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). 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.

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). 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. The Commission further stated that the standard procedures would facilitate market entry for generation competitors by reducing interconnection costs and time. 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.

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, 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.

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; (2) increase the speed of interconnection queue processing; and (3) incorporate technological advancements into the interconnection process.

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 (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.

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.

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. 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)].” 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.” 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.

12. To initiate the generator interconnection process set forth in the Commission's pro forma LGIP, 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. 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. The queue position determines the order in which the transmission provider studies the interconnection requests in its interconnection queue.

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. Transmission providers study interconnection requests in three phases: (1) the interconnection feasibility study (feasibility study); (2) the interconnection system impact study (system impact study); and (3) the interconnection facilities study (facilities study). 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; (2) determine the interconnection facilities and network upgrades needed to reliably interconnect the generating facility; and (3) estimate the interconnection customer's cost responsibility for these facilities. 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.

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. 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. 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.

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. 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” that uses technical screens to evaluate a certified small generating facility no larger than 2 MW; and (2) a “10 [kilowatt (kW)] inverter process” that uses the same technical screens to evaluate a certified inverter-based small generating facility no larger than 10 kW. The Commission later issued Order No. 792, 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.

16. In response to concerns voiced to the Commission about interconnection queue management, in 2007, the Commission held a technical conference, and later issued an order 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. 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. 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). 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.

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. The Commission therefore adopted reforms designed to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the generator interconnection process.

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. 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. 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 that minimizes their network upgrade costs. 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.

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. 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. 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.

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. 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; (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; 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. To implement these reforms, the Commission also proposed to require transmission providers to establish a transition process.

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; (2) revisions to establish an affected system study process, along with necessary pro forma affected system agreements; and (3) revisions to establish an optional resource solicitation study.

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; (2) incorporate the enumerated alternative transmission technologies into the interconnection study process at the request of the interconnection customer; 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.

24. In response to the NOPR, 189 comments were filed. These comments have informed our determinations in this final rule.

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. 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. 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.

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.

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. 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. 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. 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. 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.

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.

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.

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. 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. 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.” 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. 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. Senators Hickenlooper and King note that, in the past decade, 23% of proposed generating facilities reached commercial operation, while 72% were withdrawn. 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. 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. 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. 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. Consumers Energy argues that delays in processing interconnection requests will exacerbate resource adequacy challenges.

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. 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. 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.

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. Southern disagrees entirely with the Commission's preliminary conclusion that there is a need for reform. 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. 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.

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.

34. Some commenters argue that the sum of the NOPR may actually slow study processes, increase backlogs, and may unintentionally increase costs to ratepayers. 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. 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. Further, some commenters oppose any generic one-size-fits-all reform, arguing that queue reform is best left to the regional level.

35. Several commenters generally support the suite of proposed reforms in their entirety. 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. Google urges the Commission to prioritize reforms that provide a level playing field for both utility-backed resources and independent power producer-developed resources. 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.

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. 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. 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.

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. We therefore adopt the preliminary findings in the NOPR concerning the need for reform 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 and timing of interconnecting to the transmission system. These backlogs and delays, and the resulting timing and cost uncertainty, 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.

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. 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. 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. 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. 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. 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%.

39. Additionally, recent data continue to show that interconnection customers are waiting longer in the interconnection queue before withdrawing their interconnection requests, even as overall interconnection study timelines are increasing in many regions. 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. 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. 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. And despite efforts to address these challenges, 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.

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. Furthermore, at the end of 2022, an additional 2,544 studies were delayed ( i.e., ongoing and past their deadline). All of the RTOs/ISOs except CAISO and 14 non-RTO/ISO transmission providers reported delayed studies at the end of 2022.

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. 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. 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. 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. 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. 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. 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.

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, 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.

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. First, delayed interconnection study results or unexpected cost increases can disrupt numerous aspects of generating facility development. 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. 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.

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. 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. 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. 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. 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.

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. 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. Late-stage withdrawals of interconnection requests are also increasing. 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.

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. 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. 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. 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. 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.

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. 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.

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. 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.

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. 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. As a result, we find the existing pro forma LGIP and pro forma LGIA results in Commission-jurisdictional rates that are unjust and unreasonable.

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. 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. 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.

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. 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. 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.

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.” That some interconnection processes may fare better in the face of industry-wide challenges would be “as unastonishing as it is irrelevant.” 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.

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. 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%. For example, only 10% of interconnection requests, by capacity, have reached commercial operation in the non-RTO/ISO southeast region between 2000 and 2017. 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. 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. Finally, as recognized in Order No. 2003, interconnection queue delays may “provide[] an unfair advantage to utilities that own both transmission and generation facilities,” 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. 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.

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, to determining the replacement rate, described—at some length—below.

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. 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.

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. 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.

63. Many commenters agree with the goal of providing additional information prior to entering the interconnection queue. Some commenters state that additional information prior to entering the interconnection queue is beneficial, in particular access to information on potential network upgrades and the cost and time to interconnect. 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.

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. 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. 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.

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. 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.

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. 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.

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. We also agree with commenters that additional access to interconnection information is a valuable goal as it can increase the likelihood that an interconnection request is viable when submitted. We disagree with commenters that current information requirements are sufficient. 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. 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.

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. 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.

69. Under the Commission's proposal, prospective interconnection customers could request up to five separate informational interconnection studies at a time. 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.

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. 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.

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. 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.

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. 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.

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.

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.

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. Several commenters agree that the informational interconnection study proposal could reduce the number of speculative or other interconnection requests and improve the efficiency of siting decisions. Some commenters expect that these changes will have other benefits for the interconnection process, including cost savings from fewer and more viable interconnection requests, a reduced need for project withdrawals and queue restudies, and reduced burden on transmission providers, which will result in fewer interconnection study delays.

76. MISO and Fervo Energy state that it is helpful for a prospective interconnection customer to compare how various MW sizes, points of interconnection, or other scenarios could affect costs, especially for prospective interconnection customers that cannot perform such analysis in house, and that the NOPR's informational interconnection study proposal would assist in these goals. Pacific Northwest Organizations argue that, without upfront interconnection cost information, independent power producers may be discouraged from entering the interconnection queue if they are subjected to higher withdrawal fees, which may result in preventing them from being considered in request for proposals (RFPs) in the Pacific Northwest.

77. Some commenters stress the importance of the informational interconnection study in light of the other reforms proposed in the NOPR. For instance, Northwest and Intermountain aver that the informational study will be the primary resource for interconnection customers to demonstrate the feasibility and cost effectiveness of their interconnection plan and will serve as the foundation for subsequent negotiations for the documents that will establish commercial readiness of their project for the cluster study process. Pacific Northwest Organizations assert that the NOPR's proposed commercial readiness framework would be problematic in the region without something like the informational interconnection study to discover costs before entering the queue.

78. Several commenters are generally supportive of the NOPR proposal but either (1) offer qualifications to that support or (2) request specific changes to the proposal.

(b) Comments in Opposition

79. Many commenters oppose the NOPR proposal to require transmission providers to offer an informational interconnection study to prospective interconnection customers. Many commenters argue that the informational interconnection study proposal could be a burden or divert resources, which they contend would increase delays for the interconnection queue and other studies. Dominion insists that the decision as to whether to offer informational interconnection studies should be the transmission provider's and must have limits. Longroad Energy states that transmission-interconnected generating facilities are typically complex facilities with unique operating characteristics which would be poorly approximated in simplified studies. Environmental Defense Fund states that, while it supported the informational interconnection studies proposal in its initial comments, after review of the other comments submitted, it recommends that the Commission reconsider the proposal and ensure that any informational interconnection study reform not delay other interconnection processes.

80. Several commenters contend that the informational interconnection study proposal would not likely be valuable. Clean Energy Associations assert that the proposed informational interconnection study would provide no information related to stability-driven network upgrades, rendering it near-useless in areas where stability limits are most typically the driver of network upgrades. APPA–LPPC warn that informational interconnection studies could engender controversy because prospective interconnection customers would, notwithstanding the informational nature of the studies, likely rely upon the study results in making investment decisions, even though the informational study results would inevitably diverge from the actual interconnection study results.

81. Several commenters argue that the proposal is not an improvement over the status quo. National Grid and NextEra assert that it is unclear how the proposal would save any time compared to the status quo, and that the best way for an interconnection customer to obtain the necessary information is by entering and proceeding through the interconnection queue with transmission providers focusing on actual studies. NextEra adds that the proposed informational interconnection study is only informative in extreme cases, such as very limited capacity available on a transmission line, which the interconnection customer should be able to identify themselves.

82. CREA and NewSun express concern that the NOPR proposal places too much reliance on the usefulness of the informational interconnection study in order to justify the financial readiness and commitment NOPR proposals. They assert that the informational interconnection study is not a useful replacement for the feasibility study, which takes into account the impact of other interconnection customers in the interconnection queue cluster. Therefore, CREA and NewSun ask the Commission to instead retain the feasibility study as part of the cluster study process to allow interconnection customers to obtain cluster-level information on likely costs and network upgrades before proceeding further with major deposits and irretrievable commitments.

83. Several commenters point to the experience with similar studies in SPP and MISO as evidence that the optional informational interconnection study proposal will be little-used in practice. SPP reports that its interconnection customers explained that their time could be more effectively spent working on the more definitive system impact studies, that the feasibility and preliminary impact studies did not provide results that could be relied on in making business decisions, and that this same outcome would be true of the proposed informational interconnection study.

84. Several commenters point to the inability of the informational interconnection studies to provide reliable cost estimates and believe that the information provided in these studies will be quickly outdated. The New Jersey Commission is concerned that this approach may not materially reduce the uncertainty interconnection customers currently face. In particular, many commenters contend that the informational interconnection study is not meaningful in the context of a cluster interconnection

process. Commenters argue that, because the informational interconnection study does not provide information on other interconnection customers that would enter the interconnection queue at the same time, there is no guarantee that the study results will even approximate the actual network upgrade costs determined by the cluster results.

85. Some commenters expect the proposal will work against the Commission's goal of faster interconnection queue processing. Some commenters state that any reduction in speculative interconnection requests will be offset by an increase in speculative informational interconnection requests, which would require transmission providers to shift their focus from the actual interconnection queue to this more burdensome informational interconnection process, which is outside of their interconnection study process. NRECA states that, if the proposal is included in the final rule, the Commission should ensure that it is limited and is not expanded into an elaborate serial study process prior to the cluster study process. Avangrid notes that some transmission providers have recently eliminated interconnection studies to reduce interconnection queue processing time. Pennsylvania Commission asserts that the Commission should assess the results of the NOPR's proposed reforms before requiring any new study processes that may further slow the interconnection queue process.

86. Several commenters note the challenge of staffing to fulfill the informational interconnection study requirements given the limited number of qualified planners and engineers.

87. Several commenters urge the Commission to weigh the benefits against the burdens to determine whether to adopt the informational interconnection study proposal. WAPA states that, while it agrees that it is important to provide prospective interconnection customers with additional information, it has concerns about the proposed timelines and penalties, the potential amount of informational interconnection study requests it could receive, and its ability to process up to five simultaneous informational interconnection study requests per interconnection customer. According to Vermont Electric and Vermont Transco, even if the informational interconnection studies envisioned by the NOPR provide interconnection customer benefits, the burdens of providing informational interconnection studies with cost estimates under the NOPR's short proposed time frames and low deposit amounts would be considerable especially for smaller companies such as Vermont Electric and Vermont Transco. Other commenters contend that the informational interconnection study proposal has insufficient benefits.

88. Given PJM's opposition to the informational interconnect study, it recommends modifying the proposed new section 3.1.2 to the pro forma LGIP to encourage, but not require, interconnection customers evaluating different project characteristics to use a prescreening tool, such as the queue scope tool PJM is developing, prior to submitting an interconnection request.

iii. Commission Determination

89. We decline to adopt the NOPR proposal to modify the pro forma LGIP to require transmission providers to offer an informational interconnection study for prospective interconnection customers. We are persuaded by commenters' concerns that requiring an informational interconnection study could divert the transmission provider's resources away from the cluster studies we require in this final rule and undermine the benefits of those reforms that seek to reduce interconnection study delays, costs, and burden on constrained engineering labor. Moreover, we agree with commenters that highlight the various limitations of an informational interconnection study. Notably, an informational interconnection study, as proposed in the NOPR, would have provided a serial, snapshot-in-time analysis on the impact of a single interconnection request, but, in the context of the subsequent cluster study, the actual impact of an interconnection request within a larger cluster would reflect different assumptions and differ from the informational interconnection study, providing minimal or no value to interconnection customers. The cost estimates that result from such an informational interconnection study would bear little correspondence to costs determined during a cluster study process and thus provide minimal value to interconnection customers.

90. We also find persuasive comments that the informational interconnection study requirement proposed in the NOPR is not the most effective way to provide interconnection customers with the needed pre-interconnection queue information. At the same time, we continue to believe that there is a lack of information available to prospective interconnection customers prior to entering the interconnection queue, especially given other interconnection customer-related reforms adopted in this final rule. Therefore, as discussed below, we adopt the NOPR proposal to set minimum requirements for transmission providers to publicly post available information pertaining to generator interconnection. We find that the posting of this information provides a better balance between the benefits of additional information for prospective interconnection customers and the burdens on transmission providers.

91. In response to commenters that support the informational interconnection study NOPR proposal, below we explain how several of the NOPR proposals that we adopt in this final rule address their specific concerns. To address commenters' concerns with the number of speculative interconnection requests, we adopt more stringent site control requirements and increased commercial readiness deposit requirements, which we believe will better address these concerns than the informational interconnection study proposal. Additionally, we find that the minimum requirements for transmission providers to publicly post available information pertaining to generator interconnection and the existing requirements in section 2.3 of the pro forma LGIP for transmission providers to post up-to-date base case study models on their Open Access Same-time Information System (OASIS) or other password-protected websites will improve the efficiency of siting decisions and will provide interconnection customers with information about the feasibility of their interconnection plans.

92. We are not persuaded that the informational interconnection study proposal would benefit the interconnection process through: (1) cost savings from fewer, more feasible interconnection requests; (2) a reduced need for interconnection request withdrawals and restudies; and (3) accurate upfront interconnection cost information. On the contrary, the Commission's adoption of the cluster study reforms in this final rule means that the serial nature of the informational interconnection study would fail to reflect the outcome of the cluster study, and thus would provide minimal, if any, benefits to interconnection customers. We also no longer believe that adopting the informational interconnection study proposal would reduce burdens on transmission providers. This is because the record overwhelmingly demonstrates that the proposal would result in additional burdens on transmission providers and would likely cause transmission providers to divert resources from their cluster study process to conduct informational interconnection studies, thus increasing study delays and costs. Similarly, we decline CREA and NewSun's request that the Commission retain the feasibility study instead of the informational interconnection study. As we discuss below, the feasibility study was required for the serial study process but is no longer relevant for the cluster study process. We believe that our requirement for transmission providers to publicly post certain interconnection information will provide interconnection customers with the information they need prior to entering the interconnection queue, and therefore decline to adopt CREA and NewSun's request to maintain the feasibility study.

93. Because we do not adopt the NOPR proposal to require transmission providers to offer an informational interconnection study, we decline to adopt the proposal to add new section 3.1.2 to the pro forma LGIP to encourage interconnection customers to use the informational interconnection study.

c. Public Interconnection Information

i. NOPR Proposal

94. In the NOPR, the Commission proposed to require transmission providers to maintain and make publicly available an interactive visual representation of available interconnection capacity (commonly known as a “heatmap”) as well as a table of relevant interconnection metrics that allow prospective interconnection customers to see certain estimates of a potential generating facility's effect on the transmission provider's transmission system. Specifically, the Commission proposed to revise section 6.4 of the pro forma LGIP to require transmission providers to post on their public website a heatmap of estimated incremental injection capacity (in MW) available at each bus in the transmission provider's footprint under N–1 conditions, as well as provide a table of results showing the estimated impact of the addition of a proposed project (based on the user-specified MW amount, voltage level, and point of interconnection) for each monitored facility impacted by the proposed project on: (1) the distribution factor; (2) the MW impact (based on the proposed project size and the distribution factor); (3) the percentage impact on the monitored facility (based on the MW values of the proposed project and the monitored facility rating); (4) the percentage of power flow on the monitored facility before the proposed project; and (5) the percentage power flow on the monitored facility after the injection of the proposed project. The Commission explained that these metrics would be calculated based on the power flow model of the cluster study or restudy with the transfer simulated from each bus to the whole transmission provider's footprint (to approximate Network Resource Interconnection Service (NRIS)), and with the incremental capacity at each bus decremented by the existing and queued generation in the cluster (based on the existing or requested interconnection service limit of the generation). The Commission proposed to require transmission providers to update this information within 30 days after the completion of each cluster study and restudy.

95. The Commission sought comment on whether: (1) there are any security concerns with this proposed requirement; and (2) the assumptions specified for the analysis are the right set of assumptions.

ii. Comments

(a) Comments in Support

96. Many commenters express support for the NOPR's proposal to require transmission providers to provide public interconnection information. Several commenters agree that the NOPR proposal will provide valuable information to interconnection customers before they enter the interconnection queue. Several commenters aver that the proposal could reduce the number of interconnection requests withdrawn and therefore could reduce costs for all parties. Alliant Energy and Clean Energy Associations also see value in the standardized format of the proposed public interconnection information. R Street states that a properly done visual representation of interconnection capacity can be a “powerful decentralized self-screening tool.” R Street states that better information and simpler deliverability requirements shift congestion performance risk to generating facilities while reducing barriers to entry. The Ohio Commission Consumer Advocate states that the visual map of available interconnection capacity would be useful both to transmission providers and interconnection customers and would encourage information sharing on transmission system congestion during the interconnection process. Google argues that making these data publicly available to consumers would allow buyers to make informed choices regarding power procurement. Additionally, Google asserts that there needs to be a standard of reasonable care applied to ensure that the publicly available information is reasonably current and useful to avoid exploratory interconnection requests. SEIA argues that greater transparency will increase competition between merchant and utility developed generating facilities, benefiting consumers. Illinois Commission contends that, if properly implemented, the NOPR proposal will increase the pace at which new generating facilities can connect to the transmission system, furthering state policy objectives.

97. Some commenters contend that the proposal to provide public interconnection information is not overly burdensome. APPA–LPPC members report that the information posting and interactive capability described in the NOPR could be feasibly implemented with available industry system simulation tools. Clean Energy Associations state that heatmaps should be as automated as possible, without significant commitments of staff or resources.

98. Several commenters point to the fact that some transmission providers are already developing such tools as evidence that these tools are unlikely to cause further delays to stressed interconnection queues or additional burden on transmission providers. For instance, some commenters note that MISO already offers a heatmap that represents geographically advantageous siting locations. Several commenters also note that PJM is developing such a tool. PJM states that in 2023 its queue scope tool will provide a congestion map with colors or symbols indicating the worst flowgate loading at each point of interconnection. SPP states that it is also developing a tool to be implemented by 2025 that would provide much of the functionality described in the Commission's public information proposal to new interconnections.

99. Several commenters contend that the public information proposal is a more reasonable balance of costs and benefits relative to the informational interconnection study proposal. Pennsylvania Commission states that, once a public information tool is established, it may require fewer ongoing resources, continuing to inform interconnection customers while freeing those resources for additional interconnection studies as compared to the proposed informational interconnection study.

(b) Comments in Opposition

100. A few commenters oppose the NOPR proposal to require transmission providers to provide public interconnection information. A larger number of commenters express reservations about the proposal, in particular regarding its usefulness or the burden it creates. Other commenters request that the Commission make public interconnection information posting optional.

101. Several commenters argue that the proposal to require transmission providers to provide public interconnection information is not useful, particularly because it might not provide sufficient detail or commercially actionable information for interconnection customers. Commenters explain that heatmaps are specific to a moment in time and thus not representative of actual available injection across the transmission system, which is ever-changing. NextEra observes that heatmaps do not contain actionable information for interconnection and instead focus on energy prices and congestion. ISO–NE, MISO, and Omaha Public Power note that a visual representation of interconnection capacity cannot account for all of the conditions identified in a system impact study, including different system stresses, operability issues ( e.g., N–1–1), stability and voltage issues, and weak transmission system issues. Longroad Energy asserts that generator interconnection heatmaps or hosting capacity maps can be of some use for interconnections to the distribution system but are unlikely to be beneficial for projects interconnecting at transmission voltages.

102. Some commenters do not believe that the heatmap proposal will appreciably reduce speculative interconnection requests. MISO explains that, in its experience, few interconnection customers use its interconnection heatmap tool and instead tend to use their own tools. Puget Sound states that, even with a heatmap, if an interconnection customer has a request that would require energy transfer across balancing authorities, it would have to submit an interconnection request to get information on the scope of necessary network upgrades. NV Energy asserts that a heatmap of its transmission system would be of little value, appearing as though there is no available transfer capacity, because the generation in its interconnection queue is more than five times the level of NV Energy load. Meanwhile, Puget Sound states that a heatmap of its territory would only account for generation and interconnection capacity in its balancing authority footprint even though its transmission goes beyond this footprint.

103. Several commenters contend that a heatmap tool as proposed would be less useful in a cluster study than it is in a serial process because it cannot include similarly queued generation. Ohio Commission Consumer Advocate questions whether it will capture the “dynamic elements” of cluster studies and restudies. PacifiCorp and AEP state that the mere fact that an area is not shown as congested on a heatmap does not mean that it will be a suitable interconnection location, particularly if multiple interconnection customers seek to interconnect there.

104. Longroad Energy and PacifiCorp express concern that the heatmap tools would not be restricted to prospective interconnection customers and could instead be used by third-party consultants for their own business interests; for instance, real estate speculators could use the information to secure exclusive site control for locations that show significant generator interconnection capacity. According to Longroad Energy, such risk is particularly harmful to wind and solar generation interconnection customers' needs for large tracts of land to accommodate their generation equipment.

105. Some commenters assert that maintaining the heatmap and posting required information on available interconnection capacity would be burdensome for transmission providers, especially in non-RTO/ISO regions. Similarly, NV Energy states that it participates in the CAISO energy imbalance market and its energy management system does not currently have the technical functionality to build an interactive map that shows information like the available interconnection capacity. Some commenters argue that the heatmaps may provide insufficient benefit to justify cost, resources, and time it would take to produce them. Omaha Public Power further asserts that interconnection customers will likely find it more valuable for a transmission provider invest in more reliable and consequential studies. Pacific Northwest Utilities assert that the Commission should present additional data regarding the benefits of requiring a heatmap before mandating their use. Clean Energy Associations recommend that the Commission consider other means of increasing information to prospective interconnection customers, such as public scoping meetings prior to the prospective interconnection customers entering the interconnection queue.

106. Some commenters express concern that the public information proposal will impose new costs on ratepayers and market participants. WAPA states that, given its defined appropriations and budgets, it is difficult to create new programs, unlike for larger investor-owned utilities or RTOs/ISOs. Dominion estimates that implementation would require a large up-front financial commitment, potentially for third-party software and personnel hours, and longer-term financial commitment to maintain such a site. NV Energy contends that creating such a heatmap showing interconnection capabilities would require finding an eligible software, an ongoing expense.

107. Several commenters speak to the burden of additional staffing needs to provide public interconnection information. National Grid states that the interactive visual representation tool, even if contracted from a third party, would require significant time commitments from numerous personnel with relevant and advanced expertise in transmission and interconnection engineering. Tri-State notes that the Commission has recognized the lack of available engineers and that imposing a heatmap requirement would exacerbate the problem. Dominion and Duke Southeast Utilities state that any additional process would require additional financial and personnel resources, and also burden the same personnel that are already engaged in managing the interconnection queue. El Paso Electric argues that transmission providers should not be required to allocate human resources from interconnection studies to monthly transmission line capacity estimates because the staff reallocation could cause interconnection study backlogs. PacifiCorp states that this burden will be particularly onerous to transmission providers outside RTO/ISO regions, which have comparatively few transmission staff available.

108. Several commenters suggest that interconnection customers, on their own or with consultants, can perform studies with the available information that would provide estimates on available capacity similar to that produced under the NOPR proposal. PPL states that interconnection customers can make their own such maps using transmission planning models the Commission makes available following a Freedom of Information Act request. APPA–LPPC argue that the Commission fails to establish that the information already available to prospective interconnection customers under the existing pro forma LGIP, along with the substantial supplement implemented with Order No. 845, is inadequate. SoCal Edison states that the information included in the NOPR proposal and more is already available if interconnection customers request it from the Commission for their own studies or use studies developed by transmission providers. The Ohio Commission Consumer Advocate states that the determination of a suitable site depends largely on the location and geography of the resources, which is publicly available from national labs and the U.S. Energy Information Administration.

109. Several commenters state that sufficient data are already required to be posted on OASIS. According to Idaho Power, Order No. 2003–A required interconnection study reports to be publicly available and provide locational and cost information for previously studied interconnections, but this has not reduced the amount of interconnection requests at congested locations. SoCal Edison and NYISO state that this information is already available in FERC Form 715, where it is protected with a non-disclosure agreement as critical energy infrastructure information (CEII) and has the benefit of being available in one centralized location. On the other hand, ACE–NY disagrees with the assertion that FERC Form 715 provides sufficient information for interconnection customers to do their own analysis, asserting that the FERC Form 715 database base cases do not contain sufficient data about the generation interconnection queue and study assumptions and are therefore inadequate. Rather, ACE–NY argues that more detailed base cases such as those currently being made available by MISO and PJM, should be required.

110. Several commenters state that the usefulness of public interconnection information proposal will depend on the implementation details. For example, Illinois Commission and CESA recognize that the accuracy of the heatmaps is an important part of how useful they will be. Puget Sound states that it has considered creating such a heatmap but has concerns about its effectiveness given implementation challenges. SPP states that technology, information, and tools are quickly evolving and that a standardization tool might be obsolete before it is implemented. CESA explains that currently CAISO provides static, snapshot-in-time transmission capability estimates that are helpful but do not capture locational granularity or other projects already in the interconnection queue, making it difficult to make an informed project siting decision and at times requiring data requests of CAISO. For this reason, CESA stresses that the heatmaps and associated data must be made available in a user-friendly format. CREA and NewSun argue that the Commission should be careful not to overestimate the ability to forecast interconnection costs and project viability that will ultimately result from a cluster study. Several commenters stress that any potential increase in transparency and interconnection process performance resulting from this proposal must outweigh the additional burden imposed on transmission providers.

(c) Comments on Specific Proposal

(1) Metrics

111. While some commenters agree with the Commission's proposed table of metrics, multiple commenters suggest additional metrics that should be posted. For instance, Public Interest Organizations request information on the available interconnection capacity (including, at a minimum, a snapshot of existing available interconnection capacity and associated transmission during high load conditions for each substation) including projects already in the interconnection queue, and the capacity those projects are requesting, as well as metrics on whether power flows from a point of interconnection are likely to serve low income and people of color communities (which would be consistent with Executive Order 13985). Other commenters suggest that the posted metrics should also include: circuit strength and the harmonics of transmission system elements; limiting elements at a substation or associated transmission infrastructure; the level of congestion and resource curtailment by location (historic, current, and/or expected); overload conditions; contingencies that drive the impacts to the monitored facility; for a given transmission line, information on the circuit ( e.g., single or double), the conductor type, pole types, the ratings of the equipment, and the age of the equipment; flowgate data, such as disconnect switches, breakers, transformers, conductors, series reactors, and ground clearances of lines; change file models of network upgrades for deliverability in advance of providing study results; base case models paired with contingencies including local contingencies (below 200 kV); incremental injection capacity available at each bus in the transmission provider's footprint under N–1 conditions with a five-year outlook; the rating of the monitored facility; estimated costs of interconnection or transmission service, including where interconnection is likely to be costly and not costly; proposed upgrades in the region that could affect interconnection requests; lists of potential upgrades that would be needed to export power to other regions or that would allow the transmission provider to increase injection capacity at each substation; more granular load growth data, defined by region, which could be combined with existing and planned generation and congestion to view anticipated system changes; and the share that all generating facilities contribute to a network upgrade along with their share of allocated costs. Tesla requests information that would particularly developers of non-synchronous generating facilities to decide what project controls might be best suited for a given point of interconnection, including: the number of generating facilities and power control devices (including series compensation systems, static synchronous compensator devices and other power control devices) that are two busses away from the given point of interconnection; the circuit breaker short circuit ratings of the nearest substation; and the maximum and minimum fault current in megavolt amperes (MVA) at the given point of interconnection.

112. Several commenters highlight that additional information regarding transmission system conditions, such as previous cluster studies and models, posted in a secure way subject to CEII processes, would allow interconnection customers to conduct their own initial analyses of system conditions and desirable points of interconnection. SoCal Edison states that, alternatively, the transmission providers could identify areas where new generation is desired, guided by state processes identifying the locations that can accommodate additional generation currently or locations intended for types of generation sought state policy.

113. Some commenters oppose these requests for additional metrics. Dominion notes that tracking and providing the information requested by Public Interest Organizations, including documenting the study process, providing enhanced interconnection queue tracking, and metrics on constraints that cause bottlenecks, would be burdensome, taking engineers' time, slowing down the cluster study process, and diverting resources. EEI and WIRES contend that certain information on transmission line design, such as circuit type, conductor type, and pole type, would be overly burdensome and offer little benefit, adding that this information could invite potential disputes or be used to threaten to the reliability of the transmission system or for commercial gain if the information is not subject to confidentiality protections. EEI also asserts that any additional information beyond that proposed in the NOPR would complicate the interconnection process by adding another potential area of dispute and risks potential “backseat driving” by the interconnection customer, while the transmission provider is responsible for performing and standing by its study results.

114. Some commenters disagree as to the appropriate level of granularity of the required metrics. SEIA and ENGIE support the NOPR proposal to require transmission providers to post bus-level interconnection capacity constraints. Dominion disagrees, arguing that requiring capacity constraint information to be provided at the bus-level is outside the scope of the NOPR and would not necessarily be useful in a networked system where injection at one bus will affect the capability at other buses and significant additional power flow analysis would be required to determine these values at each bus. According to Dominion, information about bus-level interconnection capacity constraints makes more sense where the system is radial in nature and injection capability at one bus is not dependent on contingencies or injections at another bus. Eversource adds that bus level information will not provide significant benefits because it may be too simplistic if it is not based on N–1 conditions or if it fails to incorporate stability considerations. Public Interest Organizations state that many utilities provide hosting capacity information on their websites at the distribution level in heatmaps or tables, in particular to help distributed solar interconnection customers, and this information is required by states and updated regularly. Public Interest Organizations ask the Commission to require analogous hosting capacity information to be provided by transmission providers for all potential generation locations with exemptions for urban substations where there is limited potential for generation development. PJM requests that, rather than requiring that all buses be made available in a large RTO/ISO, a transmission provider should be allowed to screen and only present the majority of the feasible points of interconnection. As an alternative to providing information at every bus, Tri-State states that a transmission provider could post the most recent cluster study to provide information for the buses that were studied as opposed to studying all buses on the system, while also making clear that the heatmap does not reflect interconnection requests in neighboring systems. Similarly, Bonneville argues that cluster studies would not provide the incremental injection capacity at each bus on the transmission provider's system, which would warrant a separate study, and therefore, transmission providers should be afforded flexibility to provide this capacity information as it becomes available.

115. Some commenters argue that the proposed heatmap is not an ideal way to present public interconnection information. For instance, Illinois Commission states that it is not immediately evident what information maps posted to an RTO/ISO website would reflect. For example, Illinois Commission questions whether congestion maps would reflect present congestion or congestion that might arise after generating facilities interconnect. Fervo Energy states that additional research might be needed to determine the most useful informational suite. Clean Energy Associations proposes, and SEIA supports, that two maps, one for Energy Resource Interconnection Service (ERIS) and one for capacity or NRIS, should be made available where appropriate, and notes that in ISO–NE overlapping impact analysis is used to determine eligibility for capacity NRIS. Finally, Clean Energy Associations and ISO–NE recommend that the Commission consider allowing information to be qualitative, such that, rather than a “hosting map,” transmission providers could post a map and accompanying report regarding system conditions at various points on the transmission system.

(2) Security of Critical Information

116. Several commenters express concern that the NOPR's proposed heatmap and/or metrics may create a security risk by, among other things, indicating areas where transmission is heavily loaded and more vulnerable to interference. In particular, LADWP and Bonneville express concerns over sharing distribution factor and MW impact, which they believe could identify highly stressed transmission lines, as well as concerns with identifying the line locations, which are not currently provided publicly. LADWP further expresses concern with CEII issues that may arise from publicly releasing a table of metrics regarding the estimated impact of a potential generating facility.

117. Other commenters counter that the security risks associated with the NOPR proposal are reasonable or non-existent. For example, Pacific Northwest Utilities and Puget Sound states that the purpose of the heatmap is to provide an overview of interconnection capacity, which is unlikely to implicate CEII, and thus the risk of unrestricted critical infrastructure information should be low. Indicated PJM TOs and PPL state that a visual map with limited information, excluding reliability constraints or other particular information that could be used to identify vulnerabilities, could be made public without security concerns and highlight PJM as a good example of this. Xcel states that it does not have security concerns about posting estimated injection capacity but that some of the more detailed information should be limited. MISO states that it is currently unaware of any security concerns associated with the proposal.

118. While SoCal Edison and Southern assert that there should be no requirement on transmission providers to make public or display any CEII or confidential information, other commenters contend that the CEII label should not be used to unreasonably impede interconnection customers' access to interconnection information necessary to understand the cost and other impacts of locating their projects in different areas of the transmission system. Some commenters recommend that the Commission require transmission providers to make CEII data available only to interconnection customers who meet restricted access requirements, such as through a secure portal or subject to a confidentiality agreement. Pattern Energy asks that this information be made available through a cost-free process that takes no longer than two weeks, and Pine Gate adds that the retrieval of this information should not require background checks, as required by certain transmission providers. EEI suggests that transmission providers should have the discretion to identify sensitive information that should be withheld. Clean Energy States add that the Commission may want to limit access to permitted users, controlling the copying and dissemination of data, or take other security measures.

(3) Miscellaneous

119. SEIA requests that the Commission require transmission providers to use the most recent available study models as well as the most recently completed system impact study in creating their data results.

120. A few commenters express concern with the proposal to require updated information 30 days after the completion of each cluster study and restudy and instead request that the Commission allow for regional flexibility on the timing of updates. MISO states that, as written, the NOPR proposal would require it to update the tool available to help interconnection customers pre-screen for potential points of interconnection each time a regional system impact study is issued, which would be numerous times during a calendar year due to the configuration of MISO's transmission system. PJM states that it is not feasible for an RTO/ISO as large as PJM to update an interactive public interconnection information tool within 30 days after completing a cluster restudy. PJM states that, once the tool includes light load results, it will be uploading four to six datasets a year with each dataset including millions of points of interconnection flowgate records, which may eventually not be feasible to maintain from a storage perspective. According to El Paso Electric, the interconnection queue changes often as interconnection customers withdraw their requests and therefore transmission providers should not be required to update capacity line estimates monthly because the burden on staff could increase interconnection study delays. Tri-State explains that only a subset of buses and lines are studied in each cluster study, so to require an estimate of the injection capacity at every bus in each cluster study to be posted within 30 days would greatly increase the scope and cost and would likely have a negative impact on the time to complete the study and cause rates to increase.

121. On the other hand, Ørsted notes that any system representation needs to be frequently updated to be useful and avoid the risk of becoming out-of-date, and Public Interest Organizations state that hosting capacity data should be updated at least quarterly. Environmental Defense Fund argues that the public interconnection information should be updated immediately at the end of each cluster request window so that interconnection customers using that information are informed of generating facilities being studied that may impact transmission capacity.

