# Improvements to Generator Interconnection Procedures and Agreements > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2023-16628 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** September 6, 2023 - **Citation:** 88 FR 61014 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM22-14-000; Order No. 2023] Improvements to Generator Interconnection Procedures and Agreements AGENCY: Federal Energy Regulatory Commission, Department of Energy. ACTION: Final rule. SUMMARY: The Federal Energy Regulatory Commission (Commission or FERC) is adopting reforms to its pro forma Large Generator Interconnection Procedures, pro forma Small Generator Interconnection Procedures, pro forma Large Generator Interconnection Agreement, and pro forma Small Generator Interconnection Agreement to address interconnection queue backlogs, improve certainty, and prevent undue discrimination for new technologies. The reforms are intended to ensure that the generator interconnection process is just, reasonable, and not unduly discriminatory or preferential. DATES: This final rule is effective November 6, 2023. FOR FURTHER INFORMATION CONTACT: Tristan Kessler (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6608, tristan.kessler@ferc.gov. Franklin Jackson (Technical Information), Office of Energy Market Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-6464, franklin.jackson@ferc.gov. Sarah Greenberg (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-6230, sarah.greenberg@ferc.gov. SUPPLEMENTARY INFORMATION: Table of Contents Paragraph Numbers I. Introduction 1 A. Historical Framework: Order Nos. 2003, 2006, and 845 11. B. Regional Transmission Planning and Cost Allocation and Generator Interconnection Advance Notice of Proposed Rulemaking 18 C. Notice of Proposed Rulemaking 20 D. Joint Federal-State Task Force on Electric Transmission 25 II. Overall Need for Reform 27 A. NOPR 27 B. Comments 30 C. Commission Determination 37 III. Reforms 61 A. Reforms To Implement a First-Ready, First-Served Cluster Study Process 61 1. Interconnection Information Access 61 2. Cluster Study Process 165 3. Allocation of Cluster Study Costs 405 4. Allocation of Cluster Network Upgrade Costs 422 5. Shared Network Upgrades 468 6. Increased Financial Commitments and Readiness Requirements 490 7. Transition Process 814 B. Reforms To Increase the Speed of Interconnection Queue Processing 872 1. Elimination of the Reasonable Efforts Standard 872 2. Affected Systems 1026 3. Optional Resource Solicitation Study 1294 C. Reforms To Incorporate Technological Advancements Into the Interconnection Process 1324 1. Increasing Flexibility in the Generator Interconnection Process 1324 2. Incorporating the Enumerated Alternative Transmission Technologies Into the Generator Interconnection Process 1534 3. Modeling and Ride-Through Requirements for Non-Synchronous Generating Facilities 1621 D. Issues Beyond the Scope of this Rulemaking 1736 1. Comments 1736 2. Commission Determination 1743 IV. Compliance Procedures 1744 A. NOPR Proposal 1744 B. Comments 1747 1. Compliance Filing Deadline 1747 2. Regional Flexibility 1750 3. Reciprocity Tariffs 1759 4. Effective Date 1760 5. Miscellaneous 1761 C. Commission Determination 1762 V. Information Collection Statement 1772 VI. Environmental Analysis 1779 VII. Regulatory Flexibility Act 1780 VIII. Document Availability 1783 IX. Effective Date and Congressional Notification 1785 I. Introduction 1. This final rule requires all public utility transmission providers to adopt revised pro forma Large Generator Interconnection Procedures (LGIP), pro forma Small Generator Interconnection Procedures (SGIP), pro forma Large Generator Interconnection Agreements (LGIA), and pro forma Small Generator Interconnection Agreements (SGIA). 1 These revisions will ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, and will prevent undue discrimination. 1 Section 201(e) of the Federal Power Act (FPA) defines “public utility” to mean “any person who owns or operates facilities subject to the jurisdiction of the Commission under this subchapter.” 16 U.S.C. 824(e). A non-public utility that seeks voluntary compliance with the reciprocity condition of a tariff may satisfy that condition by filing a tariff, which includes the pro forma LGIP, the pro forma SGIP, the pro forma LGIA, and the pro forma SGIA. See Standardization of Generator Interconnection Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ¶ 61,103, at PP 1, 616 (2003), order on reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 5, 2004), 106 FERC ¶ 61,220, order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ¶ 61,287 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (July 18, 2005), 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) ( NARUC v. FERC ). As stated in the pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA, transmission provider “shall mean the public utility (or its designated agent) that owns, controls, or operates transmission or distribution facilities used for the transmission of electric energy in interstate commerce and provides transmission service under the [Transmission Provider's Tariff]. The term . . . should be read to include the Transmission Owner when the Transmission Owner is separate from the Transmission Provider.” Pro forma LGIP section 1; pro forma LGIA art. 1; pro forma SGIP attach. 1; pro forma SGIA attach. 1. 2. Twenty years ago the Commission issued Order No. 2003, in which the Commission required all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file standard procedures and a standard agreement for interconnecting generating facilities larger than 20 megawatts (MW) (called the pro forma LGIP and the pro forma LGIA). 2 The Commission stated its expectation that the changes would prevent undue discrimination, preserve reliability, increase energy supply, and lower wholesale prices for customers by increasing the amount and variety of new generation that would compete in the wholesale electricity market. 3 The Commission further stated that the standard procedures would facilitate market entry for generation competitors by reducing interconnection costs and time. 4 In Order No. 2006, the Commission adopted standard procedures and a standard agreement for interconnecting generating facilities no larger than 20 MW (called the pro forma SGIP and the pro forma SGIA), citing the same purposes outlined in Order No. 2003. 5 2 Order No. 2003, 104 FERC ¶ 61,103 at P 2. 3 Id. P 1. 4 Id. P 12. 5 Standardization of Small Generator Interconnection Agreements & Procs., Order No. 2006, 111 FERC ¶ 61,220, at PP 15, 35-36, order on reh'g, Order No. 2006-A, 70 FR 71760 (Dec. 30, 2005), 113 FERC ¶ 61,195 (2005), order granting clarification, Order No. 2006-B, 71 FR 42587 (July 27, 2006), 116 FERC ¶ 61,046 (2006). 3. The electricity sector has transformed significantly since the issuance of Order Nos. 2003 and 2006. The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources have created new challenges for the generator interconnection process. These new challenges are creating large interconnection queue backlogs and uncertainty regarding the cost and timing of interconnecting to the transmission system, increasing costs for consumers. Backlogs in the generator interconnection process, in turn, can create reliability issues as needed new generating facilities are unable to come online in an efficient and timely manner. While the Commission recognized these issues and sought to address them in Order No. 845, 6 it is clear that further action is needed. Therefore, we believe that it is necessary to reform the Commission's standard interconnection procedures and agreements to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. 6 See Reform of Generator Interconnection Procs. & Agreements, Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ¶ 61,043, at P 24 (2018), order on reh'g, Order No. 845-A, 84 FR 8156 (Mar. 6, 2019) 166 FERC ¶ 61,137, order on reh'g, Order No. 845-B, 168 FERC ¶ 61,092 (2019). 4. Accordingly, we adopt reforms to the Commission's pro forma LGIP and pro forma LGIA. Specifically, as explained in detail in this final rule, we adopt reforms to: (1) implement a first-ready, first-served cluster study process; 7 (2) increase the speed of interconnection queue processing; and (3) incorporate technological advancements into the interconnection process. 7 A first-ready, first-served cluster study process improves efficiency in the interconnection study process by including the following elements: increased access to information prior to entering the queue; a mechanism to study interconnection requests in groups where all interconnection requests in the group are equally queued and of equal study priority; and increased financial commitments and readiness requirements to enter and proceed through the queue. In contrast, the existing first-come, first-served serial study process in the pro forma LGIA and LGIP provides limited information to interconnection customers prior to entering the queue, assigns interconnection requests an individual queue position based solely on the date of entry into the queue, and contains limited financial and readiness requirements. 5. First, in order to implement a first-ready, first-served cluster study process, this final rule requires: (1) transmission providers to publicly post available information pertaining to generator interconnection; (2) transmission providers to use cluster studies as the interconnection study method; (3) transmission providers to allocate cluster study costs on a pro rata and per capita basis; (4) transmission providers to allocate network upgrade costs based on a proportional impact method; (5) interconnection customers to pay study and commercial readiness deposits as part of the cluster study process; (6) interconnection customers to demonstrate site control at the time of submission of the interconnection request; and (7) transmission providers to impose withdrawal penalties on interconnection customers for withdrawing from the interconnection queue, with certain exceptions. We also require transmission providers to adopt a transition process to move from the existing serial interconnection process to the new cluster study process. 6. Second, in order to increase the speed of interconnection queue processing, this final rule: (1) eliminates the reasonable efforts standard for conducting interconnection studies and imposes a financial penalty on transmission providers that fail to meet interconnection study deadlines; and (2) establishes an affected system study process and associated pro forma affected system agreements. 7. Third, in order to incorporate technological advancements into the interconnection process, this final rule requires transmission providers to: (1) allow more than one generating facility to co-locate on a shared site behind a single point of interconnection and share a single interconnection request; (2) evaluate the proposed addition of a generating facility at the same point of interconnection prior to deeming such an addition a material modification if the addition does not change the originally requested interconnection service level; (3) allow interconnection customers to access the surplus interconnection service process once the original interconnection customer has an executed LGIA or requests the filing of an unexecuted LGIA; (4) use operating assumptions in interconnection studies that reflect the proposed charging behavior of an electric storage resource; and (5) evaluate the list of alternative transmission technologies enumerated in this final rule during the generator interconnection study process. This final rule also requires interconnection customers requesting to interconnect a non-synchronous generating facility to: (1) provide the transmission provider with the models needed for accurate interconnection studies; and (2) have the ability to maintain power production at pre-disturbance levels and provide dynamic reactive power to maintain system voltage during transmission system disturbances and within physical limits. Finally, this final rule requires that all newly interconnecting large generating facilities provide ride through capability consistent with any standards and guidelines that are applied to other generating facilities in the balancing authority area on a comparable basis. 8. We also adopt reforms to the pro forma SGIP and pro forma SGIA. Specifically, as explained in detail in this final rule, for small generating facilities we propose reforms to incorporate the enumerated alternative transmission technologies into the interconnection process, and to provide modeling and ride through requirements for non-synchronous generating facilities. 9. Many of the reforms adopted in this final rule track the notice of proposed rulemaking's 8 (NOPR) proposed reforms closely. However, as discussed more fully below, we have revised aspects of the reforms pertaining to the cluster study process, allocation of cluster study and network upgrade costs, increased financial commitments and readiness requirements, financial penalties for delayed interconnection studies, the affected system study process, pro forma affected system agreements, the material modification process, operating assumptions for interconnection studies, incorporating the enumerated alternative transmission technologies, and ride through requirements. Additionally, as discussed more fully below, we decline to adopt the NOPR proposals pertaining to informational interconnection studies, shared network upgrades, the optional resource solicitation study, and the alternative transmission technologies annual report. 8 Improvements to Generator Interconnection Procs. & Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ¶ 61,194 (2022) (NOPR). 10. We recognize that transmission providers have undertaken efforts to address interconnection queue management issues. This final rule is not intended to divert or slow the potential progress represented by those efforts, and we encourage transmission providers to continue to innovate to remedy their identified interconnection queue management issues. We note that the compliance obligations that result from this final rule will be evaluated in light of the independent entity variation standard for regional transmission organizations (RTO) and independent system operators (ISO) and the consistent with or superior to standard for non-RTO/ISO transmission providers. 