unilateral Market Power in Electricity, Policy Research Working Paper; No. 3691, at 8 (2005) (“Expansion of the transmission network typically increases the number of independent wholesale electricity suppliers that are able to compete to supply electricity at locations in the transmission network served by the upgrade . . . .”)). 39 See, e.g., PJM Interconnection, L.L.C., PJM Value Proposition (2019), https://www.pjm.com/about-pjm/~/media/about-pjm/pjm-value-proposition.ashx (PJM's planning of resource adequacy over a large region is estimated to result in savings of $1.2-1.8 billion.); Midcontinent Independent System Operator, Value Proposition (2020), https://www.misoenergy.org/about/miso-strategy-and-value-proposition/miso-value-proposition/ (MISO estimates $517-572 million in savings from more efficient use of existing assets and $2.5-3.2 billion from reduced need for additional assets.); Southwest Power Pool, SPP's Value of Transmission: 2021 Report and Update (Jan. 5, 2022) (SPP estimates $382.7 million in adjusted product costs savings in 2020 due to transmission investment.). 40 U.S. Dep't of Energy, National Electric Transmission Congestion Study, at 11 (Sept. 2015) (stating transmission expansion can strengthen and increase the flexibility of the overall network and “create real options to use the transmission system in ways that were not originally envisioned”); Vikram S. Budhraja et al., Improving Electricity Resource Planning Processes by Considering the Strategic Benefits of Transmission, 22 ELEC. J. 54 (Mar. 2009), (high voltage transmission affords “mitigation of risks as a form of insurance against extreme events”). 30. Given these potential benefits, it should be no surprise that investments in more efficient or cost-effective transmission infrastructure can yield substantial benefits to consumers. 41 For example, MISO's MVP transmission planning process resulted in transmission facilities that are estimated to generate $2.20 to $3.40 of benefit per dollar invested. 42 41 See, e.g., Southwest Power Pool, The Value of Transmission (Jan. 2016), https://www.spp.org/value-of-transmission/ (A 2016 study of 348 transmission projects in SPP constructed between 2012 and 2014 found the overall ratio of benefits to costs to be at least 3.5 to 1.); NextEra Comments at 95 (citing ACEG, Texas as a National Model for Bringing Clean Energy to the Grid (Oct. 2017), https://cleanenergygrid.org/texas-national-model-bringing-clean-energy-grid/ ) (Transmission developed due to Texas's Competitive Renewable Energy Zone planning process estimated to save $1.7 billion each year in production costs alone, far surpassing its $6.9 billion cost.); Brattle-Grid Strategies Oct. 2021 Report at 4-8 & app. A (describing evidence showing that well-planned transmission expansion resulted in lower total cost to construct the needed transmission facilities). 42 MTEP17 Review at 4. 31. MISO achieved these benefits by proactively planning over a 20-year period for two key drivers of transmission needs: The impacts of changing state laws on the resource mix, and a large increase in the number of generator interconnection requests. 43 To mitigate the uncertainties of such projections of need, MISO relied on scenarios to consider a range of potential future conditions 44 and disclosed the assumptions and inputs underlying each. 45 The MVP process then identified a portfolio of “no regrets” transmission projects that were projected to provide multiple kinds of reliability and economic benefits under all the alternate future scenarios studied. 46 At each stage of the MVP process, MISO invested in significant stakeholder engagement and collaboration, from developing the technical parameters underlying its scenarios and the weights to give to each, to the metrics and methodology used to evaluate the portfolio of transmission projects. 47 43 Midcontinent Independent System Operator, RGOS: Regional Generation Outlet Study at 2 (Nov. 19, 2010) (RGOS Study). MISO staff and stakeholders determined that allowing the transmission expansion needed to accommodate these requests to occur through the generator interconnection process “would not be an efficient means for building a cost-effective transmission system either immediately, over the next 5-10 year period or in the foreseeable future beyond that time-frame.” Id. 44 MISO relied on stakeholder surveys of likely renewable energy needs over the next 20 years, and calculations of the new generation that would be needed in order to achieve state renewable portfolio standards by 2027. MISO also identified the location of expected “renewable energy zones” with potential to achieve high capacity factors for use in its analysis. Id. at 26-29. 45 See, e.g., MTEP17 Review at 16. 46 Id. at 13. 47 MISO Comments at 9. 32. Although, as illustrated by the MVP example, transmission infrastructure can provide significant benefits to consumers, there are often substantial barriers to developing more efficient or cost-effective transmission facilities. For example, as the Commission has long recognized, “vertically-integrated utilities do not have an incentive to expand the grid to accommodate new entries or to facilitate the dispatch of more efficient competitors.” 48 Further, because large-scale transmission investments that geographically extend or strengthen the integration of the transmission system are both costly and tend to produce widespread benefits, there is significant risk that free ridership problems inhibit their development. 49 In any event, the logistics alone of coordinating among multiple public utility transmission providers within a region, seeking support across what is often multiple state jurisdictions, and attaining sufficient certainty over who will pay the costs of the needed transmission facilities can thwart investments in more efficient or cost-effective transmission expansion. 50 48 Order No. 890, 118 FERC ¶ 61,119 at P 57. 49 Order No. 1000, 136 FERC ¶ 61,051 at P 486. 50 Id. PP 498-501. 33. We are concerned that these barriers continue to stymie investment in more efficient or cost-effective transmission facilities. In particular, we are concerned that public utility transmission providers are not engaging in the type of long-term, more comprehensive regional transmission planning and cost allocation processes—like the process used to plan the MISO MVPs—that is necessary to increase the likelihood that such highly beneficial transmission infrastructure is developed. Without this kind of transmission planning and cost allocation process, opportunities to meet transmission needs more efficiently or cost-effectively may be lost. Customers may be forced to pay for less efficient or cost-effective investment in transmission facilities that, for example, achieve lower cost-benefit ratios than would otherwise be achieved with long-term, more comprehensive regional transmission planning and cost allocation. In short, absent reforms, we are concerned customers may be paying more for less. B. Unjust and Unreasonable and Unduly Discriminatory and Preferential Commission-Jurisdictional Rates 34. The evidence suggests that sufficiently long-term, forward-looking regional transmission planning and cost allocation to meet transmission needs driven by changes in the resource mix and demand is not occurring in most transmission planning regions on a regular or consistent basis. As such, consumers may not be seeing the benefits such as enhanced reliability, improved resource adequacy, access to lower cost and diverse resources, and other benefits that result from regional transmission planning and cost allocation processes that identify, select, and allocate the costs of the more efficient or cost-effective transmission solutions to transmission needs driven by changes in the resource mix and demand. We preliminarily find that the failure of existing regional transmission planning and cost allocation processes to perform this type of transmission planning and cost allocation is resulting in unjust, unreasonable, unduly discriminatory, and preferential Commission-jurisdictional rates. 35. More specifically, we preliminarily find that reforms are needed to the Commission's existing regional transmission planning and cost allocation requirements because they fail to require public utility transmission providers to: (1) Perform a sufficiently long-term assessment of transmission needs; (2) adequately account on a forward-looking basis for known determinants of transmission needs driven by changes in the resource mix and demand; and (3) consider the broader set of benefits and beneficiaries of transmission facilities planned to meet those transmission needs. We believe that these deficiencies may be resulting in unjust and unreasonable and unduly discriminatory and preferential Commission-jurisdictional rates to the extent that they lead to public utility transmission providers failing to identify transmission needs driven by changes in the resource mix and demand, failing to select more efficient or cost-effective transmission facilities to meet those transmission needs, and failing to allocate the costs of transmission facilities selected in the regional transmission plan for purposes of cost allocation to meet those transmission needs in a manner that is at least roughly commensurate with the estimated benefits. 