(4) Requests for Flexibility

122. Several commenters request flexibility from the Commission with respect to the particular information included in a potential heatmap. Dominion asserts that the proposal is overly prescriptive and that the Commission should focus on the goal itself rather than uniformity. Clean Energy Associations state that the heatmaps may need to be tailored to the services offered by a particular transmission provider, because their services are not uniform. Several commenters claim that flexibility will help ensure that the information provided is useful and understandable, and will place a reasonable level of burden on transmission providers. MISO states that flexibility is reasonable given the burden on transmission providers of maintaining a heatmap tool relative to the limited value of frequent updates given that few interconnection customers use this tool and its inability to include future queued projects that will be relevant to the prospective interconnection customer. Bonneville also argues that flexibility is needed to ensure consistency with security requirements. On the other hand, Cypress Creek asserts that, as a broad consideration, the particular types of information to be made transparent that are valuable should be determined by the Commission in consultation with market participants who are best positioned to identify information relevant to financing and constructing new projects.

123. Several commenters ask for flexibility in the way information is shared. SEIA states that whether the data are in a map or other format is not as important as the product itself. NYTOs expect that flexibility would allow regions to adopt some form of the virtual tool as long as it is clear that the information is illustrative, non-binding, and subject to change. NRECA states that smaller generation and transmission cooperatives may be able to just post a table with bus names and injection capability and present the same useful information in a more economical way. NV Energy states that, if it were to post to its OASIS the CAISO locational marginal price map with a link to CAISO's OASIS to provide a list of interchange limits and interchange schedules, this would be just as valuable as a map for its own transmission system.

124. Some commenters argue that transmission providers that already provide public interconnection information should have flexibility to use their existing systems to comply. However, Environmental Defense Fund avers that this flexibility should not extend to transmission providers who, prior to the NOPR, were without a substantial public interconnection information system, because they have no sunk costs related to public interconnection information systems.

125. Several commenters express concern that heatmaps would be technically difficult to implement outside of RTOs/ISOs and ask the Commission to provide non-RTO/ISO regions with flexibility in how they comply with the mapping tool. Tri-State states that, in non-RTO/ISO regions, it is common for multiple transmission providers to use a single substation, making injection capacity dependent on interconnection requests in neighboring interconnection queues and their associated study assumptions. Tri-State, therefore, encourages the Commission to permit variations among heatmaps, adding that entities in non-RTOs/ISOs should not be required to study every bus.

126. Xcel recommends that the Commission consider applying the requirement only in RTO/ISO regions or granting non-RTO/ISO transmission providers sufficient time, such as two years, to comply. WAPA asks the Commission to first require data visualization by larger utilities, wait approximately 18 months after implementation, and then measure the benefits of interactive tools produced by larger utilities, giving stakeholders a chance to comment before extending the heatmap requirement.

127. On the other hand, some commenters expressly argue that uniformity should be required inside and outside of RTO/ISO regions. Google states that such publicly available information would begin to address the critical information advantage that transmission owners have over independent power producers, particularly in non-RTO/ISO regions. R Street notes that non-RTO/ISO regions may have additional challenges in implementing such a tool but states that this should not eliminate their requirement to do so and those regions could be granted extra implementation time.

(d) Requests for Clarification or Technical Conference

128. Several commenters seek clarification on the information transmission providers are required to present in the heatmap, use of that information, who has the responsibility of presenting the information, timing of updating that information and recovery of costs for providing this information. PJM asks that the Commission clarify that an interactive visual congestion map could comply, instead of requiring its specific form.

129. APPA–LPPC ask the Commission to clarify that it is not proposing that transmission providers be required to conduct any individualized analyses or take any action in response to particular prospective interconnection customers' use of the interactive tools.

130. Some commenters request that the Commission make clear that the public information is published only as a guide and not as a binding or definitive statement of available interconnection capacity or costs. Xcel asks the Commission to clarify that transmission providers have no liability associated with the posting of public information. EEI urges the Commission to make clear that interconnection customers that rely exclusively on this information, including these maps, do so at their own risk.

131. Eversource asks that the Commission clarify that “no information would be required to be made available before the conclusion of the first cluster study.”

132. Dominion seeks clarification that, in an RTO/ISO context, the proposed requirements to maintain a visual representation would apply to the RTO/ISO, and not additionally to individual transmission owners.

133. Several commenters request clarification on how the public information proposal will be funded. Some commenters assert that a user-pays model is the only appropriate funding mechanism because not all interconnection customers will use the public information tools, and the transmission provider or their customers should not be required to pay for work that only benefits some. Tri-State asserts that it might increase the $5,000 application fee to cover the significant heatmap costs.

134. AEP, Tesla, and ACORE ask the Commission to initiate a proceeding and hold a technical conference to, among other things, identify useful information tools that could be feasibly developed, establish uniform and transparent study assumptions, share best practices, and help less sophisticated interconnection customers learn to use available tools and information to lessen their own risk before entering an interconnection queue.

iii. Commission Determination

135. We adopt, without modification, the NOPR proposal to revise pro forma LGIP section 6.4, now section 6.1, to require transmission providers to publicly post available information pertaining to generator interconnection ( i.e., public interconnection information or a heatmap). We require transmission providers to update the heatmap within 30 calendar days after the completion of each cluster study and cluster restudy. Such heatmaps must be calculated under N–1 conditions and studied based on the power flow model of the transmission system with the transfer simulated from each point of interconnection to the whole transmission provider's footprint (to approximate NRIS), and with the incremental capacity at each point of interconnection decremented by the existing and queued generation at that location (based on the existing or requested interconnection service limit of such generation). We require transmission providers to provide the following information as outputs at each point of interconnection: (1) the distribution factor; (2) the MW impact (based on the proposed project size and the distribution factor); (3) the percentage impact on each impacted transmission facility (based on the MW values of the proposed project and the facility rating); (4) the percentage of power flow on each impacted transmission facility before the proposed project; and (5) the percentage power flow on each impacted transmission facility after the injection of the proposed project.

136. We find that the benefit of providing further transparency to interconnection customers about potential points of interconnection outweighs the added administrative burden to transmission providers. Commenters generally support supplementing the existing publicly available interconnection information and note their broad support for the NOPR proposal. Many commenters further assert that the heatmap will provide valuable information to interconnection customers before they enter the interconnection queue, and as SEIA explains, interconnection customers currently lack substantial information prior to entering the interconnection queue, which is valuable in determining whether to proceed with a proposed generating facility. In particular, the information that we require transmission providers to provide to prospective interconnection customers will allow such interconnection customers to learn about available interconnection capacity as well as other metrics that reflect the impact of the addition of a proposed generating facility to the transmission provider's transmission system at a particular point of interconnection. Such information may allow a prospective interconnection customer to estimate expected congestion, and, in turn, to assess likely network upgrades triggered by a proposed generating facility or the possibility of curtailment of a proposed generating facility.

137. With access to this type of information, a prospective interconnection customer will be able to better assess the viability of a proposed generating facility before it submits an interconnection request and therefore may be able to submit fewer exploratory and unviable interconnection requests. We believe that, by reducing the number of speculative interconnection requests, this reform will reduce the delays caused by restudies triggered by interconnection request withdrawals and overcrowded interconnection queues. We believe that this information is also beneficial in the cluster study context, contrary to some commenters' concerns regarding the availability of information about the composition of the cluster and the effect of the other proposed generating facilities in the cluster. In fact, interconnection customers will be able to evaluate the viability of their proposed generating facility in the context of a cluster by using the publicly posted information as a baseline and incorporating the cluster information that transmission providers are required to post, during the customer engagement window, per new pro forma LGIP section 3.4.5 (Customer Engagement Window). Further, the heatmap requirement will standardize the information available to interconnection customers across regions and such standardization will provide interconnection customers with consistency as they assess the viability of proposed generating facilities, including where to site them, across regions. Despite MISO's assertion that interconnection customers typically use their own tools to conduct analyses, as opposed to MISO's heatmap, several commenters identify MISO's heatmap tool as an example of a transmission provider posting generator interconnection information that is useful for prospective interconnection customers. Therefore, we continue to find that it is important to make similar information available to prospective interconnection customers across the country to ensure comparable access to information and the above mentioned resultant benefits of such information for the interconnection process.

138. Some commenters assert that the NOPR proposal is not useful in part because it does not provide sufficient detail and may not correspond with future study conditions, its usefulness depends on its implementation, and it is unlikely to address cost uncertainty challenges. In response to such objections, we find that the public interconnection information requirements we adopt in this final rule will provide further transparency of interconnection conditions, but, as we have acknowledged above, will remain non-binding and therefore cannot provide cost certainty. We recognize that this requirement does not provide real-time transmission system information, but we find that this information is valuable to prospective interconnection customers before they enter the interconnection queue.

139. We disagree with commenters that assert that the NOPR proposal is overly burdensome. By moving the pro forma LGIP from a serial to a cluster study process, the reforms adopted in this final rule will reduce the number of studies and restudies performed by transmission providers, therefore reducing the burden on both transmission providers and their staff. In addition, as commenters assert, and we agree, the information posting and interactive capability we require in this final rule could feasibly be implemented with available industry system simulation tools. We also agree with Clean Energy Associations that providing these data in a standardized format should be a “relatively low-impact” requirement for transmission providers. This appears to be consistent with comments from Dominion that suggests that the majority of the burden associated with complying with this reform will be through an up-front financial commitment in new software, rather than ongoing costs. Having made such software commitments, though, transmission providers should be able to automate much of the heatmap development, without significant commitments of staff or resources. In doing so, we expect the ongoing costs of maintaining such a heatmap to be relatively low. Moreover, because transmission providers must use the most recent cluster study or cluster restudy to populate the heatmap, they will not face the burden of individualized analyses, which addresses the concern raised by some commenters.

140. We adopt the requirement for transmission providers to update the heatmaps within 30 calendar days after the completion of each cluster study and cluster restudy. We recognize the need to balance the burden of a specific update frequency with the value of ensuring uniform, up-to-date information that can inform prospective interconnection customers evaluating whether to enter the next cluster. While some commenters support the timeline proposed in the NOPR, others argue that it is overly burdensome or, given the division of their footprint into regions that have different timelines, would trigger frequent updates. We find that the requirements we adopt here establish an appropriate period of time because, as discussed above, once the necessary software is in place, updating the heatmap after the completion of a study is expected to be largely automated without significant commitments of staff or resources. As the record demonstrates, such heatmaps can be implemented with available industry system simulation tools and with a standardized format that causes the burden to be a “relatively low-impact” requirement for transmission providers, once transmission providers have invested in new software.

141. In response to Eversource, which asks the Commission to clarify that the heatmap would not be required to be made available before the first cluster study concludes, we agree and further clarify that the heatmap would not be required to be made available until after the transition period. In response to El Paso Electric's comments regarding the burden of a monthly update, we clarify that the heatmaps must be updated within 30 calendar days after the completion of each cluster study and cluster restudy, not on a cycle of every 30 calendar days.

142. In response to comments from PJM, Bonneville, and Tri-State requesting flexibility for the posting of information for points of interconnection that have yet to be studied, we clarify that transmission providers need to provide updates only for anything that has changed in the most recent cluster study or restudy after the first cluster study after the Commission-approved effective date of the transmission provider's filing in compliance with this final rule. Requiring transmission providers to study each potential point of interconnection, rather than just those requested in each cluster, would expand the scope of this requirement. In turn, requiring such expanded studies would be inconsistent with ensuring that interconnection customers are able to interconnect in a reliable, efficient, transparent, and timely manner. In response to PJM, which states that transmission providers should be allowed to use prescreened datasets that capture a majority of the feasible points of interconnection that remove existing generator buses on the low side of the generator step-up unit, rather than using all buses to populate the heatmap, we agree that the heatmap may not differ significantly between the existing generating facility's point of interconnection on the low voltage side of the generating facility's step-up unit and the high voltage side of the step-up unit. If that is the case, this final rule provides transmission providers with the flexibility to populate the heatmap with only the high side of the step-up unit.

143. In response to comments arguing that the Commission has failed to demonstrate that information already made available is inadequate, we disagree. The heatmap requirement is distinct from information that transmission providers are already required to provide. The existing pro forma LGIP requires transmission providers to post the interconnection models and assumptions on OASIS or a password-protected website. But the information that we require to be posted in compliance with this final rule is the output of such models and assumptions. We believe that publicly posting such resulting output is necessary to aid prospective interconnection customers in their decision-making prior to entering the interconnection queue. While interconnection customers, on their own or through the hiring of consultants, may be capable of performing studies with information already published by transmission providers to arrive at information similar to that required as part of this final rule, we believe that making high-level information more easily accessible to all prospective interconnection customers is needed to remedy unjust and unreasonable Commission-jurisdictional rates. While Order No. 845 and FERC Form 715 do require certain, more detailed information to be filed with the Commission and/or posted on OASIS or a password-protected website, access to this information has not addressed the problem of speculative interconnection requests that we aim to remedy with several reforms adopted in this final rule.

144. We recognize the need to balance security concerns with the benefits of additional transparency. While some commenters express security-related concerns with the NOPR proposal, as discussed below, we are not modifying the Commission's CEII procedures, which we believe are sufficient to address security concerns raised in comments. Some commenters state that publicly posting information that indicates areas of transmission congestion or constraints is a risk as these areas are more vulnerable. We are not persuaded by these concerns and note that location-specific congestion information is already publicly available in RTO/ISO markets. Moreover, the Commission's regulations already provide that, upon request, transmission providers must make available all data used to calculate available transfer capability, total transfer capability, capacity benefit margin, and transmission reliability margin for any constrained posted paths publicly available (including the limiting element(s) and the cause of the limit ( e.g., thermal, voltage, stability)). Additionally, we find these concerns to be speculative, particularly in light of the fact that MISO already provides similar information over a large area. Rather, we agree with those commenters that do not believe that the NOPR proposal introduces additional security concerns.

145. In response to concerns from PPL and LADWP regarding the distribution factor analysis being made public, we are not persuaded and find these concerns to be speculative as well. MISO has long made distribution factors publicly available and states it is currently unaware of any security concerns associated with the proposal. As such, there is no evidence in the record to suggest this posting has raised any concerns in the past. Moreover, we observe that the distribution factor analyses informing the heatmaps are the result of multi-year forward projections that inevitably diverge from actual, real-time conditions, mitigating any potential concerns with publicly posting this information.

146. We are similarly unpersuaded by potential data confidentiality concerns. As with distribution factors, we find such concerns to be speculative and contrary to the experience of MISO, which, for the last several years, has already provided this information publicly, as well as contrary to the statements of commenters that support the NOPR proposal and do not raise data confidentiality concerns.

147. We provide further clarification in response to comments regarding the scope of analysis and assumptions which must provide the basis for the heatmaps. In response to comments from Public Interest Organizations, we decline to specifically require the heatmap to be studied at high load conditions. Instead, we reiterate that such heatmap should be based on the power flow model of the cluster study or restudy. While such cluster studies are often simulated at high load conditions, we understand that transmission providers typically conduct interconnection studies by studying a variety of situations. As such, we clarify that the information posted, for consistency and actionability, must not only be based on the cluster studies, but also must reflect the most limiting result of each of these situations studied.

148. We find that it is necessary for the heatmaps to reflect N–1 conditions because transmission systems are operated to withstand N–1 contingencies. To the extent that such information was not calculated under N–1 conditions, the results would not be useful or sufficiently actionable to potential interconnection customers. As Eversource asserts, point of interconnection level information would be too simplistic if it is based only on N–0 conditions and would not provide prospective interconnection customers with the information necessary to select viable points of interconnection. Similarly, we find that it is necessary for such posted information to approximate NRIS because such level of interconnection service is generally subject to more stringent requirements and therefore, reflecting this type of service will cover both types of interconnection requests, whether they are NRIS or ERIS. Similar to information calculated under only N–0 conditions, to the extent such a heatmap was not calculated to approximate NRIS, the results would not be useful or sufficiently actionable to a significant portion of interconnection customers.

149. In response to comments from AES, we decline to require the heatmaps to include a five-year outlook of available interconnection capacity. The purpose of the heatmaps is to provide potential interconnection customers an idea of the amount of interconnection capacity available at the conclusion of each cluster study or restudy. Because we are requiring transmission providers to consider pending generating facilities when collating the information to make public, interconnection customers will be aware of some of the future conditions on the transmission system. Further, any requirement to produce forecasts would place an additional burden on transmission providers that we find would outweigh its usefulness to interconnection customers.

150. In response to comments from Alliant Energy and Clean Energy Associations arguing that the assumptions used to produce the heatmap should be made clear to users, we find that the assumptions used to produce the heatmap should be consistent with those used in the interconnection cluster studies. As those assumptions are already required to be publicly posted, along with the models themselves, the assumptions used to produce the heatmap will be publicly posted via these preexisting requirements.

151. Tri-State describes difficulties associated with multiple transmission providers that inhabit a single substation. In such situations, we clarify that transmission providers must populate the required heatmaps using the results from their interconnection studies. In response to the Illinois Commission, we clarify that the heatmaps must represent potential congestion that might result after a generating facility interconnects, not present congestion values. The heatmap must reflect the base case assumptions from the most recent cluster study or cluster restudy. Such studies are not intended to analyze current operational conditions.

152. We next respond to specific objections raised regarding the heatmaps' required level of granularity and scope, requested flexibilities regarding alternatives to the adopted reform, and clarifications regarding which transmission providers are required to provide heatmaps, whether heatmaps are non-binding, and how costs related to the heatmaps requirement are to be recovered. We decline to alter the level of granularity of the heatmaps from that proposed in the NOPR. As Ameren and MISO attest, the five data points proposed in the NOPR are reasonable and sufficient to provide a high-level comparison between several points of interconnection, and therefore to satisfy the goals of this reform.

153. Similarly, consistent with support from ENGIE and SEIA, we adopt the scope of the heatmap requirement proposed in the NOPR, which is the amount of point of interconnection-level interconnection capacity available to be injected at each point of interconnection. We decline to expand the scope of the reporting. We believe that the scope of information that we require transmission providers to publicly post appropriately balances the burdens on transmission providers associated with providing this information with the benefits that might be realized by prospective interconnection customers of having ready access to this information. In response to Dominion, which argues that point of interconnection-level information may not necessarily be useful because, in a networked system, injection at one point of interconnection will affect the capability at other points of interconnection, we agree that injections at one location affect capabilities at other locations. Because the information provided by the transmission provider accounts for full transmission system conditions, interconnection customers should have the information they need to approximate the impact of their potential generating facility on the transmission system. For example, interconnection customers will know if they are proposing to interconnect near constrained regions even if those constraints are not necessarily at the proposed point of interconnection.

154. We decline to require transmission providers to provide additional interconnection information metrics, as requested by some commenters. While we are supportive of increased transparency, we are not persuaded that the benefits of such information would outweigh the burden of tabulating and posting such information.

155. In response to ISO–NE, we decline to require that the heatmap be qualitative only. We find that providing information only qualitatively would not provide interconnection customers information they could use to adequately mitigate risks such as obtaining site control and providing significant deposits to the transmission provider in order to enter the interconnection queue. Thus, providing only qualitative information would be insufficient to address the lack of information available to interconnection customers prior to entering the interconnection queue, which leads to speculative interconnection requests and the problems identified in the need for reform section above.

156. In response to requests for flexibility for transmission providers to identify and post alternative heatmaps, we decline to grant such additional flexibility. In this final rule, we establish a set of required information that transmission providers must publicly provide. We believe that this level of information is what is needed to address the lack of information available to interconnection customers prior to entering the interconnection queue, and therefore remedy the unjust and unreasonable Commission-jurisdictional rates discussed in section II of this final rule. We therefore disagree that the proposal is overly prescriptive, as we believe that the required information is necessary to adequately inform prospective interconnection customers. While we establish a set of required information, in response to comments from Clean Energy Associations that the heatmap may need to be tailored to the services offered by a particular transmission provider, and comments from Bonneville that flexibility would allow transmission providers to determine whether a different methodology would more clearly identify interconnection capability for interconnection customers, we note that if transmission providers find value in providing additional or different information, they may propose such variations on compliance.

157. While we acknowledge that, as a result of the relative interconnection queue sizes and load levels, many transmission providers may have heatmaps that indicate negative interconnection capacity and thereby would simply be “red,” we agree with R Street that providing a visual representation of available interconnection capacity is a best practice and should be required nationwide. Moreover, we find that there is value in providing an all “red” heatmap, as such information will demonstrate to prospective interconnection customers the potential and likely network upgrade-related consequences associated with interconnecting. In other words, an all “red” heatmap sends a valuable signal to interconnection customers regarding where proposed generating facilities may be more or less economic to interconnect prior to entering the interconnection queue.

158. Not only is there value in requiring this information from all transmission providers, we are not persuaded that the burden is so great as to outweigh the benefits for non-RTO/ISO transmission providers and for smaller transmission providers. We acknowledge that RTOs/ISOs are operationally different from their non-RTO/ISO counterparts and that RTOs/ISOs are often more technologically advanced, but the requirement is to reproduce interconnection studies and publish the results in a heatmap. No commenter attests that existing interconnection studies in non-RTO/ISO regions fail to evaluate point of interconnection-level interconnection injection capability. Moreover, we find that by publicly reproducing the results of existing interconnection studies, the heatmaps will address the need for additional interconnection information that exists in both RTOs/ISOs and non-RTOs/ISOs. In other words, we find that there are unjust and unreasonable Commission-jurisdictional rates stemming from the lack of this information for prospective interconnection customers both within and outside of RTOs/ISOs and that this problem must be remedied. Additionally, as Environmental Defense Fund comments, at least one other relatively small transmission owner posts an interactive capacity heatmap for its distribution system comparable to that required by this final rule. Thus, contrary to comments from PPL, we find that smaller transmission providers are able to provide this information to prospective interconnection customers and that the benefits outweigh the burdens.

159. In response to comments from the NY Commission and NYSERDA asking for flexibility to ensure that the information is accessible and understandable, we do not think that such flexibility is needed—we specifically require the information to be contained within an interactive map and posted on transmission providers' websites for this purpose. Contrary to comments from NV Energy, we find that the interactive map is necessary to ensure accessibility and understandability. Absent the map, potential interconnection customers would need to separately map injection points of interconnection to specific locations.

160. In response to comments from PJM and NV Energy requesting flexibility for transmission providers, in lieu of the heatmap, to post congestion information and a link to OASIS with interchange limits and schedules, we decline to grant such flexibility. We find that there are meaningful differences between the results of planning studies, such as those used in the interconnection process, and operational data, like congestion and interchange schedules. Interconnection studies are generally conducted at a specific high-stress point in time for injection at a specific point of interconnection to determine flows across the whole transmission system, while operational data are simply the accumulation of real-time and/or day-ahead results. Thus, posting such operational data would only introduce timing differences and could not substitute for the deliverability analyses conducted in the interconnection processes.

161. In response to NYTOs, we clarify that the information displayed in the heatmap will be illustrative, non-binding, and subject to change. We agree with Tri-State's statement that transmission providers must also caveat that the results do not account for affected system impacts. As we have acknowledged, one primary driver of the available interconnection capacity is the composition of the interconnection customer's cluster, and the heatmap cannot reflect those additional interconnection requests prior to the end of the customer request window.

162. In response to requests to clarify the funding mechanism associated with the heatmap requirement, we clarify that transmission providers, not interconnection customers, are responsible for paying for costs associated with posting the relevant heatmaps required in pro forma LGIP section 6.1. However, we note that, to the extent such costs are properly recoverable in transmission rates consistent with existing Commission accounting and ratemaking policy, such rate treatment is appropriate, and this final rule does not preclude such treatment. We find that this reform will improve overall interconnection queue efficiency to the benefit of transmission customers, consistent with Commission policy.

163. In response to Dominion, which requests clarification in the RTO/ISO context, we clarify that within an RTO/ISO, the heatmap requirement applies to the RTO/ISO, rather than to an individual transmission owner in an RTO/ISO. Thus, transmission owners in RTOs/ISOs are not required to separately post their own visual representations and results.

164. Finally, in response to concerns from WAPA about Federal power marketing agencies having defined budgets and appropriations, we note that transmission providers may explain specific circumstances on compliance and justify why any deviations are either “consistent with or superior to” the pro forma LGIP or merit an independent entity variation in the context of RTOs/ISOs.

2. Cluster Study Process

a. Need for Reform and Interconnection Study Procedures

i. NOPR Proposal

165. To remedy what may now be an unjust and unreasonable interconnection process, the Commission proposed to eliminate the serial first-come, first-served study process in the pro forma LGIP and instead require transmission providers to use a first-ready, first-served cluster study process. The Commission explained that under a first-ready, first-served cluster study process, transmission providers would perform larger interconnection studies encompassing numerous proposed generating facilities, rather than separate studies for each individual interconnection request. Under the NOPR proposal, transmission providers would perform a single cluster study and cluster restudy each year, the particulars of which are further discussed below.

ii. Comments

166. Many commenters support the elimination of the serial study process and the use of the proposed cluster study process. Several commenters assert that the proposed cluster study process will increase efficiency in the interconnection process by diminishing delays and backlogs in processing interconnection queues. Several commenters also believe that the proposed cluster study process will result in fewer interconnection request withdrawals and will discourage speculative interconnection requests. Some commenters assert that, from the interconnection customer's perspective, the proposed cluster study process provides more certainty on timing and cost. Several commenters state that they have already implemented some of the proposed cluster study process reforms.

167. Dominion states that another benefit of moving to the proposed cluster study process is that, if a proposed generating facility is not ready for its cluster study, it can join the next cluster rather than losing its interconnection queue position as occurs in a serial study process. Dominion asserts that, as a result, the proposed cluster study process removes the incentive for an interconnection customer to “reserve a spot in line” for a proposed generating facility is not yet viable. Ohio Commission Consumer Advocate believes that larger interconnection studies encompassing numerous proposed generating facilities would be especially beneficial for interconnection customers with multiple proposed generating facilities in close geographical proximity. Avangrid believes that applying this concept to more regions will lead to a more guided and proactive build-out of new generation and required transmission upgrades.

168. Several commenters argue that the proposed cluster study process will foster renewable resource development and aid in meeting national and/or state clean energy and carbon emissions reduction goals. Puget Sound states that over the past year, it has seen unprecedented numbers of interconnection requests in response to the resource solicitation process and a demand for new renewable energy sources. Puget Sound adds that it has experienced a backlogged interconnection queue, entry of speculative interconnection requests, and uncertainty for interconnection customers relying on higher-queued interconnection requests to complete the interconnection process for their proposed generating facilities to be feasible. Clean Energy States assert that, because wind and solar projects can be relatively small, clustering should help smaller projects share the cost of interconnection studies and upgrades, thereby providing them a viable path through the interconnection process.

169. Some commenters support the use of the proposed cluster study process, so long as it is coupled with additional requirements, some of which the Commission proposed in the NOPR. AEE recommends that the Commission consider further reforms to harmonize study assumptions and more closely link generator interconnection and long-term regional transmission planning processes. R Street states that the Commission should consider an interconnection study approach that uses transparent, realistic study assumptions. Clean Energy Associations argue that certain conservative assumptions—such as NERC standard TPL–001's extreme contingency cases—can lead to the identification of unreasonably large and costly upgrades. Clean Energy Associations also assert that the Commission should make clear in its final rule whether moving from a serial study process to a cluster study process should or should not be accompanied by any change in the interconnection standards and assumptions used in those studies. Ameren generally supports the proposal to move to a first-ready, first-served cluster study process, but argues that this move without other reforms is unlikely to clear the interconnection queue backlog. NERC states that its support for cluster studies is predicated on parallel enhancements for model validation with actual installed equipment and a true-up prior to interconnection.

170. Other commenters express some concern with the move to the proposed cluster study process. For example, Enel states that cluster studies increase interdependence between interconnection requests, with a greater likelihood that multiple interconnection customers are responsible for a single network upgrade, which creates a paradigm where one interconnection customer's actions, such as withdrawing from the interconnection queue, can have drastic impacts on many other interconnection customers. Enel also asserts that, while the proposed cluster study process has some benefits, recent cluster studies are resulting in significant regional transmission constraints with very high associated network upgrade costs and long construction schedules. Enel contends that the proposed cluster study process can still reduce interdependency and succeed if there are much smaller, more local, regional groupings of interconnection requests in cluster studies and lower minimum impact thresholds for determining network upgrades. Enel says the Commission should adopt these two practices if it adopts the proposed cluster study process.

171. Some commenters note that, where the demand for generator interconnection significantly exceeds the available supply of interconnection access, the NOPR's proposed cluster study process and interconnection queue management reforms alone may be insufficient to address the backlog of interconnection requests. Other commenters assert that under these circumstances, some form of interconnection request prioritization may be needed to effectively allocate scarce interconnection access to the lowest-cost or highest-value proposed generating facilities.

172. Several commenters state that, while they support the use of the proposed cluster study process, the Commission should allow variation among transmission providers in the makeup of the study process. Some commenters argue that regional variations should be permitted, especially where transmission providers have already implemented a first-ready, first-served cluster study process. Environmental Defense Fund, on the other hand, argues that the Commission should provide limited flexibility for transmission providers to demonstrate in their compliance filing that a preexisting cluster study process is substantially similar to the process established in the Commission's final rule.

173. Pacific Northwest Utilities and CREA and NewSun urge the Commission to allow flexibility for transmission providers to design the cluster study process to implement either a single-phase or two-phase cluster study process. Pacific Northwest Utilities contend that requiring full commercial readiness in a single-phase study process, as proposed in the NOPR, significantly restricts an interconnection customer's ability to enter the interconnection queue. Pacific Northwest Utilities argue that a two-phase approach provides greater accessibility to some interconnection customers by not requiring commercial readiness for entry into the first phase. According to Pacific Northwest Utilities, this is because all interconnection customers who have attained site control will have information about the network upgrades needed to meet the interconnection requirements of the cluster and the expected cost responsibility for each interconnection customer in the cluster. Pacific Northwest Utilities aver that this information reduces the potential for interconnection customers to withdraw from phase two and, therefore, should reduce the need for additional restudies that might slow or stall the interconnection process.

174. Some commenters argue that it may not be appropriate to mandate the proposed cluster study process for every transmission provider as cluster studies can be complex, expensive, and not the most efficient or necessary approach for all proposed generating facilities or circumstances. Some commenters generally support the use of cluster studies if transmission providers retain discretion to use the existing serial study process. Vermont Electric and Vermont Transco notes that not all interconnection requests need to be studied in a cluster format, and that this has frequently been the situation in New England, where interconnection queue bottlenecks have historically been locational and driven by state clean energy procurement efforts. ISO–NE requests that the Commission consider a more targeted approach for clusters triggered by geographic or electric proximity among interconnection requests, rather than a blanket clustering process for all interconnection requests. Instead of mandating a clustering in all regions, ISO–NE contends that the Commission consider the expanded use of clustering in areas with larger concentrations of proposed generating facilities, while allowing use of serial studies for customers seeking to interconnect in areas with low activity, where serial studies could proceed relatively quickly.

175. National Grid asks for clarification as to whether the proposed cluster study process encompasses energy or capacity interconnection service requests, or both.

176. Some commenters contend that the Commission should encourage relevant state entities to consider the efficient coordination of their state-jurisdictional interconnection process with Commission-jurisdictional interconnection processes. Avangrid argues that sizable distributed energy resources should be aggregated and included in the broader cluster study of large and small Commission-jurisdictional generating facilities. Pine Gate suggests the Commission require transmission providers, on compliance, to “document how they will ensure that any serial processes for state-jurisdictional interconnection agreements will interact with the required cluster study process” and explain how the interconnection queue position of qualifying facilities (QFs) will not be prejudiced by the transition to a cluster study process.

iii. Commission Determination

177. We adopt the NOPR proposal to revise the pro forma LGIP and pro forma LGIA to make cluster studies the required interconnection study method. We find that the move from the serial study process in the pro forma LGIP to the proposed cluster study process, alongside the other reforms adopted in the final rule, will remedy the unjust and unreasonable rates discussed in section II of this final rule. Specifically, we believe that this reform will help remedy the problems of the existing interconnection process for large generating facilities in several ways. First, the cluster study process will increase efficiency because transmission providers can perform larger interconnection studies encompassing many proposed generating facilities, rather than separate studies for each individual interconnection customer. The cluster study process will provide greater certainty to interconnection customers, regarding both the timing of studies and the magnitude of network upgrade costs. Coupled with the increased financial commitments and requirements to enter the interconnection queue, such as a demonstration of site control, as discussed further below, the cluster study process will also disincentivize interconnection customers from submitting interconnection requests for speculative generating facilities and ensure that ready, more viable proposed generating facilities can proceed through the study process. We also expect that the cluster study process will result in fewer withdrawals because conducting a single cluster study and cluster restudy will minimize delays that arise from proposed generating facility interdependencies under the existing serial study process, in which lower-queued interconnection customers can strategically and monetarily benefit from network upgrades and associated costs borne earlier in the interconnection process by higher-queued interconnection customers. We further expect that the cluster study process will minimize the risk of cascading restudies when an interconnection customer withdraws.

178. We are not persuaded by Enel's request that the Commission adopt smaller, more local regional groupings of proposed generating facilities in interconnection studies and lower minimum impact thresholds for determining upgrades. We find the record insufficient to support these additional requirements. We also decline requests to allow transmission providers to either continue to use a serial study process or to create a parallel serial study process because, as discussed further below, we find that establishing in the pro forma LGIP a separate interconnection process outside the cluster study process could detract from transmission providers' efforts to efficiently process cluster studies, and would be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner.

179. In response to requests to allow variation in how clusters are formed, we emphasize that the reforms to the pro forma LGIP adopted in this final rule do not prescribe how transmission providers should form clusters.

180. In response to National Grid, we decline to clarify whether the proposed cluster study process encompasses energy or capacity interconnection service requests. “Energy interconnection requests” and “capacity interconnection requests” are not defined terms in the pro forma LGIP, and we decline to define them here. We do not believe that such detail is needed for transmission providers to implement the reforms adopted herein.

181. In response to Avangrid, we encourage relevant state entities to consider the efficient coordination of their state-jurisdictional interconnection processes with Commission-jurisdictional interconnection processes.

182. In response to requests to create some form of generating facility prioritization, we are neither persuaded that such prioritization is needed, nor do we have an adequate record to dictate how generating facility prioritization should be implemented in a just, reasonable, and not unduly discriminatory or preferential manner.

183. Finally, we decline to adopt the following proposals advocated by some commenters because they are outside the scope of this proceeding: (1) AEE's request that the Commission consider further reforms to more closely link generator interconnection and long-term regional transmission planning process; (2) Cypress Creek's request to require transmission providers to allow interconnection customers to seek energy-only injection as a default and provide a subsequent process (needed to address capacity-market constructs) by which an interconnection customer can add firm rights; (3) Pine Gate's suggestion for the Commission to require transmission providers to document on compliance how they will ensure that any serial study processes for state-jurisdictional interconnection agreements will interact with the required cluster study process and explain how the interconnection queue position of QFs will not be prejudiced by the transition to a cluster study process; and (4) AEE's and Clean Energy Associations' request that the Commission also harmonize study standards and assumptions. We find that these proposals are outside the scope of this proceeding as the Commission did not propose specific reforms on these issues, and we find an inadequate record to fully consider or adopt these requested changes.

b. Defined Terms in the Pro Forma LGIP and Pro Forma LGIA

i. NOPR Proposal

184. In the NOPR, the Commission proposed to add several new defined terms (such as cluster, cluster study process, and cluster request window) and to revise several defined terms (such as stand alone network upgrade and material modification) in section 1 of the pro forma LGIP and article 1 of the pro forma LGIA.

ii. Comments

185. Starting with the proposed definition of stand alone network upgrade, a few commenters support the Commission's proposal. Tri-State suggests adding to the definition of stand alone network upgrade that a transmission provider's interconnection facilities may be shared by more than one generating facility in a given cluster study, including a co-located resource.