9 9 Order No. 2003, 104 FERC ¶ 61,103 at P 26; see infra section IV. A. Historical Framework: Order Nos. 2003, 2006, and 845 11. In Order No. 2003, the Commission recognized a need for a standard set of interconnection procedures for transmission providers and a single, uniformly applicable interconnection agreement for large generating facilities. 10 The Commission noted that generator interconnection is a “critical component of open access transmission service and thus is subject to the requirement that utilities offer comparable service under the [ pro forma open access transmission tariff (tariff)].” 11 The Commission found that it was appropriate to establish a standard set of generator interconnection procedures to “minimize opportunities for undue discrimination and expedite the development of new generation, while protecting reliability and ensuring that rates are just and reasonable.” 12 To this end, the Commission adopted the pro forma LGIP and pro forma LGIA and amended its regulations to require all transmission providers to incorporate these standard procedures and agreement into their tariffs. 13 10 Order No. 2003, 104 FERC ¶ 61,103 at P 11. Large generating facilities are defined to mean “a Generating Facility having a Generating Facility Capacity of more than 20 MW.” Pro forma LGIP section 1. 11 Order No. 2003, 104 FERC ¶ 61,103 at P 9 (citing Tenn. Power Co., 90 FERC ¶ 61,238 (2000)). 12 Id. P 11. 13 18 CFR 35.28(f)(1) (2022). 12. To initiate the generator interconnection process set forth in the Commission's pro forma LGIP, 14 the interconnection customer submits an interconnection request for its proposed generating facility that includes preliminary documentation of the site of the proposed generating facility, certain technical information about the proposed generating facility, and the expected commercial operation date of the proposed generating facility, along with a refundable deposit of $10,000. 15 After the transmission provider determines that the interconnection request is complete, the interconnection request enters the transmission provider's interconnection queue with other pending interconnection requests and is assigned a queue position based on the time and date of its receipt. 16 The queue position determines the order in which the transmission provider studies the interconnection requests in its interconnection queue. 17 14 While we provide a broad description of the process in the Commission's pro forma LGIP as background here, we recognize that many transmission providers have adopted (and the Commission has accepted) variations to many of the terms in the Commission's pro forma LGIP and pro forma LGIA. Consequently, some or many of the details of a particular transmission provider's generator interconnection procedures may vary considerably from the broad description provided here. 15 Order No. 2003, 104 FERC ¶ 61,103 at P 35; pro forma LGIP sections 3.1, 3.4. 16 Pro forma LGIP section 4.1. 17 Id. 13. Transmission providers must schedule a scoping meeting with the interconnection customer to discuss possible points of interconnection for the proposed generating facility and exchange technical information, which is followed by a series of interconnection studies to evaluate the proposed interconnection in detail. 18 Transmission providers study interconnection requests in three phases: (1) the interconnection feasibility study (feasibility study); 19 (2) the interconnection system impact study (system impact study); 20 and (3) the interconnection facilities study (facilities study). 21 These studies contain the power flow, short circuit, and stability analyses necessary to: (1) identify any adverse impacts on the transmission providers' transmission system or any affected systems; 22 (2) determine the interconnection facilities and network upgrades 23 needed to reliably interconnect the generating facility; and (3) estimate the interconnection customer's cost responsibility for these facilities. 24 The pro forma LGIP requires that transmission providers use reasonable efforts to complete: (1) feasibility studies within 45 calendar days; (2) system impact studies within 90 calendar days; and (3) facilities studies within 90 or 180 calendar days, depending on the interconnection customer's requested accuracy margin. 25 18 Order No. 2003, 104 FERC ¶ 61,103 at P 36; pro forma LGIP sections 3.4.4, 6-8. 19 The pro forma LGIP defines a feasibility study as “a preliminary evaluation of the system impact and cost of interconnecting the Generating Facility to the Transmission Provider's Transmission System.” The scope of a feasibility study is described in section 6 of the pro forma LGIP. Pro forma LGIP sections 1, 6. 20 The pro forma LGIP defines a system impact study as “an engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of Transmission Provider's Transmission System and, if applicable, an Affected System.” In particular, a system impact study identifies and details “the system impacts that would result if the Generating Facility were interconnected without project modifications or system modifications, focusing on the Adverse System Impacts identified in the [feasibility study], or to study potential impacts, including but not limited to those identified in the Scoping Meeting.” Id. section 1. 21 The pro forma LGIP defines a facilities study as “a study conducted by the Transmission Provider or a third-party consultant for the Interconnection Customer to determine a list of facilities (including Transmission Provider's Interconnection Facilities and Network Upgrades as identified in the [system impact study]), the cost of those facilities, and the time required to interconnect the Generating Facility with the Transmission Provider's Transmission System.” The scope of a facilities study is described in section 8 of the pro forma LGIP. Id. sections 1, 8. 22 The pro forma LGIP defines an affected system as an electric system other than the transmission provider's transmission system that may be affected by the proposed interconnection. Id. section 1; pro forma LGIA art. 1. 23 For purposes of this final rule, unless otherwise noted, “network upgrades” refer to interconnection-related network upgrades. More specifically, the pro forma LGIP and pro forma LGIA provide that, “Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission Provider's Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission Provider's Transmission System to accommodate the interconnection of the Large Generating Facility to the Transmission Provider's Transmission System.” Pro forma LGIP section 1; pro forma LGIA art. 1. 24 Order No. 2003, 104 FERC ¶ 61,103 at PP 35-37; pro forma LGIP sections 6-8. The interconnection customer is responsible for the actual costs of interconnection studies and any necessary restudies. Pro forma LGIP section 13.3. 25 Pro forma LGIP sections 6.3, 7.4, 8.3. 14. At the completion of the facilities study, the pro forma LGIP requires the transmission provider to issue a report on the best estimate of the costs to effectuate the requested interconnection and provide a draft generator interconnection agreement to the interconnection customer. 26 If the interconnection customer wishes to proceed, after negotiations, the interconnection customer enters into a generator interconnection agreement with the transmission provider or, in specific circumstances, requests that the transmission provider file the agreement with the Commission unexecuted. 27 The transmission provider is responsible for the construction of all network upgrades, but, as further discussed below, the interconnection customer has the option to build these facilities in certain circumstances. 28 26 Order No. 2003, 104 FERC ¶ 61,103 at P 38. Section 11.1 of the pro forma LGIP requires the transmission provider to tender a draft LGIA to the interconnection customer “in the form of Transmission Provider's FERC-approved standard form LGIA.” 27 If the transmission provider and interconnection customer execute an LGIA that conforms to the transmission provider's Commission-approved standard form LGIA, the agreement does not need to be filed with the Commission (if the transmission provider has such a standard form LGIA on file and submits an Electronic Quarterly Report). Alternatively, the transmission provider must file an LGIA with the Commission for review and approval if: (1) the interconnection customer determines that negotiations with the transmission provider over the terms of an LGIA are at an impasse and requests submission of the unexecuted LGIA with the Commission; or (2) the LGIA does not conform to the transmission provider's Commission-approved standard form LGIA. See Order No. 2003-A, 106 FERC ¶ 61,220 at P 201; pro forma LGIP sections 11.2-11.3. 28 Order No. 2003, 104 FERC ¶ 61,103 at PP 351-354; pro forma LGIA art. 5.1.3. 15. Similar to Order No. 2003, in Order No. 2006, the Commission recognized the need for standardized interconnection procedures and agreements for small generating facilities with a capacity of 20 MW or less. 29 In addition to establishing a pro forma interconnection study process for small generating facilities similar to the process for large generating facilities established in Order No. 2003, the Commission included: (1) a “fast track process” 30 that uses technical screens to evaluate a certified small generating facility no larger than 2 MW; and (2) a “10 [kilowatt (kW)] inverter process” 31 that uses the same technical screens to evaluate a certified inverter-based small generating facility no larger than 10 kW. 32 The Commission later issued Order No. 792, 33 in which the Commission revised the pro forma SGIP and pro forma SGIA to provide for interconnection customers to receive point of interconnection information in advance of submitting an interconnection request, increase the threshold for participation in the fast track process to five MW, and to specifically include electric storage devices. 34 29 Order No. 2006, 111 FERC ¶ 61,220 at P 36. 30 Pro forma SGIP section 2.1. 31 Id. attach. 5. 32 Order No. 2006, 111 FERC ¶ 61,220 at PP 36, 38-39. 33 Small Generator Interconnection Agreements & Procs., Order No. 792, 78 FR 73240 (Dec. 5, 2013), 145 FERC ¶ 61,159 (2013), clarifying, Order No. 792-A, 146 FERC ¶ 61,214 (2014). 34 See Order No. 792, 145 FERC ¶ 61,159 at P 1. 16. In response to concerns voiced to the Commission about interconnection queue management, in 2007, the Commission held a technical conference, 35 and later issued an order 36 addressing interconnection queue issues in RTOs/ISOs. In the order, the Commission noted that some transmission providers were not processing their interconnection queues within the timelines established in the pro forma LGIP, and in certain cases, were greatly exceeding them. 37 The Commission stated that, although it “may need to [impose solutions] if the RTOs and ISOs do not act themselves,” each RTO/ISO would have an opportunity to work with its stakeholders to develop its own solutions. 38 As further discussed below, following the order, multiple RTOs/ISOs submitted queue reform proposals to the Commission, some of which moved away from a so-called “first-come, first-served” approach (whereby interconnection requests are processed in the order they are received) to a so-called “first-ready, first-served” approach (whereby interconnection requests are processed based on when interconnection customers meet certain project development milestones). 39 The reason for this move was to allow interconnection customers with interconnection requests for generating facilities more likely to achieve commercial operation to move faster instead of being delayed by interconnection requests that were higher in the interconnection queue but making limited or no progress towards commercial operation and creating unreasonable queue delays. 35 Interconnection Queuing Practices, Notice of Technical Conference, Docket No. AD08-2-000 (issued Nov. 2, 2007). 36 Interconnection Queuing Pracs., 122 FERC ¶ 61,252 (2008) (2008 Technical Conference Order). 37 Id. P 3. 38 Id. P 8. 39 See, e.g., Sw. Power Pool, Inc., 128 FERC ¶ 61,114 (2009); Midwest Indep. Transmission Sys. Operator, Inc., 124 FERC ¶ 61,183 (2008); Cal. Indep. Sys. Operator Corp., 124 FERC ¶ 61,292 (2008). 17. In 2018, the Commission issued Order No. 845, in which the Commission made the most comprehensive revisions to the pro forma LGIP and pro forma LGIA since their adoption in Order No. 2003. In Order No. 845, the Commission concluded that reforms to the pro forma LGIP and pro forma LGIA were needed to mitigate concerns regarding systemic inefficiencies, remedy discriminatory practices, and address recent developments, including changes in the resource mix and emergence of new technologies. 40 The Commission therefore adopted reforms designed to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the generator interconnection process. 41 40 Order No. 845, 163 FERC ¶ 61,043 at P 7. 41 Id. P 2. B. Regional Transmission Planning and Cost Allocation and Generator Interconnection Advance Notice of Proposed Rulemaking 18. On July 15, 2021, the Commission issued an advance notice of proposed rulemaking (ANOPR) in Docket No. RM21-17-000, presenting potential reforms to the Commission's requirements governing the regional transmission planning and cost allocation and generator interconnection processes. 42 Specific to the generator interconnection process, the Commission sought comment on whether and which reforms may be necessary to ensure a more purposeful integration of the generator interconnection process with the regional transmission planning and cost allocation processes, establish a faster and more efficient interconnection queueing process, and promote a more efficient and cost-effective allocation of network upgrade costs. 43 For instance, the Commission noted that the cost of network upgrades can depend largely on both the timing of when the interconnection customer enters the interconnection queue and where the interconnection customer proposes to interconnect its generating facility. Therefore, the Commission noted, interconnection customers may submit multiple interconnection requests in an effort to determine the most favorable point of interconnection 44 that minimizes their network upgrade costs. 