1. The Transmission Investment Landscape Today 36. We begin with the facts on the ground: The evidence suggests that long-term regional transmission planning and cost allocation to identify and plan for transmission needs driven by changes in the resource mix and demand is not occurring in most transmission planning regions on a regular or consistent basis. Rather, the status quo appears to be resulting in a disproportionate share of transmission facilities to meet transmission needs driven by changes in the resource mix and demand being developed outside regional transmission planning and cost allocation processes, resulting in less efficient and cost-effective transmission development. Significant expansion of the transmission system instead appears to occur through interconnection-related network upgrades 51 constructed as a result of generator interconnection requests. Because the generator interconnection process is not designed to consider how to more efficiently or cost-effectively address transmission needs beyond the interconnection request(s) being studied, it cannot achieve the economies of scale in transmission investment needed to integrate significant quantities of new generation resources while maintaining Commission-jurisdictional rates that are just and reasonable and not unduly discriminatory or preferential. Transmission expansion in this incremental manner may miss the potential for more efficient or cost-effective transmission facilities to solve transmission needs driven by changes in the resource mix and demand, as well as to afford system-wide benefits that may not be achieved through piecemeal, one-off transmission upgrades. Robust long-term regional transmission planning, on the other hand, may enable the same needs to be met more efficiently or cost-effectively, or identify transmission facilities that meet those same needs while generating additional benefits. Today's incremental transmission planning may also fail to consider opportunities to “right size” certain replacement transmission facilities and thereby fail to identify the potential for more efficient or cost-effective regional transmission facilities. 51 The Commission's pro forma large generator interconnection agreement (LGIA) defines Network Upgrades as: “the additions, modifications, and upgrades to the Transmission Provider's Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission Provider's Transmission System to accommodate the interconnection of the Large Generating Facility to the Transmission Provider's Transmission System.” Pro forma LGIA Art. 1 (Definitions); see also Standardization of Generator Interconnection Agreements & Proc., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ¶ 61,103, at P 21 (2003) (describing network upgrades developed through the generator interconnection process as those interconnection facilities located at or beyond the point where the interconnection customer's generating facility interconnects to the transmission provider's transmission system), order on reh'g, Order No. 2003-A, 106 FERC ¶ 61,220, order on reh'g, Order No. 2003-B, 109 FERC ¶ 61,287 (2004), order on reh'g, Order No. 2003-C, 111 FERC ¶ 61,401 (2005), aff'd sub nom. Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008). We refer to network upgrades developed through the generator interconnection process as interconnection-related network upgrades. 37. The problems with the status quo are evident in the dramatic increase in recent years (and continuing upward trend) in investment in transmission facilities through the generator interconnection process in the form of interconnection-related network upgrades. The evidence demonstrates 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. It appears that the average cost of interconnection-related network upgrades is increasing over time as the transmission system is fully subscribed and demand for interconnection service outpaces transmission investment. Recent studies of the total cost of network upgrades needed to interconnect new generation resources reflect this trend. In the generator interconnection study MISO published in July 2020, MISO identified the need for nearly $2.5 billion in interconnection-related network upgrades to interconnect 9.2 GW of generation in MISO South. 52 In MISO's 2020 interconnection queue outlook, MISO reported that it expects new generation resources in MISO West will need over $3 billion in interconnection-related network upgrades and noted a similar trend in other MISO sub-regions. 53 In its most recent system impact study for generator interconnection, published in April 2021, SPP identified the need for over $4.6 billion in network upgrades to interconnect 10.4 GW of generation. 54 52 ICF Resources, LLC, Just and Reasonable? Transmission Upgrades Charged to Interconnecting Generators Are Delivering System-Wide Benefits, at 2 (Sept. 9, 2021), https://acore.org/wp-content/uploads/2021/09/Just-Reasonable-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf (ICF Sept. 2021 Report) (attached to ACORE Comments as Exhibit 5). 53 Americans For A Clean Energy Grid, Disconnected: The Need for a New Generator Interconnection Policy, at 14 (Jan. 2021), https://acore.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.14.21.pdf (ACEG Jan. 2021 Interconnection Report) (attached to ACORE Comments as Exhibit 2); NextEra Comments at 16 (citing Midcontinent Independent System Operator, 2020 Interconnection Queue Outlook, at 9 (2020), https://cdn.misoenergy.org/MISO2020InterconnectionQueueOutlook445829.pdf (MISO 2020 Queue Outlook)). 54 ICF Sept. 2021 Report at 2. 38. The dramatic increase in the cost of interconnection-related network upgrades per kilowatt (kW) of an interconnection customer's generating capacity may also be problematic. For example, interconnection-related network upgrade costs in MISO West went from approximately $300/kW in 2016 to nearly $1,000/kW in 2017. 55 The trend is evident in other parts of the country as well. 56 The costs of interconnection-related network upgrades seem to have become an ever-growing percentage of the total capital costs of new generation projects. According to one report, interconnection costs for new renewable resources were less than 10% of total generation project costs until a few years ago, but recently these costs have risen to as much as 50-100% of the total generation project costs. 57 At the same time, interconnection-related network upgrades appear to have transitioned from primarily small transmission facilities that serve the needs of a limited number of interconnection customers to the size and scope of what has traditionally been considered high voltage transmission facilities. For example, interconnection-related network upgrades have recently included demolishing and rebuilding multiple 500 kV transmission lines 58 and constructing long, double-circuit, 765 kV transmission lines, 59 all at significant cost to the interconnection customer—and ultimately to consumers. 55 ACEG Jan. 2021 Interconnection Report at 14; NextEra Comments at 16 (citing MISO 2020 Queue Outlook at fig. 7). 56 E.g., ACEG Jan. 2021 Interconnection Report at 14 & tbl. 2 (showing that, as of 2019, interconnection costs in PJM for constructed wind and solar projects were $19.07/kW and 61.83/kW, respectively, as compared to a greater than 100% increase to $54/kW and $131.90/kW, respectively, for projects newly proposed today); NextEra Comments at 16-17 (stating that interconnection-related network upgrade cost estimates have nearly tripled for newly proposed wind projects, and more than doubled for solar projects in PJM); see also ACEG Jan. 2021 Interconnection Report at 16 (illustrating an increase in average interconnection-related network upgrade costs in NYISO from $67/kW in 2013 to $124/kW in 2019). Compare ACEG Jan. 2021 Interconnection Report at 15 (identifying interconnection-related network upgrade costs in 2013 in SPP as $89/kW) with ICF Sept. 2021 Report at 2 (citing interconnection-related network upgrade costs of $448/kW for interconnection customers studied in SPP's system impact study published in April 2021). 57 ACEG Jan. 2021 Interconnection Report at 6; see also id. at 13 (stating that the rising interconnection costs of wind projects in MISO recently reached approximately 23% of the capital cost of the project); id. at 15 (identifying the increase in interconnection-related network upgrade costs in SPP between 2013 and 2017 as representing an increase from around 8% to over 43% of the capital cost of wind generation); NextEra Comments at 17 (similar). 58 See ACEG Jan. 2021 Interconnection Report at 15 (describing interconnection-related network upgrades for a 120 MW solar plus storage project in southern Virginia to interconnect to PJM that cost as much as $12,086/kW). 59 See id. (describing one interconnection-related network upgrade in SPP identified in the system impact study published in April 2021); ICF Sept. 2021 Report at 3 (same); NextEra Comments at 17 (same). 39. In contrast to the significant investment in transmission facilities through the generator interconnection process, the regional transmission planning and cost allocation processes have yielded limited investment in regional transmission facilities. Transmission developers in the United States invested $20 to $25 billion annually in transmission facilities from 2013 to 2020. 