186. Other commenters oppose the proposed revisions to the definition of stand alone network upgrade. Clean Energy Associations argue that the proposal to modify the definition of stand alone network upgrade to restrict it to those needed only for a single interconnection customer is problematic and counterproductive. Clean Energy Associations contend that allowing interconnection customers the right to self-build interconnection facilities and stand alone network upgrades since Order No. 845 has served as a welcome relief valve to transmission providers' lengthy construction timelines, giving customers increased control of both the time and cost for building these upgrades. As an alternative, Clean Energy Associations suggest an approach similar to ISO–NE's for network upgrades that are needed for multiple interconnections where an independently developed elective network upgrade, if selected by all of the interconnection customers in the cluster that require the network upgrade, can take the place of the incumbent-built cluster enabling network upgrade.

187. Pine Gate states that in its experience, after Order No. 845, transmission providers have taken a very narrow view of the facilities that constitute stand alone network upgrades, and thus the potential for interconnection customers to exercise the option to build has not been fully realized. Pine Gate asserts that the proposed change would further restrict the opportunity for interconnection customers to exercise the option to build, exacerbate construction delays, and result in a lack of competition to construct stand alone network upgrades, ultimately harming consumers. Pine Gate therefore recommends that the Commission not modify the definition of stand alone network upgrade as proposed and instead grant the interconnection customer with the largest projected impact on a potential stand alone network upgrade facility the ability to elect the option to build with priority falling to each interconnection customer based on the next largest impact on the stand alone network upgrades.

188. Enel argues that the Commission should not adopt the proposed substantive revisions to the definition of stand alone network upgrades and should instead expand the definition of stand alone network upgrades to include upgrades to an existing transmission facility which involves a transmission line or substation being entirely rebuilt. Enel offers suggestions for implementing a third-party option that would give interconnection customers more control over the cost and schedule of larger network upgrades, resolving a frequent barrier to bringing needed generating facilities online. To that end, Enel states that pro forma LGIA article 5.1 could be modified to specify that the option to build is only eligible for stand alone network upgrades funded by a single interconnection customer, while the proposed third-party option could be used for all stand alone network upgrades, including line and substation rebuilds.

189. Moving to the proposed definition of material modification, some commenters support the Commission's proposal. Ørsted urges the Commission to ensure that under the newly proposed definition of material modification, any changes to a proposed generating facility that occur on the generating facility side of the point of interconnection that do not result in changes to the electrical output at the point of interconnection or the electrical characteristics of the generating facility's interconnection: (1) will not be deemed to be a material modification; and (2) will not result in the termination of the interconnection customer's queue position.

190. Ameren suggests that the Commission consider clarifying the proposed definition of material modification, so that cost and timing are factors to be considered in addition to when the transmission provider determines changes to the point of interconnection are otherwise material ( e.g., from an electrical standpoint). Ameren states that the Commission may want to consider whether the change should only be triggered by a change to the point of interconnection or whether a change to the inverters or other pieces of equipment in the interconnecting generating facility, which could require other upgrades, should also result in the determination of a material modification.

191. EPSA asks the Commission to be clearer in determining a standard definition of a material modification. EPSA argues that, at minimum, the Commission should direct each RTO/ISO or each NERC region to establish clear criteria for the evaluation of material modifications.

iii. Commission Determination

192. We adopt the proposed revisions to section 1 of the pro forma LGIP and article 1 of the pro forma LGIA to revise and add several defined terms. Specifically, we adopt the proposed revisions to the definition of stand alone network upgrade to clarify that, for a network upgrade to be eligible for treatment as a stand alone network upgrade, the network upgrade must be required for only one interconnection customer and must meet the other existing requirements in the definition of stand alone network upgrade. We address further modifications to the definition of stand alone network upgrade below where discussing network upgrade cost allocation (section III.A.4.c of this final rule). We also adopt the proposed revisions to the definition of material modification, which account for the equal interconnection queue position of proposed generating facilities that are part of the same cluster. We also modify the NOPR proposal to define interconnection facilities study report.

193. With respect to the definition of stand alone network upgrade, in response to Clean Energy Associations' concerns, we note that we do not remove the right to self-build interconnection facilities and stand alone network upgrades established in Order No. 845. Rather, we are explicitly maintaining the status quo, which is to say that, under the existing pro forma LGIP, there is no potential for a stand alone network upgrade to be shared by more than one interconnection customer. With the revision proposed in the NOPR and adopted here, we are ensuring that within the structure of a cluster study process adopted in this final rule, stand alone network upgrades continue to be defined as only those required for a single interconnection customer, and therefore the option to build is only available for a single interconnection customer. Were we to not adopt this revision, multiple interconnection customers could potentially attempt to construct the same stand alone network upgrades, leading to confusion and potentially lengthy negotiations and/or disputes regarding which interconnection customer had the right to construct the stand alone network upgrade. Additionally, with regard to Clean Energy Associations' request that the Commission consider an approach similar to ISO–NE's for certain upgrades that are needed for multiple interconnections, we decline to adopt this approach because it is outside the scope of this proceeding. We are not proposing in this proceeding to modify the pro forma LGIP to address the cost responsibility and division of work between interconnection customers that may share cost allocation for stand alone network upgrades.

194. Similarly, Tri-State, Pine Gate, and Enel argue that the Commission should expand the definition of stand alone network upgrade, thereby expanding the right of interconnection customers to build certain network upgrades. These requests are outside the scope of this proceeding, which is not proposing to modify the scope of interconnection customers' option to build certain stand alone network upgrades but rather is only revising definitions insofar as is necessary to implement reforms adopted elsewhere in this final rule. For the same reason, we decline to expand the definition of material modification, as Ørsted, Ameren, and EPSA request.

c. Definitive Point of Interconnection

i. NOPR Proposal

195. In the NOPR, the Commission proposed to add new section 3.1.2 to the pro forma LGIP and therein to require interconnection customers to select a definitive point of interconnection to be studied no later than the execution of the cluster study agreement. The Commission also proposed that, upon mutual agreement, the transmission provider may make reasonable changes to the requested point of interconnection to facilitate efficient generator interconnection of clustered interconnection requests at common points of interconnection.

ii. Comments

196. MISO supports the Commission requiring the selection of a definitive point of interconnection when executing the cluster study agreement; however, MISO encourages the Commission to require the selection of a definitive point of interconnection even earlier, as part of the interconnection request. MISO notes that requiring an earlier selection of the definitive point of interconnection will assist in interconnection queue processing, as a transmission provider would not be able to begin modeling work if the interconnection customer is permitted to wait until a later point in time to select its definitive point of interconnection. MISO further argues that the definitive point of interconnection (even if subject to change) should be selected prior to any scoping meeting. MISO also supports the proposed language that limits the ability of the interconnection customer to change its point of interconnection after the submission of interconnection request.

197. Other commenters do not support the Commission's proposal to require a definitive point of interconnection when executing the cluster study agreement. ACE–NY supports making the demonstration of a feasible point of interconnection a requirement for a generating facility to move into the facilities study phase of the generator interconnection process.

198. Pine Gate and CREA and NewSun assert that the Commission should modify its proposal to permit interconnection customers to request alternative points of interconnection. Pine Gate argues that the Commission should permit interconnection customers to request a study of a primary and secondary point of interconnection within one or two electrical buses, then select a point of interconnection restudy after receiving initial cluster study results. Similarly, CREA and NewSun assert that the Commission should permit alternative points of interconnection, and collective points of interconnection for proposed generating facilities in a cluster ( e.g., those that could connect to a single substation), to be proposed and studied, at least through the system impact study in order to obtain more complete cost information.

199. Enel suggests that, in the second paragraph of proposed section 3.1.2 of the pro forma LGIP, the Commission should change the word “make” to “propose” in the following quoted language: “For purposes of clustering Interconnection Requests, Transmission Provider may make reasonable changes to the requested Point of Interconnection.” Enel explains that this would clarify that any such changes can only be made with the consent of the interconnection customer, as specified in the proposed new final sentence to that paragraph.

iii. Commission Determination

200. We adopt the proposed section 3.1.2 of the pro forma LGIP insofar as it requires an interconnection customer to select a definitive point of interconnection to be studied when executing the cluster study agreement, with one modification discussed below.

201. Requiring interconnection customers to select a definitive point of interconnection when executing the cluster study agreement allows the interconnection customer to submit its interconnection request with a proposed point of interconnection, participate in the scoping meeting during the customer engagement window, and receive feedback on its proposed point of interconnection. We believe that this strikes the right balance between allowing for flexibility and potential adjustments to the point of interconnection, based on discussion with the transmission provider and the transmission provider's detailed knowledge of its transmission system, and providing transmission providers with the information necessary to conduct the cluster study, thus reducing the potential for restudies that would be required if interconnection customers could change their points of interconnection later in the process.

202. We decline to: (1) require that the definitive point of interconnection be selected earlier ( e.g., as part of the interconnection request); (2) only require that the definitive point of interconnection be selected later ( e.g., at the facilities study phase); or (3) permit interconnection customers to submit multiple alternative points of interconnection for study in a single interconnection request. We believe that requiring the selection of a definitive point of interconnection earlier in the cluster study process, as suggested by MISO, would deprive interconnection customers of information that could aid in their selection. Similarly, we believe that requiring the selection of a definitive point of interconnection after the cluster study, as suggested by ACE–NY, or allowing multiple points of interconnection to be studied before the interconnection customer is required to select the definitive point of interconnection, as suggested by Pine Gate and CREA and NewSun, fails to take into account the fact that, if an interconnection customer changes the definitive point of interconnection after the cluster study, it will likely impact the study results of the other interconnection customers in the cluster and could lead to restudies and delays. We do not believe that the alternatives suggested by commenters would remedy the unjust and unreasonable status quo described in section II of this final rule.

203. Finally, we agree with Enel's suggestion to change the word “make” to “propose” in pro forma LGIP section 3.1.2. We modify that section to state: “For purposes of clustering Interconnection Requests, Transmission Provider may propose reasonable changes to the requested Point of Interconnection.” We agree that this clarifies that any such changes can only be made with the consent of the interconnection customer.

d. Cluster Request Window and Customer Engagement Window

i. NOPR Proposal

204. In the NOPR, the Commission proposed to add new section 3.4.1 (Cluster Request Window) to the pro forma LGIP to require interconnection customers to submit an interconnection request during the cluster request window—a 45-calendar day period with the start date to be determined by each transmission provider (with the annual start date for the transmission provider's cluster request window included in its LGIP). The transmission provider would consider all interconnection requests accepted during this period to have equal queue priority for purposes of the cluster study. The Commission also proposed to add in pro forma LGIP section 3.1.1 (Initial Study Deposit) a non-refundable application fee of $5,000 to be submitted with the interconnection request. The Commission further proposed that interconnection customers must cure deficient interconnection requests within 10 business days after receipt of notice from the transmission provider, but no later than the close of the cluster request window.

205. The Commission also proposed to add new pro forma LGIP section 3.4.5 (Customer Engagement Window), which provides that, following the close of the cluster request window, the transmission provider begins a 30-calendar day customer engagement window. New pro forma LGIP section 3.4.5 also requires the transmission provider to post within the first 10 business days following the close of the cluster request window a list of interconnection requests for that cluster.

ii. Comments

206. Clean Energy Associations support the proposal to require interconnection customers to submit interconnection requests during the cluster request window. MISO supports the Commission requiring a definitive application deadline as part of the implementation of cluster studies, and equal interconnection queue priority for all interconnection requests submitted prior to that deadline, but does not see an intrinsic value in a defined application start time. MISO supports granting interconnection customers flexibility to submit an interconnection request earlier than the beginning of a cluster request window. Noting that, under proposed pro forma LGIP section 3.4.5, interconnection requests that are deemed valid during the customer engagement window are placed into the cluster study, Southern proposes that if an interconnection request is not deemed valid, the interconnection request should be withdrawn from the interconnection queue.

207. MISO expresses concern that the timelines listed in the customer engagement window for posting information are impractical. MISO asserts that the Commission should not require a posting so near to the close of the cluster request window because the transmission provider must devote its resources to reviewing the interconnection requests for deficiencies. MISO contends that this information would only be useful at this time to interconnection customers with speculative interconnection requests that may be trying to determine if their proposed generating facility is economically viable and that may be trying to identify a point of interconnection change to increase the viability of their interconnection requests.

208. MISO argues that the Commission should not require any informational posting pertaining to an interconnection request prior to the interconnection customer's finalization of the interconnection request because a definitive point of interconnection has not yet been selected. MISO highlights that the proposed pro forma LGIP section 3.4.5 requires the transmission provider's OASIS posting to include “(3) the station or transmission line where the interconnection will be made.” However, MISO notes that an interconnection customer is not required to select a definitive point of interconnection until the end of the customer engagement window. As such, MISO contends that the posting requirement is impossible if the transmission provider is required to post the point of interconnection. MISO argues that the Commission should not require any posting until a reasonable period after the interconnection customer is required to select its definitive point of interconnection and the information is complete, such as when the customer engagement window is completed and cluster studies are about to begin.

209. Regarding the makeup of the cluster, Clean Energy States assert that the cluster study process should allow for changes in the makeup of the cluster, and that the study process may identify ways to improve a cluster to provide better performance for the transmission system, such as by adding or subtracting certain interconnection requests from the cluster. Clean Energy States assert that a transmission provider should be able to modify the cluster in response to interconnection customer changes or study findings without threatening the interconnection customer's queue priority or paying penalties.

210. EPSA argues that the final rule should specify that transmission providers are required to work with interconnection customers during the customer engagement window and study agreement negotiation in a manner that is fair and equitable regarding the study models to be used, data verification, and stakeholder engagement—regardless of the planning or procurement method used by the prospective interconnection customer.

211. Enel recommends that the Commission consolidate the interconnection request and cluster and facilities study agreements into a single study agreement to be submitted at the time of application. Enel also recommends that the Commission include language in the pro forma LGIP that provides that transmission providers will not post information about interconnection requests proceeding through or withdrawing from the interconnection queue until all interconnection requests submitted within a cluster request window successfully meet their milestone requirements to proceed, withdraw, or fail to cure their breach within the specific cure period.

212. Regarding the length of the cluster request window, some commenters support the proposed 45-calendar day time frame for the cluster request window. Although it supports the 45-calendar day time frame, Eversource suggests the Commission add more structure to this element of its proposal by establishing rules that enable potential interconnection customers to be informed of when the request windows will be open and how to prepare to apply.

213. Other commenters argue that the proposed 45-calendar day time frame for the cluster request window is too short and should be increased to 60 calendar days. ISO–NE states that, based on its experience implementing its forward capacity market process, each of the cluster study windows proposed in the NOPR should be extended to help ensure an efficient cluster study process. Pine Gate also argues that a longer cluster request window would reduce the burden on transmission providers by providing more time to administer their deficiency notice processes. Pine Gate explains that, for larger interconnection customers that may be developing numerous interconnection requests for multiple transmission providers, overlapping cluster request windows are likely. Additionally, Pine Gate contends that, as contemplated by the NOPR, it is likely that increased requirements and additional information for interconnection customers will be due at the time of interconnection queue entry ( e.g., the complex modeling required to be submitted) and burdensome to accommodate in the proposed time frame.

214. On the other hand, some commenters argue that a shorter cluster request window is appropriate. CAISO argues that longer cluster request windows result in low quality requests because interconnection customers have more time within the window to fix their submissions. CAISO contends that its use of a shorter 15-day interconnection request completeness window followed by a longer validation and scoping meeting window have significantly improved interconnection request quality and the speed with which CAISO processes requests. Similarly, Tri-State recommends that the cluster request window be shortened because, based on its experience, most interconnection requests submitted in the cluster request window are received the last two days of the request window.

215. Regarding the requirement for correcting deficiencies in the proposed pro forma LGIP section 3.4.4 (Deficiencies in Interconnection Request), Tri-State argues that requiring interconnection customers to provide any requested information within 10 business days after receiving notice of deficiencies in the interconnection request, but no later than the close of the cluster request window, does not take into account that most requests are not submitted until the last day of the cluster request window.

216. Regarding the number of cluster request windows opened each year, a couple of commenters argue that there should be more than one cluster request window per year. Clean Energy States assert that, because presumably there will be fewer generator interconnection studies to be done, transmission providers should provide opportunities more frequently ( e.g., quarterly) for interconnection customers to submit interconnection requests. Environmental Defense Fund argues that the Commission should require that the cluster request windows occur bi-annually, rather than once a year, to reduce the delay caused by missing a cluster request window while still covering a large enough time period that a number of interconnection requests will be included in each cluster.

217. Southern generally agrees with the Commission that a cluster study process, including the individual facilities study, should be completed within a year, but recommends eliminating unnecessary delays, such as multiple, overlapping clusters, by only permitting one cluster study at a time ( i.e., that a new cluster should not commence until the previous cluster has been completed). According to Southern, under this format, an annual cluster study can be performed because the previous cluster study process has been completed. Southern asserts that overlapping cluster study processes will not help end interconnection queue backlogs and uncertainty, but rather add to them.

218. Regarding the length of the customer engagement window, Clean Energy Associations support the proposed 30-calendar day time frame for the customer engagement window as a baseline. A number of commenters argue that the proposed 30-calendar day customer engagement window is too short and recommend a longer window. Duke Southeast Utilities argue that, based on experience with Duke Carolinas Utilities' cluster study process, which includes a 60-calendar day customer engagement window, the proposed 30-calendar day customer engagement window may not provide sufficient time to facilitate robust engagement. Duke Southeast Utilities therefore urge the Commission to adopt a 60-calendar day customer engagement window. Xcel describes PSCo's recent interconnection queue reform, which extended the customer engagement window to 95 calendar days to allow interconnection customers additional time to reevaluate their readiness in a way that includes other customers.

219. ISO–NE suggests a 90-calendar day customer engagement window. In addition, ISO–NE suggests that the Commission clarify that transmission providers may withdraw interconnection requests for which the models and data do not meet the requirements following the customer engagement window in order to improve efficiency. ISO–NE further asks that the Commission recognize the role of the participating transmission owners in performance of interconnection studies and build time into the cluster study time frames that accounts for this coordination.

220. Indicated PJM TOs argue that there should be a 30-calendar day window after the date that the cluster request window closes, and between the time the transmission provider posts the interconnection cases for the cluster study and the cluster study commences, during which interconnection customers qualified to receive CEII information have the opportunity to conduct their own studies with the transmission provider's base case and the new interconnection service requests. Indicated PJM TOs assert that during this time, interconnection customers should be able to withdraw their interconnection request with minimal financial impact.

221. APS states that multiple customers requesting individual scoping meetings could place a significant burden on the transmission provider to schedule several meetings under a condensed time frame if the customer engagement window remains 30 calendar days. For example, APS states that, assuming all notifications of valid interconnection requests are made by the time the customer engagement window starts, the interconnection customer has 15 business days to request an individual meeting and, if an interconnection customer uses all 15 business days, that is a minimum 21 calendar days out of the total 30 calendar days of the overall customer engagement window. APS contends that this leaves nine calendar days at most ( i.e., no more than seven business days) to schedule an individual customer meeting, which could be less if there are holidays occurring within the customer engagement window.

222. Similarly, Tri-State argues that the proposed 30-day customer engagement window is not sufficient to meet the purpose of the customer engagement window and recommends it be extended to allow adequate time to cure deficiencies and hold individual scoping meetings. Tri-State argues that a 75-day customer engagement window would give interconnection customers an opportunity to: (1) assess the viability of their proposed generating facilities before committing to the interconnection process and subjecting themselves to a withdrawal penalty; and (2) cure deficiencies in their interconnection requests.

iii. Commission Determination

223. We adopt the proposed new pro forma LGIP section 3.4.1 (Cluster Request Window), which provides that interconnection customers must submit an interconnection request during a specified period—the cluster request window—a 45-calendar day period with the start date to be determined by each transmission provider. We also adopt the non-refundable $5,000 application fee required to be submitted with the interconnection request. We also adopt the requirement that interconnection customers provide requested information within 10 business days of receiving an interconnection request deficiency notice but no later than the close of the cluster request window, as proposed and adopted in new pro forma LGIP section 3.4.4 (Deficiencies in Interconnection Request), but we modify that section to clarify the timeline for curing deficiencies. We modify the proposed new pro forma LGIP section 3.4.5 (Customer Engagement Window) and extend the customer engagement window from 30 days to 60 calendar days.

224. To ensure clarity for both interconnection customers and transmission providers, based on the record, we believe that 45 calendar days is a sufficient window to adequately notify prospective interconnection customers of the formation of a new cluster but not so long as to delay the processing of the interconnection queue.

225. Contrary to commenters' assertions, we are not persuaded to extend the cluster request window. We do not believe that more time is needed for transmission providers to work with interconnection customers that submitted invalid interconnection requests to cure deficiencies, particularly given the limit we adopt on the time for such additional information to be submitted by interconnection customers, and because the start date of the cluster request window will be included in the transmission provider's LGIP for prospective interconnection customers. We similarly do not believe that shortening the cluster request window would result in fewer “low quality” interconnection requests, as CAISO argues. Given the package of reforms adopted in this final rule, we expect fewer speculative interconnection requests and that interconnection customers will be more likely as a result of this final rule to submit interconnection requests for proposed generating facilities that they believe are viable and ready to move forward in the interconnection process.

226. As for Tri-State's concern about the requirement for correcting deficiencies in new pro forma LGIP section 3.4.4 (Deficiencies in Interconnection Request), we clarify that the 10-business day window is the maximum time allowed to submit a response. This means that an interconnection customer that submits its interconnection request more than 10 business days before the close of the cluster request window will have a full 10 business days to submit a response, whereas an interconnection customer that does not submit its interconnection request until less than 10 business days before the close of the cluster request window will have however many days remain in the cluster request window to respond to any deficiencies. Accordingly, we modify pro forma LGIP section 3.4.4 to provide that if the interconnection customer does not respond before the deadline: (1) the interconnection request is immediately deemed withdrawn (without the cure period provided under pro forma LGIP section 3.7); (2) the application fee is forfeited to the transmission provider; and (3) because the cluster study has not commenced, the study deposit and commercial readiness deposit are returned to the interconnection customer.

227. We decline to adopt revisions to the pro forma LGIP to require biannual or quarterly cluster study windows, as suggested by Clean Energy States and Environmental Defense Fund. Based on the record, we are not convinced that mandating multiple cluster request windows per year will result in a more efficient cluster study process, especially considering the various sizes of transmission provider footprints and interconnection queues. As we adopt an annual cluster study process, an annual cluster request window will allow transmission providers to dedicate resources to the cluster request window only once per year, dedicating their resources to the remainder of the cluster study process for the rest of the year. We also are not convinced by Environmental Defense Fund's concern with interconnection customers missing a cluster request window, as the date of the start of the cluster request window will be in each transmission provider's LGIP, providing sufficient notice for prospective interconnection customers to prepare required application materials accordingly. We do not believe that additional rules are needed to govern how transmission providers will inform interconnection customers about the cluster request window.

228. We disagree with Southern's suggestion that the cluster study process should only permit transmission providers to conduct one cluster study at a time ( i.e., eliminating the possibility of conducting multiple cluster studies at any time). Prohibiting the transmission provider from conducting overlapping cluster studies, in the instance where it is necessary to process cluster subgroups or to process delayed studies, would delay the interconnection process for interconnection customers. We therefore find that this suggestion would contribute to more backlogs and uncertainty, as delays to any cluster study would significantly delay cluster studies for all remaining interconnection requests in an interconnection queue and would be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. Transmission providers with the capacity to conduct multiple cluster studies at a given time should be permitted to do so to facilitate more effective and efficient interconnection processes.

229. In response to MISO's concern about posting requirements close to the conclusion of the cluster request window, we reiterate that we are extending the length of the customer engagement window from the proposed 30 calendar days to 60 calendar days, which will allow transmission providers a total of 60 calendar days from the close of the cluster request window to post the list of interconnection requests for that cluster.

230. MISO argues that the Commission should not require any OASIS posting prior to the interconnection customer's finalization of the interconnection request because a definitive point of interconnection would have not yet been selected. While we recognize MISO's concern about transmission providers posting interconnection request information on OASIS that may later change, we find that providing as much information as possible to interconnection customers early in the customer engagement window provides important transparency to improve interconnection queue processing. Providing information about other interconnection requests that may be studied within the same cluster to interconnection customers considering whether to execute a cluster study agreement and to continue with the cluster, may help them determine the viability of their proposed generating facilities, making it less likely that interconnection customers will withdraw later in the cluster study process, triggering delays and restudies and the associated problems discussed in section II of this final rule.

231. We disagree with Clean Energy States' assertion that a cluster should be able to be modified in response to interconnection customer changes or study findings without threatening the interconnection customer's relative queue priority or paying penalties. Any interconnection customer that submits a valid interconnection request during the customer request window will become part of the cluster, if the interconnection customer chooses to execute a cluster study agreement by the end of the customer engagement window. The transmission provider may not modify the makeup of the cluster or pick and choose which interconnection customers to keep in the cluster in the way Clean Energy States describes. We also note that interconnection customers can request a modification assessment pursuant to section 4.4 of the pro forma LGIP.

232. Regarding the customer engagement window, we adopt the NOPR proposal to add a new section 3.4.5 (Customer Engagement Window) to the pro forma LGIP, which provides that, following the close of the cluster request window, the transmission provider begins a customer engagement window. Additionally, we modify the proposal to extend the customer engagement window from 30 calendar days, as proposed, to 60 calendar days. Under this provision, the transmission provider must post new cluster information on OASIS with details of each interconnection request for that cluster, including information on the amount of interconnection service and the location of the proposed generating facility, within the first 10 business days of the customer engagement window. While we extend the customer engagement window from 30 calendar to 60 calendar days, we retain the proposed 10 business day deadline by which the transmission provider must post new cluster information on OASIS. We find that it is more beneficial for interconnection customers to have this information as early as possible, such that they are able to assess the composition of the cluster and make informed choices moving forward with their interconnection requests earlier rather than later in the customer engagement window. Further, during the customer engagement window, an interconnection customer may withdraw its interconnection request without penalty.

233. We extend the customer engagement window to 60 calendar days in response to numerous commenters' arguments that 30 calendar days is insufficient to adequately engage with interconnection customers in a cluster, including based on experience implementing a similar cluster study process to that we require as part of this final rule. By extending the customer engagement window, we provide transmission providers with additional time to conduct individual meetings with interconnection customers that submitted interconnection requests within the cluster request window, lessening the burden on transmission providers, particularly larger transmission providers such as RTOs/ISOs. At the same time, we provide interconnection customers with more time to consider information collected during this period of engagement with the transmission provider—including the makeup of the cluster—and assess the continued viability of their proposed generating facilities before withdrawal of the interconnection request will incur a penalty. For example, the interconnection customer can assess the expected costs of potential network upgrades and the impact of those costs on the viability of its proposed generating facility in the context of the size and location of other interconnection requests in the cluster. Interconnection customers will have 46 calendar days to consider the posted information (which must be posted within 10 business days after the start of the customer engagement window). Not only will this longer time period for interconnection customers to consider whether to withdraw their interconnection requests prior to the start of the cluster study save interconnection customers' resources by avoiding future penalties, but it will also result in more efficient interconnection queue processing with fewer withdrawals later in the cluster study process—withdrawals that can trigger restudies and cause the problems discussed in section II of this final rule.

234. We reject Southern's suggestion that if an interconnection request is not deemed valid, the interconnection request should be withdrawn from the interconnection queue. Under new section 3.4.5 of the pro forma LGIP, any interconnection requests not deemed valid at the close of the customer engagement window will not be included in the cluster. This provision is designed to ensure that interconnection customers and transmission providers have sufficient time to conduct scoping meetings and to discuss and comprehensively evaluate whether interconnection requests are fully valid during the customer engagement window. We find that forced withdrawals prior to the close of the customer engagement window could result in potentially valid interconnection requests being rejected prior to allowing for interconnection customers and transmission providers to discuss alternative interconnection options, exchange information that could impact such options, and conduct due diligence informed by information discussed during the customer engagement window per the provisions set forth in new pro forma LGIP section 3.4.6 detailing scoping meetings.

235. In response to EPSA, we note that transmission providers and interconnection customers should always work in a manner that is fair and nondiscriminatory, including during the customer engagement window and study agreement negotiation.

236. We decline to adopt MISO's suggestion that transmission providers allow interconnection customers to submit an interconnection request prior to the beginning of the cluster request window. We note that the cluster request window is specifically designed to structure when transmission providers should expect interconnection customers to submit interconnection requests for assessment. We find that allowing interconnection request submission prior to the cluster request window may be burdensome to transmission providers, who would have to dedicate staff and resources towards assessing the viability of interconnection requests before the designated request window opening, instead of concentrating their resources towards the prior stage of the interconnection process.

237. We agree with Enel's recommendation that the Commission include language in the pro forma LGIP that, in the cluster study process, the transmission provider will not post detailed information about interconnection requests proceeding or withdrawing until all interconnection requests successfully meet their milestone requirements to proceed, withdraw, or fail to cure their breach within the specific cure period. We note that transmission providers are required to post this information at the conclusion of the cluster request window, at which point interconnection customers must provide significant requirements to proceed. We find that maintaining confidentiality early in the customer engagement window stage is appropriate to reduce opportunities for developers to gain competitive advantage over others before interconnection requests have been finalized and accepted by the transmission provider. We therefore adopt the following modification to section 3.4.5 of the pro forma LGIP (addition in italics): “Within ten (10) Business Days after the close of the Cluster Request Window, Transmission Provider shall post on its OASIS site a list of Interconnection Requests for that Cluster. The list shall identify, for each anonymized Interconnection Request[s]: (1) the requested amount of Interconnection Service; (2) the location by county and state; (3) the station or transmission line or lines where the interconnection will be made; (4) the projected In-Service Date; (5) the type of Interconnection Service requested; and (6) the type of Generating Facility or Facilities to be constructed, including fuel types, such as wind, natural gas, coal, or solar. The transmission provider must ensure that project information is anonymized and does not reveal the identity or commercial information of interconnection customers with submitted requests.” Further, as discussed below, we modify section 3.4.6 of the pro forma LGIP to require that transmission providers exercise the use of non-disclosure agreements to maintain confidentiality of identifying or commercially sensitive information for all other interconnection customers in a group scoping meeting.

e. Scoping Meeting

i. NOPR Proposal

238. In the NOPR, the Commission proposed to renumber and revise section 3.4.4 of the pro forma LGIP as section 3.4.6 to provide that, during the proposed customer engagement window, transmission providers must hold a scoping meeting with all interconnection customers whose valid interconnection requests were received in that cluster request window. Revised section 3.4.6 of the pro forma LGIP would also require transmission providers to hold individual customer-specific scoping meetings, at the interconnection customer's request, which must be requested by no later than 15 business days after the close of the cluster request window.

ii. Comments

239. MISO supports the Commission requiring individual customer-specific scoping meetings only when requested by interconnection customers. APS agrees that a single scoping meeting with all interconnection customers in the cluster during the customer engagement window is beneficial to transmission providers and eases the burden of scheduling individual meetings with all parties. However, APS has concerns about security and confidentiality. APS notes that, currently, each interconnection customer in the interconnection queue is provided a queue number that becomes the only identifying information posted publicly. APS requests that the Commission provide clarity on whether the requirements to treat additional information as confidential no longer apply or if there is a form of good utility practice as it pertains to holding a single scoping meeting without revealing the identities of the other interconnection customers involved and some examples thereof.

240. MISO expresses concern that the timelines listed in the customer engagement window for posting information are impractical. MISO asserts that the Commission should not require a posting so near the close of the request window because the transmission provider must devote its resources to reviewing the interconnection requests for deficiencies.

241. Enel and AEE argue that the Commission should also require transmission providers and transmission owners to hold individual, customer-specific scoping meetings at the request of the interconnection customer before the customer commits to entering the cluster. Enel states that an individual pre-interconnection queue scoping meeting would be an opportunity for the interconnection customer to ask basic questions that can help inform economically significant decisions an interconnection customer faces in deciding to enter the interconnection queue. As an alternative to requiring a pre-interconnection queue meeting, Enel suggests that the Commission could require transmission providers to maintain an electronic inbox where prospective interconnection customers could submit interconnection-related questions and be guaranteed a response in time to inform decisions on entering the interconnection queue.

242. PJM believes that “grouping kick off meetings” will reduce the burden on transmission owners and providers of scheduling and participating in hundreds of meetings, and the burden on interconnection customers of waiting for their meeting to be scheduled. PJM requests clarification that a transmission provider may group requests for this customer engagement window unless an interconnection customer requests otherwise.

243. Tri-State asks the Commission to consider providing only one week to schedule the requested individual customer-specific scoping meeting if the interconnection customer does not request a scoping meeting until the fifteenth business day.

244. Noting the difficulty of coordinating in-person scoping meetings, SEIA requests that the Commission clarify that both generating facility-specific and cluster scoping meetings must provide the option for interconnection customers to attend via teleconference, which is currently not available in all regions. Enel suggests that, for all scoping meetings, the Commission should require transmission owners, not just interconnection customers and transmission providers, to attend; otherwise, Enel continues, there could be crucial questions that the transmission provider may not be able to answer.

iii. Commission Determination

245. We adopt, in part, the proposed revisions to section 3.4.6 of the pro forma LGIP, and therefore require that, during the customer engagement window, transmission providers hold a scoping meeting with all interconnection customers whose interconnection requests were received in that cluster request window. We decline to adopt the NOPR proposal to require transmission providers to hold individual customer-specific scoping meetings at the interconnection customer's request.

246. These revisions to the pro forma LGIP align the timing and purpose of scoping meetings between transmission providers and interconnection customers with the adoption of the cluster study process in this final rule. We do not believe that providing the option for interconnection customers to request an individual customer-specific scoping meeting is necessary to ensure that interconnection customer-specific questions are answered as interconnection customers consider whether to remain in the interconnection queue for the cluster study or to withdraw their interconnection request. We find that this requirement would be comparatively inefficient and burdensome for transmission providers, leading to potentially significant interconnection delays. We thus find that this requirement would be inconsistent with the goal to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. We find that the cluster-wide scoping meeting is an appropriate forum in which all interconnection customers can direct questions to transmission providers in an efficient manner without delaying the cluster process with unnecessarily time-consuming individual scoping meetings.

247. We agree with APS' concerns pertaining to good utility practices for security and confidentiality regarding the disclosure of potentially sensitive commercial information during the cluster scoping meeting that will include numerous interconnection customers in the cluster. We therefore modify section 3.4.6 of the pro forma LGIP to require that transmission providers use non-disclosure agreements to maintain confidentiality of identifying or commercially sensitive information for all other interconnection customers in a group scoping meeting until the close of the customer engagement window.

248. In response to Enel and AEE, we will not modify the pro forma LGIP to require transmission providers to hold individual interconnection customer-specific scoping meetings at the request of the interconnection customer before the interconnection customer commits to entering the cluster. As discussed above, we decline to adopt a requirement that transmission providers conduct individual interconnection customer scoping meetings. Additionally, as discussed above, we adopt the heatmap requirement, which will assist interconnection customers prior to entering the interconnection queue in evaluating the viability of their proposed generating facilities, and we are also permitting interconnection customers to withdraw from the interconnection queue without penalty prior to the close of the customer engagement window. With these reforms, we do not believe that pre-interconnection queue scoping meetings should be required to ensure just and reasonable rates.