45 The Commission stated that this practice, in turn, may lead to late-stage withdrawals of the excess interconnection requests, which can then impede the transmission provider's ability to process its interconnection queue in an efficient manner. As a result, the Commission stated that it may be time to consider reforms to the generator interconnection process that would make it more efficient and ensure that generating facilities that are more “ready” than others are not unduly delayed in the interconnection queue. 42 Bldg. for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation & Generator Interconnection, 86 FR 40266 (July 15, 2021), 176 FERC ¶ 61,024 (2021) (ANOPR). 43 Id. P 5. 44 The pro forma LGIP defines point of interconnection as “the point, as set forth in Appendix A to the Standard Large Generator Interconnection Agreement, where the Interconnection Facilities connect to the Transmission Provider's Transmission System.” Pro forma LGIP section 1. 45 ANOPR, 176 FERC ¶ 61,024 at P 41. 19. On April 21, 2022, the Commission issued a notice of proposed rulemaking (Transmission Planning and Cost Allocation NOPR) proposing reforms to its existing regional transmission planning and cost allocation requirements in the same proceeding as it issued the ANOPR. 46 While the Transmission Planning and Cost Allocation NOPR did not address many of the concerns raised by the Commission in the ANOPR with respect to the generator interconnection queue process, the Commission noted in the Transmission Planning and Cost Allocation NOPR that it would continue to review the record and that it expected to address possible inadequacies through subsequent proceedings that propose reforms, as warranted, related to that topic. 47 The Commission took that next step with the reforms proposed in the NOPR in this proceeding, many of which we adopt in this final rule. 46 Bldg. for the Future Through Elec. Reg'l Transmission Plan. & Cost Allocation & Generator Interconnection, 87 FR 26504 (May 4, 2022), 179 FERC ¶ 61,028 (2022). 47 Id. P 10. C. Notice of Proposed Rulemaking 20. On June 16, 2022, the Commission issued the NOPR, proposing reforms focused on improving aspects of the pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA. The Commission also sought comment on, but did not propose, tariff revisions on other issues. 21. First, the Commission proposed reforms focused on improving interconnection processes to ensure interconnection customers can proceed in an efficient and timely manner. 48 Among those, the Commission proposed to: (1) require transmission providers to offer an optional informational interconnection study to serve as additional information for prospective interconnection customers in deciding whether to submit an interconnection request and set minimum requirements for transmission providers to publicly post available information pertaining to generator interconnection; 49 (2) require transmission providers to implement a first-ready, first-served cluster study process that allocates costs associated with cluster studies and identified network upgrades consistent with the discussion below; 50 and (3) impose more stringent financial commitments and readiness requirements on interconnection customers, including increased study deposits, more stringent site control requirements, a commercial readiness framework, and higher withdrawal penalties. 51 To implement these reforms, the Commission also proposed to require transmission providers to establish a transition process. 52 48 NOPR, 179 FERC ¶ 61,194 at P 4. 49 Id. PP 42-52. 50 Id. PP 56-101. 51 Id. PP 104-148. 52 Id. PP 150-160. 22. Second, the Commission proposed three reforms to increase the speed of interconnection queue processing, including: (1) revisions to eliminate the reasonable efforts standard for interconnection study processing; 53 (2) revisions to establish an affected system study process, along with necessary pro forma affected system agreements; 54 and (3) revisions to establish an optional resource solicitation study. 55 53 Id. PP 168-173. 54 Id. PP 182-215. 55 Id. PP 223-237. 23. Finally, the Commission proposed three reforms to incorporate technological advancements into the interconnection study process. With these reforms, the Commission proposed to require transmission providers to: (1) increase flexibility in the generator interconnection process by allowing generating facilities to co-locate, allow the interconnection customer to request the addition of a generating facility to an existing interconnection request, increase the availability of surplus interconnection service, and allow interconnection customers to propose operating assumptions for their generating facilities; 56 (2) incorporate the enumerated alternative transmission technologies into the interconnection study process at the request of the interconnection customer; 57 and (3) list required modeling standards for inclusion in all interconnection requests that include inverter-based resources (IBRs), as well as require certain performance standards from IBRs during system disturbances. 58 56 Id. PP 242-288. 57 Id. PP 297-302. 58 Id. PP 328-341. 24. In response to the NOPR, 189 comments were filed. 59 These comments have informed our determinations in this final rule. 59 Appendix A lists the entities that submitted comments on the NOPR and the shortened names used through this final rule to describe those entities. D. Joint Federal-State Task Force on Electric Transmission 25. 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. 60 The Commission explained that the development of new transmission infrastructure implicated a host of different issues, including generator interconnection. 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. 61 The Task Force convenes for multiple formal meetings annually, which are open to the public. Since its creation and as of the date of issuance of this final rule, the Task Force has met seven times. 60 Joint Fed.-State Task Force on Elec. Transmission, 175 FERC ¶ 61,224, at PP 1, 6 (2021). 61 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. 26. The discussion at the May 2022 meeting focused on interconnection issues, including generator interconnection queue processes and backlogs. The Task Force members discussed: the primary challenges preventing more efficient processing of interconnection queues; specific improvements to interconnection processes (such as tighter applicant requirements to enter and remain in the queue, clustering, fast tracking, tighter deadlines on transmission providers completing studies, and minimizing reiterative studies); and how to balance near-term improvements to the interconnection procedures with longer-term regional transmission planning and development. 62 62 Joint Fed.-State Task Force on Elec. Transmission, Notice of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022). II. Overall Need for Reform A. NOPR 27. In the NOPR, the Commission noted that the serial first-come, first-served study process was adopted at a time when most interconnection requests were for large traditional generating facilities that would use readily available transmission capacity. 63 The Commission stated that the continued use of this process in the face of dramatic changes to the electric power industry, principally the surge in interconnection requests, the rapidly changing resource mix, evolving market forces, and the emergence of new technologies, has led to a growing backlog of interconnection requests and study delays for many transmission providers. 64 The Commission also stated that these interconnection queue backlogs and study delays create uncertainty and inhibit project developers' ability to interconnect generating facilities to the transmission system. 65 The Commission preliminarily found that the existing pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA may be insufficient to ensure that new generating facilities are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner and to thereby ensure that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. 66 Further, because the interconnection queue backlogs and study delays afflicting generator interconnection service nationwide hinder the timely development of new generation and thereby stifle competition in the wholesale electric markets, the Commission also preliminarily found that the Commission's pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA result in rates, terms, and conditions in the wholesale electric markets that are unjust, unreasonable, and unduly discriminatory or preferential. 63 NOPR, 179 FERC ¶ 61,194 at P 18. 64 Id. PP 18-20. 65 Id. P 19 (citing Joint Fed.-State Task Force on Elec. Transmission, Technical Conference, Docket No. AD21-15-000, Tr. 15:21-16:1 (Ted Thomas) (May 6, 2022) (May Joint Task Force Tr.) (“Houston, we have a problem. As stated in the NARUC ANOPR comments, existing methods for interconnecting new resources to the transmission grid are inadequate and inefficient because of the time necessary to interconnect new resources and the corresponding network upgrade costs.”)). 66 Id. P 22 (citing May Joint Task Force Tr. 23:6-11 (Riley Allen) (“Ultimately, this system is not working efficiently now and those inefficiencies translate into costs. It's not just cost on the developers, but I find from my decades of experience that, if there are inefficiencies in the system, they ultimately have to be borne by the loads and ratepayer interests.”)). 28. The Commission stated that its preliminary findings were based on several features of the Commission's existing generator interconnection procedures and agreements that are of concern, specifically: (1) the information (or lack thereof) available to prospective interconnection customers and the commitments required of them to enter and progress through the interconnection queue; (2) the reliance on a serial first-come, first-served study process and the standard to which transmission providers are held for meeting interconnection study deadlines; (3) the protocols for affected systems studies; (4) the provisions for studying new or hybrid generation technologies and considering alternative transmission technologies; and (5) the performance requirements for non-synchronous generating facilities, including wind, solar, and electric storage facilities. 67 67 Id. PP 23-36 (citing May Joint Task Force Tr. 70:20-71:6 (Matthew Nelson) (analogizing reiterative studies to going to the supermarket to buy ingredients for a recipe without knowing how much the ingredients cost, finding out at the register that they cost too much for your budget, and having to “go home, get a new recipe, and start it all over again”)). 29. The Commission found that some of the same issues persist in the small generating facility context and, therefore, proposed limited reforms to the pro forma SGIP and pro forma SGIA to incorporate alternative transmission technologies into the interconnection process and to provide modeling and performance requirements for non-synchronous generating facilities. 68 68 Id. P 5. B. Comments 30. The vast majority of commenters overwhelmingly agree with the Commission's preliminary conclusion that there is a need to reform the Commission's pro forma interconnection procedures and agreements to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. 69 These commenters generally agree that the unprecedented volume of generation in the interconnection queue, which is almost equal to the current U.S. generation fleet, has resulted in severe backlogs in interconnection processes across the country. 70 For example, the Ohio Commission Consumer Advocate states that “there is an urgent need to clear the current generator interconnection queue backlog and to facilitate timely and economic interconnection of new resources in a way that responds to current and future market conditions.” 71 EEI recognizes that, despite many efforts underway across the country to fix individual transmission provider interconnection queue processes, there is still a need for the Commission to address backlogs and improve certainty in the interconnection queue process. 72 Several commenters assert that these interconnection backlogs have resulted in commercial uncertainty regarding both the magnitude of identified upgrade costs and the timeline for completion of interconnection studies, delayed project development, increased costs for consumers due to the prevention of new supply from reaching the market, and impaired reliability. 73 Senators Hickenlooper and King note that, in the past decade, 23% of proposed generating facilities reached commercial operation, while 72% were withdrawn. 74 ELCON and APPA-LPPC both argue that uncertainty, on the part of both transmission provider and generator project developer, inevitably leads to an increase in costs to consumers. 75 U.S. DOE submits a recent report published by the Lawrence Berkeley National Laboratory, which finds that interconnection costs in MISO have escalated as the number of interconnection requests has increased. 76 Specifically, the report finds that interconnection costs in MISO doubled for projects completed between 2019-2021 compared to projects completed prior to 2018, and cost estimates tripled for projects still active in the queue between the same time periods. Some commenters agree that the existing interconnection rules in the pro forma LGIP and pro forma LGIA create an incentive for interconnection customers to submit interconnection requests even if they are not prepared to move forward with their projects, in order to secure a favorable position in the interconnection queue or in an attempt to obtain locations with available transmission capacity. 77 They assert that the withdrawal of each speculative interconnection request triggers reassessments and possible restudies by the transmission provider that can increase the timing and interconnection cost for lower-queued interconnection requests. Several commenters point to ambitious climate goals (such as the United States' commitment to reducing net greenhouse gas emissions by 50-52% by 2030 under the Paris Climate Agreement) and argue that: (1) these changes will likely spur greater investment in new generation and exacerbate the delays in processing interconnection requests; and/or (2) without an efficient and transparent interconnection process, none of the clean energy generating facilities intended to meet these goals can be effectively deployed. 78 Consumers Energy argues that delays in processing interconnection requests will exacerbate resource adequacy challenges. 