60 Yet only a limited portion of these investments have gone toward regional transmission facilities since Order No. 1000. In fact, investment in regional transmission facilities in some regions has declined compared to prior Order No. 1000. 61 Moreover, across all the non-RTO/ISO regions, there has not yet been a single transmission facility selected in a regional transmission plan for purposes of cost allocation since implementation of Order No. 1000. 62 60 Brattle-Grid Strategies Oct. 2021 Report at 2 (citing Johannes Pfeifenberger & John Tsoukalis, The Brattle Group, Transmission Investment Needs and Challenges, at slide 2 (June 1, 2021), https://www.brattle.com/wp-content/uploads/2021/10/Transmission-Investment-Needs-and-Challenges.pdf ); Johannes Pfeifenberger et al., The Brattle Group, Cost Savings Offered by Competition in Electric Transmission: Experience to Date and the Potential for Additional Customer Value, at 2-3 & fig.1 (Apr. 2019), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf (Brattle Apr. 2019 Competition Report). 61 See, e.g., Rob Gramlich & Jay Caspary, Americans for a Clean Energy Grid, Planning for the Future, at 25 & fig. 8 (Jan. 2021) (included as Ex. 1 to ACORE Comments) (ACEG Jan. 2021 Planning Report) (charting the annual investment in regional transmission facilities in RTOs/ISOs from 2010 to 2018); ACORE Comments at 4 (citing Ex. 1, ACEG Jan. 2021 Planning Report at 25). 62 LS Power Oct. 12 Comments, app. I, at 18 & n.57; FERC, Staff Report, 2017 Transmission Metrics, at 19 (Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf. 40. The vast majority of investment in transmission facilities since the issuance of Order No. 1000 has been in local transmission facilities. 63 For example, transmission investment to resolve local needs accounted for almost 80% of total transmission investment in MISO from 2018 to 2020. 64 Similarly, in PJM, about two-thirds of the total transmission investment in the region went to resolving local needs. 65 63 See generally ACEG Jan. 2021 Planning Report at 25-26, 71 (describing investment in local transmission facilities nationwide since implementation of Order No. 1000). In MISO, investment in local transmission facilities went from $1.1 billion per year from 2010 to 2013, to $2.7 billion per year from 2014 to 2019. Harvard ELI Comments at 20 & n.89; see also ACEG Jan. 2021 Planning Report at 104 (charting MISO transmission investment by project type from 2010 to 2019); ACPA and ESA Comments at 22 (showing $247 million invested in nine regional transmission projects versus $16.6 billion in 2,165 local transmission projects in MISO between 2016 and 2020). In PJM, investment in local transmission facilities went from $1.25 billion per year from 2005 to 2013, to $3.79 billion per year from 2014 to 2020. During the same time periods, investment in regional transmission facilities decreased from $2.76 billion per year to $1.65 billion per year. Harvard ELI Comments at 21 n.92; PIOs Comments at 33 n.98 (citing PJM Transmission Expansion Advisory Committee, Project Statistics (May 12, 2020)); Ari Peskoe, Is the Utility Transmission Syndicate Forever?, 42 Energy L.J. 1, 51 n.324 (2021), https://www.eba-net.org/assets/1/6/5_-_%5BPeskoe%5D%5B1-66%5D.pdf. 64 Brattle-Grid Strategies Oct. 2021 Report at 2-3. 65 LS Power October 12 Comments, Ex. 9, at 7. 41. This evidence runs counter to the Commission's expectation that, in light of growing demand for transmission, the regional transmission planning and cost allocation reforms adopted in Order No. 1000 should have resulted in investment in more efficient or cost-effective transmission facilities over time. In Order No. 1000, the Commission recognized a growing need for transmission investment to ensure reliability and integrate new resources in light of industry trends changing the demands placed on the transmission system. 66 The Commission concluded that increasing transmission needs amplified the need for and importance of effective transmission planning and cost allocation processes to identify transmission needs and select regional transmission facilities where they are more efficient or cost-effective than the alternatives. 67 66 See Order No. 1000-A, 139 FERC ¶ 61,132 at P 5. 67 See id. 42. In sum, the evidence suggests that improvements to the Commission's regional transmission planning and cost allocation requirements may be needed to realize the full potential of the benefits to be achieved through the planning and development of regional transmission facilities. Today, transmission needs driven by changes in the resource mix and demand appear to be largely addressed outside the regional transmission process— e.g., through generator interconnection processes—through mechanisms that are not designed to consider regional transmission needs and identify and select the more efficient or cost-effective transmission facility to meet those needs. We believe that this may result in an inefficient expansion of the transmission system to meet transmission needs driven by changes in the resource mix and demand. 43. To the extent public utility transmission providers may not be identifying the more efficient or cost-effective transmission facilities needed to meet underlying transmission needs, including needs driven by changes in the resource mix and demand, over time, consumers may ultimately bear the costs of inefficient piecemeal transmission expansion. Moreover, this concern may be exacerbated when wholesale electricity rates reflect the costs of the interconnection-related network upgrades that address needs that could have been more efficiently or cost-effectively addressed through effective regional transmission planning and cost allocation. Additionally, relying on generator interconnection processes to identify transmission facilities to address transmission needs driven by changes in the resource mix and demand leaves other benefits on the table as well, as described earlier, 68 some of which are almost always (if not exclusively) achieved through the development of regional transmission facilities ( e.g., avoiding emergency operations and lost load, especially during extreme weather events, and increased wholesale market competition). We preliminarily find that this paradigm results in Commission-jurisdictional rates that are unjust and unreasonable and unduly discriminatory and preferential. 68 See supra PP 28-32. 44. While the reforms adopted in Order No. 1000 were an important first step towards improved regional transmission planning and cost allocation, we preliminarily find that further reforms are necessary to ensure that public utility transmission providers engage in regional transmission planning and cost allocation on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand. In Order No. 1000, the Commission was focused in particular on: The lack of an affirmative obligation for public utility transmission providers “to develop a regional transmission plan that reflects the evaluation of whether alternative regional solutions may be more efficient or cost-effective than solutions identified in local transmission planning processes;” the absence of a “requirement that public utility transmission providers consider transmission needs at the local or regional level driven by Public Policy Requirements;” the potential for federal rights of first refusal to discourage investment by nonincumbent transmission developers; the limited procedures in place for interregional transmission coordination and cost allocation; and the failure of many cost allocation methods “to account for the beneficiaries of new transmission facilities.” 69 Order No. 1000 was aimed at ensuring two things: (1) That regional transmission planning processes “consider and evaluate, on a non-discriminatory basis, possible transmission alternatives and produce a transmission plan that can meet transmission needs more efficiently and cost-effectively;” and (2) “that the costs of transmission solutions chosen to meet regional transmission needs are allocated fairly to those who receive benefits from them.” 70 To that end, the Commission adopted reforms that set forth the minimum requirements to achieve these goals, requirements that were noteworthy at the time and required public utility transmission providers to expend substantial time and effort to comply. 69 Order No. 1000, 136 FERC ¶ 61,051 at P 3. 70 Id. P 4. The interregional transmission coordination and cost allocation requirements were aimed at the same objectives with respect to possible transmission solutions located in neighboring transmission planning regions. Id. 45. We believe that it is time to take the next step. The generation fleet is changing rapidly. In many cases, this is taking the form of a shift from large, centralized resources located close to population centers toward renewable resources (sometimes in combination with electric storage resources) that are often, but not always, located far from load centers where access to their fuel source, such as the wind or the sun, is greatest. 71 The growth in these resource types is driven by many factors, including: (1) The improved economics of certain renewable resources; 72 (2) increased customer demand for such resources, including among major corporations; 73 (3) utility commitments to procure most or all of their electricity from renewable and/or non-emitting resources; 74 and (4) federal, state, and local policies incentivizing various forms of generation resources and other technologies. 