249. In response to MISO's concern about posting requirements close to the conclusion of the cluster request window, we find that allowing transmission providers a total of 10 business days from the close of the cluster request window to post the required list of interconnection requests for that cluster is a reasonable amount of time.

250. In response to SEIA, we decline to modify the pro forma LGIP to require transmission providers to include an option for interconnection customers to attend via teleconference for cluster-wide scoping meetings. We do not believe that such level of logistical specification governing how transmission providers choose to conduct scoping meetings with interconnection customers is needed in the pro forma LGIP.

251. In response to Enel, we decline to modify the pro forma LGIP to require transmission owners, not just interconnection customers and transmission providers, to attend scoping meetings. The pro forma LGIP contemplates that the transmission owner and transmission provider may be the same entity, except in the case of an RTO/ISO, in which case the transmission owner does not have operational control of the facilities and does not perform cluster studies. In the case of an RTO/ISO, only the entity that independently administers the cluster study is required to attend the scoping meeting.

f. Posting of Metrics for Cluster Study Processing Time and Restudy Processing Time

i. NOPR Proposal

252. In the NOPR, the Commission proposed to revise the requirements included in section 3.5.2 of the pro forma LGIP to post metrics for interconnection feasibility study processing time and system impact study processing time, to instead require transmission providers to post metrics for cluster study processing time and cluster restudy processing time. The Commission also proposed to require transmission providers to post the time from when the transmission provider received a valid interconnection request to the completion of the cluster study, cluster restudy, and facilities study.

253. Specifically, in section 3.5.2.1 of the pro forma LGIP, the Commission proposed requiring that transmission providers must post the number of interconnection requests that had cluster studies completed within the transmission provider's coordinated region during the reporting quarter that were completed more than 150 calendar days after the close of the customer engagement window. Similarly, in section 3.5.2.2 of the pro forma LGIP, the Commission proposed requiring that transmission providers must post the number of interconnection requests that had cluster restudies completed within the transmission provider's coordinated region during the reporting quarter that were completed more than 150 calendar days after the transmission provider's receipt of the interconnection customer's executed cluster restudy agreement.

254. In section 6.4 of the pro forma LGIP, the Commission proposed that transmission providers publicly post new metrics requirements on their websites pertaining to various technical specifications for, and impacts of, potential generating facilities on the transmission provider's transmission system, requiring that these metrics must be updated on the transmission provider's website “within 30 days after the completion of each Cluster Study and Cluster Restudy period.”

ii. Comments

255. Clean Energy Associations support the proposal to require the posting of metrics for cluster study processing time and cluster restudy processing time, starting from when the transmission provider received a valid interconnection request. Clean Energy Associations further argue that these reports should also identify the level of accuracy of these studies relative to final costs.

256. While supportive of the use of metrics that reflect cluster study and cluster restudy processing time, some commenters do not support measuring these metrics from the date that the transmission provider received the interconnection request. APS argues that this seems contradictory to the NOPR proposal that the 150-day timeline to process cluster study requests begins at the end of the customer engagement window. MISO asserts that for study metrics to be a useful measurement of whether a transmission provider is meeting its tariff deadlines, the start date used in the metrics must reflect when studies actually commence. MISO notes that an interconnection customer may choose to submit its interconnection request weeks ahead of the cluster request window deadline and that the time between that deadline and study commencement is variable. MISO urges the Commission to allow RTOs/ISOs flexibility to maintain metrics that reflect their tariff deadlines, especially where the RTO/ISO already has a Commission-approved cluster study process.

257. Ameren contends that if the Commission retains the proposal to require the posting of the time from when the transmission provider received a valid interconnection request to the completion of the cluster study, cluster restudy, and facilities study, it should clarify that in the context of an RTO/ISO, “complete” refers to the final sign-off by the RTO/ISO. Ameren asserts that transmission owners within an RTO/ISO may act on behalf of the RTO/ISO transmission provider for purposes of certain studies; however, it is the RTO/ISO and not the transmission owner that decides when a study is complete.

258. In section 6.4 of the pro forma LGIP, regarding the proposed requirement that “[t]hese metrics must be updated within 30 days after the completion of each Cluster Study and Cluster Re-study period[,]” Enel recommends that the word “period” should be deleted. Enel argues that the trigger should be the completion of the studies themselves.

iii. Commission Determination

259. We adopt the proposed revisions to section 3.5.2 of the pro forma LGIP to require transmission providers to post metrics for cluster study processing time and cluster restudy processing time, including the number of cluster studies completed within 150 calendar days of the close of the customer engagement window. We modify section 3.5.2.2 of the pro forma LGIP as proposed in the NOPR to be consistent with the new requirement adopted in section 7.5 of the pro forma LGIP that cluster restudies should be completed within 150 calendar days of the transmission provider notifying interconnection customers in the cluster and that a cluster restudy is required. The requirement to post these metrics replaces the existing requirement to post metrics for interconnection feasibility study processing time and system impact study processing time, which were relevant for the serial study process but are no longer relevant for the cluster study process required by this final rule. We therefore believe that these revisions are necessary to implement the change from a serial study process to the cluster study process.

260. As for the point at which to begin measuring the metrics, several commenters argue against using the date on which the transmission provider received the interconnection requests. We clarify that sections 3.5.2.1 and 3.5.2.2 of the pro forma LGIP adopted in this final rule establish that these metrics must be measured from the close of the customer engagement window for the cluster study processing time metric and from when transmission provider notifies interconnection customers in the cluster that a cluster restudy is needed for the cluster restudy processing time metric. We find that these are appropriate start dates from which to calculate the metrics because they reflect when the respective studies are to actually commence. We decline to grant additional flexibility to maintain metrics and associated timelines for those metrics, as urged by MISO.

261. Regarding Clean Energy Associations' suggestion that the metrics also identify the level of accuracy of studies relative to final costs, we decline to adopt this suggestion. For one, it is unclear to what final costs Clean Energy Associations is referring to. Additionally, the metrics that we require transmission providers to post as part of this final rule focus on the timing of interconnection studies and not on the accuracy of cost estimates. The metrics are intended, as described in Order No. 845, to provide needed transparency “to allow interconnection customers to develop informed expectations about how long the interconnection study portion of the process actually takes.”

262. We decline to adopt Ameren's suggestion to base the 150-calendar day cluster study deadline on the RTO/ISO's completion of the cluster study rather than the transmission owner's completion because the deadlines are applicable to the transmission provider and such a clarification is unnecessary to be added to the pro forma LGIP.

263. We agree with Enel's suggestion to modify proposed pro forma LGIP section 6.4—now pro forma LGIP section 6.1—by deleting “period” because, as Enel explains, this would more concisely convey that the metrics should be updated following the completion of the studies themselves.

g. Interconnection Request Evaluation Process

i. NOPR Proposal

264. In the NOPR, the Commission proposed several changes to pro forma LGIP section 4, renamed “interconnection request evaluation process” from “queue position.” First, the Commission proposed to rename and revise section 4.1 of the pro forma LGIP as “queue position” and added two new proposed sections: (1) section 4.1.1 (Assignment of Queue Position), which provides that queue position will be based on the time and date that the transmission provider receives all items required under section 3.4 (Valid Interconnection Request) and that there is no queue priority for interconnection customers that opted for informational interconnection studies; and (2) section 4.1.2 (Higher Queue Position), which provides that all interconnection requests studied in a single cluster shall be considered to have equal queue priority, but clusters initiated earlier in time shall be considered to have a higher queue position than clusters initiated later in time.

265. The Commission also proposed to remove from section 4.2 of the pro forma LGIP the provisions allowing transmission providers to study interconnection requests serially and the requirement for transmission providers to provide 180 calendar days' advance notice before opening a cluster window. The Commission also proposed to rename section 4.2 of the pro forma LGIP “general study process,” and revise it to require transmission providers to perform interconnection studies within the cluster study process.

266. In the NOPR, the Commission also proposed changes to the material modification provisions in section 4.4 (Modification) of the pro forma LGIP to provide that moving a point of interconnection shall result in a loss of interconnection queue position if it is deemed a material modification by the transmission provider. Additionally, proposed additions to pro forma LGIP section 4.4 require that any identified changes to a planned interconnection, proposed by an interconnection customer or the transmission provider, must be acceptable to any impacted interconnection customer in the same cluster, and such acceptance is not to be unreasonably withheld. The Commission noted that the interconnection customer may decide to forego the requested change that constitutes a material modification and retain its existing queue position.

267. Further, the Commission proposed to revise section 4.4.1 of the pro forma LGIP to make clear that: (1) the modifications previously permitted prior to return of the executed system impact study agreement are now permitted to be made prior to return of the executed cluster study agreement; and (2) for generating plant increases, the incremental increase will be studied with the next cluster study for purposes of cost allocation and study analysis. ⁶²⁴ Pro forma LGIP section 4.4.1 also explicitly permits specific modifications prior to the interconnection customer's return of the executed cluster study agreement to the transmission provider, including: (a) a decrease of up to 60 percent of electrical output (MW) of the proposed project, through either a decrease in plant size or a decrease in interconnection service level; (b) modifying the technical parameters associated with the generating facility technology or step up transformer; and (c) modifying the interconnection configuration.

ii. Comments

268. With regards to the proposed changes to section 4.1 (Queue Position), Tri-State questions whether the proposed definition of queue position includes surplus interconnection requests. Xcel argues, and EEI agrees, that the Commission should modify the proposal to clarify that queue position or queue priority is based on interconnection request readiness and not on the date and time the interconnection request is submitted.

269. CAISO asserts that it is unclear what losing a queue position means in a cluster-based study ( e.g., being withdrawn from the interconnection queue or moving to a lower interconnection queue position), but also contends that no specification or reform is necessary because interconnection customers will simply withdraw the modification every time if it is found to be material. CAISO argues that the Commission should either remove the “option” to lose an interconnection queue position when a proposed modification is found to be material, or clarify what replaces the interconnection queue position when it is lost.

270. Clean Energy States argue that, in addition to the “signs of commercial progress” proposed by the Commission, clusters should be prioritized for study based on a number of other transparent and quantifiable factors, such as alignment with state policy ( e.g., participation in procurement actions), and benefits to low-income, environmentally impacted, and “energy communities” as defined under the Inflation Reduction Act, state policies, and the Justice40 Initiative. Clean Energy States assert that clusters could further be prioritized for development by how well the combined cluster meets transmission system needs, with preference for interconnection agreements given to those that result in the lowest cost upgrades, have the most attractive operational profile, or deliver the best reliability improvements.

271. Regarding the proposed changes to pro forma LGIP section 4.4 (Modifications), Enel argues that the Commission should remove the proposed language requiring the acceptance of “any impacted Interconnection Customer in the same Cluster” to modify an interconnection request. Enel asserts that this requirement not only will be challenging to facilitate (especially in large clusters) but is also a redundant and unnecessary hurdle that could result in anticompetitive behavior. If the Commission keeps this language, to avoid uncertainty regarding the application of this provision, Enel proposes to replace this language with “any Interconnection Customer in the same Cluster whose interconnection would be delayed or whose interconnection-related costs would be increased as a result of the identified changes.”

272. A few commenters argue that the Commission should consider changes to the material modification process such that only certain modifications trigger a restudy. Clean Energy Associations recommend that the Commission modify the current material modification definition to clearly state that certain changes are presumptively immaterial, such as changing solar modules or turbines, adding storage capacity, or making minor adjustments to inverter performance. Clean Energy Associations argue that this presumption should be in place so long as planned export and import capacity remains the same. Clean Energy Associations also support the concept of expedited, limited studies for project modifications, provided that: (1) an expedited approach does not change the level of interconnection service; (2) there is no impact on cost or timing of an interconnection request that is lower- or equally queued; and (3) it does not cause any reliability concern. Additionally, Pattern Energy asserts that, in its experience, transmission providers apply widely disparate standards where even de minimis impacts—timing or financial—can be determined to be material, which Pattern Energy believes is unreasonable and unduly discriminatory in light of the dynamic nature of the generator interconnection processes. Pattern Energy argues that, absent severe delay, timing delay should not be factored into materiality. Pattern Energy suggests instead that materiality be tied to financial impact on a proposed generating facility (or group of proposed generating facilities).

273. With regard to modifications under proposed pro forma LGIP section 4.4.1, MISO supports the proposed revisions to avoid proposed project service level increasing and other changes disrupting cluster studies that are in progress or delaying the negotiation and execution timelines for the LGIA.

274. Enel recommends that the Commission modify the proposed pro forma LGIP section 4.4.1 language to give interconnection customers flexibility in the initial stages of interconnection studies, otherwise, it argues that, interconnection customers are more likely to work around the rules by submitting multiple smaller interconnection requests to retain size flexibility after seeing their initial results, which is more administratively burdensome for transmission providers and leads to its own form of inefficiency as size reductions come in the form of withdrawals at any point in the process rather than being limited to partial reductions prior to entering the cluster restudy.

275. CREA and NewSun argue that the Commission should explicitly permit interconnection customers to modify their interconnection requests to reduce or eliminate the assignment of network upgrade or stand alone network upgrade costs associated with a proposed generating facility after receipt of the first cluster-level interconnection study. CREA and NewSun argue that interconnection customers should be permitted to modify their proposed generating facilities to avoid impacts on the transmission system that trigger network upgrades by, for example, reducing their capacity or installing devices that will limit their output during critical periods. CREA and NewSun state that the existing pro forma LGIP allows an interconnection customer to downsize its interconnection capacity up to 60% upon receipt of the first interconnection study ( i.e., the feasibility study) and before progressing to the second study ( i.e., the system impact study). CREA and NewSun state that, in contrast, the NOPR proposes to only allow downsizing to occur before receipt of the first cluster system impact study and, as a result, the opportunity to downsize the interconnection request to tailor the facility to the available capacity identified in the first useful interconnection study would be lost. Therefore, CREA and NewSun argue that the Commission should revise the NOPR proposal to ensure that a reasonable amount of downsizing ( e.g., 60%) is permitted after receipt of the first cluster-level interconnection study.

iii. Commission Determination

276. We adopt the proposed revisions to pro forma LGIP section 4.1 (Queue Position), section 4.2 (General Study Process), and section 4.4.1, and we modify the proposed definition of queue position and the proposed revisions to the material modification provisions in section 4.4 (Modification). These are discussed below.

277. First, we adopt the proposed revisions to section 4.1 of the pro forma LGIP (Queue Position), which reflect the impact of the adoption of the proposed cluster study process in this final rule on queue position assignments. These revisions provide that transmission providers must assign queue positions based on the date and time of receipt of a valid interconnection request, but all interconnection customers that submit interconnection requests within a cluster request window must be considered equally queued. Clusters initiated earlier in time must have a higher queue position than clusters initiated later in time. Under the existing serial study process in the pro forma LGIP, queue position had a greater effect on an interconnection customer, for instance, in the allocation of network upgrade costs. By contrast, network upgrade costs within a cluster will not be allocated by queue position; rather, as discussed below, network upgrade costs within a cluster must be allocated generally through a proportional impact method among the interconnection customers in the cluster. Given the nature of the cluster study process, including the nature of the cost allocation for network upgrades, it is appropriate for all interconnection customers in a cluster to be considered equally queued.

278. Second, we adopt the proposal to remove from section 4.2 of the pro forma LGIP the provisions allowing transmission providers to study interconnection requests serially and the requirement for transmission providers to provide 180 days' advance notice before opening a cluster window. We also adopt the proposal to rename section 4.2 of the pro forma LGIP “General Study Process” and revise it to require transmission providers to perform interconnection studies within the cluster study process. These revisions are necessary to implement the cluster study process required by this final rule.

279. As requested by Tri-State, we clarify that the definition of queue position is not relevant to surplus interconnection requests, which are processed outside of the normal interconnection queue, as further discussed in section III.A.2.n below.

280. We also maintain the language in the pro forma LGIP that moving a point of interconnection in a way that is deemed a material modification will impact an interconnection customer's queue position, but we clarify the meaning of this in the context of the cluster study process. Specifically, if moving a point of interconnection is deemed by the transmission provider to be a material modification to the interconnection request, and the interconnection customer chooses to proceed with the proposed modification, the interconnection request will be deemed withdrawn and the interconnection customer must re-enter the interconnection queue with a new interconnection request, if it desires to proceed to interconnect. To avoid being deemed withdrawn, the interconnection customer may choose not to move its point of interconnection and to instead remain in the same cluster with the original interconnection request, and, thus, in the same queue position.

281. In response to CREA and NewSun, we do not opine on whether moving a point of interconnection within a cluster will be a material modification. Instead, we leave the determination as to whether it is deemed a material modification to the transmission provider, as in the existing process for determining whether a proposed modification is material.

282. We decline to adopt Clean Energy States' suggestion that, in addition to the “signs of commercial progress” proposed by the Commission, clusters should be prioritized for study based on other transparent and quantifiable factors. Clean Energy States neither provides sufficient rationale or detail regarding such factors by which clusters would be prioritized by transmission providers, nor explains how such prioritization criteria would be determined. We note that the Commission did not propose alternative factors for consideration. Additionally, we note that the record lacks adequate discussion in favor of such prioritization mechanisms or such “factors” for the Commission to consider adopting in this final rule.

283. Third, we modify the proposed definition of queue position in the pro forma LGIP and LGIA to provide that queue position is established pursuant to section 4.1 of the pro forma LGIP. Fourth, we modify the proposed revisions to the material modification provisions in section 4.4 (Modification) of the pro forma LGIP. We adopt the language that provides that moving a point of interconnection shall result in a loss of queue position if it is deemed a material modification by the transmission provider, for the reasons discussed above. At the same time, we modify the proposed revisions to remove the requirement to obtain the approval of “any impacted Interconnection Customer in the same Cluster.” We are persuaded by Enel's argument that this proposed language in pro forma LGIP section 4.4 should be struck for two reasons. First, we find this language unnecessary because the point of interconnection could be changed only if the transmission provider had deemed it to not be a material modification to the interconnection request. Through this requirement, the transmission provider's analysis ensures that the change will not have a material impact on the cost or timing of another interconnection request in the cluster. Second, although the proposal included the language “such acceptance not to be unreasonably withheld,” we are still concerned about the potential for anticompetitive behavior to the extent that other interconnection customers in the cluster could refuse to accept the point of interconnection change to limit competition. The interconnection customers within a cluster will be competitors in the wholesale markets in many, if not all, respects. To ensure competitive market outcomes, they should not be provided an undue opportunity to affect the advancement or the costs for a proposed generating facility of one of their competitors.

284. A number of commenters argue that the Commission should consider changes to the material modification process such that only certain modifications trigger a restudy. We decline to adopt any of the suggested revisions to the material modification provisions and restudy triggers in the pro forma LGIP. We did not propose changes suggested by commenters and do not find the need to adopt such changes to the material modification provisions to ensure just and reasonable rates. We believe that the list of permitted modifications in section 4.4 of the pro forma LGIP is appropriate because they allow interconnection customers a degree of flexibility with respect to generating facility size, interconnection service level, and specific generating facility technology that appropriately balances the high burden to enter the interconnection queue and the lengthy duration of the interconnection queue, during which external factors may change, including the introduction of new technology that interconnection customers may wish to incorporate into their generating facility design.

285. Finally, we adopt the proposed revisions to section 4.4.1 of the pro forma LGIP to make clear that: (1) the modifications previously permitted prior to the return of the executed system impact study agreement are now permitted to be made prior to return of the executed cluster study agreement; and (2) for plant increases, the incremental increase will be studied with the next cluster study for purposes of cost allocation and study analysis. We believe that these revisions are needed to implement the cluster study process adopted to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. Notably, we believe that prior to the return of the executed cluster study agreement is the appropriate time to permit the modifications previously permitted prior to the return of the executed system impact study agreement because these represent approximately the same point of the interconnection process in a serial study process versus a cluster study process. For plant increases, we find that it is appropriate to exclude increases to proposed generating facility size from the cluster study that is ongoing as any increase to size may create the need for restudies. By moving the increase to the subsequent cluster, the interconnection customer can still pursue its requested addition, albeit on a delayed schedule.

286. We decline to adopt Enel's alternative proposed language that would allow the same modifications permitted to be made prior to the executed cluster study agreement to also be permitted before a cluster restudy. This would not only represent a significant change from the existing modification language in pro forma LGIP section 4.4.1, but allowing such modifications at the cluster restudy stage could negatively affect the integrity of the cluster and cause further restudies, which would not ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner.

287. We also decline to adopt the revisions suggested by CREA and NewSun that would explicitly permit interconnection customers to modify their interconnection requests to reduce or eliminate the assignment of network upgrade or stand alone network upgrade costs associated with a proposed generating facility after receipt of the first cluster-level interconnection study. The “loss” of the opportunity for interconnection customers to downsize the interconnection request to tailor the facility to the available capacity identified in the first useful interconnection study reflects the nature of moving from a serial study process, with an initial, high-level feasibility study, to a cluster study process, with the benefit of a customer engagement window, potential for shared cost allocation, and lower likelihood of cascading restudies. Moreover, providing interconnection customers an opportunity to reduce the size of their proposed generating facilities after the cluster study would undercut the increased certainty and efficiency that are key benefits of the shift to a cluster study process. With the adoption of clusters, a reduction in size that may eliminate one interconnection customer's cost responsibility for a network upgrade could affect other interconnection customers in the cluster, either by increasing their costs or requiring a different network upgrade. This type of uncertainty could lead to further reductions, withdrawals, and restudies, and would be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. We note, however, that interconnection customers may request a material modification assessment under section 4.4 of the pro forma LGIP for reductions and that if those reductions are found to not be material, the interconnection customer may proceed with them without a loss of queue position.

h. Fewer Than Three Year Extension to Commercial Operation Date

i. NOPR Proposal

288. Currently, if an interconnection customer's generating facility is delayed by fewer than three years, the pro forma LGIP states that such extensions are not material and shall be handled through construction sequencing. However, the pro forma LGIP does not state the starting point for this fewer than three-year period. In the NOPR, the Commission proposed to revise section 4.4.5 of the pro forma LGIP, which currently allows an extension of less than three cumulative years of the generating facility's commercial operation date, to require that the commercial operation date reflected in the initial interconnection request be used in calculating the permissible fewer than three-year extension.

ii. Comments

289. Several commenters contend that the commercial operation dates set out in the executed LGIA, rather than the date in the initial interconnection request, are generally more accurate and provide more certainty when established at the end of the interconnection study process as they would include the schedule estimates for network upgrades, and the interconnection customer may have greater control over pursuing its development timeline.

290. Invenergy argues that, because assigned upgrades necessary for interconnection can require more than three years for construction, it would be reasonable to permit a greater extension right of five years from the date set out in the LGIA. Enel also argues that the Commission should grant a longer extension of time if the transmission provider's studies are delayed or if more time is required to build network upgrades because these circumstances are beyond the interconnection customer's control. Enel also recommends requiring the transmission provider to grant a day-for-day delay to the originally requested commercial operation date for any delays in the study process relative to the LGIP deadlines as well as due consideration for network upgrades that require more than 18 months to design, procure, and construct.

291. Ameren and PPL assert that continuing to provide a three-year extension of the commercial operation date would allow projects to move forward when they are not ready or viable. APS believes that limiting the ability to suspend interconnection requests or extend the commercial operation date to instances of force majeure, including where a customer demonstrates specific timeline obstructions such as permit issuance or supply chain delays, is more in line with the proposals in the NOPR.

292. NV Energy seeks clarification on how long an interconnection customer may extend its commercial operation date because the pro forma LGIP allows seven to 10 years from the initial interconnection request to construct. NV Energy requests clarification on how the three-year suspension clause in the pro forma LGIA plays into the timeline for the commercial operation date. Pine Gate argues that any extension period from the commercial operation date be subject to the overall seven-year time period for achieving commercial operation. Invenergy argues that the Commission should also make clear that the limits on the initial proposed in-service date that can be specified in an interconnection request to no more than seven years beyond the interconnection request date, does not limit the ability to take advantage of commercial operation date extensions that are otherwise provided under the pro forma LGIP or an LGIA. For example, some transmission owners have taken the position that, when exercising a suspension right, if the suspension would result in an in-service date greater than seven years after the date specified in the interconnection request, the interconnection customer cannot use its full suspension period. Invenergy asserts that the Commission has already clarified that the interconnection request limitation on proposed in-service dates is applicable only for the purpose of limiting the date requested at the application stage, and does not limit in-service dates that extend beyond that period as a result of other factors, which would include transmission owner delay, exercise of suspension, and here, additional commercial operation date extensions. Invenergy also states that the Commission should clarify that its revisions to pro forma LGIP section 4.4.5 are in addition to, and do not limit, an interconnection customer's suspension rights under its interconnection agreement.

iii. Commission Determination

293. We adopt the proposed revisions to section 4.4.5 of the pro forma LGIP that require that interconnection customers receive an extension of fewer than three cumulative years of the generating facility's commercial operation date without requiring them to request such an extension from the transmission provider. In response to commenters' concerns, however, we modify our proposal to clarify that the commercial operation date reflected in the initial interconnection request shall be used in calculating the permissible fewer than three-year extension until the interconnection customer executes, or requests the unexecuted filing of, an LGIA. Once the interconnection customer has executed an LGIA or requested that the LGIA be filed unexecuted, the commercial operation date established in the LGIA shall be the date from which the up to three cumulative years is calculated.

294. At the time the pro forma LGIP was adopted, the interconnection process was considerably shorter than it is now; the delays and sizeable interconnection queues facing transmission providers create a situation where many interconnection customers use this up to three-year period to ensure that their proposed generating facilities reach commercial operation. Furthermore, the length of the interconnection queues is such that at the time an interconnection customer enters the queue, it may have little idea of how long it will spend in the interconnection queue before commencement of the construction of its generating facility and required interconnection facilities and network upgrades. Thus, we agree with Invenergy, Ørsted, and Pine Gate, and we modify our proposal to require the up to three-year period to commence from the commercial operation date established in the interconnection customer's LGIA once the LGIA is executed or the interconnection customer has requested that it be filed unexecuted with the Commission.

295. We decline commenters' requests to revise the actual length of the permissible extension of a proposed generating facility's commercial operation date. The Commission did not propose to change the length of the permissible extension in the NOPR, and we lack an adequate record that the existing up to three-year extension is unjust and unreasonable.

296. Commenters request clarification of how the changes to pro forma LGIP section 4.4.5 adopted in this final rule affect other provisions such as pro forma LGIP section 3.4.2 and pro forma LGIA article 5.16, which provide for extensions of the in-service date or suspension of construction. We reiterate that the revisions to section 4.4.5 of the pro forma LGIP adopted in this final rule establish only the starting point for the less than three-year extension to the commercial operation date. The Commission did not propose in the NOPR, and we do not adopt in this final rule, changes to the extension of in-service date provisions in pro forma LGIP section 3.4.2, or to the suspension provision in pro forma LGIA article 5.16.

i. Cluster Study Provisions (Pro Forma LGIP Sections 6, 7)

i. NOPR Proposal

297. As part of the proposed revisions to the pro forma LGIP, the NOPR proposed to replace section 6 (Interconnection Feasibility Study) with the new requirements to publicly post interconnection information, i.e., the “heatmap” as discussed above in section III.A.1.c, thereby removing the entirety of the feasibility study from the pro forma LGIP. Furthermore, in the NOPR, the Commission proposed to rename pro forma LGIP section 7 from “interconnection system impact study” to “cluster study.” The Commission proposed revisions to pro forma LGIP section 7.1 (Cluster Study Agreement) to state that the transmission provider must tender to each interconnection customer that submitted a valid interconnection request a cluster study agreement no later than five business days after the close of the cluster request window. The Commission proposed revisions to pro forma LGIP section 7.2 (Execution of Cluster Study Agreement) to state that if the interconnection customer does not provide technical data when it delivers the cluster study agreement, the transmission provider must notify the interconnection customer of the deficiency within five business days, and the interconnection customer must cure the deficiency within 10 business days of receipt of the notice. The Commission proposed revisions to pro forma LGIP section 7.3 (Scope of Cluster Study Agreement) to make clear that the stability analysis, power flow analysis, and short circuit analysis previously conducted under the feasibility and system impact studies would be conducted on a clustered basis. The Commission also proposed changes to pro forma LGIP section 7.3 to make clear that, for purposes of determining necessary interconnection facilities and network upgrades, the cluster study shall use the level of interconnection service requested by interconnection customers in the cluster, except where the transmission provider otherwise determines that it must study the full generating facility capacity due to safety or reliability concerns. The Commission proposed revisions to pro forma LGIP section 7.4 (Cluster Study Procedures) to state that, within 10 business days of simultaneously furnishing a cluster study report and a draft facilities study agreement to each interconnection customer within the cluster and posting such report on OASIS, the transmission provider shall convene an open meeting to discuss the study results and shall, upon request, make itself available to meet with individual interconnection customers after the report is provided. Pro forma LGIP section 7.4 also states that the transmission provider must complete the cluster study within 150 calendar days. The Commission proposed revisions to pro forma LGIP section 7.5 (Cluster Study Restudies) to state that the interconnection customer must provide, within 20 calendar days after the cluster study report meeting, a study deposit, demonstration of site control, and a commercial readiness demonstration. Pro forma LGIP section 7.5 also states that the transmission provider must complete the cluster restudy within 150 calendar days and delineates the steps the transmission provider must take when a restudy is required or not required.

ii. Comments

298. MISO supports the deletion of section 6 of the pro forma LGIP and the removal of the feasibility study from the pro forma LGIP.

299. In reference to the proposed revisions to section 7.1 (Cluster Study Agreement) of the pro forma LGIP, Tri-State stresses that five business days is a tight time frame to tender a valid cluster study agreement to each interconnection customer that submitted a valid interconnection request and argues that this timeline is not feasible for transmission providers with greater than 50 interconnection requests submitted in a cluster request window.

300. In reference to the proposed revisions to section 7.2 of the pro forma LGIP, Tri-State asserts that the Commission needs to confirm or reiterate that the interconnection request is considered withdrawn if the interconnection customer does not cure a deficiency identified by the transmission provider.

301. In reference to the proposed revisions to section 7.3 (Scope of Cluster Study) of the pro forma LGIP, Tri-State asks the Commission to add language to address situations with studies pending completion of higher-queued project cluster studies.

302. Enel proposes an alternative method for performing the cluster study and restudy to the NOPR proposal. Enel states that if the Commission wants to retain the full scope of analyses in the cluster study, the Commission could require draft power flow analyses to be provided to interconnection customers part way through the cluster study. Enel explains that interconnection customers could be granted the right to reduce interconnection service amounts and make other changes pursuant to pro forma LGIP section 4.4.1 following receipt of these results. Enel states that the transmission provider would repeat the power flow analyses until the queue stabilized, with the motivation for interconnection customers to make changes in a timely way being driven by knowledge that once the latter portion of the studies started, the interconnection customer would lose this flexibility.

303. In the list of requirements to proceed to the cluster restudy in proposed revisions to section 7.5 of the pro forma LGIP, Enel proposes to add “(d) election of project changes as permitted by LGIP section 4.4.1.”

304. In the proposed revisions to section 7.5 of the pro forma LGIP, Enel suggests removing item (2), which states that if there are no changes to the composition of the cluster, a cluster restudy is not required, because it claims that the cluster restudy would always be required, at least in part, to add short circuit and stability analyses.

305. With regard to the 150-day cluster study deadline, some commenters generally support the proposed 150-day deadline to complete the cluster study. Enel recommends a reduction in the scope and schedule of the cluster study to only include power flow analysis and a short circuit ratio test (to test grid strength and flag potential inverter instability issues) and suggests that this initial cluster study be completed in 90 days instead of 150 days. Enel contends that, the availability of some information from this first study, interconnection customers retain more flexibility up to the point of committing to the initial cluster restudy, which allows interconnection customers to optimize the characteristics of their proposed generating facilities, most notably the amount of ERIS and NRIS interconnection service requested, in response to the results of the study. Enel argues that early flexibility for optimization of proposed generating facilities is better than forcing interconnection customers to withdraw and re-enter the interconnection queue, is less disruptive, and does not add a year of delay to an interconnection customer completing the interconnection process.

306. A number of commenters argue that the proposed 150-day deadline to complete the initial cluster study may be, or is, too short and recommend a longer study window. A few commenters also argue that the study timelines are too short, given the proposal to eliminate the reasonable efforts standard and impose penalties on transmission providers that miss those deadlines. National Grid asserts that the proposed 150-day deadline may be “unreasonably condensed” and could result in a decline in the quality of the studies, which could lead to delays. Specifically, National Grid claims that rushing the issuance of the cluster study could lead to later amendments or corrections to certain engineering requirements or cost estimates, that in turn may lead to later-stage interconnection request withdrawals.

307. Tri-State notes that it currently implements a 270-day system impact study period, specifically 150 days for phase 1 (power flow, short circuit, reactive capability) and 120 days for phase 2 (short circuit, transient stability), and has yet to miss a study deadline. Tri-State argues that this time frame allows for a thorough study process, including coordination with neighboring systems and the correction of errors found in interconnection customers' modeling data.

308. AES contends that cluster study timelines should be tailored to the types of studies being completed at each stage of the respective cluster. For example, AES states that steady state analysis takes less time to complete than dynamic analysis, meaning that a longer time frame should be afforded for dynamic analysis in the cluster study process. Accordingly, AES recommends that the Commission adopt a 150-day general study timeline for cluster studies and restudies (system impact study-steady state, and short-circuit analysis performed) and a 200-day timeline for facilities studies (dynamic analysis performed).

309. APS requests that the Commission extend the initial study time frame to 180 days to provide meaningful studies identifying feasible proposed generating facilities, explaining that the APS transmission system is situated in such a way that many interconnections are at jointly owned facilities that require reviews and sign-off from multiple owners, including non-jurisdictional entities. APS argues that 180 days is more prudent for initial studies, with the exception of specific criteria such as jointly owned facilities, Western Electricity Coordinating Council (WECC) rated paths, and federally owned and Tribal lands, for which studies take significantly longer despite good faith efforts.

310. NYTOs and National Grid argue that the proposal is not clear on which specific steps would be included in the 150-day time frame for the initial cluster study and argue that certain additional special studies that a transmission provider may need to perform should not be subject to a 150-day time frame. NYTOs state that it is unclear when the clock starts for the proposed 150-day cluster study deadline and how the scope of the work can be reasonably limited to comply with the 150-day deadline. NYTOs argue that transmission providers and transmission owners should be afforded the flexibility to provide clarifications and supporting details on compliance.

311. Similarly, National Grid notes that certain RTO/ISO interconnection processes require special supplemental studies in addition to general system impact studies and that, while the NOPR recognizes that these studies may be required to ensure reliable interconnection of new generating facilities, it does not address whether such studies must be conducted within the proposed 150-day cluster study window or could be conducted outside of this window. National Grid argues that the time to complete such special studies should not be included in the NOPR's proposed 150-day cluster study window and that the final rule should allow regions to adjust their overall interconnection timelines to accommodate such region-specific studies and take into consideration the time required to develop system models. Finally, National Grid states that the NOPR does not address whether the 150-day cluster study window includes the time required to develop system models and base case data for the cluster study.

312. Several commenters recommend that the Commission provide transmission providers with flexibility to specify study timelines.

313. Regarding the 150-day cluster restudy deadline, several commenters agree that the 150-day deadline is reasonable for a cluster restudy. Other commenters oppose the 150-day deadline. Bonneville argues that the proposed requirement to conduct a cluster restudy within 150 days is unworkable because the complexity of the cluster restudy would vary and directly impact the completion timeline. Therefore, Bonneville seeks a longer time frame.