79 69 ACE-NY Initial Comments at 2; ACE-NY Reply Comments at 5; AEE Initial Comments at 3, 5; AEE Reply Comments at 5; AES Initial Comments at 2; Affected Interconnection Customers Initial Comments at 2; Ameren Initial Comments at 2; APPA-LPPC Reply Comments at 2; Avangrid Initial Comments at 6, 8; Bonneville Initial Comments at 3; CESA Initial Comments at 3; CESA Reply Comments at 1; Clean Energy Associations Initial Comments at 8; Clean Energy Buyers Initial Comments at 3; Clean Energy States Initial Comments at 2-3; Colorado Commission Initial Comments at 1; Consumers Energy Initial Comments at 2; Cypress Creek Initial Comments at 1; Dominion Initial Comments at 4; EEI Initial Comments at 2; EEI Reply Comments at 3; EDF Renewables Initial Comments at 1-2; Enel Initial Comments at 2; Energy Keepers Initial Comments at 2; Evergreen Action Initial Comments at 1; Eversource Initial Comments at 2; Fervo Energy Initial Comments at 2; Google Initial Comments at 2; Guzman Energy Initial Comments at 2; Hannon Armstrong Initial Comments at 1; Hydropower Commenters Initial Comments at 5; Illinois Commission Initial Comments at 2-3, 5; Interwest Initial Comments at 3; Interwest Reply Comments at 2; ISO-NE Initial Comments at 2-3; MISO TOs Initial Comments at 2, 6; NARUC Initial Comments at 3; New Jersey Commission Initial Comments at 4-9; NY Commission and NYSERDA Initial Comments at 3; NV Energy Initial Comments at 3; Ohio Commission Consumer Advocate Initial Comments at 3-4; OMS Initial Comments at 2; Ørsted Initial Comments at 5; Pine Gate Initial Comments at 8; PJM Initial Comments at 1, 4; PJM Coalition Initial Comments at 1; RWE Renewables Initial Comments at 1; Senators Hickenlooper and King Initial Comments at 1-2; Shell Initial Comments at 5-6; State Agencies Initial Comments at 1-2; TAPS Initial Comments at 1; Union of Concerned Scientists Reply Comments at 1; UMPA Initial Comments at 1; WATT Coalition Initial Comments at 1; Xcel Initial Comments at 8. 70 AEE Initial Comments at 3; Apple Initial Comments at 1; Bonneville Initial Comments at 3; Clean Energy Buyers Initial Comments at 3; Colorado Commission Initial Comments at 2, 8-11; EDF Renewables Initial Comments at 2; Evergreen Action Initial Comments at 1; Eversource Initial Comments at 2; Interwest Initial Comments at 1-2; NV Energy Initial Comments at 2-3; Ohio Commission Consumer Advocate Initial Comments at 3-4; Ørsted Initial Comments at 2; Senators Hickenlooper and King Initial Comments at 1-2; U.S. Chamber of Commerce Initial Comments at 5; UMPA Initial Comments at 1. 71 Ohio Commission Consumer Advocate Initial Comments at 3-4. 72 EEI Reply Comments at 3. 73 ACE-NY Initial Comments at 2; AEE Initial Comments at 4; EDF Renewables Initial Comments at 2; ELCON Initial Comments at 2; Fervo Energy Initial Comments at 2; PJM Coalition Initial Comments at 2; Xcel Reply Comments at 1. 74 Senators Hickenlooper and King Initial Comments at 1 (citing Joseph Rand et al., Lawrence Berkeley Nat'l Lab., Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection (Apr. 2022) (Queued Up 2022), https://emp.lbl.gov/sites/default/files/queued_up_2021_04-13-2022.pdf )). 75 ELCON Initial Comments at 2; APPA-LPPC Initial Comments at 2. 76 U.S. DOE Initial Comments at 1 (citing Joachim Seel et al., Lawrence Berkeley Nat'l Lab., Interconnection Cost Analysis in the MISO Territory at 1 (Oct. 2022)). 77 Clean Energy Buyers Initial Comments at 3; Dominion Initial Comments at 4-5; PJM Initial Comments at 12; U.S. Chamber of Commerce Initial Comments at 4-5. 78 AEP Initial Comments at 2; Affected Interconnection Customers Initial Comments at 2; Allen Meyer Initial Comments at 1; Apple Initial Comments at 1; Bretton C Little Initial Comments at 1; Colorado Commission Initial Comments at 13-14; EDF Renewables Initial Comments at 2-3 (referencing Inflation Reduction Act, Pub. L. 117-169 (2022)); ELCON Initial Comments at 2; Evergreen Action Initial Comments at 2; GSCE Initial Comments at 5-6; Individual Signatories Initial Comments at 1-2; Interwest Comments at 1-2; National Grid Initial Comments at 2; Payton Alaama Reply Comments at 1; Pine Gate Reply Comments at 3-4; Rick K Lathrop Reply Comments at 1; Shell Initial Comments at 6; State Agencies Initial Comments at 8-9 (citing Int'l Energy Agency, Net Zero by 2050: A Roadmap for the Global Energy Sector (2021) https://www.iea.org/reports/net-zero-by-2050; The United States' Nationally Determined Contribution (2021), https://www4.unfccc.int/sites/ndcstaging/PublishedDocuments/United%20States%20of%20America%20First/United%20States%20NDC%20April%2021%202021%20Final.pdf; White House, FACT SHEET: Biden Administration Jumpstarts Offshore Wind Energy Projects to Create Jobs (Mar. 29, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/03/29/fact-sheet-biden-administration-jumpstarts-offshore-wind-energy-projects-to-create-jobs/ ); Sue Hilton Initial Comments at 1; Union of Concerned Scientists Reply Comments at 6; Vistra Initial Comments at 4. 79 Consumers Energy Initial Comments at 7. 31. A small subset of commenters, while supporting an overall need for reform, disagree with some of the Commission's preliminary conclusions about the need for reform. 80 A few other commenters claim that there is no basis for the Commission's preliminary conclusion that speculative projects that enter the interconnection queue and later withdraw, causing cascading restudies, are responsible for interconnection queue backlogs. 81 A few commenters assert that the Commission did not take into account pertinent factors affecting interconnection queue sizes, such as an increase in the development of smaller, more diverse generating facilities. 82 80 For instance, Affected Interconnection Customers disagree with the Commission's reference to a nationwide shortage of qualified engineers and contend that the Commission fails to support this conclusion with any evidence beyond statements made by CAISO and MISO. Affected Interconnection Customers Initial Comments at 14 (citing NOPR, 179 FERC ¶ 61,194 at P 20 n.67). 81 CREA and NewSun Initial Comments at 35-37 (countering that interconnection requests do not reach commercial operation due to other reasons such as permitting or financing difficulties); NextEra Initial Comments at 4; Public Interest Organizations Initial Comments at 1-7 (arguing that the rate of queue withdrawal has been consistent over the last decade); SEIA Reply Comments at 1. 82 AEE Initial Comments at 6-7; Pine Gate Reply Comments at 4; SEIA Reply Comments at 1. 32. Three comments note that various transmission providers use vastly different interconnection procedures from the pro forma procedures established in Order No. 2003 and argue that there is an insufficient legal foundation under FPA section 206 to demonstrate that all of these approved interconnection procedures are unjust, unreasonable, and unduly discriminatory or preferential. 83 Southern disagrees entirely with the Commission's preliminary conclusion that there is a need for reform. 84 Southern argues that the Commission based its proposed actions in the NOPR on conjecture and thus failed to provide substantial evidence or engage in reasoned decision-making to demonstrate that the current interconnection processes are unjust and unreasonable. 85 In addition, Southern contends that the Commission's proposals are arbitrary and capricious because they impose a broadly applicable remedy to a problem that does not exist uniformly. 86 83 Early Adopters Coalition Initial Comments at 1-2; PacifiCorp Initial Comments at 9; Southern Initial Comments at 10-11. 84 Southern Initial Comments at 10-12; Southern Reply Comments at 1, 4. 85 Southern Initial Comments at 10 (citing Emera Me. v. FERC, 854 F.3d 9, 24 (D.C. Cir. 2017)); Southern Reply Comments at 1, 4. 86 Southern Initial Comments at 11-12. 33. Southern further asserts that the Commission failed to provide any actual evidence that its proposals will reduce interconnection queue backlogs or increase certainty for interconnection customers. 87 87 Id. at 10; Southern Reply Comments at 5. 34. Some commenters argue that the sum of the NOPR may actually slow study processes, increase backlogs, and may unintentionally increase costs to ratepayers. 88 For example, CAISO asserts that shortening study timelines results in rushed, unreliable studies which would ultimately require more iteration and longer interconnection queue processing times. 89 Additionally, NextEra argues that the NOPR provides few, if any, solutions relevant to those regions that have already implemented cluster studies yet continue to experience significant study delays. 90 Further, some commenters oppose any generic one-size-fits-all reform, arguing that queue reform is best left to the regional level. 91 88 CAISO Initial Comments at 3; Dominion Initial Comments at 7; New York State Department Initial Comments at 2; NextEra Reply Comments at 2; NRECA Initial Comments at 7. 89 CAISO Initial Comments at 3. 90 NextEra Reply Comments at 7. 91 Avangrid Initial Comments at 36-37; Southern Initial Comments at 14-15. 35. Several commenters generally support the suite of proposed reforms in their entirety. 92 As discussed in detail in each section below discussing individual reforms, most commenters either support specific proposals or suggest that the Commission prioritize certain proposed reforms. For instance, Consumers Energy supports reforms that increase the speed of interconnection queue processing because it claims that the reforms provide clarity for resource planners and interconnection customers as well as improve the reliability of the bulk electric system and the clean energy resource transformation. 93 Google urges the Commission to prioritize reforms that provide a level playing field for both utility-backed resources and independent power producer-developed resources. 94 Google also expresses concern that the layering of increased study deposits, more stringent site control requirements, the proposed commercial readiness requirements, and withdrawal penalties may place undue burden on interconnection customers if the Commission does not also adopt proposals for more publicly available interconnection information, firm study deadlines, and penalties for missed study deadlines. 95 92 APPA-LPPC Initial Comments at 2-3; APPA-LPPC Reply Comments at 2; Apple Initial Comments at 1; ACORE Initial Comments at 2; Amazon Initial Comments at 2; Evergreen Action Initial Comments at 1-4; Individual Signatories Initial Comments at 1; PJM Coalition Initial Comments at 2. 93 Consumers Energy Initial Comments at 10-11. 94 Google Initial Comments at 3. 95 Id. at 16. 36. Some commenters support adopting most or all of the limited reforms to the pro forma SGIP and pro forma SGIA proposed in the NOPR. 96 For instance, Microgrid Resources asserts that including the proposed reforms in the pro forma SGIP is necessary to reflect the operating assumptions of, and to provide equitable treatment for, microgrids and other behind-the-meter resources. 97 Microgrid Resources asserts that, if the Commission succeeds in expediting interconnections for large generating facilities, while small generating facility interconnections languish, it will bias the system against smaller local generating facilities that are the backbone of community resilience. 96 Bonneville Initial Comments at 24 (supporting applying some of the Commission's proposed reforms to the pro forma SGIP and pro forma SGIA ( e.g., commercial readiness requirements), but asking that transmission providers be granted flexibility to determine which reforms should be applicable to small generator procedures and agreements); IREC Initial Comments at 3 (stating that the pro forma SGIP lacks the necessary provisions to safely and reliably interconnect storage to the electric grid while enabling its unique operating characteristics); Microgrid Resources Initial Comments at 8-9; Xcel Initial Comments at 19 (supporting applying reforms to small generating facilities requesting energy only interconnection service). 97 Microgrid Resources Initial Comments at 8-9. C. Commission Determination 37. Based on the record, including comments submitted in response to the NOPR, as discussed below, we find that there is substantial evidence to support the conclusion that the existing pro forma generator interconnection procedures and agreements are unjust, unreasonable, and unduly discriminatory or preferential. 98 We therefore adopt the preliminary findings in the NOPR concerning the need for reform 99 and, pursuant to FPA section 206, conclude that certain revisions to the pro forma open access transmission tariff and the Commission's regulations are necessary to ensure rates that are just, reasonable, and not unduly discriminatory or preferential. Specifically, we find that the existing pro forma generator interconnection procedures and agreements are insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. Absent reform, the current interconnection process will continue to cause interconnection queue backlogs, longer development timelines, and increased uncertainty regarding the cost 100 and timing of interconnecting to the transmission system. These backlogs and delays, and the resulting timing and cost uncertainty, 101 hinder the timely development of new generation and thereby stifle competition in the wholesale electric markets resulting in rates, terms, and conditions that are unjust, unreasonable, and unduly discriminatory or preferential. 98 16 U.S.C. 824e(a); 18 CFR 385.206 (2022). 99 NOPR, 179 FERC ¶ 61,194 at PP 18-36. 100 See May Joint Task Force Tr. 74:9-21 (Andrew French) (stating that generator developers complain principally about cost certainty and cost sharing and that “cost certainty is the much bigger issue” given that “an essential element of being able to sell a product is to know what your inputs are so you can market it”). 101 See May Joint Task Force Tr. 23:18-25 (Jason Stanek) (expressing frustration with the status quo and agreement that it is “no longer tenable” considering the inability of generators to interconnect in a timely manner, e.g., there are “2,500 projects under study [in the MACRUC region] and about a half of them have been in the queue since at least 2001”). 38. Indeed, recent data support the Commission's preliminary findings in the NOPR that the dramatic increase in the number of interconnection requests and limited transmission capacity are increasing interconnection queue backlogs across all regions of the country. 