75 Similarly, changes in electric demand and associated load profiles are occurring as load-serving entities shift to meet increasing needs due to the electrification of our power system as well as new large loads associated with evolving industrial and commercial needs such as the growth in data centers. 76 Moreover, transmission system operators are also increasing their reliance on regional and interregional transmission facilities to ensure operational stability in light of the rising share of variable resources in the resource mix and increasingly frequent extreme weather events. 77 Lastly, in recognition of the benefits of regional power markets, regional integration efforts have expanded since Order No. 1000, as illustrated by the creation of the Western Energy Imbalance Market (EIM) and SPP Integrated Marketplace in 2014. 78 These changes in the resource mix and demand, operational challenges, and increasing regional integration increase the importance of engaging in regional transmission planning and cost allocation to meet long-term transmission needs more efficiently or cost-effectively. 71 In its 2021 Long-Term Reliability Assessment, NERC reports over 504 GW of nameplate capacity from new solar and wind in development through 2031. In contrast, confirmed coal-fired, nuclear, and natural-gas-fired retirements through the year 2026 total approximately 48.4 GW. NERC, 2021 Long-Term Reliability Assessment, at 30, 35 (Dec. 2021). 72 See Lawrence Berkeley National Laboratory, Wind Energy Technology Data Update: 2020 Edition, at 66 (Aug. 2020) (noting the average levelized cost of wind energy for commercial wind generation has decreased from $90 per MWh in 2009, to $35 per MWh in 2019); Lawrence Berkeley National Laboratory, Utility-Scale Solar Data Update: 2020 Edition, at 32 (Nov. 2020) (noting the average levelized power purchase agreement price for utility-scale solar generation has decreased from approximately $160 per MWh in 2009, to approximately $40 per MWh in 2020). 73 See National Renewable Energy Laboratory (NREL), H2 2020 Solar Industry Update, at 31 (2021) (stating that U.S. corporate solar contracts were up 34% annually in 2020, and 7.4 times higher over 5 years). 74 See Deloitte, Insights, Utility Decarbonization Strategies, Renew, Reshape, and Refuel to Zero, at 4 (2020) (indicating 43 of 55 utilities surveyed have emissions reductions targets and 22 have net-zero or carbon-free electricity goals); Esther Whieldon, S&P Global Market Intelligence, Path to net zero: 70% of biggest US utilities have deep decarbonization targets, at 3-6 (2020) (indicating based on a review of utilities' climate goals and decarbonization plans that, as of December 2020, 70% of the 30 largest utilities have net-zero carbon targets, or are moving to comply with similarly aggressive state mandates). 75 See Lawrence Berkeley National Laboratory, U.S. Renewables Portfolio Standards 2021 Status Update: Early Release, at 9 (Feb. 2021) (stating renewable portfolio standards exist in 30 states and the District of Columbia, and apply to 58% of total U.S. retail electricity sales). 76 For example, the electrification of end uses that currently rely on other energy sources is expected, under a moderate scenario that does not factor in public policy drivers, to increase electricity demand by 2050 to about 25% above today's level. ACEG Jan. 2021 Planning Report at 35 (discussing National Renewable Energy Laboratory's “medium electrification” case); see also AEE Comments at 14-18 (describing local, state, and federal policies, technical and economic trends that are leading to increased electrification). 77 For example, during Winter Storm Uri in February 2021, SPP and MISO were able to avoid major power shortfalls during the extreme cold by importing electricity from the east. During the event, MISO imported nearly 9,000 MW from PJM and several thousand MW from the Tennessee Valley Authority. ACORE Comments, Ex. 4, Transmission Makes the Power System Resilient to Extreme Weather, at 7. 78 Moreover, we note that efforts for further regional integration of power markets continue today. See, e.g., Kassia Micek, Megawatt Daily, Three Colorado utilities to join SPP's Western Energy Imbalance Service Market (Jan. 26, 2022) (“Three Colorado utilities announced plans to join [SPP's] Western Energy Imbalance Service market and continue studying long-term solutions to join or develop an organized wholesale market.”). 46. A diverse range of stakeholders, including state and regulatory entities, 79 consumer interest groups, 80 transmission owners, 81 independent power producers, 82 and various trade 83 and non-government organizations, 84 identify the need to build on existing regional transmission planning and cost allocation processes. A still broader range of stakeholders acknowledge, at a minimum, that there is scope for improvements in existing regional transmission planning and cost allocation processes. 85 While RTOs/ISOs defend the sufficiency of their regional transmission planning and cost allocation processes, all recognize the potential for reforms to respond to ongoing developments in the electric industry 86 and, in some instances, they have initiated analysis and other early steps toward proposing reforms. 87 79 See, e.g., NARUC Comments at 5 (“NARUC identifies opportunities for reforms that may result in more efficient transmission planning and investment to the benefit of consumers, all while preserving jurisdictional authorities.”); NASEO Comments at 1 (“NASEO shares the Commission's concern that the current approach to planning and allocating the costs of transmission facilities may lead to an inefficient, piecemeal expansion of the transmission grid.”); NESCOE Comments at 35 (“NESCOE appreciates the Commission's leadership in recognizing a need for longer-term and comprehensive regional transmission analysis to account for this changing resource mix.”); Kansas Commission Comments at 5 (stating “the KCC believes that improvements can be made to optimize regional transmission planning policies and proceedings”). 80 Iowa Consumer Advocate Comments at 1 (recognizing “an urgent need to review existing processes and identify opportunities for reform” and that failure to do so could “negatively impact reliability, and result in rates that are unjust and unreasonable”); Consumers Council Comments at 3-4 (stating reforms are “crucial” and that “since Order No. 1000 was implemented, several inefficiencies and unintended consequences have emerged in transmission planning”); District of Columbia's Office of the People's Counsel Comments at 2 (arguing there are “significant flaws” in the regional transmission planning process in PJM). 81 See, e.g., NY TOs Comments at 14 (“In conclusion, the NY TOs support the ANOPR's goals of proactive, multi-value scenario modeling and recognize that further refinements to New York's transmission planning processes and modeling will likely be needed to integrate renewables and to maintain reliability.”); SoCal Edison Comments at 3 (asserting that “enhancements are necessary” to CAISO's regional transmission planning structure); AEP Comments at 2 (encouraging the Commission “to consider broad reforms for both transmission planning and generator interconnections”). 82 See, e.g., Enel Comments, attach. ( Plugging In: A Roadmap for Modernizing & Integrating Interconnection and Transmission Planning ) at 4 (arguing certain deficiencies result in inadequate building of transmission and result in cost-inefficient solutions for load); Northwest and Intermountain Comments at 3-4 (pointing to limitations in existing Order No. 1000 processes and advocating additional reforms are needed to ensure just and reasonable transmission rates). 83 See, e.g., Joint Statement in Support of Large Scale Transmission at 1 (ACORE, ACPA, ACEG, AEE, National Electrical Manufacturers Association, and SEIA, among other signatories, support reforms to transmission planning and cost allocation policies); WIRES Comments at 7-18 (advocating for several reforms to regional transmission planning and cost allocation processes, and against others). 84 See, e.g., R Street Comments at 1 (stating “planning processes require an overhaul”); Policy Integrity Comments at 1 (arguing “current approaches to transmission planning and cost allocation are failing to capture [ ] large potential benefits”). 85 See, e.g., EPSA Comments at 2, 4 (asserting reforms will be necessary to accommodate the evolving transmission system and longer-term regional transmission planning is warranted); Industrial Customers Comments at 13 (stating “[t]o be sure, there is room for improvement”); Northern VA Coop Comments at 2 (noting “improvement is possible”). 86 MISO Comments at 7 (arguing its transmission planning process is serving its intended purpose but acknowledging “improvements may be made”); SPP Comments at 9 (stating “SPP realized there was a need to more strategically consider broader changes to SPP's transmission planning process”); PJM Reply Comments at 6 (stating “it is appropriate to enhance the long-term planning process to consider scenario planning and the interaction of many system enhancement drivers”); ISO-NE Comments at 26 (noting “improvements may be needed to optimize transmission solutions for reliability, economic, and public policy based needs”); NYISO Comments at 2 (“NYISO sees an opportunity to build on the existing successes of its processes and to evolve them to address current conditions.”); CAISO Comments at 2 (supporting the goal of enhancing regional transmission planning and generator interconnection processes to account for the transmission needs of a changing resource mix). 