314. On the other hand, several commenters argue that the deadline to conduct a cluster restudy should be shorter. AES recommends that the Commission instead require transmission providers to include restudies and model rebuilds between cluster study phases, and to require that the timeline for such model rebuilds and restudies cannot be greater than 90 days. Enel similarly asserts that if the Commission leaves the cluster study timeline at 150 days and does not change the study scope, the timeline for cluster restudies should be 90 days.

315. A few commenters argue that a 30-day window per restudy is more reasonable because network models are already built, and therefore substantially fewer staff resources should be required than for the initial study. Cypress Creek adds that a shorter restudy window will also help avoid potential delays in a cluster study process in which multiple restudies are required. AEE also recommends that the Commission limit interconnection restudy timelines to 30 days, arguing that this will encourage transmission providers to treat customers in interconnection restudy with the same urgency as customers in the initial interconnection study, eliminating the possibility of asymmetric treatment of interconnection customers and alleviating interconnection queue congestion by moving those interconnection customers that have been in the interconnection queue the longest to study completion.

iii. Commission Determination

316. We adopt the proposed deletion of the feasibility study as effectuated by the replacement of the current section 6 (Interconnection Feasibility Study) of the pro forma LGIP with the new heatmap requirements, as discussed in section III.A.1.c. The move from a serial interconnection process to the new cluster study process, coupled with the Commission's heatmap requirements, render the feasibility study redundant at best and an unnecessary burden on transmission provider resources. As discussed in section III.A.1.c, above, we find that the publicly available information required by this final rule will provide the appropriate level of pre-interconnection queue information for interconnection customers to make informed choices.

317. We also adopt, with one modification, the proposed revisions to section 7 of the pro forma LGIP that rename it “cluster study” instead of “interconnection system impact study,” which set out the requirements and scope of the cluster study agreement, as well as the cluster study and restudy procedures. These revisions reflect the adoption of the cluster study process set forth in this final rule by making clear that the interconnection studies that transmission providers previously performed as part of the serial system impact studies ( i.e., stability analysis, power flow analysis, and short circuit analysis) must now be conducted on a clustered basis. As discussed further in section III.A.6 of this final rule, pro forma LGIP section 7.5 is modified to remove the requirement to provide an initial study deposit that would have been applied towards the cost of the cluster study process.

318. We are not persuaded by Tri-State's concern that five business days after the close of the cluster request window is too short a time frame for a transmission provider to tender a cluster study agreement to each interconnection customer. Transmission providers may start to prepare cluster study agreements before the close of the cluster request window, as the overall terms and conditions of the cluster study agreement are standardized so that a transmission provider need not engage in rewriting each agreement before tendering a draft to the interconnection customer.

319. In response to Tri-State's comments concerning section 7.2 of the pro forma LGIP, we confirm that an interconnection request is considered withdrawn if the interconnection customer does not cure deficiencies identified by the transmission provider. We note that under new section 3.4.4 of the pro forma LGIP, if a transmission provider identifies that an interconnection customer's technical data are incomplete or contain errors, both parties must “work expeditiously and in good faith to remedy such issues,” but the failure by the interconnection customer to provide the missing data or correct data errors will be treated as a withdrawal and dealt with under pro forma LGIP section 3.7 (Withdrawal).

320. In reference to Tri-State's comments on the proposed revisions to section 7.3 of the pro forma LGIP, we decline to add language to address situations with studies pending completion of higher-queued project cluster studies because Tri-State's comments are unclear as to what additional language may be needed.

321. We decline to adopt the alternative methods to perform cluster studies and restudies suggested by Enel. The current pro forma LGIP does not prescribe particular study methods and instead provides discretion to transmission providers to determine the particular methods of study appropriate for their transmission systems. We do not, based on the record in this proceeding, find a basis to determine that existing study methods are unjust, unreasonable, and unduly discriminatory or preferential. We also decline to add Enel's suggested section (d) to section 7.5 of the pro forma LGIP. Pro forma LGIP section 4.4.1 contains the modifications permitted to an interconnection request prior to the return of an executed cluster study agreement, which predates any potential cluster restudy. We further note that the record does not support Enel's modification request.

322. We decline to adopt the provision requiring transmission providers to hold cluster study report meetings with individual customers as proposed in section 7.4 of the pro forma LGIP. We find that the individual meetings would be unnecessary, and that individual customers should utilize the group cluster study report meeting as a more efficient forum in which to address any questions or concerns pertaining to the cluster study report. We also find that requiring transmission providers to conduct individual meetings would impose unnecessarily burdensome additional requirements on transmission providers and would be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner.

323. Also, we decline to remove proposed section 7.5(2) of the pro forma LGIP, as suggested by Enel. Contrary to Enel's claim, pro forma LGIP section 7.3 establishes that the cluster study will consist of short circuit and stability analyses; therefore, we disagree with Enel that a cluster restudy will be needed in all cases to perform the short circuit and stability analyses. Section 7.5(2) states that if there are no changes to the composition of the cluster, a cluster restudy is not required. We find that this is appropriate as it prevents the transmission provider from performing an unnecessary restudy if no conditions have changed after the first cluster study. This will increase efficiency, free up the transmission provider's resources to perform other studies, and increase the speed of interconnection, ensuring that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner.

324. Based on the record, we find that a 150-calendar day cluster study deadline provides a sufficient time to allow transmission providers to perform the stability analyses, power flow analyses, and short circuit analyses required in the cluster study process for complex clusters consisting of numerous interconnection requests. We find that the 150-calendar day time frame balances providing transmission providers with sufficient time to perform these technical cluster studies while providing certainty about the timeline for the interconnection process and ensuring that cluster studies progress in a timely manner. We note that depending on the cluster size, cluster studies may not always consume the entire 150 calendar days, and if a cluster study is complete prior to this deadline, transmission providers have flexibility to provide the cluster study report at that time prior to the deadline indicated in its LGIP and commence any necessary restudies or move to the facilities study phase. We also note that if a transmission provider progresses to the next study phase prior to the deadline indicated in its LGIP, the transmission provider must post any changes on its website or OASIS.

325. We disagree with Enel's suggestion to reduce the scope and schedule of the cluster study in the proposed pro forma LGIP. The cluster study represents the first time the interconnection customer will obtain information about its potential interconnection costs. At this point, interconnection customers will have to make significant financial decisions about whether to remain in the interconnection queue. The information provided in the cluster study report will likely dictate that decision, and we find that the scope of the study is appropriate to allow interconnection customers to make these types of decisions and evaluate whether they will face significant risk. Given that we decline to reduce the scope of the study, we find Enel's request to reduce the timeline overly restrictive. Enel's proposal would create significant burden on transmission providers to perform complex studies in an even shorter timeline, and we therefore decline to adopt it.

326. We also disagree with commenters that argue that the 150-calendar day time frame to complete the cluster study is too short. As discussed above, numerous commenters agree with the Commission's conclusion that the significant interconnection queue backlogs create uncertainty and risk in bringing new generating facilities online, rendering Commission-jurisdictional rates unjust and unreasonable. While we have extended the timeline from that provided in the individual serial study process, we believe that 150 calendar days is a reasonable extension to account for the more complex study. We also note that transmission providers will be conducting only one interconnection study, or at most a small number of interconnection studies, at a time, allowing them to devote more resources to completing the studies in a timely manner. Thus, on balance, we believe that 150 calendar days represents an appropriate and reasonable timeline on which transmission providers must complete initial cluster studies.

327. We disagree with NYTOs that it is not clear as to when the clock starts for the proposed 150-calendar day cluster study deadline, as proposed pro forma LGIP section 7.3 contains this information (150 calendar days from the close of the customer engagement window). We also disagree with NYTOs' statement that it is not clear how the scope of the work can be reasonably limited to comply with the 150-calendar day deadline, as we are not proposing to limit the scope of work necessary to effectively run a cluster study. As discussed above, we find that the 150-calendar day cluster study deadline, combined with the fewer necessary studies, provides a reasonable amount of time to allow transmission providers to perform the required studies.

328. In response to National Grid's concern that some RTO/ISO interconnection processes require supplemental studies and that these studies should not be required to be conducted within the 150-calendar day cluster study window, we decline to modify the pro forma LGIP to provide for more time for such studies. We also clarify for National Grid that the 150-calendar day deadline includes the time required to develop system models and base case data for the cluster study.

329. Regarding the 150-calendar day cluster restudy deadline, we agree with commenters that the proposed 150-calendar day deadline is reasonable for a cluster restudy. We acknowledge that some commenters argue that 150 calendar days is too short, while others argue that it is too long. On balance, we find that 150 calendar days is a just and reasonable time frame for purposes of the pro forma LGIP that allows transmission providers to conduct potentially complex restudies for instances in which larger clusters experience multiple withdrawals and/or modifications.

330. In response to commenters' arguments that a 150-calendar day restudy deadline is too long, we note that if transmission providers complete the cluster restudy prior to the full 150-calendar day period elapsing, transmission providers may move to the facilities study stage at that time. As such, the adopted 150-calendar day cluster restudy time frame accommodates more complex instances of cluster restudies while still allowing flexibility for transmission providers to move forward without waiting for the deadline to pass if the restudy does not take the full 150 calendar days.

331. Additionally, we decline to adopt suggestions to allow transmission providers flexibility to set their own study deadlines, which would undermine the purpose of ensuring that transmission providers complete interconnection studies by standard deadlines prescribed by their tariffs and would thus be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner.

j. Restudies Triggered by Higher- or Equally Queued Generating Facility

i. NOPR Proposal

332. In the NOPR, the Commission proposed to revise section 8.5 (Restudy) of the pro forma LGIP to make clear that restudies can be triggered by a higher- or equally queued interconnection request withdrawing from the interconnection queue or modification of a higher- or equally queued interconnection request pursuant to section 4.4 (Modifications) of the pro forma LGIP.

ii. Comments

333. Shell argues the withdrawal of an interconnection request should not automatically trigger a cluster restudy, and instead the Commission should consider a process and cost allocation method that creates a “secondary market” to replace a proposed generating facility that withdraws with another generating facility in the same location or nearby. CREA and NewSun agree with Shell's suggestion to allow interconnection customers to step in and assume the rights of any interconnection customer that withdraws its interconnection request. Similarly, R Street argues that the cluster study process should not impede the transfer of interconnection request “ownership,” as, according to R Street, allowing parties to trade will help ensure an efficient balance between generation additions and transmission interconnection costs.

334. MISO seeks clarification on the trigger for restudies. MISO states that its understanding is that any modification during its study process that is found to be material would not be allowed. Further, MISO contends that allowing a material modification to impact an equally queued interconnection customer seems to be inconsistent with the Commission's proposal to modify the definition of material modification. Therefore, MISO argues that there should not be a need for a restudy due to such modification. MISO asserts that the Commission should not allow modifications during the study process that materially impact other interconnection customers and may require restudies.

iii. Commission Determination

335. We adopt the proposed revisions to section 8.5 of the pro forma LGIP to make clear that restudies can be triggered by a withdrawal or modification by a higher- or equally queued interconnection request. First, we clarify that the “modification” we refer to in this section must be explicitly permitted under pro forma LGIP section 4.4. Any other modification that triggered a restudy would be found to be material and would not be allowed, as it would affect the cost and/or timing of the other customers in the interconnection queue by necessitating a restudy. Next, we find that restudies may be triggered if there is either a withdrawal or a modification explicitly permitted under pro forma LGIP section 4.4. Changes to the composition of the cluster often require the transmission provider to restudy the entire cluster to ensure that all network upgrades and the associated costs are still needed. Finally, we find that stating that restudy may be required due to the withdrawal or modification of a higher- or equally queued interconnection request, rather than requiring that a restudy must occur, provides the transmission provider with flexibility to assess whether the restudy is necessary. If the transmission provider is able to move forward without performing a full restudy, that is a preferable outcome in terms of interconnection queue efficiency, as the transmission provider can maintain the study milestones already achieved and maintain progress towards completion and operation for generating facilities in the cluster, as opposed to dedicating significant additional time required to restart and conduct the study process over again when it may not be necessary or beneficial to do so.

336. In response to Shell, CREA and NewSun, and R Street, we decline to consider modifications to the pro forma LGIP to create a “secondary market” process that would allow one generating facility to replace a similarly situated one that withdraws from the interconnection queue, where that withdrawal would otherwise trigger a restudy. The Commission did not propose such a process in the NOPR, and we do not have a sufficient record to consider adopting such a process in this final rule.

337. In response to MISO, we clarify that material modifications are defined in section 1 of the pro forma LGIP as modifications that have a material impact on the cost or timing of any interconnection request with an equal or later queue position. Under section 4.4.3 of the pro forma LGIP, if an interconnection customer chooses to move forward with the modification that has been deemed material by the transmission provider, the interconnection customer will lose its queue position and must proceed with a new interconnection request if desired. However, we note that certain modifications as listed in pro forma LGIP sections 4.4.1, 4.4.2, and 4.4.5 are permitted regardless of their impact on other interconnection customers.

k. Timing of LGIA Tender, Execution, and Filing

i. NOPR Proposal

338. In the NOPR, the Commission proposed to revise sections 11.1 (Tender) and 11.3 (Execution and Filing) of the pro forma LGIP, which include provisions related to the tender, execution, and filing of the LGIA, to incorporate a 60 calendar-day negotiation period and to incorporate the site control demonstrations and LGIA deposit provisions included in proposed section 3 of the pro forma LGIP.

ii. Comments

339. Enel states that many transmission providers and interconnection customers are confused as to how to interpret pro forma LGIP sections 11.1 and 11.2 in relation to each other, and Enel thus recommends that the Commission revise and simplify sections 11.1 and 11.2 of the pro forma LGIP to provide more clarity. Enel argues that additional changes are needed to address common delays in completion of the final facilities study report; delays in a transmission provider issuing the draft LGIA; and delays in the transmission provider executing the LGIA after receiving the interconnection customer's signature and milestones, and subsequently proposes targeted revisions to pro forma LGIP sections 11.1 and 11.2 to provide additional time for interconnection customers to review and negotiate LGIAs.

340. Tri-State notes that section 11.3 of the pro forma LGIP is unclear when it states that the “Transmission Provider must not suspend the LGIA” until the interconnection customer meets the tariff requirements because it is the interconnection customer that has the ability to suspend a proposed generating facility.

341. APS requests that the Commission be more prescriptive on what is considered reasonable evidence of achieving development milestones when executing an LGIA in the same manner that the Commission defines commercial readiness milestones in order to avoid subjectivity and potential disagreements regarding what is considered “reasonable.” APS also asserts that the reference to simultaneous submission of the interconnection customer-executed LGIA and the continued demonstration of site control is duplicative and unnecessary if an interconnection customer demonstrates site control at the time an interconnection request is made.

342. Hydropower Commenters contend that the Commission should provide additional time for payment of interconnection costs after the interconnection process is complete. Hydropower Commenters assert that once a transmission provider delivers the interconnection agreement and construction agreement to the interconnection customer, the interconnection customer has only 60 days to execute the agreements and 15 business days after receipt of the signed agreements to demonstrate site control or post a non-refundable additional security deposit to cover the interconnection costs. Hydropower Commenters argue that, because the end of the study process may occur long before a proposed generating facility is fully funded, and the interconnection customer risks losing its queue position if it does not execute the agreements, the Commission should extend this period to at least one year so the interconnection customer has time to secure funding and avoids having to restart the interconnection process.

343. NV Energy similarly suggests changes to the NOPR proposal to allow interconnection customers that request a transmission provider to file an unexecuted LGIA to satisfy these requirements within 15 days of the Commission issuing an order. NV Energy states that the proposed extra time between receiving a draft LGIA and having to satisfy these requirements creates an undue preferential advantage for those interconnection customers that request unexecuted LGIAs to be filed at the Commission and could delay the interconnection process for others. To address this issue, NV Energy suggests that interconnection customers who choose to have their unexecuted LGIAs filed with the Commission should be required to submit their data to the transmission provider by the day after the filing of the LGIA.

iii. Commission Determination

344. We adopt, in part, and modify, in part, the proposal to revise sections 11.1 and 11.3 of the pro forma LGIP, regarding the tendering, execution, and filing of the LGIA, to incorporate a 60-calendar day negotiation period and to incorporate the site control demonstrations and LGIA deposit provisions included in proposed section 3 of the pro forma LGIP. We find that the revisions to section 11.1 of the pro forma LGIP that we adopt herein clarify the process of tendering an LGIA and the revisions to section 11.3 of the pro forma LGIP that we adopt herein incorporate the site control and LGIA deposit provisions adopted elsewhere in this final rule.

345. We do not adopt the proposed revisions to pro forma LGIP section 11.3 that reference the commercial readiness demonstration provisions of proposed section 8.1 of the pro forma LGIP because we are not adopting those provisions, as discussed below in section III.A.6.

346. We modify the proposed revisions to pro forma LGIP section 11.3, as requested by Tri-State, because we agree that the proposal was unclear when it stated that “Transmission Provider must not suspend the LGIA under LGIA article 5.16” until the interconnection customer meets certain tariff requirements. We modify pro forma LGIP section 11.3 to instead state: “Interconnection Customer may not request to suspend its LGIA under LGIA Article 5.16 until Interconnection Customer” meets certain tariff requirements. This reflects the fact that it is the interconnection customer, not the transmission provider, that has the right to suspend the LGIA.

347. We also modify proposed section 11.3 of the pro forma LGIP in response to NV Energy's concerns about favoring interconnection customers that request a transmission provider to file an unexecuted LGIA. We agree that the proposal has the potential to encourage more filings of unexecuted LGIAs simply to delay the due date for submission of deposits, evidence of site control, and milestone progress data. We therefore modify the proposal such that interconnection customers that request a transmission provider to file an unexecuted LGIA must satisfy these submission requirements within 10 business days after the date of the filing of the unexecuted LGIA with the Commission.

348. We decline to make further modifications to the proposal beyond those discussed above. Enel has neither explained why pro forma LGIP sections 11.1, as revised by this final rule, and 11.2, cause an unjust and unreasonable result for interconnection customers, nor has it explained why changes to the negotiation process between transmission providers and interconnection customers are needed at this time.

349. Similarly, we decline APS' request that the Commission be “more prescriptive” on what is considered reasonable evidence of achieving development milestones when executing an LGIA. We believe that the requirement that interconnection customers provide reasonable evidence is sufficient to ensure just and reasonable rates without imposing detailed requirements surrounding the meaning of “reasonable.” There is inadequate record to demonstrate a more prescriptive approach is needed. For example, development milestones generally involve the execution of contracts or applications for permits.

350. We also decline to adopt Hydropower Commenters' request to modify the pro forma LGIP to provide additional time for payment of interconnection costs after the conclusion of the interconnection study process. The pro forma LGIP, as modified by this final rule, requires transmission providers to give interconnection customers ample notice of costs and the timing that costs are due as part of the interconnection process so that interconnection customers can secure funding for a proposed generating facility. We are unpersuaded that interconnection customers should have additional time beyond that already provided, especially given the number of generating facilities that have been developed using the existing process and the added transparency that we adopt in this final rule that will only serve to improve the ability of interconnection customers to secure financing.

l. Cluster Subgroups

i. NOPR Proposal

351. In the NOPR, the Commission sought comment on whether to require transmission providers to conduct cluster studies on subgroups of interconnection customers based on areas of geographic and electric relevance, and, if so, whether to adopt provisions governing how cluster areas should be formed to ensure that cluster areas are formed in a transparent and not unduly discriminatory manner.

ii. Comments

352. A number of commenters support permitting transmission providers to study clusters in subgroups based on geographic or electrical relevance, but some argue that clustering projects in subgroups should not be required.

353. Several entities argue that clustering around subgroups of geographic or electrical relevance is a reasonable approach, particularly for transmission providers with a large or fragmented footprint. Some commenters argue that creating sub-clusters may not make sense for transmission providers with small footprints. Several commenters argue that transmission providers should have flexibility in deciding whether to form subgroups of interconnection customers because geographic and electric relevance will vary with each cluster study. Similarly, some commenters contend that the Commission should not mandate studying subgroups based on geographic and electric relevance, and that the efficacy of this approach should instead first be evaluated through experience.

354. PacifiCorp notes that using cluster study areas allows it to assess and more efficiently allocate the costs of network upgrades to requesters triggering the improvements and protect interconnection customers in different clusters from bearing the cost of network upgrades triggered by interconnection customers in different parts of PacifiCorp's system, thereby facilitating more expedient processing of all the cluster studies. PacifiCorp asserts that its ability to create cluster areas where appropriate is a critical feature of its cluster study process, adding that cluster areas can facilitate expedient processing of interconnection requests that might otherwise be delayed due to restudies or other study complications.

355. On the other hand, Pattern Energy asserts that designating subregions may result in separate geographic regions bearing a disproportionate share of network upgrade costs that provide regional benefits and should be subject to regional cost allocations. Pattern Energy notes that it is also important for the transmission provider to review subregional cluster study results and determine whether inter-cluster network upgrades would better serve the needs of the subregional clusters during each planning cycle. Illinois Commission asserts that interconnection requests that are near one another might have a greater impact on each other, and subgroups could ease the study process, but any subgroup process should not compromise cost or timing efficiency gains that the clustering process is meant to address. OPSI argues that to reduce the “first mover disadvantage” most effectively, the Commission should continue to analyze and further explain in any final rule whether a region-wide, annual cluster in a large region like PJM could benefit from better defined subclusters. OPSI asserts that the Commission should further evaluate methods to ensure that clusters facilitate identification of shared network upgrades by grouping generating facilities based on areas of geographic and electrical relevance.

356. Avangrid contends that the open call cluster request window should have geographic distinctions, but that if the open call results in only one interconnection request in a particular area of the system electrically, this interconnection should be able to undergo a process reminiscent of current serial study processes in a parallel track if it will influence, or be influenced by, the broader cluster study process.

357. Some commenters argue that the Commission should set forth specific mandates to transmission providers on how cluster areas should be formed. CREA and NewSun argue that clear mandates would prevent transmission providers from subgrouping as a means to engage in anti-competitive conduct ( e.g., assigning the utility's own generation to subgroups with lower congestion or network upgrade costs). Similarly, Fervo Energy contends that the Commission should adopt provisions governing how cluster areas should be formed to ensure that clusters are formed in a transparent and not unduly discriminatory manner.

358. Other commenters argue that the Commission should provide flexibility by creating a general framework for defining cluster study subgroups appropriate for their own regions, rather than a specific set of requirements. Some commenters further contend that transmission providers have extensive knowledge of their own transmission systems, and the particular interconnection requests that should and should not be included within a cluster based on their system's geography, electric configuration, or other relevant factors.

A number of commenters suggest that transmission providers develop subgroup criteria with stakeholder input.

359. Other commenters argue that the Commission should allow variation in how transmission providers form clusters. For example, R Street argues that the Commission should refrain from being too prescriptive regarding how cluster areas are defined, and instead require that transmission providers publish their cluster definitions well in advance of the request window for interconnection requests. Clean Energy States believe that allowing interconnection customers to create their own clusters would result in an internal vetting of proposed generating facilities in the cluster and negotiation about how costs and penalties will be managed. Regarding how clusters should be defined, several commenters provide suggestions for subgroup criteria beyond geographic proximity or electrical relevance. PPL suggests cluster formation be based on geographic or electrical proximity only and that interconnection customers should not be separated based on fuel type. Energy Keepers asserts that, when utilities are considering cluster studies on subgroups of interconnection customers, those clusters should be based on location. Clean Energy Associations, Vistra, and ENGIE assert that cluster studies should evaluate subgroups of projects based on electric proximity to one another. Further, ENGIE agrees that distribution factors should not be the sole indicator of electrical proximity as there are other factors around which subgroups might appropriately be grouped.

360. Xcel argues that it is not necessary to create “separate” clusters for electrically distinct regions, noting that PSCo separates interconnection requests into “study pockets” based on geographic/electrical separation but studies all the interconnection requests in a single cluster.

361. Clean Energy Associations assert that the Commission should make clear whether a cluster study must identify the upgrades required in order to interconnect every interconnection request in whole, or whether it might identify upgrades that would be sufficient for only a subset of the interconnection requests; if the latter, Clean Energy Associations continue, the Commission should establish a pro forma process for determining which requests might proceed with those initial upgrades. Clean Energy Associations claim that transmission development is a “lumpy” process, and in some cases there can be “breakpoints” where adding one more generating facility can result in a significant per-unit cost increase compared to the interconnection costs that could have been achieved for a subset of the interconnection requests up to that point. Clean Energy Associations state that, in the current ISO–NE cluster study process, ISO–NE attempts to identify such breakpoints and fills each cluster up to that level, with remaining requests able to either withdraw or proceed into the next cluster study. Some commenters contend that studies should include or consider including breakpoints, which can provide helpful information to inform interconnection customers' next steps.

362. Finally, several commenters encourage transparency and request that any subgrouping criteria be publicly posted or filed by transmission providers or RTOs/ISOs.

iii. Commission Determination

363. We will neither require transmission providers to conduct cluster studies on subgroups of interconnection customers based on areas of geographic and electric relevance, nor adopt provisions governing how cluster subgroup areas should be formed. However, we adopt revisions to section 7.4 of the pro forma LGIP to permit transmission providers to use subgroups in their cluster study process if they so choose. To the extent a transmission provider chooses to use subgroups, it must include provisions in its pro forma LGIP in its tariff that state that it will use subgroups. We further modify section 7.4 of the pro forma LGIP to require that the criteria used to define subgroups be publicly posted on a publicly accessible website. We believe that publicly sharing these criteria is important to ensure adequate transparency and to safeguard against the potential for undue discrimination in the design and implementation of cluster subgroups.

364. We agree with commenters that support permitting transmission providers to study clusters in subgroups based on geographic or electrical relevance but argue that clustering projects in subgroups should not be required. We believe that there may be benefits to studying clusters in subgroups in certain circumstances, and therefore we do not want to preclude transmission providers from proposing such a process on compliance. At the same time, based on the record, we do not believe that requiring subgroups for all transmission providers is appropriate. In some instances, the administrative burden of defining and separately studying subgroups may not outweigh the benefits.

365. Consistent with our decision to not require transmission providers to conduct cluster studies on subgroups of interconnection customers, we decline to adopt provisions governing how clusters should be formed. Rather, we believe it more appropriate to allow transmission providers to determine how to define subclusters appropriate for their regions, taking into consideration their system geography, electrical configuration, and other relevant factors.

366. Regarding concerns raised by Pattern Energy and others about the use of subgroups resulting in a disproportionate allocation of network upgrade costs, we note that if a transmission provider opts to study in subgroups, it cannot change how it allocates network upgrade costs. That is, it must follow the requirement adopted in this final rule to use a proportional impact method to allocate system network upgrade costs among all interconnection customers in the cluster regardless of subgroup, as discussed further below. Because transmission providers will be using a proportional impact method to allocate system network upgrade costs, regardless of whether interconnection customers are studied in subgroups, we believe subgroups would not change an interconnection customer's potential cost allocation. An interconnection customer with an impact on a network upgrade would be allocated its portion of the cost of that network upgrade regardless of whether its request was studied in a subgroup with another interconnection customer allocated a different portion of that network upgrade.

m. Restudy

i. NOPR Proposal

367. In the NOPR, the Commission sought comment on whether to specify in the pro forma LGIP how cluster studies must be rerun after restudy is triggered or whether there are provisions the Commission could adopt to improve the efficacy of the restudy process, such as preventing excessive restudy by limiting the transmission provider to two restudies per month within the 150-calendar day cluster restudy period.

ii. Comments

368. Eversource recommends that the Commission adopt detailed restudy rules. Pine Gate suggests that the Commission provide guidance on when the need for a restudy is triggered, as even minimal changes can trigger long and costly restudies. Pine Gate recommends that the Commission: (1) furnish criteria to be used by transmission providers in determining whether a restudy is required; (2) require transmission providers to limit the scope of restudies if only a local impact is anticipated; (3) require transmission providers to publish restudy criteria, determinations, and scoping as resources for interconnection customers; (4) permit interconnection customers to send engineering analyses applying the transmission provider's published criteria, which could be used by the transmission provider to help decide whether to conduct a restudy, thereby reducing the transmission providers' burden; and (5) not require every cluster participant to submit additional study deposits until the transmission provider determines the need for and scope of any restudy and affected cluster participants are notified. Pattern Energy believes that transmission providers should be required to develop expedited modeling processes to evaluate whether the withdrawal of an interconnection request or other allowed modification may cause a full restudy. Pattern Energy argues that such a requirement would allow interconnection customers to make better informed decisions about withdrawing or modifying interconnection requests.

369. Conversely, a number of commenters recommend that the Commission provide flexibility to transmission providers and not adopt overly prescriptive requirements specifying how cluster studies must be rerun after a restudy is triggered. MISO encourages the Commission to grant maximum flexibility to transmission providers regarding the necessity of restudies and the scope of restudies as the situations that give rise to restudies are varied and unique. PJM states that it finds acceptable the NOPR's proposal requiring transmission providers to specify in their tariffs how cluster studies must be rerun, but suggests the Commission avoid being overly prescriptive regarding restudies. Xcel recommends that the Commission not propose additional prescriptive requirements on how restudies must be performed, but suggests that if there are multiple clusters impacted, where each cluster only has “ready” projects, the transmission provider may combine the clusters into a single cluster for a single restudy instead of restudying multiple clusters.

370. Some commenters support limiting the number of restudies a transmission provider may perform within a restudy period. Ameren states that limiting the number of restudies to two within the 150-day cluster restudy period seems reasonable, given the size of the many interconnection queues and the reported uncertainty of interconnection customers in the queue. Ohio Commission Consumer Advocate concurs that conducting a single cluster study and cluster restudy annually may reduce the risk of cascading restudies occurring if an interconnection customer withdraws from the interconnection queue.

371. A few commenters argue that the Commission should address the lack of any limit on restudy requests, stating that this issue is a known shortcoming that results in essentially unlimited time and resource obligations for interconnection customers. Southern expresses concern that the proposed pro forma LGIP language allows for multiple restudies, which would interfere with a one-year timeline maximum.

372. A number of commenters do not support a set limit on the number of restudies a transmission provider may perform. Bonneville asserts that efforts to prevent excessive restudies ( e.g., limit of two per month) could be overly prescriptive. Bonneville argues that transmission providers should be afforded the flexibility to determine and publish the timing of any restudy, and limits thereto, on their OASIS sites to help to facilitate transparency and ensure timelines are attainable. NextEra states that experience has shown that having a defined and limited number of restudies, such as in MISO's three-phase process, can help limit the duration of the study process. However, NextEra contends that it would be too restrictive for the Commission to dictate exactly how transmission providers should limit the number of restudies, and argues that the final rule should instead require that each transmission provider propose to the Commission on compliance what rules or processes it will use to ensure there is not an undefined and unpredictable number of restudies, e.g., whether it will have a fixed number of scheduled restudies or some other method to limit the number of restudies and associated potential delays. PacifiCorp notes that, because restudies are typically triggered through a withdrawal or modification of an interconnection request, the transmission provider is responding to changes, typically outside of its control, that warrant a restudy and undertaking efforts to complete the restudy as efficiently as possible.

373. Idaho Power requests clarification surrounding the single cluster and cluster restudy process and the suggested limitation of allowing only two restudies per month within the 150-day cluster restudy period. Idaho Power states, for example, an entity may have three cluster areas requiring three cluster studies, and withdrawals from those studies may require more than two simultaneous cluster restudies in the same month to prevent delay of any one cluster restudy.

iii. Commission Determination

374. We decline to modify the pro forma LGIP to specify how a transmission provider conducts cluster restudies and when it must conduct a cluster restudy. We find persuasive the arguments of several commenters that the Commission allow transmission providers flexibility on how and whether to conduct a restudy and the scope and frequency of any restudies. The transmission provider is best positioned to determine when and how to conduct a restudy, including the scope and frequency of restudies, because it determines the need for the restudies to maintain the reliability of the transmission system. We agree with commenters like MISO and Xcel that different events can trigger restudies, and transmission providers are in the best position to determine whether an event warrants a restudy, and if so, what the scope of that restudy should be (for example, whether a new study is required, or whether only a modification as to certain model data and a reanalysis is required).

375. As to frequency of restudies, we also agree with PacifiCorp that because restudies are typically triggered through a withdrawal of an interconnection request, the transmission provider is responding to changes, typically outside of its control, that warrant a restudy, and thus limiting the number of restudies could hinder the ability of a transmission provider to undertake efforts to complete a restudy as efficiently as possible. Because we are not modifying the pro forma LGIP to specify how cluster studies must be rerun after restudy is triggered, we will also not limit the transmission provider to two restudies per month within the 150-calendar day cluster restudy period. We agree with commenters like Bonneville, NextEra, and PacifiCorp that it would be too restrictive for the Commission to dictate exactly how transmission providers should limit the number of restudies.

376. Regarding Idaho Power's request for clarification on the suggested limitation of allowing only two restudies per month within the 150-calendar day cluster restudy period, because we are not adopting a limit of two restudies per month within the restudy period, Idaho Power's clarification request is moot.

n. Exceptions to the Cluster Study Process

i. NOPR Proposal

377. In the NOPR, the Commission sought comment on whether there should be an option in the pro forma LGIP for transmission providers to process some interconnection requests outside of the annual cluster study process, and if so, in what circumstances and on what time frame (for completion of the study), and on what priority compared to any active clusters.

ii. Comments

378. Several parties generally support an option in the pro forma LGIP for some interconnection requests to be processed outside of the annual cluster study process, with some commenters supporting such an option only under specific circumstances. For example, Ørsted argues that such an option could be beneficial in the case of a stand alone network upgrade built to serve a single interconnection customer that will not impact the cluster. Some commenters suggest establishing a separate process outside of the cluster study process to expedite certain interconnection requests. Several commenters contend that an option to study interconnection requests outside of clusters would be particularly beneficial as more renewable generating facilities are added to the resource mix. Two commenters support exceptions for replacement resources specifically. A few commenters argue that the Commission should allow transmission providers to separately or individually study certain interconnection requests that are not geographically or electrically relevant to other interconnection requests in the interconnection queue.

379. Additionally, APPA–LPPC request that the Commission recognize that there are transmission providers, principally in rural communities or where the transmission system provides limited opportunities for advantageous interconnections, where there are too few interconnection requests to justify a cluster study approach. In these cases, APPA–LPPC recommend that the Commission provide for a self-executing “opt out,” permitting the transmission providers to continue to study interconnection requests on a serial basis.

380. Northwest and Intermountain recommend a limited exception to the cluster study process requirement to allow existing interconnection customers seeking to make changes to their proposed generating facilities to be processed outside of the cluster study process where the proposed change had no demonstrable incremental impact on the transmission system.

381. Xcel argues that proposed generating facilities needed to serve load should be allowed to be processed outside of the annual cluster study process. AEP argues that transmission providers with a reserve margin obligation must have the ability to prioritize the interconnection of needed capacity in the interconnection process.

382. Iowa Commission argues that state commissions should have the ability to require studies outside of annual cluster studies, which would help increase the availability of needed generation for resource adequacy and maintain local reliability needs, particularly as large intermittent generating facilities are interconnecting to the system at a rapid pace. Iowa Commission explains that such studies could potentially address increased transmission system stability and also minimize future transmission costs because of the “transient nature” of some load and resource changes.