102 As of the end of 2022, there were over 10,000 active interconnection requests in interconnection queues throughout the United States, representing over 2,000 gigawatts (GW) of potential generation and storage capacity. 103 This potential generation is the largest interconnection queue size on record, more than four times the total volume (in GW) of the interconnection queues in 2010, and a 40% increase over the interconnection queue size from just the year prior. 104 These trends are not exclusive to any one region of the country. Instead, every single region has faced an increase in both interconnection queue size and the length of time interconnection customers are spending in the interconnection queue prior to commercial operation in recent years. 105 This is true for RTO/ISO and non-RTO/ISO regions alike. The non-RTO/ISO west and southeast regions both have faced queue size increases ranging from tripling to a 12-fold increase while also seeing longer timelines between interconnection requests and commercial operation dates. 106 Furthermore, the uncertainty and delays in the interconnection queues have resulted in fewer than 25% of interconnection requests, by capacity, reaching commercial operation between 2000 and 2017 in any region of the country—with some regions as low as 8%. 107 102 Joseph Rand et al., Lawrence Berkeley Nat'l Lab., Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection, at 7-8 (Apr. 2023) (Queued Up 2023), https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf; see also Order No. 845, 163 FERC ¶ 61,043 at P 305 (requiring transmission providers to post interconnection study metrics). See appendix B to this final rule, which provides an overview of recent data based on reporting by transmission providers in compliance with Order No. 845. 103 Queued Up 2023 at 7-8. 104 Id. at 10. 105 Id. at 9, 32. 106 Id. at 9, 32. 107 Id. at 3, 21. 39. Additionally, recent data continue to show that interconnection customers are waiting longer in the interconnection queue before withdrawing their interconnection requests, 108 even as overall interconnection study timelines are increasing in many regions. 109 For example, AEE states that, as of February 2022, all 2,274 projects waiting for an interconnection agreement in the PJM interconnection queue had been waiting for a year or more; 33% (758 projects) had been waiting more than 500 days, 22% (497 projects) have been stuck for more than two years, and 7% (166 projects) have been waiting more than three years. 110 NV Energy explains that several western utilities that are not currently part of an RTO/ISO are experiencing an unprecedented high volume of requests in excess of the utility's peak load. 111 AEE notes that wait times for generating facilities in interconnection queues nationwide have increased from 2.1 years for generating facilities built in 2000-2010 to 3.7 years for those built in 2011-2021. 112 And despite efforts to address these challenges, 113 interconnection queue backlogs and delays have persisted and worsened. For generating facilities built in 2022, wait times in the interconnection queue saw a marked increase to now roughly five years. 114 108 Id. at 25 (reporting that, although the median withdrawal duration has been relatively consistent over time, the mean withdrawal duration and distributions have edged higher in recent years). 109 Id. at 27. 110 AEE Initial Comments at 4 (citing Advanced Energy Economy, “In PJM, Renewable Energy Projects Are Getting Stuck” (February 2022), https://blog.aee.net/in-pjm-renewable-energy-projects-are-getting-stuck ). 111 NV Energy Initial Comments at 2-3. NV Energy explains that it has a peak load of 9,400 MW with an interconnection queue backlog for projects totaling more than 27,000 MW; Idaho Power has a peak load of 3,751 MW with an interconnection queue backlog of over 18,000 MW; PacifiCorp has a peak load of 13,000 MW with an interconnection queue backlog of over 45,000 MW; and APS has a peak load of 7,600 MW with an interconnection queue backlog of over 50,000 MW. 112 AEE Initial Comments at 4 (citing Queued Up 2022); see also ACE-NY Initial Comments at 2 (arguing that the ability of New York to meet its clean energy goals is threatened by an interconnection process that is too slow); Affected System Interconnection Customers Initial Comments at 2 (stating that Affected System Interconnection Customers have navigated the generator interconnection queues of various transmission providers around the country and experienced firsthand the inefficiencies and delays, which represent the greatest obstacle to achieving commercial operation of a new energy project); GSCE Initial Comments at 5-6 (contending that an average of 6,000 MW of new solar, wind, and batteries must be added each year until 2045 to reach California's electric sector carbon-neutrality requirement, but that over the past decade California has only succeeded with adding an average of 1,000 MW of utility-scale solar and 300 MW of wind to the transmission system each year). 113 Order No. 845, 163 FERC ¶ 61,043 at P 24. 114 Queued Up 2023 at 31; see also Shell Initial Comments at 6 (describing multiple instances of five to six years until execution of an interconnection agreement, four years waiting for an initial “kick-off” call, two years waiting for a feasibility study, three years waiting for a system impact study, and over two years waiting for a facilities study). 40. Delays in the interconnection study process are an important contributor to interconnection queue backlogs nationwide. For instance, based on the recent interconnection study metrics transmission providers posted in compliance with Order No. 845, of the 2,179 interconnection studies completed in 2022, 68% were issued late. 115 Furthermore, at the end of 2022, an additional 2,544 studies were delayed ( i.e., ongoing and past their deadline). 116 All of the RTOs/ISOs except CAISO and 14 non-RTO/ISO transmission providers reported delayed studies at the end of 2022. 117 115 This is based on data provided by transmission providers in compliance with Order No. 845. See appendix B to this final rule for the underlying data. Note that data from SPP is omitted here and in follow-on references to Order No. 845 data in this determination. This is because during 2022, SPP was transitioning to a new interconnection study process, and thus its data is not comparable to the other transmission providers. 116 Id. Note that the vast majority of these studies (2,211) were in PJM. 117 Id. CAISO revised the interconnection study deadlines of their queue cluster 14 to account for the unprecedented increase in interconnection requests. Cal. Indep. Sys. Operator Corp., 176 FERC ¶ 61,207 (2021). 41. Consistent with the NOPR, we find that numerous factors have contributed to the increasing volume of interconnection requests, including a rapidly changing resource mix, market forces, and emerging technologies. For example, the interconnection queues in all parts of the country are now predominantly made up of comparatively new technologies that have operating characteristics and generally shorter construction cycles that were not taken into account when the Commission issued Order No. 2003, such as solar, battery storage, and hybrid resources, as older, larger generating facilities retire. 118 The Colorado Commission notes that solar projects account for roughly half of the cumulative requests in the five RTO/ISO queues and likely an even greater percentage of the most recent requests. 119 In addition to the drastic increase in the number of interconnection requests in all regions of the country, evidence shows that interconnection studies have increased in complexity since the Commission issued Order No. 2003, potentially straining transmission provider resources. 120 At the same time, we find that available transmission capacity has been largely or fully utilized in many regions, creating situations where interconnection customers face significant network upgrade cost assignments to interconnect their proposed generating facilities. 121 For example, as referenced by the U.S. DOE, a recent report finds that interconnection costs in MISO doubled for generating facilities for which the interconnection studies were completed between 2019 and 2021 as compared to those completed prior to 2019, and cost estimates tripled for proposed generating facilities still active in the interconnection queue between the same time periods. 122 These cost increases are similar to those being faced in NYISO and PJM, where interconnection costs, per kW, have doubled (or more) for recently completed generating facilities. 123 As a result, we find that this combination of increased volume of diverse interconnection requests and insufficient transmission capacity leading to higher costs to interconnect, which can result in interconnection request withdrawals, has resulted in longer interconnection queue processing times and larger, more delayed interconnection queues. 118 Queued Up 2023 at 9; see also Colorado Commission Comments at 9 (stating that the growth of solar project interconnection requests is a significant cause of the overall supply and demand imbalance across all RTOs/ISOs as well as other regions). 119 Colorado Commission Initial Comments at 9. 120 See, e.g., NYISO Initial Comments at 6-7 (stating that “[s]tudies are only becoming more complex with the expanding scope of ISO/RTOs' interconnection responsibilities”); Xcel Initial Comments at 7 (stating that “in many cases study models with large clusters are difficult to solve . . . Ensuring new transmission lines are realistic and even validating substation designs and locations takes significant work to be done properly”). 121 See, e.g., ACORE Initial Comments at 2 (noting that “upgrades based on generation interconnection may be a sub-optimal, expensive, and ultimately ineffective way to accomplish transmission expansion”); AEE Initial Comments at 3 (asserting that “inefficient and impeded interconnection processes lead to unacceptable delays and artificially high interconnection costs”); EDF Renewables Initial Comments at 3. 122 Joachim Seel et al., Generator Interconnection Cost Analysis in the Midcontinent Independent System Operator (MISO) Territory, at 1, 4-5 (2022), https://emp.lbl.gov/interconnection_costs. 123 Julia Mulvaney Kemp et al., Interconnection Cost Analysis in the NYISO Territory (2023), https://emp.lbl.gov/publications/interconnection-cost-analysis-nyiso (showing that costs have doubled for generating facilities studied since 2017, relative to costs for generating facilities studied from 2006 to 2016); Joachim Seel et al., Interconnection Cost Analysis in the PJM Territory (2023), https://emp.lbl.gov/publications/interconnection-cost-analysis-pjm (showing that costs for recent “complete” generating facilities have doubled on average relative to costs from 2000-2019). 42. In response to comments asserting that the Commission did not take into account other factors affecting interconnection queue sizes, such as the development of smaller, more diverse generating facilities, in its preliminary findings on the need for reform in the NOPR, 124 we find that the record shows that interconnection queue sizes are increasing in both number of interconnection requests and in total MW capacity in all regions of the country and such increases are not due to an influx of any particular size of proposed generating facility. Moreover, data show that the median duration for all generating facilities that enter the interconnection queue hovers around 30 months, independent of the size of the interconnection request. 125 124 See, e.g., Pine Gate Reply Comments at 4 (stating that “the days of . . . large, conventional resources are waning as the majority of interconnection requests are now comprised of smaller, more diverse resource” and that “[l]arger interconnection queues are, to a certain extent, a natural byproduct of this change”); SEIA Reply Comments at 1 (contending that interconnection requests have increased in number “because newer projects are smaller and have less capacity” and “[m]ore interconnection requests are needed to integrate the same amount of generation capacity into the grid”). 125 Queued Up 2023 at 29. 43. Interconnection queue backlogs and delays have created uncertainty for interconnection customers regarding the timing and cost of ultimately interconnecting to the transmission system. We agree with commenters that such uncertainty, on the part of both transmission provider and interconnection customer, may lead to an increase in costs to consumers. 126 First, delayed interconnection study results or unexpected cost increases can disrupt numerous aspects of generating facility development. 127 Cost uncertainty poses an especially significant obstacle because interconnection customers may not be able to finance substantial increases in unexpected interconnection costs. Second, transmission providers may face uncertainty regarding the size and makeup of the interconnection queue and the commercial viability of the project in the interconnection queue, creating inefficiencies in the study process, increasing interconnection study costs, and delayed study results. Such uncertainty, either on the part of transmission providers or interconnection customers, are ultimately passed through to consumers through higher transmission or energy rates. 128 Increases in energy rates may result from wholesale customers having limited access to new and more competitive supplies of generation. Conversely, efficient interconnection queues and well-functioning wholesale markets deliver benefits to consumers by driving down wholesale electricity costs. 126 See, e.g., Ameren Initial Comments at 2; ELCON Initial Comments at 2; ELCON Initial Comments at 2; Xcel Initial Comments at 8. 127 See, e.g., Interwest Initial Comments at 8 (contending that “[t]he harm to interconnection customers associated with interconnection study delays can be significant and costly, including liquidated damages if compliance with a commercial operation deadline is at risk”). 128 Ameren Initial Comments at 2. 