87 See, e.g., SPP Comments at 10 (SPP Board of Directors-appointed team identified critical issues with existing transmission planning process including sub-optimal transmission plans; deficiency in collective quantification of cost-causers and beneficiaries which create free rider situations; and failure to consider congestion costs and other economic impacts in processes used to identify needed upgrades.); ISO-NE Comments at 14-16 (initiating a 2050 Transmission Study at the request of ISO-NE states and efforts to incorporate a new forward-looking, scenario-based transmission planning tool). 2. Deficiencies in the Commission's Existing Regional Transmission Planning and Cost Allocation Requirements 47. We preliminarily find deficiencies in the Commission's existing regional transmission planning and cost allocation requirements are resulting in Commission-jurisdictional rates that are unjust and unreasonable and unduly discriminatory and preferential. In particular, we preliminarily find that the Commission's regional transmission planning and cost allocation requirements fail to require public utility transmission providers to: (1) Perform a sufficiently long-term assessment of transmission needs; (2) adequately account on a forward-looking basis for known determinants of transmission needs driven by changes in the resource mix and demand; and (3) consider the broader set of benefits and beneficiaries of regional transmission facilities planned to meet those transmission needs. We believe that these deficiencies may be resulting in unjust and unreasonable and unduly discriminatory and preferential Commission-jurisdictional rates to the extent that they lead public utility transmission providers to fail to identify transmission needs driven by changes in the resource mix and demand, select more efficient or cost-effective transmission facilities to meet those transmission needs, and allocate the costs of transmission facilities selected in the regional transmission plan for purposes of cost allocation to meet those transmission needs in a manner that is at least roughly commensurate with the estimated benefits. We address each deficiency in turn. 48. The first deficiency—that the Commission's existing regional transmission planning and cost allocation requirements do not require public utility transmission providers to perform a sufficiently long-term assessment of transmission needs—is reflected across multiple components of existing regional transmission planning processes, from the degree to which studies that inform assessment of transmission needs are forward looking, to whether forward-looking assessments actually inform selection and cost allocation of regional transmission facilities. Existing regional transmission planning and cost allocation processes typically look out and plan for transmission needs based on a relatively near-term horizon. While some existing regional transmission planning and cost allocation processes may incorporate studies or assessments that have a longer forward-looking period, these are typically for informational purposes and do not result in identification of long-term regional transmission needs, assessment of transmission alternatives to meet those needs, or selection of transmission facilities in the regional transmission plan for purposes of cost allocation. 88 Such studies or assessments may be one-off, available only upon request, or conducted at irregular intervals. 89 Additionally, many forward-looking studies treat key variables that affect transmission needs, such as generation additions and retirements, as fixed over the full time horizon of the study, even though these variables are likely to change. 90 Such studies are therefore unlikely to adequately assess transmission needs over the longer-term horizon, as they do not attempt to assess the likelihood that conditions contributing to transmission needs change. 91 88 For example, SPP is required under its tariff to conduct a 20-year study of transmission at least every five years but is prohibited from using that study as the basis for authorizing construction of a transmission solution. SPP Market Monitor Comments at 4 (citing SPP, OATT, attach. O, § IV.2 (8.0.0), § IV.2.a) 89 For example, in response to state requests, ISO-NE recently initiated a stakeholder process to respond to the problem that “[t]he current processes do not support the performance of state-requested transmission analysis based on state-developed scenarios, inputs and assumptions, nor do they support transmission analysis beyond the ten-year horizon.” ISO-NE, Attachment K Revisions: Extended-Term Planning, Transmission Committee, at slide 3 (Sept. 28, 2021), https://www.iso-ne.com/static-assets/documents/2021/09/a07_tc_2021_09_28_attk_ext_trans_presentation.pdf; see also Indicated PJM TOs Comments at 25 (stating “the PJM Tariff does not provide concrete time windows for scenario planning”). 90 Policy Integrity Comments at 29. 91 PJM's long-term assessment of the transmission system ostensibly considers a 15-year horizon, for example, but does not account for changes to the generation mix beyond a 5-year period. See PSEG Comments at 11 (stating that “in practice only new resources that are near the end of the interconnection queue process and have signed an Interconnection Service Agreement are considered in the RTEP base case”); Union of Concerned Scientists Comments at 10 & n.11 (“Generation additions are unchanged in the 15-year study period, as the input assumption has no additional information that would expand the set of generators included in the forecast.”). 49. While it is reasonable for regional transmission planning and cost allocation processes to include near-term study of the transmission system, the absence of any longer-term assessment of transmission needs that may form the basis for selection and cost allocation may prevent public utility transmission providers from considering regional transmission facilities that may be more efficient or cost-effective in light of changing transmission needs. 92 The failure to assess longer-term transmission needs is particularly problematic given the long-lead times necessary to construct large ( e.g., high voltage or long distance) transmission facilities, the potential for economies of scale in transmission investment, and the long life of transmission assets, which will continue to serve transmission needs well beyond a 5- or 10-year planning horizon—all of which suggest that relying solely on shorter-term studies may fail to identify transmission needs and undervalue the benefits of transmission investments to meet those needs. Moreover, the likelihood that near-term assessments will fail to identify more efficient or cost-effective regional transmission facilities is higher during periods, as the sector is now experiencing, in which the need for transmission is expected to grow considerably. 93 92 U.S. DOE Comments at 10 (stating 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”); MISO 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.”). 93 U.S. DOE Comments at 10 (“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.”); see also Policy Integrity Comments at 29 (citing Álvaro García-Cerzo et al., Robust Transmission Network Expansion Planning Considering Non-Convex Operational Constraints, 98 Energy Econ. (June 2021)). 50. The second deficiency is that existing requirements fail to ensure that public utility transmission providers adequately account on a forward-looking basis for known determinants of transmission needs driven by changes in the resource mix and demand. This is closely related to the first deficiency in the sense that both relate to the failure of the existing requirements to result in processes that adequately plan for the foreseeable future. Orders Nos. 890 and 1000 afforded flexibility to public utility transmission providers to determine the inputs, assumptions, and methodologies that are used in analyses of the transmission system to identify transmission needs and produce a regional transmission plan. In the absence of clear standards, public utility transmission providers have adopted widely divergent approaches to determining the factors that are relevant to regional transmission planning and addressing uncertainty in these variables. The result is that public utility transmission providers in some transmission planning regions do a better job than others in accounting for changes in the resource mix and demand when performing transmission planning studies. We are concerned that the reality is that none do so in a manner that ensures the consideration of more efficient or cost-effective transmission facilities to meet transmission needs driven by changes in the resource mix and demand. 51. While we recognize the inevitable uncertainty in forecasting, a number of factors that increasingly shape the resource mix and demand are known in advance and have reasonably predictable effects, especially in the aggregate. For example, the economics of new and existing generating facilities has predictable effects on the resource mix, including which existing generating facilities are likely to retire and which type of new generating facility is likely to be built to replace them. Similarly, state laws, utility integrated resource plans and resource procurements, and other regulatory actions necessarily implicate the resource mix and demand for Commission-jurisdictional services. 