383. Similarly, UMPA contends that the Commission should require a process outside of the annual cluster study process to expedite interconnection requests that are beyond the exploration phase and ready for development. UMPA explains that some load serving entities search for potential resources to meet their integrated resource plan based on a request for proposal or certain competitive criteria, but are then confronted with a choice among proposed generating facilities that meet the criteria but are lower in the interconnection queue, or proposed generating facilities that do not satisfy the criteria, but are higher in the interconnection queue. Therefore, UMPA argues that it would be helpful to a load serving entity with a development-ready generating facility to be able to enter into a parallel process outside of the annual cluster study process in order to expedite an interconnection request.

384. AEP also suggests that RTOs/ISOs that have consolidated their small and large generator interconnection procedures into a single generator interconnection procedure should be permitted to propose that all or some smaller-sized generating facilities, such as 20 MW or smaller generating facilities, would be “too small” to need to be included in the cluster.

385. Other commenters believe that any exceptions to the cluster study process requirement should be very limited. NRECA asserts that if the final rule provides for any interconnection requests to be processed outside the annual cluster study process, it should be limited to a narrow category of interconnection requests, such as emergency replacements of failed equipment driven by near-term reliability needs. MISO asserts that there should be very limited exceptions, explaining that it has limited its non-queue interconnection requests to those that are associated with existing generating facilities that do not seek to add new or additional interconnection service, or small interconnection requests. Outside of those limited exceptions, MISO states that it does not support processing any other interconnection requests outside of the interconnection queue.

386. ENGIE recommends that exceptions be limited to requests that “need[ ] to be studied outside of the cluster process, e.g., transmission planning and state or public policy issues.” ENGIE states that it is possible that there may be other exceptions made in emergency situations, in which case, the granting of exceptions should be very limited in scope, subject to transparent criteria, and the rationale made publicly available. ENGIE further recommends that every interconnection request, including emergency requests, enter through the cluster request window, but that an emergency request be accelerated if it meets the pre-determined and publicly available requirements.

387. A number of commenters oppose an option to process interconnection requests outside of the annual cluster study process. A few parties argue that maintaining an option to process interconnection requests outside of the annual cluster study process would likely create an administrative burden for transmission providers without a clear benefit. Some commenters assert that processing certain interconnection requests outside of the interconnection queue could increase the time needed to complete the cluster studies or could increase restudies.

388. Some commenters express concern that such an option could become overly used or abused. Enel asserts that if interconnection requests could be accepted for processing outside the annual cluster study process, especially on an individual basis, there would be a high degree of interest because this would allow interconnection customers to avoid being allocated the costs of regional upgrades that result from many cluster studies. Bonneville asserts that permitting an interconnection request to be processed outside of the annual cluster study process would create a “perverse incentive” for some interconnection customers to forgo the cluster study process to avoid cluster study requirements.

389. OMS states that it has considered the benefits of some sort of a “fast-lane process” for resources that are more “certain,” like those that have received all necessary permits and regulatory approvals. OMS states that use of such a mechanism may be important or necessary in the future to address reliability concerns, but OMS explains that it is neutral on the proposal because bypassing the interconnection queue invites a myriad of potential unintended consequences that might not outweigh the value OMS otherwise envisions in this type of mechanism.

390. PacifiCorp states that the Commission's proposal on this topic is not clear. PacifiCorp states that, if the NOPR refers to an interconnection customer's ability to request surplus or provisional interconnection service or an informational interconnection study, PacifiCorp supports maintaining these options. However, PacifiCorp requests the Commission clarify that requests for such service will be evaluated in the order that completed interconnection requests are received. PacifiCorp states that it does not currently support expanding non-cluster service and study offerings.

391. Regarding under what time frame and at what priority interconnection requests should be studied outside of the cluster study process, as compared to any active clusters, Fervo Energy recommends a 270-day time frame for completion of the study with secondary priority to the active cluster studies.

iii. Commission Determination

392. We decline to include an additional option in the pro forma LGIP for transmission providers to process some interconnection requests outside the annual cluster study process adopted in this final rule. We find that establishing in the pro forma LGIP a separate interconnection process outside the cluster study process could detract from transmission providers' efforts to efficiently process cluster studies—a point persuasively argued by commenters. A separate set of interconnection studies outside of the cluster study process could cause transmission providers to divert resources away from cluster studies and cluster restudies. Such diversion could hinder the transmission provider from meeting the cluster study and cluster restudy deadlines adopted in this final rule, which would be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. We also find that such an option in the pro forma LGIP would be too open-ended, as it would leave a significant amount of discretion to the transmission provider to create new study processes for processing any types of interconnection requests it chooses outside the cluster study process and could therefore result in a separate but unduly discriminatory interconnection process. We further find that establishing such an open-ended option in the pro forma LGIP could create an incentive for some interconnection customers to forgo the cluster study process, which could increase the time and resources needed for transmission providers to complete the cluster studies or could increase restudies.

393. A number of commenters see benefits to establishing an option in the pro forma LGIP for particular types of interconnection requests to be processed outside of the annual cluster study process, such as for generator replacement, projects ready for development, emergency replacements, for certain special circumstances, or for transmission providers who have too few interconnection requests to justify a cluster study approach. However, we are not persuaded that establishing such processes in the pro forma LGIP is necessary to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. We believe that processing such one-off interconnection requests will be needed less often under the cluster study process adopted in this final rule, and therefore, any benefits that exist to processing some interconnection requests outside a transmission provider's interconnection process may be outweighed by the benefit of allowing transmission providers to conduct cluster studies efficiently without diverting resources to a separate set of studies.

394. In response to the Iowa Commission's argument that state commissions should be able to require studies outside of annual cluster studies, we similarly find that any such studies would divert a transmission provider's resources away from conducting the cluster studies and cluster restudies.

395. Regarding AEP's suggestion that those RTOs/ISOs that have consolidated their small and large generator interconnection procedures should be permitted to propose that all or some smaller-sized generating facilities would be “too small” to be included in the cluster, we note that the Commission did not propose the cluster study process for small generating facilities subject to the pro forma SGIP.

396. Finally, because we are not revising the pro forma LGIP to add a new option for some interconnection requests to be processed outside of the annual cluster study process, we find moot those comments on the time frame and priority of interconnection requests studied outside of the cluster study process. In response to PacifiCorp, we clarify that requests for surplus interconnection service, or an optional interconnection study, will continue to be processed as received and outside of the cluster study process, and that this does not entail an expansion of non-cluster service and study offerings.

o. Other Comments

i. Comments

397. Some entities recommend automation or standardization of the interconnection queue process and studies. NextEra states that the proposed cluster study process time frame requires significant information technology and personnel resources. NextEra argues that, despite the lack of such a proposal in the NOPR, automation of the interconnection queue process and studies is likely the key to compressing interconnection process timelines. NextEra encourages the Commission to convene a technical conference or other process to focus on the root causes of interconnection study delays as well as the potential to accelerate the interconnection queue process through enhanced automation.

398. Several commenters argue that the Commission should require transmission providers to provide more cost information to interconnection customers throughout the interconnection process. Clean Energy Associations and SEIA argue that cluster studies should also ensure that interim cost information is made available to interconnection customers so that they can make more informed decisions earlier in the interconnection process, which will in turn lead to a more efficient interconnection process overall. Clean Energy Associations argue that as part of the cluster studies provided to interconnection customers prior to their receiving facilities studies, the Commission should require transmission providers to provide interconnection customers with cost estimates for the upgrades required if they were to request ERIS or NRIS (or long-term firm transmission service), respectively—and coupled with minimum thresholds for materiality (such as distribution factor) and transparency regarding how these costs are derived (detailing the assumptions and criteria that will be used). Clean Energy Associations also suggest that the Commission should provide concrete direction regarding how differing service types should be studied, and what outcome an interconnection customer should receive for making the necessary transmission system improvements to obtain that interconnection service. AEE similarly believes that additional reforms are needed to bring more transparency and predictability to interconnection costs, and without this transparency and predictability, interconnection customers face continued risks of unjust and unreasonable interconnection study results that derail or delay interconnection requests and cause increased costs.

399. Affected Interconnection Customers state that the Commission should permit interconnection customers to use independent studies to demonstrate whether the request for limited interconnection service would result in stability, short circuit, thermal, and/or voltage issues, if the transmission provider or transmission owner is unable to complete the studies on time. Affected Interconnection Customers argue that allowing interconnection customers to use any available resources to conduct these studies would enable already built interconnection facilities to flow power onto the system, as long as studies show that such interim services will not harm the system.

400. Clean Energy Associations ask that in a final rule, the Commission adopt a cost threshold (in terms of the anticipated upgrade cost relative to distribution factor) beyond which upgrades should be evaluated in the next near-term transmission planning process. Similarly, Clean Energy Associations argue that cumulative congestion issues should also be addressed via the transmission planning process.

ii. Commission Determination

401. We decline to adopt the remainder of the proposals advocated for in the comments regarding our requirement for transmission providers to use a cluster study process. We decline to adopt three of these proposals because they are outside the scope of the NOPR: (1) NextEra's request to require or standardize automated processing of interconnection requests; (2) Clean Energy Associations' argument that the Commission should adopt a cost threshold beyond which upgrades should be evaluated in the next near-term transmission planning process; and (3) Clean Energy Associations' argument that the Commission should provide concrete direction regarding how differing service types should be studied, and what outcome an interconnection customer should receive for making the necessary transmission system improvements to obtain that interconnection service.

402. Regarding Affected Interconnection Customers' arguments discussing the use of independent studies, we note that interconnection customers can use independent resources during the interconnection process. However, the results of independent studies will not be binding on transmission providers, as the use of studies conducted by an interconnection customer cannot ensure that the cluster study process results in a just, reasonable, and not unduly discriminatory or preferential outcome for all interconnection customers in the cluster. In addition, transmission providers must be able to conduct the necessary studies to maintain the reliability of their transmission system.

403. We will not require transmission providers to provide additional cost information to interconnection customers that is not already required to be provided pursuant to the pro forma LGIP, as modified by this final rule. For example, revised pro forma LGIP sections 3.4.5 (Customer Engagement Window) and 8.1 (Interconnection Facilities Study Agreement) require the transmission provider to provide the interconnection customer with a good faith estimate of the costs of the cluster study and the interconnection facility study, respectively. Similarly, revised pro forma LGIP sections 7.3 (Scope of Cluster Study) and 8.2 (Scope of Interconnection Facilities Study) require the transmission provider to provide cost estimates for interconnection facilities and network upgrades. It is unclear what other “interim cost information” Clean Energy Associations want transmission providers to provide, nor the value of such information vis-à-vis the burden on transmission providers to develop it.

404. Clean Energy Associations argue that as part of the cluster studies provided to interconnection customers prior to receiving facilities studies, the Commission should require transmission providers to provide interconnection customers with cost estimates for the upgrades required if they were to request ERIS or NRIS. Section 3.2 of the pro forma LGIP provides that an interconnection customer requesting NRIS may also request that it be concurrently studied for ERIS, up to the point when the facility study agreement is executed. As the pro forma LGIP already provides interconnection customers the ability to have both ERIS and NRIS studied concurrently, we find Clean Energy Associations' request moot.

3. Allocation of Cluster Study Costs

a. NOPR Proposal

405. In the NOPR, the Commission proposed to require transmission providers to allocate the shared costs of cluster studies as follows: 90% of the applicable study costs allocated pro rata to interconnection customers based on requested MWs included in the applicable cluster, and 10% of the applicable study costs allocated per capita to interconnection customers based on the number of interconnection requests included in the applicable cluster. The Commission preliminarily found that this allocation of the costs of cluster studies would result in just and reasonable Commission-jurisdictional rates because it appropriately recognizes that the MW size of a cluster has a dramatic impact on the cost of studying the cluster, while also recognizing that the number of interconnection requests included in the cluster also impacts the cost of studying the cluster, but to a lesser degree. The Commission sought comment on whether a different cost allocation approach may be appropriate or whether each transmission provider should be provided additional flexibility to propose a cost allocation approach on compliance with any final rule.

b. Comments

i. Comments in Support

406. Multiple commenters support the proposal. Clean Energy Buyers note that certainty and consistency in cost allocation for interconnection studies will be helpful for interconnection customers that site generating facilities in more than one region. Idaho Power adds that a uniform cost allocation would prevent interconnection customers from “shopping around” for the best price for larger generating facility locations. Duke Southeast Utilities note that Duke Carolinas Utilities' currently effective LGIP/LGIA contains the same 90/10 cost allocation, which it states provides a balanced and equitable study cost allocation based on the Commission's cost causation principle. Duke Southeast Utilities assert that the proposed allocation aligns with study deposits that would be submitted based on varying assumptions around the number and size of interconnection requests submitted into the cluster study process.

ii. Comments in Opposition

407. Several commenters oppose the proposal. For instance, National Grid and NRECA argue that any predetermined study cost allocation method will produce results that do not comport with cost causation. National Grid gives the example of a 20 MW generating facility that has unique or complex engineering features at a particular point of interconnection that may require considerably more time to conduct a study than a much larger 100 MW generating facility; in this situation, according to National Grid, the 90/10 cost allocation methodology proposed in the NOPR would not align with cost causation, a problem that would be exacerbated if the interconnection customer withdraws the interconnection request. National Grid asserts that a predetermined cost allocation risks undermining competitive pressures in the interconnection process, which it states should be retained to the maximum extent possible consistent with revisions to mitigate the existing interconnection queue inefficiencies. Similarly, Xcel and NextEra argue that the size of the interconnection request does not impact the study costs by a 9:1 ratio compared to the number of interconnection requests, noting that the size of the interconnection request does not materially impact the time to add the generating facility to the model or time to design the interconnecting substation. NRECA adds that the Commission has not produced data showing the fixed costs of processing an interconnection request or a precise linear correlation between generating facility size and study costs. rPlus argues that the proposed 90/10 cost allocation is “unduly discriminatory toward pumped storage, and wholly disincentivizes large capacity projects.” rPlus argues that the assertion that the MW size of a cluster study is significantly more impactful on the cost and effort required to perform the study is incorrect. rPlus states that the number of interconnection requests and the cluster size are both burdensome for the study process, as each generating facility requires its own project management, technical review, study implementation, and deliverability assessment. SDG&E and SoCal Edison agree that a 90/10 cost allocation would inappropriately burden larger generating facilities with higher study costs, as the level of effort to study an interconnection request is driven more by complexity around the point of interconnection and is not strongly correlated to the size of the generating facility.

iii. Alternatives and Requests for Flexibility

408. Several commenters put forth alternatives to the NOPR proposal. For instance, some commenters generally contend that transmission providers should allocate study costs based on the proposed generating facility's impact on the overall study, measured by the time and resources expended on a particular generating facility within the study. National Grid asserts that this process would be consistent with the current serial study approach, which directly correlates cost responsibility to cost causation. AES argues that the final rule's cost allocation framework should reflect the reality that study costs are not only a function of generating facility size, but also the location of the generating facility and the degree to which that location is constrained.

409. Several commenters argue that the Commission should allocate cluster study costs based solely on the number of interconnection requests in the cluster. Ameren and SDG&E state that, in their experience, study costs are not based on the size of the proposed generating facilities. In contrast, Fervo Energy argues against allocating study costs evenly to all interconnection customers within a cluster, asserting that it is “not at all clear” how this proposal is just and reasonable, as it strays away from allocating costs on a pro rata basis based on requested MWs.

410. CAISO argues that the proposal appears arbitrary and capricious because the Commission does not adequately explain the basis for the 90% to 10% ratio. CAISO asserts that the 10% allocation is so small as to be de minimis, yet it still increases the administrative burden to allocate the cluster study costs. CAISO argues that it would be much simpler and easier if transmission providers simply allocated all cluster study costs based on the MW capacity alone.

411. Enel argues that there are study phases where it would be more appropriate to assign study costs to individual interconnection requests, “such as the [f]acilities [s]tudy for upgrades assigned to only a single customer.” Enel argues that a 90/10 study cost split may disproportionately exclude very small generating facilities which still require modeling from study cost responsibility, and suggests that a minimum MW size be assumed, such as was used to set the minimum study deposit in proposed pro forma LGIP section 3.1.1.1.

412. Several commenters argue for a cost allocation of 50% of the study costs based on requested MW and 50% based on the number of interconnection requests in the cluster. NextEra states that, based on its experience, it takes comparable time and effort to study a small proposed generating facility as a large one. NextEra and SoCal Edison argue that allocating study costs based mostly on the MW size would likely cause some cross-subsidies from interconnection customers submitting large proposed generating facilities to those submitting smaller ones. SEIA notes that the MW size of the cluster may be artificially inflated when certain interconnection customers submit multiple exploratory requests, and recommends a 50/50 cost allocation to deter such requests. SEIA argues that, similar to CAISO's study cost allocation, the Commission should structure the cost allocation so that interconnection customers with multiple interconnection requests are responsible for a greater share of the study costs.

413. Clean Energy Associations add that cluster studies should be conducted in subgroups based on electrical relevance, and that study costs related to each subgroup should be tracked independently and allocated only among those interconnection customers within that subgroup.

414. Multiple commenters argue that the Commission should not impose a specific cluster study cost allocation, but instead allow transmission providers flexibility in proposing their own cost allocation methods. For example, APPA–LPPC argue that the use of a “one-size-fits-all” approach may result in unreasonable results in certain circumstances. APPA–LPPC assert that weighting the allocation of cluster study costs based on MWs may unfairly burden interconnection customers proposing large generating facilities in regions where a cluster is likely to include a large number of relatively small proposed generating facilities and a small number of large proposed generating facilities because study costs do not necessarily track linearly with generating facility size.

415. Several commenters argue that RTOs/ISOs should be able to retain their existing cluster study cost allocations, where applicable, because those cost allocations accomplish the purpose of the Commission's proposal to equitably allocate study costs among interconnection customers.

c. Commission Determination

416. We adopt the NOPR proposal, with modification, to revise section 13.3 (Obligation for Study Costs) of the pro forma LGIP to allow each transmission provider to propose its own study cost allocation ratio for allocating the shared costs of cluster studies between a per capita basis and pro rata by MW, provided that: between 10% and 50% of study costs must be allocated on a per capita basis, with the remainder (between 90% and 50%) allocated pro rata by MW. Under this revised provision, a transmission provider may propose to retain its existing study cost allocation ratio if it falls within this range and meets the requirements of this final rule.

417. We are persuaded by comments arguing that it is appropriate to allow transmission providers a degree of flexibility in proposing on compliance the method for allocating study costs in their tariff to adapt to their specific regional circumstances and help avoid unreasonable outcomes. Some commenters assert that the NOPR-proposed 90%–10% allocation could in some instances unduly burden larger generating facilities, such as when a cluster includes a large number of interconnection requests representing relatively small generating facilities and a small number of large generating facilities. Conversely, other commenters caution that straying too far from the NOPR proposal for a 90%–10% allocation could disproportionately burden smaller generating facilities, given the role that size may play in determining study costs. Accordingly, we believe that granting transmission providers the flexibility to propose in their tariff the study cost allocation appropriate to their region, within the limits detailed above, strikes a better balance than the NOPR proposal.

418. The revised study cost allocation requirements that we adopt in this final rule recognize that cluster study costs are impacted by both the number of interconnection requests in a cluster and the size of the proposed generating facilities in each cluster. We find that requiring transmission providers to allocate between 10% and 50% of cluster study costs on a per capita basis is just and reasonable because it ensures that interconnection customers that propose smaller generating facilities or submit multiple interconnection requests to explore different interconnection scenarios for a single proposed generator adequately contribute to study costs, particularly given that some study costs are incurred independent of the MW size of a specific proposed generating facility in a cluster. Further, we agree with commenters that observe that not all study costs track linearly with generating facility size because there are other factors, such as the point of interconnection selected, that can lead to increasingly complex studies and correspondingly higher study costs. We believe that the per capita component of the study cost allocation requirements addresses this fact. Requiring a per capita component also ensures that an interconnection customer that proposes a large generating facility in a cluster of many smaller generating facilities will not bear a disproportionate amount of the study costs. We likewise find that requiring transmission providers to allocate between 50% and 90% of study costs on a pro rata by MW basis prevents a disproportionate amount of study costs from being allocated to interconnection customers that propose smaller generating facilities in the cluster. The pro rata by MW component reflects the fact that, to a significant extent, study costs correlate to the total MW size of the cluster. In general, even if the number of interconnection requests in each cluster remains constant, we expect that a cluster of 10,000 MW will be significantly more costly to study than a cluster of 100 MW. Accordingly, requiring that a substantial share of study costs is allocated based on each generating facility's contribution to the total MW size of the cluster study ensures consistency with cost causation principles.

419. We disagree with CAISO that the Commission should require the allocation of all cluster study costs based on the MW capacity because allocating 10% of study costs on a per capita basis is de minimis and not worth the administrative burden. First, this final rule now allows transmission providers to allocate up to 50% of costs on a per capita basis. Even if a transmission provider chooses to allocate only 10% of study costs on a per capita basis, as explained above, we believe that this is an important component that is needed to ensure that study costs are allocated in a manner that is at least roughly commensurate with estimated benefits ( i.e., consistent with cost causation). We are unpersuaded that the administrative burden associated with allocating a potentially small fraction of the study costs among interconnection customers in a cluster outweighs the benefits, particularly given that nothing in the record demonstrates that those administrative costs are significant.

420. In response to commenters' arguments in favor of a uniform study cost allocation method across regions, we find that the benefits of allowing transmission providers flexibility to tailor their study cost allocation to the specific circumstances of their region outweigh the benefits of uniformity cited by commenters, such as consistency and preventing “shopping around.” We believe that the guardrails that we provide in this final rule will ensure just, reasonable, and not unduly discriminatory or preferential rates while at the same time addressing concerns with the different characteristics of regions. We urge stakeholders to engage with transmission providers as part of the compliance process as the transmission providers develop their proposed study cost allocations.

421. In response to National Grid, AES, and Clean Energy Associations' comments arguing that costs should be allocated based on individual calculations of the actual time and resources expended on a particular interconnection request, we find that such individual calculations would not only increase the administrative burden on transmission providers, but also would offer little benefit given the cluster study context, which requires transmission providers to evaluate multiple interconnection requests simultaneously. We are also unconvinced that a transmission provider could accurately perform such calculations because, as explained above, some study costs are unrelated to an individual interconnection request and are instead incurred as a matter of course as part of studying a cluster of interconnection requests.

4. Allocation of Cluster Network Upgrade Costs

a. NOPR Proposal

422. In the NOPR, the Commission proposed to require transmission providers to allocate network upgrade costs to interconnection customers within a cluster using a proportional impact method. The Commission also proposed to add the defined term proportional impact method to the pro forma LGIP and require transmission providers to revise their LGIPs to include the specific technical parameters and thresholds of their method for cost allocation. The Commission also proposed to require transmission providers to allocate the costs of transmission provider's interconnection facilities equally among all interconnection customers sharing use of the transmission provider's interconnection facilities. The Commission sought comment on: (1) whether there are specific types of analyses that the Commission should require transmission providers to use to determine the proportional impact attributed to an interconnection request, including the benefits and drawbacks of any proposed approach; (2) whether there are specific types of analyses that the Commission should prohibit because they are known to be inaccurate, provide undue discretion to the transmission provider, or could otherwise be problematic; (3) whether alternative methods to allocate the costs of network upgrades within a cluster, such as the proportional capacity method, can be sufficiently accurate in certain instances, in a manner consistent with or superior to the proposed method; and (4) whether there are some circumstances where the proportional capacity method would not be appropriate, such as circumstances where there may be potential for discriminatory treatment.

b. Comments

i. General Comments

423. Several commenters support the proposal. These commenters state that the proposed proportional impact cost allocation method is widely used, both by RTOs/ISOs and non-RTO/ISO transmission providers, and ensures that each interconnection customer contributes to the cost of network upgrades in proportion to its impact on the transmission system. These commenters assert that other options (such as a proportional capacity or a pro rata allocation per interconnection request) would be more likely to shift a disproportionate share of network upgrade costs to smaller generating facilities, which may have less impact on the transmission system. Bonneville and Interwest argue that the proportional impact method could also reduce the incentive for interconnection customers to submit multiple speculative requests and reduce the amount of cascading withdrawals and restudies. ELCON contends that, should any one proposed generating facility in the cluster have an outsized impact on the transmission system compared to other proposed generating facilities in the cluster, those other proposed generating facilities should be protected from exorbitant network upgrade costs to accommodate a proposed generating facility that may not be suitably located. CAISO adds that it has used distribution factor analysis without controversy.

424. NRECA states that it interprets this proposal to implement—and not modify, weaken, or permit deviations from—the Commission's established policy that transmission costs, including network upgrade costs, must be allocated in a manner at least reasonably commensurate with estimated benefits. NRECA states that, based on that interpretation of the NOPR's proposal, NRECA believes this method is fair to both interconnection customers and transmission providers and helps ensure that the costs to implement an interconnection request are allocated reasonably commensurate with cost causation and expected benefits. NRECA states that the proportional impact method is also reasonably transparent and relatively easy for transmission providers to implement, explain, and defend.

425. In response to the Commission's request for comment on whether there are circumstances in which the proportional capacity method would be appropriate, some commenters argue that the proportional capacity method is never appropriate and should be expressly prohibited for clusters. MISO argues that network upgrade cost allocation methods that only consider installed capacity without considering the network topology do not consider the full picture of what an interconnection customer's responsibility for the network upgrade costs should be. Pennsylvania Commission asserts that large generating facilities would continue to bear high network upgrade costs and would have an incentive to interconnect wisely, while small generating facilities, which are becoming the norm in interconnection queues, would not. Pennsylvania Commission contends that this would create a subsidy whereby large generating facilities pay a share of unnecessary network upgrade costs caused by poor siting of smaller generating facilities. Longroad Energy illustrates this point by noting that one of its generating facilities was recently allocated nearly $10 million under the proportional capacity method based solely on the generating facility's size, despite the fact that relevant interconnection studies firmly established that its generating facility, while large, actually reduced the identified overload.

426. NV Energy urges the Commission to reconsider the application of pro rata allocation of network upgrade costs over using the proportional impact method. NV Energy contends that the proportional impact method could negatively impact interconnection customers due to the time and risk of reallocations required by restudies. NV Energy argues that assigned network upgrade costs could change dramatically if a cluster participant withdraws from the interconnection queue and requires a restudy, potentially resulting in each participant's cost allocation changing. NV Energy asserts that in addition to disintegrating cost reassurance for the interconnection customer, performing studies using the proportional impact method defeats the purpose of completing cluster studies where each interconnection customer in the cluster has the same interconnection queue position and that this method will require the transmission provider to review each interconnection request within the cluster individually to assign the proportional impact.

427. NV Energy contends that using the proportional impact method to allocate the costs of network upgrades resulting from cluster studies will be burdensome in application because of the volume of interconnection requests being studied and the large number of network upgrades identified in each study. NV Energy states that, under a proportional capacity method, when an interconnection customer withdraws and the same network upgrades are deemed necessary, the transmission provider could simply reallocate a pro rata share to the remaining interconnection customers and expedite the study; however, in the case of the proportional impact method, the transmission provider would need to complete a full restudy to review each generating facility's impact on the system.

428. According to NV Energy, this issue is further exacerbated when a network upgrade becomes a shared network upgrade with another cluster and the proportional impact is expanded to include additional interconnection customers. NV Energy states that, not only would the restudy be required for the lower-queued cluster based on the withdrawal, but also the concurrently queued cluster to modify the network upgrade cost allocation. NV Energy also argues that, without a consistent proportional impact cost allocation amongst transmission providers, there is risk that this could lead to disputes at the Commission from interconnection customers, which would lead to increased costs and delays.

429. PacifiCorp strongly opposes the proportional impact method to allocate network upgrade costs. PacifiCorp argues that the Commission has not made a transmission provider-specific finding that the proportional capacity method, approved for PacifiCorp by the Commission in May 2020, is no longer just and reasonable. PacifiCorp contends that transmission providers should be permitted to use proportional capacity-based network upgrade cost allocation methods. PacifiCorp claims that the proportional capacity method it uses is informed by three additional mechanisms within the cluster study process, all of which work in tandem to ensure that costs are appropriately allocated: (1) the use of electrically or geographically relevant subregions; (2) iterative studies that consider ERIS network upgrades prior to NRIS requests; and (3) a floor of 1% of total MW within a cluster, under which interconnection requests will be deemed not to contribute to the network upgrades identified in the cluster study.

430. PacifiCorp states that the proportional capacity method also assists it in completing cluster studies and restudies on a timely basis, and minimizes disputes. PacifiCorp argues that, in sharp contrast, the proportional impact method involves a complex analysis that, in addition to being excessively time consuming, will result in disputes, both of which will put substantial pressure on PacifiCorp's ability to meet study deadlines. Therefore, according to PacifiCorp, requiring use of the proportional impact method will be counterproductive to the Commission's intent of making processing of interconnection requests more efficient.

431. PacifiCorp explains that the degree of contribution to a needed network upgrade can be very difficult to determine depending on the size, number of interconnection requests, and location of proposed generating facilities in a cluster. PacifiCorp adds that a proportional impact method analysis is complicated further by the fact that all interconnection requests within a single cluster are considered equally queued. In addition, PacifiCorp argues that, given the size of its multi-state system and the thousands of MWs of interconnection requests entering the cluster study process each year, it is simply not possible to both perform a proportional impact method analysis on each interconnection request and complete the cluster study process within 150 calendar days.

ii. Comments on Specific Proposal

(a) Specificity Regarding Technical Parameters and Thresholds

432. Several commenters state that, if the Commission adopts its proposal for each transmission provider to revise its tariff to include its specific technical parameters and thresholds for the proportional impact method for network upgrade cost allocation, the Commission should at least consider guidance or principles for those technical parameters and thresholds. The same commenters ask that the Commission also require sufficient specificity to provide transparency and certainty for potential interconnection customers and to avoid disputes over cost allocation.

433. EPSA and Vistra argue that the Commission should provide an opportunity for comments prior to moving to a final rule with more detailed parameters. Vistra contends that without such an opportunity, the Commission will have not provided sufficient notice. Vistra argues that adopting a final rule that contains only the very high-level requirement to allocate costs based on proportional impact method simply defers the Commission's determination on important implementation details to litigation over the individual compliance filings that will be submitted. Without sufficient detail, Vistra continues, the Commission will arguably need to accept any set of technical details as in compliance with the requirement to allocate network upgrade costs based on proportional impact.

434. PPL states that the NOPR did not address the allocation of network upgrade costs within a cluster after an interconnection customer withdraws. PPL states that, prior to the execution of an interconnection agreement by the interconnection customer(s), the Commission should provide that any interconnection facility and network upgrade costs previously allocated to the withdrawing interconnection customer be reallocated among the remaining interconnection customers in the cluster to prevent delays and allow the study process to proceed. PPL states that the Commission should allow for withdrawal to be treated as an event that allows the transmission provider to retain or call on the security provided by the withdrawing interconnection customer. PPL adds that the Commission should allow for an increase in the cost allocated to remaining interconnection customers in a cluster to account for the amount previously allocated to the withdrawing interconnection customer.

(b) Tariff Requirement for Technical Details

435. PJM states that, while it generally supports the requirement to describe the cost allocation method in the applicable tariff, the Commission should clarify that transmission providers may provide the detailed and specific technical information in business practice manuals rather than in tariffs. PJM states that these types of implementation details change from time to time and, consistent with Commission precedent, are appropriately addressed in the transmission provider's manuals. PJM asserts that mandating that these procedures be placed in the transmission provider's tariff, on the other hand, would require a transmission provider to submit an FPA section 205 filing every time the implementation details changed, which would be inefficient and burdensome.

436. In contrast, other commenters argue that these thresholds, and any associated procedures, should be codified in transmission providers' tariffs. AES explains that the thresholds used as part of the proportional impact method are important planning criteria, and constitute “practices that affect rates and services significantly, that are realistically susceptible of specification and that are not so generally understood as to render recitation superfluous;” accordingly, AES continues, they should be included in transmission providers' filed rates, and subject to review and approval by the Commission pursuant to section 205 of the FPA. Union of Concerned Scientists contends that the combination of issues that are expressed through network upgrade decisions and cost allocations for interconnection customers are arguably central to this rulemaking and the fulfillment of the competition amongst interconnection customers as a regulatory approach to setting wholesale energy prices and must be subject to notice and review, both initially and for any subsequent changes, through filings with the Commission.

437. Xcel states that the Commission should make clear that there are several just and reasonable approaches to allocating network upgrade costs to interconnection customers within a cluster. For example, states Xcel, if two generating facilities are connecting to a new a transmission line, a substation must be constructed. Xcel explains that, using some analysis, a larger generating facility might be considered to have a larger impact, but the respective size of the interconnection request did not have any impact on the cost or size of the substation needed. Xcel states that, for example, the cost of the substation is not different for a 100 MW and 500 MW generating facility or for two 300 MW generating facilities if they are interconnecting at the same voltage, and as a result, the cost of that substation should be allocated equally to both generating facilities. Xcel states that there could be a third generating facility (not directly connected to the substation) from which the power flows through the new substation, but it is not clear if the Commission is proposing that the interconnection customer proposing that third generating facility pays for a portion of the substation costs because its flows “impact” the substation. Xcel states that it does not generally support allocating network upgrade costs to interconnection customers simply because their proposed generating facilities have a flow impact if they are not causing the need for the network upgrade under a “but for” evaluation.

438. Invenergy states that, in the occasional circumstance where a point of interconnection is shared among more than one interconnection request within a cluster, which could involve new equipment that does not vary based on proportional impact, the associated costs at the point of interconnection ( e.g., the substation) could be allocated on a pro rata basis. PacifiCorp states that the proportional impact method would not be necessary to account for costs that are agnostic to interconnection customer impacts, such as the need to construct a new substation to connect to a new transmission line regardless of whether one or several generating facilities are interconnecting.

439. Invenergy states that the NOPR could be read to permit each transmission provider to adopt different and possibly inconsistent analyses and that the Commission should be clear that it is requiring a proportional impact method for allocating network upgrade costs, just as the NOPR proposes to do with respect to shared network upgrades.

440. Several commenters state that the final rule should require transmission providers to submit compliance filings that propose minimum distribution factor thresholds that will be used to evaluate NRIS and ERIS requests.

(c) Requests for Flexibility

441. Some commenters support the proportional capacity method only for certain network upgrades or limited circumstances.

442. Tri-State states that it does not apply a proportional impact method to transient-stability-driven network upgrades, which cannot be measured using a proportional impact approach; rather, Tri-State uses a MW pro rata method approach when allocating the costs of transient-stability-driven network upgrades. Longroad Energy states that, to the extent the Commission allows a transmission provider to use some method other than a flow-based proportional impact allocation for transient stability constraints, the transmission provider should be required to demonstrate that the alternative cost allocation method is based on sound engineering principles for the specific transient stability constraint observed in the studies.

443. R Street states that allocating network upgrade costs based on proportional capacity is appropriate in situations where clusters are composed of similar types of generation. R Street asserts that the default should be that all thermal network upgrade cost allocations are based on proportional capacity. R Street states that this leaves open the possibility for transmission providers to allocate other types of network upgrade costs (voltage, transient stability, short circuit) using a different but predefined method.

444. Several commenters ask the Commission to provide flexibility for transmission providers to establish a cost allocation method for network upgrades, rather than mandating a prescriptive approach. PPL claims that such region-specific cost allocations are necessary to keep disputes from overwhelming the reform process the Commission anticipates. New York State Department asserts that any strict or limiting requirement for a specific cost allocation method may undermine and replace existing processes that work well. National Grid recommends that the Commission allow for consideration of the unique circumstances of a region, input from relevant stakeholders in the region, including the potential for regions to propose cost allocation methods that allow for broader allocation to load or transmission customers in addition to interconnection customers.