44. As the interconnection queue backlogs and study delays continue and even increase, we find that the Commission's existing rules contained in the pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA result in rates, terms, and conditions for Commission-jurisdictional services that are unjust, unreasonable, and unduly discriminatory or preferential. Not only do the problems described above lead to an inability of interconnection customers to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, they also hinder the timely development of new generation, thereby stifling competition in the wholesale electric markets. We, therefore, find that reform to the Commission's existing pro forma generator interconnection procedures and agreements is necessary. 45. Our findings that the existing pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA must be reformed are based on the following features of these existing rules: (1) the information (or lack thereof) available to prospective interconnection customers and the commitments required of them to enter and progress through the interconnection queue; (2) the reliance on a serial first-come, first-served study process and the “reasonable efforts” standard that transmission providers are held to for meeting interconnection study deadlines; (3) the protocols (or lack thereof) for affected system studies; (4) the provisions for studying new generating facility technologies and evaluating the list of alternative transmission technologies enumerated in this final rule; and (5) the modeling or performance requirements (or lack thereof) for non-synchronous generating facilities, including wind, solar, and electric storage facilities. We discuss each of these five features below. 46. First, we find that existing pro forma generator interconnection procedures and agreements fail to contain a process by which an interconnection customer can obtain information about potential interconnection costs at a specific location or point of interconnection prior to submitting an interconnection request. Without this information, it is difficult for interconnection customers to assess the commercial viability of a specific proposed generating facility prior to entering the interconnection queue. 129 Furthermore, we find that for interconnection customers, the pro forma interconnection procedures and agreements fail to include meaningful financial commitment requirements to enter and stay in the interconnection queue and lack of stringent requirements to establish the commercial viability of proposed generating facilities. 130 As a result, interconnection customers often submit multiple interconnection requests for proposed generating facilities at various points of interconnection, knowing that not all of the proposed generating facilities will reach commercial operation, as an exploratory mechanism to obtain information to allow the interconnection customer to choose to proceed with the interconnection request representing the most favorable site in terms of potential interconnection-related costs. 131 For instance, recent interconnection study metrics posted by transmission providers continue to show that some interconnection customers are withdrawing interconnection requests before any studies are completed. 132 While interconnection customers may withdraw at any stage of the interconnection process, to do so before any study is completed indicates that interconnection customers may lack information prior to entering the interconnection queue and are entering to obtain valuable information about the commercial viability of their proposed projects vis-à-vis other interconnection customers in the queue or cluster. 129 See, e.g., Fervo Energy Initial Comments at 2-3 (stating that “the incidence of interconnection applications simply intended to solicit information discovery from the transmission provider . . . is a significant defect in today's queue process”); Google Initial Comments at 4 (asserting that “there is extreme information asymmetry in the interconnection process,” with transmission owners and their affiliates having greater access than independent power producers to information on the relative cost of interconnection at different points). 130 See, e.g., Dominion Initial Comments at 4 (stating that “owners of speculative projects remain in the queue process for as long as they possibly can in the hopes that their project somehow becomes viable”); U.S. Chamber of Commerce Initial Comments at 5 (concurring with the NOPR that there is a “lack of stringent financial commitments and readiness requirements on interconnection customers”). 131 See, e.g., Clean Energy Associations Initial Comments at 11 (stating that “[i]n most cases, customers must actually enter the queue to ascertain what upgrade costs they will be responsible for”); Clean Energy Buyers Initial Comments at 3 (stating that inefficiencies in the serial study queue are “compounded by exploratory interconnection requests that are based on developers' attempts to obtain locations with available transmission capacity”); NY Commission and NYSERDA Initial Comments at 6-7 (stating that “increased access to valuable information . . . could deter developers from submitting multiple, speculative [interconnection requests]”). 132 Based on data provided by transmission providers in compliance with Order No. 845 (showing that 35% of withdrawals in 2022 took place before any studies had been completed). See appendix B to this final rule for the underlying data. 47. Second, the existing serial first-come, first-served study process in the pro forma LGIP requires transmission providers to process interconnection requests in the order in which the transmission provider receives them. This approach creates incentives for interconnection customers to submit exploratory or speculative interconnection requests pursuant to which interconnection customers seek to secure valuable queue positions as early as possible, even if they are not prepared to move forward with the proposed generating facility. Such generating facilities are often not commercially viable and, thus, the interconnection customers ultimately withdraw from the interconnection queue. We agree with commenters that the withdrawal of speculative interconnection requests that trigger reassessments and possible restudies by the transmission provider can delay the timing and increase the cost to interconnect for lower-queued interconnection requests. 48. In summary, we find that the lack of (1) access of information about a specific location or point of interconnection prior to submitting an interconnection request and (2) meaningful financial commitments in the pro forma interconnection procedures and agreements for interconnection customers to enter and stay in the interconnection queue, as well as the existing serial first-come, first-served study process, all incentivize interconnection customers to submit speculative interconnection requests that contribute to interconnection study backlogs, delays, and uncertainty, and, in turn, unjust and unreasonable Commission-jurisdictional rates. 49. We disagree with commenters' assertions that there is no basis to find that speculative interconnection requests are responsible for interconnection queue backlog and delays. We highlight that more than 70% of interconnection requests were withdrawn from the interconnection queue between 2000 and 2017. 133 Although we recognize that there are various reasons an interconnection customer may withdraw its request from the interconnection queue, a withdrawal indicates an inability to reach commercial operation. Because a withdrawal can trigger costly restudies and create uncertainty in the interconnection process for interconnection customers and transmission providers alike, withdrawals of commercially non-viable interconnection requests from the interconnection queue is a significant contributing factor to interconnection queue backlogs and delays. 134 Late-stage withdrawals of interconnection requests are also increasing. 135 Late-stage withdrawals present a significant problem, as they can trigger restudies for other interconnection customers that can result in significant increases to the interconnection costs attributed to those customers and the timeline for completion of interconnection studies, which can result in further late-stage withdrawals, thus exacerbating the interconnection queue backlogs and delays. 136 133 Queued Up 2023 at 18 (reporting that 72% of all interconnection requests submitted from 2000-2017 were withdrawn). 134 See, e.g., Ohio Commission Consumer Advocate Initial Comments at 8 (stating that “[e]ach withdrawn project entails PJM restudy on lower-queued projects, which delays the processing of new service queues and may have the consequence of a cascade of withdrawals”). 135 Queued Up 2023 at 22. 136 See, e.g., AEE Initial Comments at 4-5; Queued Up 2023 at 22. 50. We also find that interconnection queue backlogs and delays, and the accompanying uncertainty, are further compounded because transmission providers have limited incentive to perform interconnection studies in a timely manner. Under the pro forma LGIP, transmission providers are held to a “reasonable efforts” standard in completing interconnection studies consistent with their tariff-imposed deadlines. However, this standard offers significant discretion to the transmission providers in extending their own deadlines. The record demonstrates that a majority of transmission providers across the country regularly fail to meet interconnection study deadlines. 137 Despite pervasive delays in completing interconnection studies by transmission providers, we acknowledge that transmission providers have faced few, if any, consequences for failing to meet their tariff-imposed study deadlines under the reasonable efforts standard. 138 This outcome stands in stark contrast to interconnection customers that face financial and commercial consequences due to late interconnection study results and may be considered withdrawn from the interconnection queue for failing to meet their tariff-imposed deadlines. 139 For these reasons, we find that the existing pro forma LGIP requirement for transmission providers to make a reasonable effort to meet interconnection study deadlines contributes to the interconnection study backlogs, delays, and uncertainty that erects barriers to new generation. 140 Therefore, we find that the use of a reasonable efforts standard in the existing pro forma LGIP results in Commission-jurisdictional rates that are unjust and unreasonable. 137 For example, based on data submitted by transmission providers in compliance with Order No. 845, 80% of transmission providers had delayed studies in at least one of the past three years (2020-2022) and 57% had delayed studies in at least two.b See also NARUC Initial Comments at 13 (stating “nearly all transmission providers across the country, including many transmission providers that have implemented queue reforms, regularly fail to meet interconnection study deadlines”). 138 See, e.g., Clean Energy Associations Initial Comments at 43-44 (stating that “[a]t present, there is no specific incentive for delivering on-time and accurate studies, and late or inaccurate studies bring few if any consequences”). 139 See, e.g., ACE-NY Initial Comments at 3 (“Project developers have strict deadlines they must adhere to in the interconnection process, with penalties that include the forced withdrawal of the project from the queue.”). 140 See, e.g., NARUC Initial Comments at 13-14 (contending that “the tendency to miss deadlines introduces uncertainty in a process that is important to bringing new generation online in a timely and cost-effective manner”). 51. Third, the pro forma LGIP includes no requirements regarding how or when transmission providers should complete affected system studies. Without requirements, affected system studies often lag behind those completed by the transmission provider to whose transmission system the interconnection customer proposes to interconnect (the so-called host transmission provider) and are sometimes completed very late in the interconnection process, causing an additional round of delays and cost uncertainty for interconnection customers. 141 Additionally, for transmission providers that have procedures for how to complete affected system studies in their tariffs or other documents ( e.g., business practice manuals or joint operating agreements), the procedures are not consistent, may be hard for interconnection customers to locate, and may not represent the actual practices in use by the transmission provider, thus still creating uncertainty for interconnection customers. As a result, we find that the lack of consistent requirements for affected system modeling and procedures results in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential. 141 See, e.g., MISO Initial Comments at 72 (stating that “the need to wait for affected systems studies is the cause of the majority of delays in the MISO study process”); May Joint Task Force Tr. 65:2-8 (Dan Scripps) (citing affected systems studies as “a growing source of delay and cost uncertainty for interconnection customers, both in terms of just the timelines involved and the difficulty in pinning those down”). 52. Fourth, we find that the Commission's pro forma LGIP fails to accommodate the operating characteristics and technical capabilities of electric storage resources when it comes to specific interconnection procedures and modeling. As stated above, the interconnection queues predominantly consist of new technologies which have operating characteristics that differ from synchronous resources and were not anticipated when the Commission established the pro forma generator interconnection procedures and agreements in Order Nos. 2003 and 2006. Specifically, electric storage resources can be charged and dispatched on a flexible, as-available basis, and are less likely than synchronous generating facilities to withdraw energy from the transmission system during peak load conditions or discharge during light load conditions. 142 However, the existing pro forma generator interconnection procedures and agreements do not contemplate these operating characteristics or technical capabilities of electric storage resources. As a result, we find that electric storage resources (whether standalone, co-located generating facilities, or part of a hybrid generating facility), may be studied under inappropriate operating assumptions ( e.g., charging at full capacity during peak load conditions) that result in assigning unnecessary network upgrades and increased costs to interconnection customers. Therefore, we find that the Commission's pro forma LGIP's lack of ability to modify operating assumptions for electric storage resources results in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential. 