94 There are other known determinants of transmission needs as well, including factors affecting electricity demand ( e.g., electrification trends, energy efficiency improvements, and demand response deployments), the risk of extreme weather, information derived from the generator interconnection process about needed transmission expansion, and the locations where transmission needs are likely to be particularly acute or concentrated because of desirable siting conditions for new generating facilities. Yet it appears that existing regional transmission planning processes may undervalue or entirely omit consideration of some or all of these factors. 95 94 See AEE Comments at 10 (explaining that the majority of U.S. electricity customers take service from a load-serving entity subject to legally binding requirements that affect the resource mix). 95 See SPP Market Monitor Comments at 3 & n.5 (describing that even SPP's more forward-looking scenario analysis of an emerging technology case in its Integrated Transmission Plan presently underestimates the actual growth of renewables so much that “[w]ind capacity in service today (29.8 GW) already exceeds wind levels projected in both 2019 ITP futures that go out to 2029”); AEE Comments at 18 (MISO projects electrification effect on load in its long-term regional transmission planning, but how other transmission providers account for electrification trends is not consistent or transparent.); Brattle-Grid Strategies Oct. 2021 Report at 36 (stating that production cost simulations that are typically used to estimate the economic benefit of regional transmission facilities assumes no extreme weather events); U.S. DOE Comments, app. B ( National Laboratories 's Supplemental Information to Comments of Department of Energy to Advance Notice of Proposed Rulemaking (ANOPR) ) at 79 (stating an array of tools exist to identify and analyze high-value zones). 52. We believe that engaging in regional transmission planning without adequate consideration of such factors may be leading to transmission investment that is not more efficient or cost-effective and, in turn, Commission-jurisdictional rates that are unjust and unreasonable and unduly discriminatory and preferential. 96 We believe that this deficiency may delay planning for the transmission system's changing operational needs until shortly before those needs manifest, despite the fact that the continued shift in the resource mix and changes in demand can be reasonably forecast based on known factors. As explained above, the lack of sufficient long-term transmission planning appears to be resulting in significant transmission investment in recent years occurring through generator interconnection processes to satisfy near-term transmission needs, resulting in piecemeal development of transmission facilities that may not more efficiently or cost-effectively meet transmission needs driven by changes in the resource mix and demand. We expect the problems created by this deficiency to only grow more acute as the factors that impact the resource mix and demand are poised to continue increasing in their impact on transmission needs. 96 NERC Comments at 17-18 (“Coordination and better certainty around anticipated future resource mix during transmission planning and interconnection studies could improve reliability assessments associated with the changing resource mix[.]”); ACPA and ESA Comments at 29 (claiming the current approach “delays overall investment in the transmission system”); AEE Comments at 8 (arguing existing transmission planning processes' failure to capture “documented and predictable trends in electricity demand and threats to the reliability, resilience, and sufficiency of the bulk electricity system” warrant reforms). 53. The third potential deficiency is that public utility transmission providers may not identify a sufficiently broad set of benefits—and beneficiaries—associated with regional transmission facilities planned to meet transmission needs driven by changes in the resource mix and demand. Failing to adequately identify and consider the benefits of such transmission facilities may lead to sub-optimal or inefficient investment therein. In particular, the cost-benefit analyses that are used as part of the selection process may fail to identify more efficient or cost-effective transmission facilities for selection in the regional transmission plan for purposes of cost allocation because they provide an inaccurate portrayal of the comparative benefits of different transmission facilities. In addition, by not considering an expanded set of benefits and beneficiaries, cost allocation methods may fail to assign the costs of such facilities to beneficiaries in a manner that is at least roughly commensurate with the benefits they derive from them. 97 97 Ill. Commerce Comm'n v. FERC, 576 F.3d 470, 477 (7th Cir. 2009). Order No. 1000, 136 FERC ¶ 61,051 at PP 622, 639 (requiring costs of regional transmission facilities to be allocated in a manner that is at least roughly commensurate with estimated benefits). 54. We recognize that, in addressing these deficiencies, the Commission would be requiring public utility transmission providers to plan on a longer-term and more comprehensive basis. As discussed below, we acknowledge that such transmission planning may entail a more complex set of considerations compared to existing regional transmission planning requirements, which, in turn, may increase the importance of ensuring that the cost allocations method for projects identified and developed through these processes are perceived as fair. 98 As discussed below, we are proposing to address these concerns in part through greater state involvement, particularly in the development of cost allocation methods. 98 See infra P-235- . 55. In sum, we preliminarily find that the deficiencies in the Commission's existing regional transmission planning and cost allocation requirements that we identify in this NOPR are resulting in Commission-jurisdictional rates that are unjust and unreasonable and unduly discriminatory and preferential. To address the enumerated deficiencies and ensure that Commission-jurisdictional rates are just and reasonable and not unduly discriminatory or preferential, we propose reforms to these requirements, as described in detail in the sections that follow. IV. Regional Transmission Planning 56. We preliminarily find that reforms to public utility transmission providers' regional transmission planning processes are necessary to ensure that Commission-jurisdictional rates are just and reasonable and not unduly discriminatory or preferential. As discussed below, the regional transmission planning reforms proposed in this NOPR would require that public utility transmission providers conduct regional transmission planning on a sufficiently long-term, forward-looking basis to identify and plan for transmission needs driven by changes in the resource mix and demand. As part of this long-term regional transmission planning, public utility transmission providers would be required, in coordination with states, to: (1) Identify transmission needs driven by changes in the resource mix and demand through the development of long-term scenarios that satisfy the requirements set forth in this NOPR; (2) evaluate the benefits of regional transmission facilities to meet identified transmission needs driven by changes in the resource mix and demand over a time horizon that covers, at a minimum, 20 years starting from the estimated in-service date of the transmission facilities; and (3) establish transparent and not unduly discriminatory criteria to select regional transmission facilities in the regional transmission plan for purposes of cost allocation that more efficiently or cost-effectively address these transmission needs driven by changes in the resource mix and demand. Additionally, we propose to require that public utility transmission providers more fully consider dynamic line ratings and advanced power flow control devices in regional transmission planning processes. A. Overview of Existing Regional Transmission Planning Processes 57. Public utility transmission providers currently plan their transmission systems to meet reliability, economic, and Public Policy Requirements needs identified through their regional transmission planning process, consistent with Order Nos. 890 and 1000. 99 The next few paragraphs provide a brief overview of how public utility transmission providers currently conduct regional transmission planning. 99 ANOPR, 176 FERC ¶ 61,024 at P 13. 1. Reliability Needs 58. Public utility transmission providers within transmission planning regions conduct planning studies to help ensure the ability of the transmission system to meet minimum performance requirements under a variety of contingencies to provide reliable service to customers. These studies cover the near-term, which is years 1 through 5, and the long-term, which covers years 6 through year 10 and beyond. 