445. Dominion points out that courts and the Commission have long recognized that there is not one single just and reasonable method for establishing cost allocation. Dominion states that rather, cost allocation proposals are reviewed to determine whether they meet certain principles, chiefly that costs are allocated in a manner that is at least “roughly commensurate” with estimated benefits received. Accordingly, Dominion recommends that if the Commission imposes any requirements related to cost allocation, it simply retains a general definition of proportional impact method and is not overly prescriptive.

iii. Requests for Clarification or Technical Conference

446. Pattern Energy generally supports the application of the proportional impact method, subject to clarification on which form of distribution factor analysis the Commission is contemplating. Pattern Energy states that there are two types of distribution factors used to determine the impact of given power injection flows over a monitored facility: (1) power transfer distribution factor, which is the percentage of power that will flow on a specific monitored facility and does not consider outage/contingent facilities; and (2) outage transfer distribution factor, which is the percentage of power that will flow on a specific facility that does consider outage/contingent facilities. Pattern Energy states that the difference between the two distribution factors ( i.e., the consideration of the outage/contingent facility) is important because power transfer distribution factor is usually more relevant for evaluating “local impacts” ( e.g., generating facilities that are connecting in very close electrical proximity to a given monitored element), compared to outage transfer distribution factor, which captures impacts that may be more geographically and electrically distant from a given monitored facility. Pattern Energy asserts that the Commission should require outage transfer distribution factor to be the required distribution factor utilized in the proportional impact method for identifying impacts to constrained facilities and resultant cost allocation for network upgrades. Pattern Energy argues that outage transfer distribution factor is a better measure of power flows on the bulk-power system, and, in turn, its use ensures that impacts to constrained facilities are properly mitigated by, and cost allocated to, the actual, full set of contributors and not just the nearby highest contributors.

447. Pine Gate contends that certain proposed enhancements to the NOPR proposal would provide much needed certainty to interconnection customers and mitigate the systematic problem of interconnection queues being the primary mechanism by which needed transmission infrastructure is identified, developed, and constructed. Specifically, Pine Gate requests that the Commission make the following clarifications: (1) transmission providers are not permitted to allocate to interconnection customers network upgrade costs associated with preexisting operating conditions (such as overloads); (2) transmission providers are not permitted to allocate network upgrade costs to interconnection customers for loading that results from the simulation of conditions that do not reflect typical operating conditions; (3) transmission providers are required to use consistent, uniform thresholds to measure the impact on a specific transmission facility caused by an interconnection request and publish these thresholds, along with the corresponding scope of the resulting network upgrades; and (4) establish a 4% impact threshold for NRIS and a 20% impact threshold for ERIS, unless there is preexisting loading on the facility. Pine Gate further requests that the Commission provide transmission providers guidance on the scope of the network upgrade required to accommodate an interconnection request. Pine Gate states that, if a network upgrade benefits other types of customers, interconnection customers should receive transmission credits or other compensation if the additional transmission capacity created is used for market dispatch or by wholesale transmission customers. Pine Gate states that, if the Commission does not adopt Pine Gate's proposed enhancements as part of a final rule in this proceeding, then the Commission should establish a technical conference to explore these issues.

iv. Miscellaneous

448. Pennsylvania Commission states that limiting the scope of each cluster to those interconnection customers most likely to share the same network upgrades may reduce the need for the proportional impact network upgrade cost allocation method. According to Pennsylvania Commission, instead of determining the degree to which interconnection requests cause specific network upgrades on the back end through cost allocation, clustering by electrical relevance may accomplish the same goal, making sure that interconnection customers are sharing the costs of network upgrades that they cause and from which they benefit. Pennsylvania Commission contends that the Commission should examine whether limiting the scope of a cluster or cost allocation, or a combination of both, is the best method to share costs among interconnection customers causing the same network upgrades.

449. Several commenters state that the NOPR leaves unresolved the fundamental question of more equitably sharing network upgrade costs across all beneficiaries, including load. They argue, for example, that policies requiring interconnection customers to pay for 100% of network upgrade costs when the benefits of those upgrades are distributed among other system users ( i.e., participant funding) causes interconnection customers to pay more than their appropriate share of the costs. In contrast, Ameren claims that it is appropriate for interconnection customers to bear responsibility for the cost of network upgrades required for their interconnection requests. Ameren argues that, to ensure the full costs of interconnection are identified and allocated, network upgrade costs associated with affected systems must also be included in cluster network upgrade cost allocation, and interconnection customers should be required to accept the assigned costs. Ohio Commission Consumer Advocate emphasizes that the Commission should not change the participant funding mechanisms in RTO/ISO markets, while PPL argues that the Commission should allow non-RTO/ISO transmission providers the option to propose allocating the costs of network upgrades to interconnection customers without credits as RTOs/ISOs do.

450. New York State Department and Shell argue that the Commission should discontinue the historical practice of allowing interconnection customers essentially free use of headroom on ratepayer-funded network facilities. New York State Department states that this occurs when transmission ratepayers fund upgrades to the transmission system that create headroom, from which interconnection customers later benefit without having to pay for access or use. In contrast, Invenergy asserts that the Commission needs to ensure that the transmission planning and interconnection models are consistent, so that interconnection customers are not required to pay for the cost of resolving overloads and other transmission system issues that exist without the proposed interconnection.

451. AEE encourages the Commission to ensure that its proposal increases cost transparency and establishes a pathway for interconnection customers to access accurate information about their network upgrade costs in a timely manner. For instance, AEE asks that the Commission also provide guidance regarding which party must pay if network upgrade costs significantly exceed estimates. AEE states that one approach to minimizing the construction time and cost of network upgrades, and consequently the interconnection process as a whole, is to provide a third-party construction option in the pro forma LGIA that would allow the interconnection customer to elect for stand alone network upgrades to be bid out and potentially built by third parties.

452. Pine Gate recommends that the Commission require transmission providers to analyze more holistically the other underlying needs driving identified network upgrades to the transmission system. Pine Gate states that the Commission should require transmission providers to only allocate to interconnection customers the costs associated with accelerating the construction of the upgrade to accommodate the interconnection customer's anticipated commercial operation date.

c. Commission Determination

453. We adopt the NOPR proposal, with modifications, to add new proposed section 4.2.3, now section 4.2.1, to the pro forma LGIP to require transmission providers to allocate network upgrade costs based on a proportional impact method. Based on the record, we modify the NOPR proposal and add definitions for substation network upgrades and system network upgrades in the pro forma LGIP and pro forma LGIA. In addition, we modify the definitions of proportional impact method and stand alone network upgrades proposed in the NOPR. We also modify proposed section 4.2.1 of the pro forma LGIP to require transmission providers to allocate the costs of network upgrades located at substations equally among each generating facility interconnecting to the same substation ( i.e., on a per capita basis), and to revise the information that a transmission provider's tariff must include regarding the proportional impact method.

454. We also modify the requirement in proposed section 4.2.1 of the pro forma LGIP for transmission providers to directly assign the cost of shared transmission provider's interconnection facilities to interconnection customers on a per capita basis ( i.e., on a per generating facility basis). Specifically, we modify proposed section 4.2.1 of the pro forma LGIP to make the new provisions applicable to the interconnection customer's interconnection facilities as well as to the transmission provider's interconnection facilities. We also modify this section to provide that interconnection customers may agree to share interconnection facilities, and that the per capita allocation will apply only where interconnection customers agree to share interconnection facilities. We also modify this section to allow the interconnection customers that share interconnection facilities to choose a different cost sharing arrangement upon mutual agreement.

455. We find that adopting the modified NOPR proposal will ensure just and reasonable rates as transmission providers transition to the cluster study process required by this final rule. We find that the cost allocation method adopted herein will allow transmission providers to allocate network upgrade costs among several interconnection customers that may benefit from (and cause the need for) certain network upgrades. We also find that allocating shared network upgrade costs among a cluster of interconnection customers will reduce the frequency of an individual interconnection customer being allocated the costs of a large network upgrade that benefits subsequent interconnection customers; reduce the incentive of interconnection customers to submit multiple speculative interconnection requests to avoid shouldering the cost of large network upgrades that may be triggered by a single interconnection customer in the existing serial study process; and reduce the number of cascading withdrawals and restudies, thereby improving the efficiency of the interconnection process and reducing interconnection queue processing delays.

456. We conclude that a proportional impact method appropriately reflects the Commission's interconnection pricing policy for facilities designated as network upgrades needed for the interconnection of the cluster. However, we are persuaded to adopt a different cost allocation method for substations at the point of interconnection that are designated as network upgrades and needed only to facilitate the interconnection of certain generating facilities within the cluster seeking interconnection to the specific substation, as demonstrated by commenters.

457. In Order No. 2003, the Commission reasoned that “it is appropriate for the Interconnection Customer to pay the initial full cost for Interconnection Facilities and Network Upgrades that would not be needed but for the interconnection” ( i.e., “but for” policy). Hence, under the serial study process in the existing pro forma LGIP, the transmission provider allocates network upgrade costs by assigning the initial full cost responsibility for all network upgrades identified in a study to a single interconnection customer that causes those upgrades. However, in transitioning to a cluster study process in this final rule, the Commission must establish a method for allocating network upgrade costs among all interconnection customers within a cluster. Based on the record in this proceeding, we find that a proportional impact method is the appropriate application of the Commission's interconnection pricing policy when allocating the costs of network upgrades needed for an entire cluster of proposed generating facilities because a proportional impact method allows transmission providers to assess a generating facility's individual contribution to the need for the network upgrades identified for the cluster. However, the need for substation network upgrades is only generated by a specific generating facility seeking interconnection at a specific substation and not by all the generating facilities in the cluster. It would be inconsistent with the Commission's interconnection pricing policy to allocate the costs of the substation network upgrades to interconnection customers in the cluster that are interconnecting at other substations because, in the case of a cluster of new interconnection requests, only the generating facilities interconnecting to the same substation generate the need for network upgrades at that substation.

458. As explained above, the cost of substation network upgrades must be initially allocated only to those interconnection customers seeking to interconnect at the same substation, while the cost of system network upgrades for all interconnection customers in a cluster must be initially allocated based on the technical analyses to be specified under the transmission provider's proportional impact method. To facilitate these differing cost allocation methods, we modify the definitions in section 1 of the pro forma LGIP and article 1 of the pro forma LGIA to distinguish substation network upgrades (including all switching stations) from system network upgrades. Using these definitions, we further modify the pro forma LGIP and pro forma LGIA to draw this distinction and to ensure that the costs for the two types of network upgrades are allocated consistent with the Commission's interconnection pricing policy, which establishes the principles for allocating the costs of network upgrades.

459. We note that we are not modifying the pro forma LGIP's definition of facilities needed beyond the point of interconnection as network upgrades; rather, we are providing greater specificity with regard to how the costs of the two distinct types of network upgrades identified within a cluster study should be initially allocated. We find that this approach will also lead to greater transparency and ease of administering the cluster study process by establishing distinct guidelines for how the costs of the two types of network upgrades will be initially allocated within a cluster. Also, as commenters note, in instances where a point of interconnection is shared among more than one interconnection request within a cluster, the cost of the substation network upgrades is more directly impacted by the number of generating facilities proposing to interconnect there because the cost of the equipment used to interconnect generating facilities to substations does not vary based on the electrical characteristics of the interconnecting generating facilities ( e.g., the MW size of the generating facility, fuel type, or services provided).

460. To further implement this modification of the NOPR proposal, we modify the definition of stand alone network upgrades proposed in the NOPR to recognize that (1) a substation network upgrade may only be considered a stand alone network upgrade if it is needed to interconnect only one generating facility in the cluster and no other interconnection customer in that cluster is required to interconnect to the same substation network upgrades, and (2) the proportional impact analysis will be used in determining whether a system network upgrade is only needed for one generating facility in the cluster and can be considered a stand alone network upgrade. Our revisions also seek to prevent lengthy disputes over which interconnection customer has the right to exercise the option to build in instances where a network upgrade could qualify under the existing definition of a stand alone network upgrade, but the network upgrade is needed for multiple interconnection customers' generating facilities.

461. Several commenters request that the Commission provide more specificity and guidance regarding the specific thresholds and metrics that transmission providers are expected to submit on compliance. In this final rule, we modify the proposed requirement in pro forma LGIP section 4.2.1 for transmission providers to revise their LGIPs on compliance to include specific thresholds and metrics. Instead, we direct transmission providers on compliance to provide tariff provisions that describe, for each type of system network upgrade that a transmission provider would identify in the cluster study process ( e.g., voltage support network upgrades or short circuit network upgrades), how the costs of each system network upgrade type will be allocated among the interconnection customers within the cluster. Transmission providers' revisions on compliance must provide that costs for a discrete network upgrade identified in the cluster study process ( e.g., reconductoring a portion of a transmission line to accommodate the interconnection of several generating facilities in the cluster) are allocated to only the interconnection customers in the cluster that are shown through technical analyses to contribute to the need for the discrete network upgrade. For example, the transmission provider must propose tariff provisions similar to the following: (1) voltage support related network upgrades shall be allocated using a voltage impact analysis, which will identify each generating facility's contribution to the voltage violation; (2) short circuit network upgrade costs within a cluster will be allocated based on the impact from each generating facility within the cluster, on the constrained facilities under the most constraining fault in the relevant study case(s); or (3) the estimated costs of short circuit related general reliability network upgrades identified through a cluster study shall be assigned to all interconnection requests in that group study pro rata on the basis of the short circuit duty contribution of each generating facility.

462. PJM requests that the Commission clarify that transmission providers may provide the detailed and specific technical information in business practice manuals rather than in tariffs. In response, we find that, as noted above, transmission providers must provide tariff provisions that describe the method they will use for allocating costs of each type of network upgrade, but specific metrics and thresholds for implementing the allocation, or other specific technical information, may be included in business practice manuals, or publicly posted on the transmission provider's website. We agree with PJM that such details are appropriate for business practice manuals, consistent with Commission precedent applying the “rule of reason” to determine whether a detail should be included in a tariff or business practice manual. In particular, the technical information surrounding implementation of the proportional impact method by a particular transmission provider does not need to be included in the transmission provider's tariff under the rule of reason because these provisions are properly classified as implementation details that do not significantly affect rates, terms, and conditions of service.

463. Several commenters request that the Commission direct transmission providers to use a specific type of proportional impact method or distribution factor analysis and apply minimum distribution factor thresholds that will be used to evaluate NRIS and ERIS requests. We are unpersuaded that such level of prescription is needed to ensure just, reasonable, and not unduly discriminatory or preferential rates. Instead, we believe that flexibility for transmission providers to develop such details as part of their compliance filings—and in their business practice manuals, where consistent with the rule of reason, as discussed above—is important to ensure that the proportional impact method used by each transmission provider reflects the characteristics of its region ( e.g., types of network upgrade facilities identified in the region, or preferred analyses in the region for determining the share of the need for the specific network upgrade type). For the same reason, we decline to require transmission providers to use consistent, uniform thresholds to measure impact, as requested by Pine Gate.

464. Based on the record, we decline to require transmission providers to use the proportional capacity method to allocate the costs of all system network upgrades, given our decision to instead opt for the proportional impact method and because it reflects the Commission's interconnection pricing policy for facilities designated as network upgrades needed for the interconnection of the cluster. Nonetheless, we recognize that there may be a tradeoff between simplicity and accuracy when considering proportional capacity versus proportional impact for cost allocation for network upgrades. While we require transmission providers to allocate network upgrade costs based on a proportional impact method based on the record in this final rule, we acknowledge that other allocation methods could potentially meet the consistent with or superior to standard or the independent entity variation standard if, among other things, they allocate network upgrade costs in a manner consistent with the Commission's interconnection pricing policy.

465. We disagree with NV Energy and PacifiCorp's arguments that the proportional impact method carries unmanageable time, restudy, and reallocation risks. In response to concerns about restudy risk resulting from withdrawals, we note that the Commission's new cluster study process requires transmission providers to complete the process within 150 calendar days, which we believe is sufficiently long for transmission providers to be able to conduct the rounds of restudy and reallocation that are needed to achieve a stable interconnection queue and reduce the risk of further withdrawals before moving to the individual facilities studies. Further, the proportional impact method is currently used by most transmission providers that conduct cluster studies, and several of these transmission providers have adopted study timelines similar to what we adopt in this final rule.

466. We disagree with claims from NV Energy and PacifiCorp that the proportional impact method must be conducted as if it were a serial study in that each interconnection request must be studied individually. When proposing a proportional impact method on compliance, transmission providers have many methods to choose from and should adopt a method that allows them to meet the timelines designated in the cluster study process. In response to PPL, we confirm that within the cluster study process, any network upgrade costs previously allocated to a withdrawing interconnection customer that are still required after the withdrawal may be reallocated among the remaining interconnection customers in the cluster based on the relevant cost allocation method applied to the network upgrade facility type.

467. Finally, several commenters suggest alternative reforms to the Commission's network upgrade cost allocation policies: (1) limit the use of cluster areas as an alternative to the proposed cost allocation method within a cluster; (2) change the interconnection pricing policy or participant funding regime (as allowed in certain RTOs/ISOs) to limit participant funding and/or require assessment of whether transmission customers benefit from and should pay for network upgrades; (3) establish a process to eliminate the use of headroom on network transmission facilities; and/or (4) provide a third-party construction option. We find these requests to be outside the scope of this proceeding and lacking in record support to adequately consider whether to adopt them in this final rule.

5. Shared Network Upgrades

a. NOPR Proposal

468. In the NOPR, the Commission preliminarily found that the absence of network upgrade cost sharing provisions in the pro forma LGIP may pose a barrier to entry to generation development. The Commission stated that absent cost sharing provisions among clusters, interconnection customers may significantly benefit from earlier-in-time network upgrades but not share in the cost of those network upgrades in a manner that is roughly commensurate with benefits. The Commission therefore proposed to require transmission providers to allocate the costs of network upgrades between interconnection customers in an earlier cluster and interconnection customers in a subsequent cluster that benefit from the same network upgrade in a manner that is roughly commensurate with the benefits received. Specifically, the Commission proposed that when the transmission provider analyzes the network upgrades identified through its cluster study process, if a generating facility of an interconnection customer in a later cluster directly connects either to (1) a network upgrade in service for less than five years or (2) a substation where the network upgrade in service for less than five years terminates, then the transmission provider would be required to designate the network upgrade a shared network upgrade. Upon such a designation, the interconnection customer in the later cluster would be required to contribute a pro rata portion of the shared network upgrade's remaining undepreciated capital cost based on the impact the interconnection customer in the later cluster has on the network upgrade, as measured using the same method the transmission provider used to determine the impact of the interconnection customer(s) in the earlier cluster.

469. The Commission proposed that if the new generating facility does not directly connect to the network upgrade, then the transmission provider would perform a power flow analysis with a two-step test to measure the lower-queued interconnection customer's use of and benefit from the network upgrade funded by interconnection customers from an earlier cluster. Under the first step, the transmission provider would determine if the impact of the interconnection customer in the later cluster exceeds five MW and exceeds one percent of the network upgrade's rating. Then, if those criteria are met, the transmission provider would determine if the lower-queued interconnection customer's impact either exceeds more than 5% of the network upgrade's facility rating or if the transmission distribution factor is greater than 20%. Finally, if either of these criteria were met, the transmission provider would be required to designate that network upgrade a shared network upgrade, and the interconnection customer in the later cluster would be responsible for a pro rata share of the network upgrade's remaining undepreciated capital cost based on the impact the interconnection customer in the later cluster has on the network upgrade, as measured using the same method the transmission provider used to determine the impact of the interconnection customer(s) from the earlier cluster.

470. The Commission proposed to require the interconnection customer in the later cluster to pay the transmission provider for the interconnection customer's share of the shared network upgrade costs through a one-time lump sum, which the transmission provider would disburse to the appropriate interconnection customer(s) from the earlier cluster. The Commission also proposed that, where applicable, the interconnection customer from the earlier cluster or the relevant transmission provider would be required to assign transmission credits for the portion of the shared network upgrade that the interconnection customer in the later cluster funded to the interconnection customer in the later cluster. Additionally, the Commission proposed to require that the interconnection customer in the later cluster not be required to pay for its share of the cost of the shared network upgrade until that shared network upgrade is in service. The Commission also proposed to require transmission providers to provide the list of shared network upgrades to interconnection customers in subsequent clusters at the conclusion of the cluster study and to list those network upgrades in the appendix of the relevant interconnection customer's LGIA. The Commission acknowledged that there could be scenarios where the network upgrade may be identified as both a shared network upgrade and a contingent facility; and, thus a designation of a network upgrade as a contingent facility does not preclude it from also being a shared network upgrade if the network upgrade meets the aforementioned criteria and passes the screens.

b. Comments

i. Comments in Support

471. Multiple commenters support the proposal. OMS states that, while cost sharing arrangements can be resource intensive and contentious, they can be crucial to facilitating an equitable interconnection process. NARUC states that the proposal is a logical extension of the cluster cost sharing concept and could spread costs over even more interconnection customers benefitting from network upgrades. A couple of commenters contend that the proposal will provide more certainty and result in fewer withdrawals, thus reducing associated restudies and study processing delays.

472. Several commenters believe that the proposal will address the issue of “first movers/free riders” when interconnection customers in a later cluster study benefit from network upgrades assigned to interconnection customers in earlier clusters. Shell claims that avoiding first mover subsidization of free riders is particularly important for offshore wind interconnections because of the potential lack of onshore access points and, therefore, argues that the Commission should be open to non-traditional cost allocation methods when contemplating methods to mitigate first mover risk.

473. Additionally, some commenters believe that the proposal is consistent with the Commission's cost causation policy. Avangrid asserts that, when surplus transmission capacity created by a recent network upgrade is used by a later generating facility, the lower-queued interconnection customer should share the costs in a way that is commensurate with benefits like those allocated using the original proportional impact method assessment.

474. Xcel does not believe the proposal will have a significant impact on the number of interconnection requests submitted but believes that it will reduce barriers to entry for all interconnection customers. Xcel believes that the proposal is appropriate where there is participant funding.

ii. Comments in Opposition

475. Some commenters oppose the proposal. Several commenters assert that it will not yield many benefits and that the Commission should focus on other reforms that are more likely to reduce network upgrade costs and improve the equity of allocating them among beneficiaries. Dominion and Fervo Energy argue that interconnection customers in subsequent clusters do not “cause” the costs to be incurred, and to the extent the interconnection customers will benefit, they will contribute through their payment for transmission service.

476. Other commenters believe that the implementation of the proposal will be administratively burdensome for transmission providers. A few commenters believe that the proposal will lead to increased disputes and FPA section 206 complaints at the Commission over cost allocation assignments.

477. Several commenters express concern that the proposal will lead to interconnection study delays and/or restudies, which would undermine the NOPR's goal to reduce interconnection study processing timelines. A few commenters state that the proposal would require transmission providers to track all in-service network upgrades on the transmission system across all cluster studies over a five-year period, which they contend would be onerous or nearly impossible. The U.S. Chamber of Commerce claims that power flow studies conducted up to five years after the in-service date of non-adjacent network upgrades will inevitably fail to accurately divide the relevant interconnection costs among disparate-in-time interconnection customers due to the many coinciding yet unrelated system changes that will affect the outcomes of such analyses. PacifiCorp contends that this requirement would require transmission providers to track multiple requests for each network upgrade on different timelines, the suspension or withdrawal of which could trigger cascading revaluations and corresponding LGIA amendments. Dominion contends that the NOPR's proposal would complicate reviews and require additional time-consuming analysis, which would only worsen for transmission providers with a high volume of interconnection requests, such as RTOs/ISOs.

478. Some commenters argue that the proposal will not create cost certainty for interconnection customers in earlier clusters when deciding whether to move forward with a generating facility because there would be no guarantee that an interconnection customer in a subsequent cluster would provide reimbursement. NextEra and PJM argue that a benefit of not sharing costs between clusters is that all the interconnection customers within a cluster simultaneously learn their network upgrade costs and associated cost responsibility, creating greater cost certainty.

iii. Alternatives and Requests for Flexibility

479. Several commenters recommend modifications to the proposal. A few recommend that the Commission implement a minimum threshold before a network upgrade would be evaluated as a potential shared network upgrade. MISO and Xcel state that changes will be necessary in RTO/ISO regions where a transmission owner may unilaterally provide upfront funding for network upgrades to integrate the cost allocation for such a funding mechanism with the shared network upgrade proposal. ENGIE recommends that the Commission set requirements in the interconnection process to identify interconnection facilities and network upgrades that are necessary to interconnect the generating facility, as well as network upgrades needed to mitigate local transmission constraints, and asserts that interconnection customers should not be responsible for the costs of distant and minimally impacted network upgrades. Xcel also contends that the interconnection customer in the subsequent cluster should enter into a multiparty facilities service agreement to reimburse the interconnection customers in the earlier cluster, rather than pay the proposed lump sum payment to the transmission provider. Pattern Energy recommends that the interconnection customer in the later cluster be required to repay the earlier interconnection customer at the time of execution of the subsequent interconnection customer's interconnection agreement, and not when the relevant shared network upgrades go into service.

480. A few commenters propose alternative methods for cost allocation for shared network upgrades. For instance, Xcel argues that the Commission should be clear that it will accept other proposals to determine if a network upgrade is shareable to subsequent interconnection requests.

481. Some commenters support regional flexibility for transmission providers to implement any shared network upgrade mechanism. For example, NESCOE suggests that allowing transmission providers, especially RTOs/ISOs, some flexibility in coordinating with their states on developing proposed approaches to sharing the costs associated with network upgrades funded by interconnection customers in earlier clusters could minimize the contentious nature of developing cost sharing arrangements.

482. Other commenters recommend that the Commission not adopt the shared network upgrade proposal in non-RTO/ISO regions where interconnection customers provide upfront funds for the network upgrades and receive reimbursement through transmission credits from the transmission provider, plus interest ( i.e., the interconnection pricing policy established in Order No. 2003). Pine Gate states that under the NOPR proposal, interconnection customers in later clusters would potentially reimburse interconnection customers in earlier clusters sooner than the transmission provider would have via transmission credits, but with the same result. Enel asserts that coupling shared network upgrades with transmission credits creates even more administrative complexity, as an interconnection customer in a later cluster providing funds to an interconnection customer in an earlier cluster would necessitate a partial transfer of transmission credits, potentially on a partially depreciated asset, which creates an extremely complex payment, reimbursement, and multiparty crediting system that would be administratively burdensome. Similarly, APS and Duke Southeast Utilities express concern over an additional complication in the event the earlier interconnection customer has already been fully reimbursed for the network upgrades through transmission credits. In contrast, Vistra contends that the shared network upgrade proposal will be beneficial in regions with transmission crediting as it will speed reimbursement relative to the status quo. Vistra claims that, when an overlap exists between the reimbursement of an interconnection customer through transmission credits and the reimbursement mechanism in this proposal, this proposal will appropriately charge interconnection customers in subsequent clusters.

483. Other commenters raise additional cost allocation concerns with the shared network upgrade proposal. Enel argues that, in markets where transmission credits do not apply, reimbursement for funding network upgrades is often granted in the form of congestion hedging mechanisms, and the repayment of network upgrade costs from a lower-queued interconnection customer to a higher-queued interconnection customer could create the need for a partial transfer of these congestion hedging rights. SDG&E cautions against allowing scenarios where an higher-queued interconnection customer with cost responsibility terminates an executed LGIA but the network upgrades are still needed for later interconnection customers, thus leaving the transmission provider as the backstop for financing the network upgrade. A few commenters argue that the Commission should limit its proposal to share network upgrade costs between clusters to areas whether interconnection customers are not already reimbursed for network upgrade costs.

484. Several commenters note that some RTOs/ISOs have similar existing cost allocation mechanisms to the NOPR proposal and request that, in those instances, the Commission defer to those transmission providers when the existing mechanisms are accomplishing the final rule's objectives. On a similar note, PJM and Indicated PJM TOs request that the Commission not require PJM to implement cost sharing between its clusters.

485. Several commenters request various clarifications of the proposal and provide their thoughts on specific aspects.

c. Commission Determination

486. We decline to adopt the NOPR proposal to revise the pro forma LGIP and pro forma LGIA to implement shared network upgrades between interconnection customers in an earlier cluster and interconnection customers in a subsequent cluster. We find that the reforms adopted in this final rule that require transmission providers to allocate network upgrade costs to interconnection customers within the same cluster using a proportional impact method, as discussed above, will provide interconnection customers with more cost certainty during the interconnection process and will allow for sharing of network upgrade costs between interconnection customers that benefit from those network upgrades within the same cluster.

487. The record demonstrates the complexity of the NOPR proposal and potentially significant administrative burdens associated with implementing it for at least some transmission providers, especially under the Commission's interconnection pricing policy. We agree with some commenters that adopting the proposal would not provide cost certainty to interconnection customers in earlier clusters at the point that they have to proceed in the interconnection process because they would lack certainty about potential reimbursement for network upgrades from interconnection customers in subsequent clusters. Thus, the NOPR proposal is unlikely to reduce barriers to generation development due to the absence of network upgrade cost sharing provisions. Further, the proposal may introduce burdens for lower-queued interconnection customers that could be faced with reimbursing a higher-queued interconnection customer for a new shared network upgrade cost late in the interconnection process. For these reasons, we decline to adopt this NOPR proposal.

488. We find that the final rule's reforms to conduct cluster studies and to allocate the costs of any assigned network upgrades to the cluster's interconnection customers on a proportional basis address the “first mover/free rider” issue. Under this final rule, a transmission provider must study interconnection customers in an earlier cluster study based on the transmission system at that time, and those interconnection customers will be assigned network upgrades that would not be needed but for their interconnection to the transmission system; then, the transmission provider will study interconnection customers in a subsequent cluster study based on the transmission system at that point in time, and those interconnection customers will be assigned any necessary network upgrades that would not be needed but for their interconnection to the transmission system. Further, we note that under the Commission's interconnection pricing policy, interconnection customers receive reimbursement for network upgrade costs, which helps to mitigate any “first mover/free rider” concerns because interconnection customers are reimbursed through transmission credits. In addition, we find that the aforementioned reforms to conduct cluster studies and use a proportional impact method to allocate the costs of network upgrades within a cluster will also address “first mover/free rider” concerns in regions with independent entity variations to the interconnection pricing policy.

489. Because we decline to adopt this proposal, we do not respond to the requests for clarification or the requests for modifications to the NOPR proposal that would not address the reasons provided above for declining to adopt the NOPR proposal as a general matter.

6. Increased Financial Commitments and Readiness Requirements

490. In the NOPR, the Commission stated that the pro forma LGIP allows an interconnection customer to proceed through the generator interconnection process without having shown evidence to the transmission provider of meaningful progress toward achieving commercial viability. The Commission stated its concern that, without requiring this type of evidence, interconnection customers will continue to submit multiple speculative interconnection requests and later withdraw those requests, triggering rounds of restudies. The Commission therefore proposed a set of reforms to adopt more stringent financial commitments and readiness requirements for interconnection customers to remain in the interconnection queue to discourage speculative interconnection requests and allow transmission providers to focus on processing viable interconnection requests and to better approximate the cost of the interconnection study process.

a. Increased Study Deposits

i. NOPR Proposal

491. In the NOPR, the Commission proposed to adopt the following study deposit framework in the pro forma LGIP:

492. The Commission proposed to require transmission providers to collect this study deposit before each phase of the new first-ready, first-served cluster study process ( i.e., cluster study, cluster restudy, and facilities study). The Commission proposed to require the interconnection customer to provide: (1) an initial study deposit along with its interconnection request, which will be used to pay for the cluster study; (2) the second study deposit of the same amount within 20 days of receiving the cluster study report from the transmission provider to cover the cost of any clustered restudies; and (3) the third study deposit of the same amount along with its executed facilities study agreement. The Commission explained that study deposits would be refundable, and that the transmission provider would refund any portion of the study deposits above the applicable study costs and withdrawal penalties once the interconnection customer executes the LGIA, requests the filing of an unexecuted LGIA and submits the corresponding payment discussed below, or withdraws from the interconnection queue. The Commission also proposed to delete section 8.1.1 of the pro forma LGIP to remove the requirement for transmission providers to invoice interconnection customers on a monthly basis for the work conducted on the facilities study.

493. The Commission sought comment on whether: (1) the proposed study deposit amounts accurately estimate the cost of conducting cluster studies; and (2) to adopt additional provisions or a different framework that would require larger proposed generating facilities to provide a higher deposit amount—such as a per MW framework.

ii. Comments

494. Several commenters fully support the NOPR proposal to increase study deposits in order to support more effective interconnection queue management and reduce speculative interconnection requests.

495. Other commenters express qualified support for the proposal. For example, ELCON, New York Commission and NYSERDA, and NextEra contend that it is important that such measures be carefully balanced so that they are not overly burdensome or discouraging to interconnection customers with legitimate proposed generating facilities that may be delayed for reasons out of their control. Clean Energy Associations do not oppose the heightened study deposit requirements, provided that they are paired with real predictability on the timing of studies and real certainty on the costs of network upgrades. CAISO argues that the Commission must raise study deposits significantly, and contends that it is illusory to argue that interconnection customers without significant capital can progress to commercial operation in today's hyper-competitive climate. PPL asserts that the Commission's proposed study deposits are likely on the low end of what is required to ensure proper “skin in the game,” but should work for many regions, including New England. Tri-State overall supports the proposed study deposit amounts but notes that interconnection customers proposing smaller generating facilities will end up paying a lower study deposit than what Tri-State is currently charging. ENGIE, MISO, and SPP would prefer to collect study deposits only once upon entry into the cluster, rather than at each stage of the cluster study process, to reduce administrative burden on them and the interconnection customers. MISO and Shell argue that limiting speculative interconnection requests and ensuring more concrete financial readiness would be better achieved by requiring a single study deposit at the initiation of the generator interconnection process. Shell urges the Commission to base that deposit on the generating facility's size.

496. Several commenters argue that the final rule should provide each region with flexibility concerning the scope and application of any modifications to increased study deposits. Indicated PJM TOs contend that the transmission provider should be entitled to adjust the study deposit value if it observes that the actual cost of studies tends to be materially higher or lower. Dominion adds that the Commission should respect the previously accepted reforms made by transmission providers like Dominion and PJM with regard to study deposits.

497. APS suggests that any refundable deposits should not include the Commission interest rate and argues that, by requiring additional funds to be deposited as described in the NOPR, the Commission's proposal would lead to an exorbitant increase in the amount of Commission interest paid back to an interconnection customer as it moves along through the process at the transmission provider's expense.

498. Other commenters mostly oppose the NOPR proposal to increase study deposits. CREA and NewSun agree that a tiered study deposit level tied to interconnection capacity requested may be warranted and at most study deposits should be increased to more accurately cover the cost of the studies, but comment that the rest of the NOPR's proposal appears to increase the study deposit levels solely to deter interconnection customers from entering the interconnection queue, not because the current level of study deposits is insufficient to cover the costs of the studies. CREA and NewSun argue that, if this rulemaking generates evidence that the current study deposit levels are insufficient to cover the typical costs of studies, an increase may be justified, but until then, study deposits should not be increased. Eversource recommends that the Commission consider making the rate of increase per MW more gradual, and that based on the current proposed figures, the deposits may increase too quickly relative to generating facility size. rPlus argues that study deposit requirements are unduly discriminatory or punitive to pumped storage as compared to other renewable technologies because a large capacity pumped storage facility would expect to hit the maximum deposit and/or penalty in every stage of the interconnection study process, LGIA, and potential withdrawal. RWE Renewables fully supports allocating some risk for each generating facility entered into the interconnection queue to interconnection customers, but argues that increased financial deposits have unfortunately not been an adequate deterrent to a high volume of non-viable generating facilities entering into the interconnection queues.