142 See, e.g., Bonneville Initial Comments at 22-23 (stating that “storage resources are less likely to charge during peak load conditions or discharge during light load conditions, and . . . those considerations can be factored into assumptions used in interconnection studies”); NARUC Initial Comments at 37 (stating that “assuming that an energy storage device will withdraw energy during peak demand . . . fails to recognize that those resources are likely to be highly responsive to price signals from the transmission provider and can improve reliability”). 53. Additionally, the record supports a finding that the existing pro forma interconnection procedures regarding material modifications do not provide for consistent evaluation of technology additions to an existing interconnection request. 143 We find that the record demonstrates that automatically deeming a request to add a generating facility to an existing interconnection request to be a material modification creates a significant barrier to access to the transmission system. 144 As a result, we find the existing pro forma LGIP and pro forma LGIA results in Commission-jurisdictional rates that are unjust and unreasonable. 143 See, e.g., NARUC Initial Comments at 35 (stating that the “loss of queue position as a result of adding a generating facility that does not increase the requested service level or cause reliability issues . . . is an inefficient and discriminatory outcome”). 144 See, e.g., AEE Initial Comments at 40-41; Public Interest Organizations Initial Comments at 45-47; SEIA Initial Comments at 38-39. 54. Finally, the record supports a finding that the Commission's pro forma LGIP and pro forma SGIP fail to require the consideration of alternative transmission technologies that can be deployed more quickly to be used as network upgrades in place of, and at a lower cost than, traditional network upgrades. 145 In addition, commenters contend that some alternative transmission technologies could provide substantial benefits by resolving thermal overloads and avoiding voltage collapse, allowing for better use of the existing transmission system, improving reliability, and reducing interconnection request withdrawals, restudies, and overall interconnection delays. 146 We find that failing to require transmission providers to evaluate the list of alternative transmission technologies enumerated in this final rule results in interconnection customers paying more than is just and reasonable to reliably interconnect new generating facilities, resulting in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential. Because the benefits of the enumerated alternative transmission technologies identified above are present across all interconnection processes, regardless of the size of the interconnection request, we find that the failure to evaluate the enumerated alternative transmission technologies results in both the pro forma LGIP and pro forma SGIP being unjust, unreasonable, and unduly discriminatory or preferential. 145 See, e.g., NARUC Initial Comments at 38 (stating that “failing to consider alternative transmission technologies that can be deployed both more quickly and at lower costs than network upgrades may render Commission-jurisdictional rates unjust and unreasonable”); OMS Initial Comments at 19 (agreeing that “failing to consider these alternative transmission technologies runs the risk of implementing longer lead-time network upgrades at a higher cost”). 146 See, e.g., AEE Initial Comments at 42 (stating that alternative transmission technologies “provide benefits beyond potential costs savings, including maximizing limited rights-of-way and potentially avooiding or minimizing environmental and property impacts taht can bog down siting and permitting proceedings”); Ohio Commission Consumer Advocate Initial Comments at 15 (stating that “[t]hese grid-enhancing technologies (‘GETs’) can improve opertations, enhance system reliability, contribute to capacity, and more” and “[s]ome [grid-enhancing technologies] could provide substantial benefits by resolving thermal overloads and avoiding voltage collapse, among other things”); WATT Coalition Initial Comments at 2 (referring to the report Unlocking the Queue with Grid Enhancing Technologies that showed that application of the three grid-enhancing technologies in the Kansas and Oklahoma transmission systems would enable twice as much renewable energy to interconnect out of the queues without any traditional transmission upgrades.). 55. Fifth, we find that the Commission's existing pro forma LGIP and pro forma SGIP do not include a modeling requirement for non-synchronous generating facilities, which is necessary to enable the transmission provider to assess and model the facility's ability to respond appropriately to transmission system disturbances. These modeling requirements include: (1) a validated, user-defined root mean square (RMS) positive sequence dynamic model; (2) an appropriately parameterized, generic library RMS positive sequence dynamic model; and (3) a validated electromagnetic transient (EMT) model, if the transmission provider performs an EMT study as part of the interconnection study process. Additionally, we find that accurate and validated models are necessary to address study delays and to ensure that transmission providers identify the necessary interconnection facilities and network upgrades to accommodate the interconnection request and appropriate assignment of interconnection costs. As a result, we find that the lack of a modeling requirement for non-synchronous generating facilities in the pro forma LGIP and pro forma SGIP results in rates that are unjust, unreasonable, and unduly discriminatory or preferential. 56. Furthermore, the physical characteristics of synchronous generating facilities allow them to continue to inject electric current during transmission system disturbances, as required by the pro forma LGIA and pro forma SGIA. 147 However, non-synchronous generating facilities do not face a comparable requirement and many cease injecting current through “momentary cessation,” which creates reliability issues on the transmission system. 148 Moreover, without requirements for non-synchronous generating facilities to remain connected to and synchronized with the transmission system, interconnection studies may not accurately model expected behavior and identify the appropriate interconnection facilities and network upgrades to accommodate the interconnection request, skewing the assignment of interconnection costs. As a result, we find that the lack of comparable requirements for non-synchronous generating facilities to remain “connected to and synchronized with the [t]ransmission [s]ystem” in the pro forma LGIA and pro forma SGIA results in rates that are unjust, unreasonable, and unduly discriminatory or preferential. 147 Pro forma LGIA art. 9.7.3 and pro forma SGIA art. 1.5.7 require synchronous generating facilities to remain “connected to and synchronized with” the transmission system during system disturbances. 148 See, e.g., NERC Initial Comments at 9 (stating that “improper planning and operation of [non-synchronous resources] can pose a significant risk to . . . reliability” and adding that “risk mitigation measures . . . have been inconsistently adopted by industry”); MISO TOs Initial Comments at 32-33 (concurring with the Commission that “with more and more non-synchronous generation facilities entering the interconnection queue, the lack of a requirement for such resources to respond to system disturbances becomes `more consequential' ”). 57. In response to commenters that express broad opposition to the need for reform, we disagree with assertions that the existence of regional variation in interconnection procedures across the country creates an insufficient legal foundation under FPA section 206 to demonstrate that rates are unjust, unreasonable, and unduly discriminatory or preferential. Similarly, we disagree with assertions that reforms to the pro forma generator interconnection procedures and agreements are arbitrary and capricious because the problems identified herein do not exist uniformly. As an initial matter, the “Commission may rely on `generic' or `general' findings of a systemic problem to support imposition of an industry-wide solution.” 149 That some interconnection processes may fare better in the face of industry-wide challenges would be “as unastonishing as it is irrelevant.” 150 The Commission may reasonably rely on rulemaking to address the systemic drivers leading to widespread interconnection queue backlogs and delays, notwithstanding regional variation among interconnection procedures. 149 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 67 (D.C. Cir. 2014) (quoting Interstate Nat. Gas Ass'n of Am. v. FERC, 285 F.3d 18, 37 (2002)). 150 Id. (quoting Wis. Gas v. FERC, 770 F.2d 1144, 1157 (D.C. Cir. 1985)). 58. Moreover, as noted above, every region of the country is seeing an increase in both interconnection queue size and the length of time interconnection customers are spending in the interconnection queue prior to commercial operation in recent years. 151 Furthermore, the uncertainty and delays in the interconnection queues have resulted in fewer than 25% of interconnection requests, by capacity, reaching commercial operation between 2000 and 2017 in any region of the country—with some regions as low as 8%. 152 For example, only 10% of interconnection requests, by capacity, have reached commercial operation in the non-RTO/ISO southeast region between 2000 and 2017. 153 Additionally, the challenges being faced across the country will be further compounded in the future given the recent spikes in interconnection queue sizes. In the non-RTO/ISO southeast region, the interconnection queue size has more than tripled between 2014 and 2022, with the increase predominantly made up of solar, storage, and hybrid generating facilities, adding potential complexity to future interconnection queue study processes. 154 To the extent existing pro forma interconnection procedures, such as first-come, first-served study processes, have worked in the past for smaller or less complex queues, such experience is not indicative of what will be necessary in the future to ensure that a growing number of interconnection requests are processed in a reliable, efficient, transparent, and timely manner. 155 Finally, as recognized in Order No. 2003, interconnection queue delays may “provide[] an unfair advantage to utilities that own both transmission and generation facilities,” 156 making it exceedingly necessary that interconnection delays are addressed in all regions of the country, especially those where transmission providers continue to own both transmission and generation. 157 As discussed above, because interconnection queue backlogs and delays afflict generator interconnection service nationwide, which hinders the timely development of new generation and thereby stifles competition in the wholesale electric markets, reforms are necessary to ensure Commission-jurisdictional rates are just, reasonable, and not unduly discriminatory or preferential. 151 Queued Up 2023 at 9, 32. 152 Id. at 3, 21. 153 Id. at 21. 154 Id. at 9. 155 See, e.g., Public Interest Organization Initial Comments at 17; R Street Initial Comments at 3. 156 Order No. 2003, 104 FERC ¶ 61,103 at P 11. 157 See, e.g., Pine Gate Initial Comments at 15; AEE Reply Comments at 22. 59. We are not persuaded by commenters' concerns that the reforms proposed in the NOPR, many of which we adopt in this final rule, will be counterproductive in addressing the need for reform. As discussed in more detail throughout this final rule, we believe that the reforms adopted herein, as a whole, will improve the efficiency of study processes, reduce interconnection queue backlogs, and thereby ensure just, reasonable, and not unduly discriminatory or preferential rates. We believe that, on balance, the reforms will produce efficiencies by, for example, reducing speculative interconnection requests and interconnection request withdrawals, which in turn will reduce the time and resources spent in interconnection studies and restudies thereby decreasing interconnection queue backlogs and delays. Additionally, the majority of the individual reforms that the Commission proposed in the NOPR and we adopt in this final rule have already been implemented in one or more regions in order to improve the interconnection process, demonstrating incremental improvements. This final rule uses some of these individual and incremental improvements as a basis for a broad suite of reforms that, in their entirety, have not yet been adopted by any region and we believe will ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. In some cases, such as for the commercial readiness reforms adopted in this final rule, we have significantly modified the NOPR proposal based on comments received. 60. Having concluded that the existing pro forma generator interconnection procedures and agreements are unjust, unreasonable, and unduly discriminatory or preferential, we turn, as we are required to do under FPA section 206, 158 to determining the replacement rate, described—at some length—below. 158 16 U.S.C. 824e(a); see, e.g., FERC v. Electric Power Supply Ass'n, 577 US 260, 277 (2016) (“If FERC sees a violation of [the just and reasonable] standard, it must take remedial action.”) III. Reforms A. Reforms To Implement a First-Ready, First-Served Cluster Study Process 1. Interconnection Information Access a. Need for Reform i. NOPR 61. The Commission noted its concern regarding the lack of information available to prospective interconnection customers regarding potential interconnection costs prior to submitting an interconnection request. 