100 Long-term transmission planning varies by public utility transmission provider; for example, studies conducted by RTOs/ISOs may range 10, 15, to 20 years 101 into the future depending on the transmission planning region's regional transmission planning process and test for violations of established North American Electric Reliability Corporation (NERC) reliability requirements. 102 Additional regional and local reliability criteria may also apply in specific transmission planning regions. In order to meet applicable reliability planning criteria, the regional transmission planning process focuses on studying and producing a transmission system that is robust enough to withstand a range of probable contingencies ( e.g., the sudden loss of a generator or higher-voltage transmission facilities) while reliably serving customer demand and preventing cascading outages. 103 Generally, public utility transmission providers identify areas of the transmission system that they predict will not be in compliance with reliability criteria and develop plans to achieve compliance. Public utility transmission providers examine potential transmission facilities to mitigate identified reliability criteria violations for their feasibility, impact, and comparative costs, culminating in a recommended regional transmission plan. 104 100 NERC,Glossary of Terms Used in NERC Reliability Standards (June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. 101 Long-term planning for reliability by RTO/ISO varies as follows: CAISO at least 10 years (CAISO, CASIO eTariff, § 24.2 (Nature of the Transmission Planning Process) (6.0.0)); ISO-NE between 5 and 10 years (ISO-NE, Transmission, Markets and Services Tariff, attach. K (Regional System Planning Process) (27.0.0), § 3.3 (RSP Planning Horizon and Parameters))); MISO maximum of 20 years (MISO, FERC Electric Tariff, attach. FF (Transmission Expansion Planning Protocol) (85.0.0), § I.C.8.a)); NYISO years 4 through 10 (NYISO, NYISO Tariffs, NYISO OATT, § 31.1, attach. Y (New York Comprehensive System Planning Process) (26.0.0)); PJM 10 years (PJM, Intra-PJM Tariffs, OA Schedule 6, § 1.4 (Contents of the Regional Transmission Expansion Plan) (2.1.0), § 1.4.b)); and, SPP 10 and 20 years (Southwest Power Pool, Inc., OATT, attach. Y, § III (The Integrated Transmission Planning Assessment) (8.0.0), § IV (Other Planning Studies) (8.0.0)). 102 For example, Reliability Standard TPL-001-4 requires that Transmission Planners conduct an annual planning assessment of their region's portion of the bulk electric system and document summarized results of the steady state analyses, short circuit analyses, and stability analyses. TPL-001-4 also requires that Transmission Planners conduct these analyses using a model of their systems operating under a wide variety of potential conditions to see under what, if any, conditions the system will fail to meet reliability criteria. TPL-001-4 lays out the variety of these conditions, including system peak, off-peak, single contingency, multiple contingencies (both sequential and simultaneous), severe contingencies on adjacent systems, sensitivity analyses to underlying model assumptions, and extreme events. Transmission Planner is defined as “the entity that develops a long-term (generally one year and beyond) plan for the reliability (adequacy) of the interconnected bulk electric transmission systems within its portion of the Planning Authority area.” NERC, Glossary of Terms Used in NERC Reliability Standards (June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. 103 The regional transmission planning process will identify the necessary transmission system facilities (which have varying costs and lead times for when they can be placed into service) that are needed to achieve reliable transmission system operations. 104 ANOPR, 176 FERC ¶ 61,024 at P 14. 2. Economic Needs 59. Public utility transmission providers within transmission planning regions also plan transmission facilities to meet economic needs. In Order No. 1000, the Commission recognized that Order No. 890 placed no affirmative obligation on public utility transmission providers to perform economic planning studies absent a request by stakeholders. 105 To remedy this deficiency, the Commission required in Order No. 1000 that, in addition to economic planning studies requested by stakeholders, public utility transmission providers evaluate, through a regional transmission planning process and in consultation with stakeholders, regional transmission facilities that might meet the needs of the transmission planning region more efficiently or cost-effectively than transmission facilities identified by individual public utility transmission providers in their local transmission planning process. 106 These regional transmission facilities could include transmission facilities needed to meet reliability requirements, address economic considerations, and/or meet transmission needs driven by Public Policy Requirements. 107 As Order No. 890 explains, the purpose of economic transmission planning is to plan transmission to alleviate congestion through the integration of new generation resources or an expansion of the regional transmission system, by an amount that justifies its cost, usually by a defined threshold. 108 Examples of regional transmission facilities driven by economic needs include transmission facilities that relieve historical or projected transmission congestion and allow lower-cost power to flow to consumers. 105 Order No. 1000, 136 FERC ¶ 61,051 at PP 3, 81, 147. 106 Id. P 148. 107 Id. PP 147-148. 108 Order No. 890, 118 FERC ¶ 61,119 at P 549. 3. Transmission Needs Driven by Public Policy Requirements 60. In Order No. 1000, the Commission required public utility transmission providers to consider transmission needs driven by Public Policy Requirements in their local and regional transmission planning processes. 109 However, the requirement in Order No. 1000 to consider transmission needs driven by Public Policy Requirements is limited, and the Commission provided public utility transmission providers with flexibility in how to meet the requirement. For example, Order No. 1000 does not require that a separate class of transmission facilities be created in the regional transmission planning process to address transmission needs driven by Public Policy Requirements, 110 nor does it mandate the consideration of any particular transmission need driven by a Public Policy Requirement. 111 In addition, while Order No. 1000 requires that public utility transmission providers consider transmission needs driven by Public Policy Requirements proposed by stakeholders, it provides flexibility on how active public utility transmission providers themselves choose to be in identifying such needs. 112 As a result, the process for identifying and considering transmission needs driven by Public Policy Requirements varies from transmission planning region to transmission planning region. 109 Order No. 1000, 136 FERC ¶ 61,051 at PP 203, 222; Order No. 1000-A, 139 FERC ¶ 61,132 at P 208. 110 Order No. 1000, 136 FERC ¶ 61,051 at P 220 (explaining that the requirements in Order No. 1000 related to transmission needs driven by Public Policy Requirements are intended to “provide flexibility for public utility transmission providers to develop procedures appropriate for their local and regional transmission planning processes”). 111 Id. P 215. 112 Order No. 1000-A, 139 FERC ¶ 61,132 at P 322. B. Comments 61. In response to the ANOPR, the Commission received many comments on the need to reform regional transmission planning processes. Many comments support long-term regional transmission planning. 113 Some transmission developers and incumbent public utility transmission providers support efforts to reform aspects of existing regional transmission planning processes, with some recommending that the Commission impose prescriptive planning requirements. 114 Some state commissions and consumer advocates also support the need to reform regional transmission planning processes, but express concern about potential costs and ensuring that such costs are allocated commensurate with estimated benefits. 115 113 E.g., CAISO Comments at 5; MISO Comments at 41; ISO-NE Comments at 23; NYISO Comments at 26-28; PJM Comments at 3-4; SPP Comments at 6; AEP Comments at 4; Ameren Comments at 5; BP Comments at 3-4; Exelon Comments at 2; National Grid Comments at 4; NextEra Comments at 56; PG&E Comments at 2; Indicated PJM TOs Comments at 3; PSEG Comments at 10-11; SDG&E Comments at 2; SCE Comments at 3-4; Shell Comments at 7; VEIR Comments at 14; Xcel Comments at 19-20; WIRES Comments at 7; EDP Renewables Comments at 4; EDF Comments at 5; EPSA Comments at 6; ITC Comments at 4; New England for Offshore Wind Comments at 1; Certain TDUs Comments at 7; ACORE Comments at 6; ACPA and ESA Comments at 44; AEE Comments at 3; EEI Comments at 12-14; Consumers Council Comments at 9; Harvard ELI Comments at 33; Nature Conservancy Comments at 2-3; PIOs Comments at 60; Resale Iowa Comments at 14; REBA Comments at 17; NARUC Comments at 6; California Public Utility Commission Comments at 5; Michigan Commission Comments at 2-3; Minnesota Department of Commerce Comments at 5; New Jersey Commission Comments at 10-11; District of Columbia Office of the People's Counsel Comments at 22-23; Oregon Public Utility Commission Comments at 1; NEPOOL Comments at 6-7; SPP RSC Comment at 2; NASUCA Comments at 4; Iowa Office Of Consumer Advocate Comments at 2; Massachusetts Attorney General Comments at 2; State of Massachusetts Comments at 2; NESCOE Comments at 5-6; NASEO Comments at 1-2; City of New York Comments at 4; APPA Comments at 9; American Municipal Power Comments at 33-34; California Municipal Utilities Association Comments at 7; Public Systems Comments at 17; U.S. DOE Comments at 12, 16; Association of Fish and Wildlife Agencies Comments at 3; see also ACEG Reply Comments, app. A (identifying 174 entities supporting planning for a future resource mix). 