159 The Commission stated that, without this information, it is difficult for interconnection customers to assess the viability of a specific proposed generating facility. Subsequently, interconnection customers submit multiple speculative interconnection requests in an attempt to obtain information through the system impact study process about the costs associated with various project configurations. The Commission preliminarily found that the Commission's pro forma LGIP and pro forma LGIA are unjust, unreasonable, and unduly discriminatory or preferential and that reforms are needed to allow interconnection customers to interconnect in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. 160 159 NOPR, 179 FERC ¶ 61,194 at P 40. 160 Id. P 39. ii. Comments 62. Several commenters contend that it is a rational response to a lack of pre-interconnection queue information for interconnection customers to submit multiple interconnection requests to gain information on which interconnection sites are favorable and hedge risks, which leads to withdrawals that exacerbate unmanageable interconnection queue backlogs. 161 ELCON and Environmental Defense Fund argue that the lack of sufficient information and unexpected cost escalation are the primary reasons interconnection requests are withdrawn, leading to delays and inefficiencies. 162 161 AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; Clean Energy Buyers Initial Comments at 5-6; CREA and NewSun Initial Comments at 45; Environmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 3; Northwest and Intermountain Initial Comments at 5; Public Interest Organizations Initial Comments at 18. 162 Environmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 4. 63. Many commenters agree with the goal of providing additional information prior to entering the interconnection queue. 163 Some commenters state that additional information prior to entering the interconnection queue is beneficial, 164 in particular access to information on potential network upgrades and the cost and time to interconnect. 165 Many commenters expect that potential interconnection customers' access to additional information prior to entering the interconnection queue will reduce speculative interconnection requests, thus promoting reliability and cost savings by encouraging more optimal interconnection requests that can be processed more efficiently and at lower overall cost. 166 163 ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP Initial Comments at 12; AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; APS Initial Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial Comments at 15; MISO Initial Comments at 20-21; NARUC Initial Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial Comments at 13; PJM Initial Comments at 45; Puget Sound Initial Comments at 5; WAPA Initial Comments at 5. 164 AEP Initial Comments at 12; APS Initial Comments at 4. 165 EEI Reply Comments at 7-8; New Jersey Commission Initial Comments at 23; NV Energy Initial Comments at 13. 166 Affected Interconnection Customers Initial Comments at 30; Clean Energy States Initial Comments at 3; Duke Southeast Utilities Initial Comments at 6; Environmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 3-4; Fervo Energy Initial Comments at 2-3; Google Initial Comments at 4-5; NARUC Initial Comments at 4-5; NESCOE Reply Comments at 3; New Jersey Commission Initial Comments at 20-22; New York State Department Initial Comments at 8; Pacific Northwest Utilities Initial Comments at 13; Public Interest Organizations Initial Comments at 18; Puget Sound Initial Comments at 5; SDG&E Initial Comments at 3-4. 64. Several commenters note the importance of additional interconnection information access in light of the other reforms proposed in the NOPR. AES contends that it would be inequitable for the Commission to increase security deposits to stay in the interconnection queue under the NOPR proposal to increase study and LGIA deposits without requiring transmission providers to provide sufficient information to interconnection customers. 167 Vistra asserts that the proposals to provide additional information will complement the exclusive site control proposals and provide an avenue for prospective interconnection customers to select the most viable sites on which to obtain rights and develop a location, which is a costly and time-consuming process, before entering the interconnection queue. 168 Northwest and Intermountain argue that, in order for the other proposed reforms in the NOPR to be effective, potential interconnection customers must have a solution to the problem of identifying optimal interconnection locations and configurations that is timely, cost-effective, and accurate. 169 167 AES Initial Comments at 13. 168 Vistra Initial Comments at 4. 169 Northwest and Intermountain Initial Comments at 9. 65. Google contends that pre-queue information is necessary because there is an extreme information asymmetry between independent power producers and transmission owners and their generating affiliates, which have greater access to planning information, including load growth, relative cost of interconnecting at different points, points of chronic congestion where upgrades might be needed, and planned local upgrades. 170 Google asserts that this information asymmetry is particularly pronounced in the non-RTO/ISO regions, and allows transmission owners and their affiliates to identify the best locations for interconnection more quickly than independent power producers. 170 Google Initial Comments at 3-4. 66. On the other hand, Dominion argues that there is no evidence in the record that a lack of information is slowing down the interconnection queue process or that transmission providers are not engaged in good faith reviews of interconnection requests. 171 According to Dominion, the Commission should focus on making the interconnection process more efficient and speedier, and the best way to achieve these goals is through the first-ready, first-served cluster study reform. While APPA-LPPC support transparency in the generator interconnection process and share the Commission's view that the availability of transmission system information should reduce the incentive to submit speculative interconnection requests, they argue that sufficient information is currently publicly available. 172 171 Dominion Reply Comments at 8-9. 172 APPA-LPPC Initial Comments at 11. iii. Commission Determination 67. We find that, absent reforms to require transmission providers to provide additional interconnection information, which can be used by interconnection customers prior to submitting an interconnection request, speculative interconnection requests will likely remain at current levels and continue to contribute to interconnection study delays and add costs to the interconnection process. Although submitting multiple interconnection requests to gain information may be a rational response to a lack of pre-interconnection queue information, this practice increases interconnection study delays. 173 We also agree with commenters that additional access to interconnection information is a valuable goal 174 as it can increase the likelihood that an interconnection request is viable when submitted. We disagree with commenters that current information requirements are sufficient. 175 While certain information is currently available through the feasibility study process, as part of our reforms discussed below, we eliminate the feasibility study. Therefore, we find it necessary to provide a means for interconnection customers to obtain additional information prior to entering the interconnection queue. We concur with comments that additional access to interconnection information prior to entering the interconnection queue is important for interconnection customers to make informed decisions, particularly given the increased requirements for interconnection customers adopted in this final rule, such as increased study deposits and site control, as discussed below. 176 We also agree that commenters raise a valid concern that an information asymmetry exists between independent power producers and transmission owner affiliates, in particular in non-RTO/ISO regions. 177 173 See AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; Clean Energy Buyers Initial Comments at 5-6; CREA and NewSun Initial Comments at 45; Enviornmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 3; Northwest and Intermountain Initial Comments at 5; Public Interest Organizations Initial Comments at 18. 174 ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP Initial Comments at 12; AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; APS Initial Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial Comments at 15; MISO Initial Comments at 20-21; NARUC Initial Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial Comments at 13; PJM Initial Comments at 45; Puget Sound Initial Comments at 5; WAPA Initial Comments at 5. 175 APPA-LPPC Initial Comments at 9. 176 AES Initial Comments at 13; Northwest and Intermountain Initial Comments at 9; Vistra Initial Comments at 4. 177 Google Initial Comments at 3-5. b. Informational Interconnection Study i. NOPR Proposal 68. In the NOPR, the Commission proposed to revise the Commission's pro forma LGIP to require transmission providers to offer an informational interconnection study for prospective interconnection customers. 178 The Commission proposed that the informational interconnection study would provide cost estimates for the transmission provider's interconnection facilities and network upgrade costs specific to the interconnection scenario detailed in the study agreement. The Commission also proposed to include new definitions for an informational interconnection study and informational interconnection study agreement. 178 NOPR, 179 FERC ¶ 61,194 at P 42. 69. Under the Commission's proposal, prospective interconnection customers could request up to five separate informational interconnection studies at a time. 179 The Commission explained that each configuration of an interconnection request would require a separate informational interconnection study. The Commission proposed that the informational interconnection study would be at the interconnection customer's expense, and each study would require a $10,000 deposit, subject to a true-up based on actual study costs. 179 Id. P 43. 70. The Commission proposed that, within seven business days of the receipt of a prospective interconnection customer's request for an informational interconnection study, the transmission provider would have to provide the prospective interconnection customer with an informational interconnection study agreement. 180 The Commission explained that the informational interconnection study agreement would specify the technical data that the prospective interconnection customer must provide and an estimate of the expected costs of the study, including, to the extent known by the transmission provider, an estimate of the study costs expected to be incurred by any relevant affected systems. Under the proposal, the prospective interconnection customer would have 10 business days to execute the agreement and deliver it to the transmission provider, along with the relevant technical data and study deposit, after which the transmission provider would have 45 calendar days to complete the study. 180 Id. P 44. 71. The Commission proposed that the informational interconnection study would consist of a sensitivity analysis based on the assumptions specified in the informational interconnection study agreement. 181 Under the proposal, the informational interconnection study would identify potential interconnection facilities and network upgrades that may be required to interconnect the prospective interconnection customer's proposed generating facility, including an approximation of the costs of such interconnection facilities and network upgrades. The Commission noted that the transmission provider would also coordinate with affected systems that may be impacted by the prospective interconnection customer's request to provide information on affected systems-related issues. 181 Id. P 45. 72. The Commission proposed an informational interconnection study agreement form, which explains that the informational interconnection study is performed solely for informational purposes and is not binding on either party. 182 The proposed agreement also requires the study report to provide specific information, including, at a minimum: (1) preliminary identification of any circuit breaker short circuit capability limits exceeded; (2) preliminary identification of any thermal overload or voltage limit violations; and (3) estimated network upgrade costs related to the identified overloads and violations. 182 Id. P 46. 73. The Commission sought comment on: (1) whether the informational interconnection study, as proposed, would provide prospective interconnection customers with sufficient and timely information to inform decision-making prior to submitting an interconnection request; (2) whether transmission providers should be required to establish a request window of a limited number of days each year in which potential interconnection customers can request an optional informational interconnection study; and (3) the burdens on transmission providers of conducting informational studies and whether other options, such as the proposal discussed below for public interconnection information, might strike a better balance of providing interconnection customers with useful information while making efficient use of transmission provider resources. 183 183 Id. PP 47-48. 74. Additionally, the Commission proposed to add new section 3.1.2 to the pro forma LGIP, which provides that interconnection customers evaluating different options (such as different sizes, sites, or voltages) are encouraged but not required to use the new informational interconnection study proposed in the NOPR before entering the cluster study. 184 184 Id. P 66. ii. Comments (a) Comments in Support 75. Several commenters support the NOPR proposal to require transmission providers to offer an informational interconnection study to prospective interconnection customers. 185 Several commenters agree that the informational interconnection study proposal could reduce the number of speculative or other interconnection requests 186 and improve the efficiency of siting decisions. 187 Some commenters expect that these changes will have other benefits for the interconnection process, including cost savings from fewer and more viable interconnection requests, 188 a reduced need for project withdraw [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%3A2023-16628. Public record. Not legal advice.