114 For example, AEP, SoCal Edison, and NextEra support a 20-year planning horizon. AEP Comments at 1-2, 7-8; SoCal Edison Comments at 4; NextEra Comments at 70, 79-80. Exelon, PSEG, and NextEra support requirements for public utility transmission providers to include state statutes and goals in their scenarios. Exelon Comments at 12-20; PSEG Comments at 3-6; NextEra Comments at 80. LS Power and Resale Iowa support a requirement that all facilities above 100 kV be regionally planned. LS Power Oct. 12 Comments at 49-60; Resale Iowa Comments at 8. NextEra supports requiring public utility transmission providers to use an expanded set of transmission benefits and to designate renewable energy development zones. NextEra Comments at 92-101. Avangrid supports requiring public utility transmission providers to plan for offshore wind development. Avangrid Comments at 21-23. 115 District of Columbia's Office of the People's Counsel Comments at 1-5; NARUC Comments at 5-7, 46-47; NASUCA Comments at 3-5; Iowa Consumer Advocate Comments at 2. 62. Some RTOs/ISOs assert that their current regional transmission planning processes already incorporate many of the potential reforms discussed in the ANOPR and ask that the Commission provide sufficient flexibility and avoid being too prescriptive should it undertake those reforms. 116 ISO-NE states that forward-looking scenario planning is underway in ISO-NE and asks that the Commission not require a one-size-fits-all approach. 117 NYISO urges the Commission to consider that in NYISO, incremental, yet meaningful, reforms can implement many of the goals of the ANOPR, and asks that the Commission recognize the need for regional variation so that each RTO/ISO can improve its regional transmission planning process in light of its regional needs. 118 116 CAISO Comments at 3-5; MISO Comments at 2-4. 117 ISO-NE Comments at 2, 13-16. 118 NYISO Comments at 2-4. 63. The market monitors express mixed views on more comprehensive or long-term transmission planning. The PJM Market Monitor expresses a concern around the lack of certainty and quality of additional information being included in regional transmission planning that may impose additional uncertainty on the regional transmission planning process. 119 Potomac Economics expresses concern regarding mandating long-term regional transmission planning that requires public utility transmission providers to speculate on certain future conditions, but notes improvements could be made to the regional transmission planning process to account for near-term emerging trends that are less uncertain than longer-term factors. 120 In contrast, the SPP Market Monitor expresses a concern that SPP's regional transmission planning process is not planning for generation resources of the future. 121 119 PJM Market Monitor Comments at 2-3. 120 Potomac Economics Comments at 4. 121 SPP Market Monitor Comments at 4. C. Proposed Reforms 1. Long-Term Regional Transmission Planning a. Need for Reform 64. We are concerned that existing regional transmission planning processes may not be planning on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand, leading to the piecemeal and inefficient development of new transmission facilities in a manner that is not more efficient or cost-effective. As discussed above, existing regional transmission planning processes typically look out and plan for transmission needs based on a relatively short time horizon. 122 While some existing regional transmission planning processes may incorporate studies or assessments that have a longer forward-looking period, these are typically for informational purposes and do not result in identification of long-term regional transmission needs, assessment of transmission alternatives to meet those needs, or selection of transmission facilities in the regional transmission plan for purposes of cost allocation. 123 In lieu of such a long-term outlook, transmission needs driven by changes in the resource mix and demand are largely addressed through generator interconnection processes. 124 However, such processes are not designed to evaluate the need for larger, regional transmission facilities to address transmission needs driven by changes in the resource mix and demand, resulting in a piecemeal expansion of the electric transmission system. 122 Supra Need for Reform: Unjust and Unreasonable and Unduly Discriminatory and Preferential Commission-Jurisdictional Rates. For example, PJM's Regional Transmission Expansion Plan (RTEP) baseline assessment looks out over a 5-year period, the NorthernGrid Regional Transmission Plan has a 10-year planning horizon, and SPP's Integrated Transmission Plan (ITP) also addresses a 10-year horizon. 123 See infra P 94. 124 See supra P 36. 65. Implementation challenges associated with long-term transmission planning—such as determining the appropriate time horizon, selecting a set of factors to forecast the future resource mix and demand, and choosing the appropriate method to account for uncertainty—make it unlikely that public utility transmission providers will engage in such transmission planning voluntarily and regularly. However, such challenges do not diminish the importance of long-term transmission planning. Moreover, even if long-term regional transmission planning is performed, failing to consider an adequate time horizon, set of factors to forecast the future resource mix and demand, and sufficient method to account for uncertainty—may result in transmission planning that is inadequate in identifying more efficient or cost-effective transmission facilities due a less comprehensive and accurate understanding of the areas impacted by transmission needs driven by changes in the resource mix and demand. Accordingly, we believe that reforms may be necessary to require public utility transmission providers to identify transmission needs driven by changes in the resource mix and demand. 66. We are also concerned that existing regional transmission planning requirements may be inadequate to ensure that public utility transmission providers adequately assess the benefits of regional transmission facilities planned to meet transmission needs driven by changes in the resource mix and demand. In Order No. 1000, the Commission declined to prescribe particular definitions of or a uniform approach to identifying benefits and beneficiaries, in order to allow flexibility for public utility transmission providers to develop cost allocation methods for their transmission planning regions. 125 However, transmission facilities may provide a wide variety of benefits to transmission customers, particularly for regional transmission facilities addressing large, systemic changes in the electric industry. We recognize that when public utility transmission providers fail to consider a broader set of benefits for transmission facilities meeting transmission needs driven by changes in the resource mix and demand, they may fail to select transmission facilities in their regional transmission plans for purposes of cost allocation that meet the transmission planning region's transmission needs more efficiently or cost-effectively. 125 Order No. 1000, 136 FERC ¶ 61,051 at PP 624-625. 67. As described in the ANOPR, existing regional transmission planning and cost allocation processes generally examine categories of transmission needs separately from one another based on the driver of the relevant transmission need, be it reliability, economic considerations, or Public Policy Requirements. 126 As a general matter, public utility transmission providers only calculate the set of benefits specific to that category of transmission need for purposes of determining whether a regional transmission facility meets the criteria for selection. However, the literature and experience demonstrates a panoply of benefits beyond those currently considered by all public utility transmission providers in existing regional transmission planning and cost allocation processes. 127 Failing to provide for the allocation of costs of transmission facilities selected in a regional transmission plan for purposes of cost allocation to address transmission needs driven by changes in the resource mix and demand in a way that aligns with a reasonable set of benefits through the transmission planning process could lead to needed transmission facilities not being built, adversely affecting ratepayers. Accordingly, we propose a list of benefits for public utility transmission providers to consider when assessing a broader set of benefits during long-term regional transmission planning, and require public utility transmission providers to provide certain information, as described below, about the benefits they will use. 126 ANOPR, 176 FERC ¶ 61,024 at P 85. 127 See generally Paul L. Joskow, Facilitating Transmission Expansion to Support Efficient Decarbonization of the Elec [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%3A2022-08973. Public record. Not legal advice.