499. In response to the Commission's request for comment on whether the proposed study deposit amounts accurately estimate the cost of conducting cluster studies, Ameren states that, based on its experience, the proposed study deposits are in line with the cost of conducting the cluster studies. Xcel contends that the proposed study deposits are more than the cost of studies in its experience, but as studies will need to be accelerated under the Commission's proposal (to meet timelines) and may involve more actions, the proposed study cost may be appropriate. NV Energy states that, on average, it spends between $80,000 and $100,000 between the cluster system impact study and facilities studies and refunds the remaining deposits with interest. Cypress Creek comments that in its experience, study costs can vary widely depending on the transmission provider, the staff resources it has available to conduct the study, and whether it needs to contract with external resources to conduct the study.

500. CREA and NewSun urge the Commission to maintain a lower study deposit prior to obtaining the initial cluster study. They argue that larger study deposits are only justified once the interconnection customer can realistically assess the commercial viability of its proposed generating facility within the cluster after obtaining the potential interconnection costs. Fervo Energy contends that more information is needed before one can conclude that the proposed study deposit amount framework would not result in deposits that far exceed the actual cost of the studies, particularly in light of the withdrawal penalty proposal. Cypress Creek suggests that the Commission should provide additional justification and argues that the NOPR fails to provide any further justification for study costs ( i.e., based on a market analysis or other method), stating only that the proposed amounts “better approximate the cost of the interconnection study process.”

501. In response to the Commission's request for comment on whether the Commission should adopt additional provisions or a different framework that would require larger proposed generating facilities to provide a higher study deposit amount, such as a per MW framework, PJM contends that the Commission should adopt readiness payments or study deposits based on the costs of the network upgrades necessary to interconnect the generating facilities in the cluster, which also contain “at-risk” non-refundable provisions.

iii. Commission Determination

502. We adopt, with modification, the NOPR proposal to require interconnection customers to pay, and transmission providers to collect, study deposits as part of the cluster study process. Specifically, we adopt the NOPR proposal to require the following study deposit framework in section 3.1.1.1 of the pro forma LGIP:

503. However, we modify the NOPR proposal to require transmission providers to collect a single study deposit only once upon entry into the cluster (initial study deposit), rather than requiring transmission providers to collect a study deposit at each phase of the cluster study process, as proposed in the NOPR. Therefore, we decline to adopt the proposed revisions to sections 3.1.1.2, 7.5, and 8.1 of the pro forma LGIP that would have implemented the phased study deposit approach. As a result of this modification to the NOPR proposal, the initial study deposit will be required only at the time the interconnection customer submits an interconnection request. The amount of the initial study deposit will be calculated using the tiered approach proposed in the NOPR based on the proposed MW size of the generating facility, as shown in the chart above.

504. We adopt the tiered approach based on the proposed MW size of the generating facility for determining the amount of the initial study deposit because larger proposed generating facilities within a cluster generally cost more to study than smaller proposed generating facilities within a cluster. Further, although we acknowledge that this approach does not perfectly approximate study costs, we find it appropriate to require the transmission provider to collect a study deposit based on a tiered approach because study costs will be trued up and any excess deposit refunded once the interconnection customer executes the LGIA or requests the filing of an unexecuted LGIA and submits the corresponding payment discussed below or withdraws from the interconnection queue.

505. We modify the NOPR proposal to require only a single initial study deposit, rather than multiple deposits at different stages of the cluster study process, as proposed in the NOPR. We believe that this modification will appropriately reduce the administrative burden for transmission providers to collect and manage the deposits. We recognize that the amount of the study deposit for interconnection customers will be lower than that proposed in the NOPR because of this modification. We are persuaded by commenters' arguments that initial study deposits are best used to provide transmission providers with funds to cover the costs of studies performed for interconnection customers rather than to serve as a disincentive against speculative interconnection requests. We therefore adopt an initial study deposit framework that better reflects the costs of the interconnection studies. For example, NV Energy states that, on average, it spends between $80,000 and $100,000 between the cluster system impact study and facilities studies and refunds the remaining deposits with interest. Under the study deposit framework we adopt, study deposits range between $55,000 and $250,000 for the smallest and largest proposed generating facilities, respectively, and thus reasonably track likely study costs based on the record. We believe that other reforms adopted in this final rule—notably, the commercial readiness deposits and the site control requirements—will adequately serve as a disincentive against speculative interconnection requests without unnecessarily duplicating those efforts through increased study deposits.

506. Additionally, we adopt the NOPR proposal to delete section 8.1.1 of the pro forma LGIP to remove the requirement for transmission providers to invoice interconnection customers on a monthly basis for the work conducted on the facilities study. We find that this monthly invoicing requirement is burdensome to the transmission provider and unnecessary given that section 13.3 of the pro forma LGIP includes policies for invoicing and establishes that interconnection customers are responsible for the actual costs of interconnection studies. Accordingly, we also delete from pro forma LGIP Appendix 3 (Interconnection Facilities Study Agreement), the portion of article 5.0 that includes the monthly invoicing requirement.

507. We disagree with rPlus' argument that study deposit requirements are unduly discriminatory or punitive to pumped storage because of its large capacity. We note that the initial study deposit reforms we adopt in this final rule are agnostic to the type of generating facility. Rather, the initial study deposits are based on the MW size of the proposed generating facility, regardless of the type of generating facility, such that interconnection customers proposing larger generating facilities will pay a larger deposit. As explained above, this reflects the fact that the expected costs to study those generating facilities are generally higher. Nonetheless, the modification we adopt here has the effect of lowering the required study deposit for all interconnection customers relative to the NOPR proposal, a finding which may partially allay rPlus' concern.

b. Demonstration of Site Control

i. NOPR Proposal

508. In the NOPR, the Commission stated that it believed that more stringent site control requirements will help prevent interconnection customers from submitting interconnection requests for speculative, commercially non-viable proposed generating facilities. The Commission preliminarily found that an interconnection customer securing the exclusive land right necessary to construct its proposed generating facility (or for co-located resources, demonstration of shared land use) is sufficient evidence of the interconnection customer's commitment to construct the generating facility.

509. The Commission proposed to revise the pro forma LGIP to require interconnection customers to demonstrate 100% site control for their proposed generating facilities when they submit their interconnection request. The Commission proposed to have transmission providers include in their tariff specific acreage requirements for each generating facility technology type to demonstrate site control.

510. To cut down on multiple interconnection customers leasing the same site in order to remain in the interconnection queue, the Commission proposed to revise the pro forma LGIP to require interconnection customers to demonstrate the exclusive land right (where the land rights are exclusive to the interconnection customer, not necessarily the individual generating facility) to develop, construct, operate, and maintain its generating facility or, where facilities are co-located, to demonstrate a shared land use right to develop, construct, operate, and maintain co-located facilities.

511. Additionally, the Commission proposed to include a limited option for interconnection customers to submit a deposit in lieu of site control when they submit their interconnection request only when regulatory limitations prohibit the interconnection customer from obtaining site control. The Commission explained that in such instances, the interconnection customer would submit an initial deposit in lieu of site control of $10,000 per MW, subject to a floor of $500,000 and a ceiling of $2 million, which would be applied toward any interconnection studies or a withdrawal penalty, if applicable. The Commission specified that such an interconnection customer must demonstrate 100% site control prior to the facilities study. The Commission further proposed that, after the interconnection customer notifies the transmission provider of a change to its site control demonstration, the transmission provider must give the interconnection customer 10 business days to demonstrate that the site control demonstration meets the applicable requirement after notification.

512. The Commission sought comment on: (1) whether there are other specific situations in which the Commission should accept a deposit in lieu of site control; (2) whether the definition of site control, including the requirement to obtain an exclusive land right (or, for co-located resources, a shared land right), should be broadened or refined to account for circumstances that may arise in, for example, the siting and permitting of offshore resources in bodies of water and/or submerged land; (3) whether and how the definition of site control should be adjusted for interconnection customers to account for any regulatory requirements they may have associated with proposed generating facilities developed on sites owned or physically controlled by a state government entity and/or a Federal Government entity; (4) the appropriate stage in developing such sites when the Commission should view completion of such stage as indicative of an interconnection customer's request being non-speculative and whether there are substantive differences among interconnection customers developing sites owned or physically controlled by a state government entity and/or a Federal Government entity; (5) whether the Commission should allow transmission providers to accept demonstrations of less than 100% site control in the initial phases of the interconnection study process, outside of when regulatory limitations prohibit the interconnection customer from obtaining site control; and (6) whether the Commission should instead adopt site control provisions that allow a deposit in lieu of site control to enter the generator interconnection process and be evaluated under the first-ready, first-served cluster study process described above but require interconnection customers to demonstrate site control to enter the facilities study.

ii. Comments

(a) General Comments

513. Several parties generally support the proposal to increase site control requirements. These commenters generally agree that the proposal is reasonable and that these measures can reduce speculative interconnection requests, represent a reasonable financial burden, help ensure that the interconnection customer is ready to enter the interconnection queue, help load serving entities have generating facilities interconnected as quickly and efficiently as possible, and reduce harm to other interconnection customers that have successfully secured site control for their proposed generating facility.

514. CREA and NewSun, on the other hand, argue that the Commission's proposed site control requirements are anti-competitive because they allow utilities to erect market barriers to competitors' generating facilities and because the requirements bar investment by companies seeking to develop generating facilities using a merchant generation model.

(b) Comments on Specific Proposal

(1) Definition and Reasonable Evidence of Site Control

515. Some commenters support the proposed definition of site control. MISO notes that the proposed requirement for exclusivity or the demonstration of a right to co-locate generating facilities is in MISO's current tariff and that these requirements have proven to be successful at preventing speculative interconnection requests from entering or continuing in the interconnection queue.

516. Some commenters suggest modifications to the definition of site control. ENGIE and Tri-State recommend that the Commission consider requirements similar to MISO's requirements to identify when and whether an interconnection request is non-speculative. Xcel supports modifying the definition of site control to ensure exclusivity and allow for co-ownership.

517. PJM requests that the Commission clarify that interconnection customers are prohibited from submitting evidence of site control that uses the same land for multiple interconnection requests, unless the site is large enough to host multiple generating facilities.

518. Enel supports the proposal to require land rights that are exclusive to one development company, but not necessarily to the individual generating facility. According to Enel, when used regarding land rights, “exclusive” means that only the owner of those land rights can possess the property, and this interpretation could prevent co-located resources from being built if one parent company was using two separate special purpose vehicles for two different generating facilities sharing land. Enel therefore recommends that the Commission clarify the intent of this word so that it does not artificially restrict multi-use applications.

519. Cypress Creek believes that, to the extent the Commission intends that a “land right” should involve zoning approval, such a proposal would be unreasonable because interconnection customers do not typically initiate local permitting until the system impact study phase, due to the system impact study's impact to overall generating facility commercial viability.

520. Southern requests that the Commission clarify subpart (3) of the proposed site control definition, arguing that, as written, it appears to be an incomplete statement that may authorize an interconnection customer to simply provide evidence that a site is big enough to host a proposed generating facility rather than evidence that the interconnection customer actually has any rights to that property. Enel argues that subpart (3) to the definition should be deleted, because as modified, that item is duplicative of and a subset of the materials covered under subpart (1).

521. Other parties request that the Commission clarify the definition of site control to specify what constitutes reasonable evidence to demonstrate 100% site control or provide suggestions for what should be considered reasonable evidence of site control. NYISO requests that the final rule establish uniform requirements across regions for making the 100% site control determination. APS requests that the Commission specify what is considered reasonable evidence in the same manner that the Commission defines commercial readiness milestones and argues that clarification is needed in order to avoid subjectivity regarding what is considered “reasonable” evidence to the transmission provider.

522. Omaha Public Power requests that the Commission clarify whether transmission providers will be able to accept lease options, instead of executed leases, as sufficient evidence of site control. Omaha Public Power notes that it has become industry standard to use lease options and argues that the Commission should not enact a rule that conflicts with current industry standard practices. SoCal Edison supports the NOPR proposal, provided that 100% site control includes an option to lease up to, and including, the commercial operation date or acquire the land when the interconnection request is submitted.

523. EPSA advises the Commission to consider options to demonstrate site control, including requiring attestations that a lessee or potential owner is in exclusive negotiations to establish site control, though it generally supports the development of clearer demonstrations. Interwest Energy Alliance recommends that the Commission consider evidence of active negotiations as potentially a sufficient demonstration of site control before the closing of the cluster request window.

524. SoCal Edison recommends that the Commission consider requiring that site control agreements be between the site owner and the same legal entity that is submitting the interconnection request. SoCal Edison explains that it has run into challenges when trying to determine whether interconnection customers have exclusive site control, in part due to the fact that companies change over time with renaming and/or mergers.

525. NRECA suggests that demonstration of site control with exclusive land rights should be allowed to include provisions that such rights are contingent upon favorable interconnection study results, inclusive of cost and schedule. NRECA notes that site control land options on many occasions come with a caveat that the lessee or purchaser has the ability to terminate within a due diligence period if interconnection results are unfavorable due to cost or schedule.

526. NV Energy requests clarification on whether an interconnection request should be deemed withdrawn if the interconnection customer does not provide demonstration of site control by the execution of the facilities study agreement.

527. Ørsted urges the Commission to clarify that, for offshore wind projects, the definition of “exclusive site control of the entire generating facility” means exclusive control of the Bureau of Ocean Energy Management (BOEM) issued offshore wind lease area, not cable routes on state submerged land or onshore cable routes to the point of interconnection. Ørsted reasons that, due to the extensive state and Federal permitting process, offshore wind developers may not have authorization in the form of permits or other land use rights for portions of the offshore wind project on state submerged land or for the offshore and onshore cable routes during the interconnection process.

528. NYTOs and Pacific Northwest Utilities argue that it is unclear what would constitute 100% site control and therefore regions should be allowed to implement appropriate definitions for their regions on compliance to address their specific circumstances.

529. ISO–NE states that its existing LGIP and SGIP provisions, which are consistent with those proposed in the NOPR, have proven to be effective, and that the Commission should extend flexibility so that they may be maintained. Similarly, Indicated PJM TOs argue that the final rule should permit PJM to implement its 2022 interconnection queue reform proposal for demonstrating site control, which is more rigorous than the NOPR proposal.

530. Several parties support the NOPR proposal to define 100% site control as an acreage requirement specific to the generating facility type and to require these acreage requirements in the tariff. Enel states that inclusion of acreage requirements in the tariff gives the Commission visibility into regional requirements to ensure that no transmission provider is significantly out of line with national assumptions.

531. Several commenters request that the Commission create a process by which an interconnection customer can demonstrate that its generating facility requires a different amount of acreage than the default value listed in the tariff. AES predicts that this approach will help ensure viable generating facilities are not inadvertently removed from the interconnection queue. MISO states that its tariff also allows an interconnection customer to demonstrate that it can operate the proposed generating facility with fewer acres. National Grid believes that regional flexibility would certainly be required for each transmission provider's proposed acreage requirements and requests clarification accordingly. Some commenters suggest that transmission providers be required to update the acreage requirements periodically to reflect technological advancements.

532. Other parties oppose the NOPR proposal to require specific acreage requirements in the tariff or suggest that these requirements should be included in business practice manuals rather than tariffs. Some commenters argue that these acreage requirements will likely change with technology advances, and it would be burdensome if transmission providers are required to submit an FPA section 205 filing every time they need to change acreage requirements. Fervo Energy argues that the risk in this proposal is that the acreage requirements may understate the energy density of a generating facility and thus overstate the number of acres required for a given number of MW, resulting in discriminatory treatment between competing generation technologies.

533. Ørsted recommends that transmission providers use the most recent estimates of power density from BOEM when establishing acreage requirements for offshore wind projects. Ørsted notes that offshore wind turbines have grown much larger in recent years, which allows significantly more power production from the same amount of acreage, and they argue that if transmission providers' tariffs were not updated frequently enough, the acreage requirements may become unreasonable.

534. Pine Gate recommends that acreage requirements specifically address how the requirements will be applied to hybrid and co-located generating facilities.

535. Some commenters request that the Commission clarify whether the site control requirement is limited to the generating facility or whether it also applies to transmission system elements like interconnection facilities or other upgrades that may be identified through the interconnection study process. Several parties argue that, for the initial request and study phase, 100% site control should not apply to land required to finalize routes for generator ties lines. AES argues that interconnection customers require flexibility when siting generator tie lines, which usually occurs near the very end of the interconnection process. Enel notes that there are sometimes crossings of railroads, streams, or other circumstances that require considerable time to complete and are outside the interconnection customer's control. AEE explains that issues can occur when interconnection customers have all but one small parcel on the route of their generating facility secured, with only one small piece of connectivity missing due to permitting delays or other issues. Similarly, Invenergy argues that it is unreasonable and impractical to predict and obtain rights to land for facilities that have not yet been identified. Invenergy also states that the point of interconnection can change during the study process, thus changing the land needs for the interconnection customer's interconnection facilities, and this change may be driven by a number of different factors, including the transmission provider's preference, which may be outside the interconnection customer's control.

536. Ørsted, ACE–NY, and Equinor Wind note a myriad of challenges for obtaining site control for interconnection facilities for offshore wind projects, such as conflicts between Federal and state permitting entity requirements for project flexibility and adaptability. Ørsted argues that site control for interconnection facilities for offshore wind developers is only obtainable very late in the interconnection process.

537. Other commenters argue that the Commission should expand the proposed definition of site control to apply some degree of site control requirements to interconnection facilities, such as a requirement to demonstrate 50% site control for interconnection facilities when submitting the interconnection request. MISO encourages the Commission to require site control for interconnection facilities at the same time that it requires site control for the generating facilities. AEP explains that some interconnection customers submit interconnection requests that are not feasible given where interconnection customer interconnection facilities would have to be sited to connect the generating facility to the transmission system at the selected point of interconnection. Additionally, AEP explains that, even if a generation site is suitable, there may not be “room” at certain locations for a substation or switchyard due to a variety of issues, including abandoned mines, surrounding wetlands, or other geographic impediments. According to AEP, site control for generating facilities can be far less important than feasible control over the land needed to connect the generating facility to the transmission system.

538. Enel argues that the addition of a generator tie line site control requirement will increase the quality of interconnection study results and increase certainty for interconnection customers as the interconnection process becomes more costly and risky to navigate. Enel states that it has observed or heard of interconnection customers submitting existing site control from very remote locations to secure interconnection queue positions, and later submitting a modification request to move the generating facility site close to the point of interconnection after the generating facility's actual intended site control has been obtained. Enel states that this is done by interconnection customers to reduce the duration and subsequently the cost of maintaining site control, as a failed distant asset can be used for a new interconnection queue position elsewhere until site control for the new generating facility area is complete. In addition, Enel states that it supports SPP's approach, which also requires 75% of generator tie line site control after the first cluster restudy, to ensure interconnection customers are making reasonable progress.

539. National Grid argues that demonstrating site control for interconnection facilities is crucial for generating facility development and interconnection queue management particularly in cases where numerous interconnection requests in the interconnection queue are reliant on the construction of certain network upgrades. National Grid argues that the payment of cash or the provision of other security in lieu of demonstration of site control of transmission owner interconnection facilities or network upgrades built by an interconnection customer does not further the goals of the NOPR.

(2) Site Control Demonstration

540. Several commenters support the NOPR proposal to require interconnection customers to demonstrate 100% site control for their proposed generating facilities when they submit their interconnection request. MISO argues that obtaining site control is consistent with the “first-ready, first-served” model and that delaying site control for interconnection requests until later in the interconnection process just increases the instances of late-stage withdrawals that leads to uncertainty, unplanned restudies, and delays for the remaining interconnection requests. National Grid asserts that the demonstration of complete and exclusive site control is necessary at the interconnection request stage to avoid submission of interconnection requests prematurely, potential conflicts with other interconnection requests, and delays in issuing cluster studies. GSCE contends that there should be few exceptions to a site exclusivity requirement to enter the cluster study process so leniency is not granted to the type of interconnection requests that linger in the interconnection queue while they struggle to secure difficult land rights and permitting.

541. PJM opposes any requirement on transmission providers to accept demonstrations of less than 100% site control at the time of an interconnection request, except for accommodations for interconnection requests for proposed generating facilities to be sited offshore or on government owned land.

542. MISO notes that its tariff requires redemonstrations of site control. Similarly, Indicated PJM TOs support requiring 100% site control at more than one decision point, and assert that transmission providers should be allowed to confirm site control throughout the interconnection process. Indicated PJM TOs and Longroad Energy argue that the Commission should strengthen the proposed site control requirements to ensure that interconnection customers are maintaining site control throughout the interconnection process.

543. On the other hand, APS believes that simultaneous submission of the interconnection customer-executed LGIA and the continued demonstration of site control is duplicative and unnecessary if an interconnection customer demonstrates site control at the time an interconnection request is made.

544. Several commenters oppose the NOPR proposal to require an interconnection customer to demonstrate 100% site control at the time of the interconnection request and/or propose alternative site control requirements. A number of commenters express concern that the NOPR proposal is not compatible with the generating facility development cycle. EPSA argues that a 100% exclusive site control requirement in advance of the processing of the facilities study is not reasonable because it overlooks the complicated and extensive process of negotiating for land leases or purchases. Similarly, Cypress Creek and AEE argue that the NOPR proposal does not reflect realities of development, which include stringent permitting requirements, and may disadvantage certain interconnection customers despite being on a path to full site control and commercial readiness. CESA and Clean Energy Associations argue that the requirement for 100% site control at the interconnection request stage is excessively stringent and would significantly favor utility-owned projects.

545. CREA and NewSun argue that the NOPR proposal is not adequately supported and urge the Commission to maintain the existing site control requirements. CREA and NewSun argue that the proposal is unreasonable and “creates a Catch-22”: specifically, that without reliable visibility as to the interconnection costs and viability for its proposed generating facility within the specific cluster, the interconnection customer will not be able to attract investment needed to secure site control. CREA and NewSun also argue that a landowner hoping to see property developed may not agree to permanently tie up land in a lease before the interconnection customer can show interconnection is viable. CREA and NewSun argue that interconnection requests may prove uneconomic after receipt of initial interconnection studies and thereafter cannot finalize site control due to uneconomic interconnection costs. CREA and NewSun also assert that the Commission made no effort in the NOPR to ascertain the impact on the market of the “draconian” site control rules for such transmission providers that have been allowed to adopt them.

546. R Street argues that requiring even partial site control at the time of the interconnection request may create delays and increase project development costs because it would require more options contracts to be in place with landowners. NextEra argues that site control is a limited indicator of generating facility viability. rPlus argues that requiring 100% site control at the interconnection request stage will inhibit the flexibility for interconnection request design changes that is needed to develop pumped storage projects.

547. Several commenters recommend that the Commission modify the site control requirements in the final rule to require less than 100% site control at the time of the interconnection request. For example, Clean Energy Associations, SEIA, and Cypress Creek argue that no more than 75% site control is appropriate at the time of the interconnection request. Shell argues that the Commission should only require partial site control when the interconnection request is made. Clean Energy Associations supports an escalating schedule of site control through the interconnection process and suggests that the Commission should modify the NOPR proposal to also require 90% site control at the post-cluster study decision point and 100% site control at the post-facilities study decision point.

548. AEE argues that 90% site control at the time of the interconnection request provides interconnection customers sufficient flexibility. Additionally, several commenters state that 100% site control at the post-facilities study decision point would be appropriate. AEE argues that these altered requirements will reduce speculative interconnection requests while also providing incentive for interconnection customers to pursue remaining land rights after entering the interconnection queue.

549. Some commenters note that less than 100% site control at the interconnection request stage would allow interconnection customers flexibility to address the results of interconnection studies or other regulatory processes, which may lead to changes in the size or design of a generating facility. Additionally, SEIA requests that the Commission require transmission providers to allow interconnection customers to change site boundaries or reduce the size of a proposed generating facility, as long as the point of interconnection remains the same, in order to accommodate changes resulting from interconnection studies or regulatory changes. Pine Gate notes that sometimes interconnection customers are still actively negotiating with landowners close to the deadline for a cluster review window and requests the Commission to permit interconnection customers to demonstrate to the transmission prover that they are in active negotiations to meet the heightened site control requirements.

550. Some commenters highlight that the NOPR proposal may be problematic or challenging for interconnection customers of certain technology types or other circumstances where obtaining site control is difficult. Hydropower Commenters argue that most new hydropower facilities are sited at existing non-powered dams and therefore hydropower interconnection customers face unique challenges when it comes to obtaining site control. The Ohio Commission Consumer Advocate asserts that the proposal may be problematic for interconnection customers in Ohio because a recent Ohio law permits Ohio counties to designate unincorporated areas in a county as an area in which the development of a renewable energy project is prohibited.

551. According to Enel, some states limit the duration of site control. Enel asserts that, if site control is near to expiring for any reason, whether due to state restriction or simply because the interconnection customer did not anticipate the length of interconnection or permitting processes, landowners can demand higher payments than agreed to in the original site control contract. Enel states that this can change the economics of a proposed generating facility and even make a proposed generating facility unprofitable, potentially leading to a late-stage interconnection request withdrawal.

552. Several commenters argue that the Commission should reject proposals to weaken the site control requirements proposed in the NOPR. APPA–LPPC argue that EPSA's and SEIA's generalized complaints do not identify a specific obstacle created by the Commission's proposal, and APPA–LPPC argue that SEIA's proposal to scale back the site control requirement to not more than 75% was considered and rejected by MISO's management and stakeholders over concerns that it may not be rigorous enough to mitigate the entry of speculative interconnection requests in the queue.

(3) Deposits in Lieu of Site Control

553. Several commenters support the NOPR proposal to eliminate the option for interconnection customers to submit a deposit in lieu of site control except in limited circumstances for regulatory limitations. These commenters express that allowing deposits in lieu of site control is not sufficient to demonstrate readiness or deter speculative interconnection requests. PJM notes that, in its experience, the option to provide money in lieu of actual site control is easily abused by interconnection customers with speculative interconnection requests. CAISO notes that its most recent cluster study was inundated by interconnection requests without site control because even a $250,000 deposit in lieu of site control has not proven to be a deterrent for interconnection customers.

554. Some commenters oppose the NOPR proposal and argue that the option to make deposits in lieu of site control should be available for all interconnection customers, not just those that demonstrate regulatory limitations. Avangrid believes that an at-risk deposit in lieu of site control that is set at a reasonable magnitude may be a good alternative to ensure that an interconnection customer is rigorously pursuing completion of a proposed generating facility. Pacific Northwest Utilities suggest that the Commission should allow transmission providers the flexibility to determine whether deposits in lieu of site control are applicable.

(4) Site Control Considerations for Interconnection Customers With Regulatory Limitations

555. Some commenters contend that the Commission should modify the proposed definition of site control to reasonably accommodate interconnection customers developing generating facilities on sites owned or controlled by a government entity. Several commenters highlight unique circumstances and challenges for obtaining site control on certain public lands and other regulatory issues that may affect an interconnection customer's ability to demonstrate site control under the NOPR definition.

556. Several commenters argue that the Commission should provide flexibility to allow transmission providers to establish site control requirements for generating facilities sited on Federal and public land. Shell notes that securing site control can often be complicated by fast-changing local, county, and state regulations, and encourages the Commission to provide sufficient flexibility to enable transmission providers to make accommodations for local site control challenges.

557. Some commenters provide recommendations on how the Commission could clarify what may constitute a sufficient demonstration of site control for generating facilities being developed on land owned or controlled by a government entity. Pattern Energy argues that interconnection customers proposing to develop generating facilities on land owned or managed by state, Federal, or Tribal government entities should be required to provide evidence that they submitted any required applications to the relevant government entity or entities in order to advance the development of their proposed generating facility. Pattern Energy states that such an interconnection request should provide for an exclusive right to advance the development of a generating facility, provided that the relevant government entity or entities allow for such an exclusive right.

558. PJM notes that the proposed site control requirements that PJM included in its interconnection queue reform filing with the Commission provide some leeway for generating facilities constructed on Federal or state lands or water, such as offshore wind projects. Alternatively, Dominion requests that the Commission clarify that the deposit in lieu of site control exception would apply to offshore wind projects, in addition to other proposed generating facilities subject to similar government control that may prevent timely demonstration of site control.

559. Several commenters note that certain interconnection customers with generating facilities and interconnection facilities on land controlled by the Bureau of Land Management (BLM) face extended time frames for obtaining firm site control. For example, NV Energy states that the BLM permitting process can take between 18 months and 5 years. Idaho Power states that BLM goes through various stages of review, but there is no specific stage that is indicative of an interconnection customer's request having firm site control until the permit is in hand, which can take up to three years to obtain. Idaho Power states that, currently, interconnection customers with generating facilities on BLM lands typically reference the section of the site control definition that allows for “an exclusivity or other business relationship between interconnection customer and the entity having the right to sell, lease or grant interconnection customer the right to possess or occupy a site for such purpose.” Idaho Power argues that generating facilities on land managed by BLM should have the same site control requirements as all other generating facilities, but that they would support an expanded and/or clarified definition of site control to capture the limitations of these generating facilities. Idaho Power states that, for example, site control evidence may include evidence that the necessary application has been received by the agency, is in process, and the agency has indicated the generating facility is permittable.

560. NV Energy proposes that the deposit in lieu of site control be used for lands that are federally managed, and that those deposits be held until the decision record, record of decision, notice to proceed, or right-of-way grant is issued for a generating facility, which NV Energy notes may not be until after the facilities study due to timing of the BLM process. To ensure the generating facility is progressing in the BLM process, NV Energy also proposes that the interconnection customer be required to submit with its interconnection request a schedule of the land rights and permitting as well as documentation from BLM that the draft environmental assessment or draft environmental impact statement is expected to be completed by issuance of the system impact study. NV Energy also proposes that interconnection customers be required to provide the administrative draft environmental assessment or draft environmental impact statement to the transmission provider for review and comment once BLM has issued it to ensure its interconnection facilities are included in the right-of-way that BLM will issue.

561. CREA and NewSun encourage the Commission to modify its proposed site control requirements, such that an interconnection customer developing generating facilities on public lands is allowed to proceed with the interconnection process if it can demonstrate that the relevant public agency has received and has agreed to process the necessary permits to develop the interconnection customer's proposed generating facility.

562. For generating facilities on Bureau of Reclamation lands, Hydropower Commenters argue that a lease of power privilege should be considered a sufficient demonstration of site control. Additionally, Hydropower Commenters note that generating facilities under a certain size can obtain an exemption from Commission licensing requirements, and they argue that an exemption from licensing should also be considered a sufficient demonstration of site control. Similarly, Hydropower Commenters argue that developers of pumped storage projects on U.S. Forest Service or BLM lands should not be required to complete the required Federal Land Policy and Management Act process before they can be considered to have demonstrated sufficient evidence of site control. Hydropower Commenters contend that such generating facilities should be allowed to demonstrate site control by submitting evidence that they have a permit application pending with U.S. Forest Service or BLM.

563. Some commenters argue that the 100% site control requirement should not apply to generating facilities being developed on Tribal lands. OSPA claims that development on Tribal land is more challenging than other kinds of development because Tribes have three different classes of land that have different ownership structures and regulatory restrictions, including “Trust” land, which is held by the Federal Government on behalf of Tribes and regulated by the Bureau of Indian Affairs. OSPA notes that Tribes' Reservations are often “checker-boarded” with the three different classes of land, and that large wind generating facilities will necessarily be sited on all three classes of land. OSPA argues that securing Bureau of Indian Affairs regulatory approvals can take years and that the ownership structure of “Allotted” lands can make it even difficult to expediently obtain consent from all owners to lease certain tracts, which is required as part of the Bureau of Indian Affairs process.

564. OSPA proposes that, for Tribes and Tribal Energy Development Organizations, the Commission clarify that interconnection queue positions may be secured if the Tribe has signed a lease, even if the Bureau of Indian Affairs has not issued a final approval. Similarly, rPlus recommends that the filing of a valid preliminary permit application with the Commission satisfy the site control requirement for a pumped storage project and for generating facilities on Tribal lands. rPlus notes that suitable pumped storage sites are limited in availability and are increasingly located on public or Tribal lands, which involve significant environmental review. rPlus notes that pumped storage projects located on Federal and Tribal lands generally cannot achieve full site control until Federal environmental reviews are complete and the Commission issues a license. For circumstances where a pumped storage project does not require a Commission license, rPlus requests that the site control requirement be only 50% of the land needed for the core generating facility.

565. Several commenters state that the proposed site control requirements may present challenges for offshore wind projects, which face extensive permitting timelines. Clean Energy Associations argue that the formal issuance of a public lease often requires multiple preliminary stages and major financial commitments from interconnection customers and that requiring a lease prior to entering the interconnection queue would unduly delay generating facilities on public lands. Ørsted and Clean Energy Associations further explain that the permitting process for an offshore wind farm often involves multiple Federal and state agencies and runs concurrently with the interconnection process. Ørsted and Clean Energy Associations note that the permitting process can lead to changes in the generating facility layout within a lease area, routing of offshore cables, siting of onshore cable landing, routing of onshore cables, and siting of the interconnection switchyard.

566. Shell, Dominion, and CREA and NewSun argue that the high cost of market entry for offshore wind projects is a substantial financial commitment and that such generating facilities are by their very nature not speculative. Shell argues that offshore wind generation should be able to demonstrate site control by showing evidence of commitments to purchase offshore lease areas from BOEM, as commitments often demand hundreds of millions of dollars.

567. CREA and NewSun contend that the site control requirements in the NOPR would require an offshore developer to win a competitive solicitation or obtain a term sheet from an off-taker before entering the interconnection queue, which at best will add years of delay to developing these generating facilities and at worst will kill the proposals outright due to a lack of information on interconnection feasibility and cost.

568. MISO notes that it has not interpreted its tariff to mean that a BOEM-administered Wind Energy Area auction that an offshore wind interconnection customer can participate in, but which will occur after the close of an application window, is a regulatory restriction. MISO is concerned that broadening the regulatory restriction interpretation to allow for offshore wind to submit an interconnection request in such instances would enable speculative interconnection requests, which will result in withdrawals, restudies, uncertainty, and study delays. MISO states that interconnection customers that seek to develop a generating facility on government owned lands that are awarded to the winner of an auction, and interconnection customers that seek to develop a generating facility on private land, are held to the same standard in the MISO process.

569. Some commenters request that “regulatory limitations” be more clearly defined. CAISO expresses concern that, absent clarification, the regulatory limitation provision will leave transmission provider staff as adjudicators of whether obtaining site control is possible for each proposed generating facility, and interconnection staff are not experts on real property law or public permitting requirements. CAISO and Indicated PJM TOs argue that without further clarification, the regulatory limitation provision may be interpreted too broadly and interconnection customers could argue site control was impossible where it was simply impractical or expensive. CAISO suggests, as an example, that the Commission could limit “regulatory limitations” only to apply to interconnection customers sited in offshore areas, public lands, and Tribal lands.

570. Several parties support the NOPR proposal to allow interconnection customers with regulatory limitations to submit a deposit in lieu of site control. For projects on government lands, Indicated PJM TOs argue that the interconnection customer should be allowed to enter and remain in the interconnection queue, with a deposit in lieu of site control, if they identify the steps needed to achieve site control and show how they are exercising due diligence to obtain a final government determination. Indicated PJM TOs argue that the regulatory limitations exception should be limited to just government lands.

571. MISO supports such an option specifically when the interconnection customer is prevented from obtaining site control by a regulatory restriction that the passage of time itself will not cure ( e.g., while participating in an auction that occurs after the interconnection request deadline can be cured by time, a requirement to obtain an LGIA to participate in an auction cannot be cured by time).

572. Tri-State suggests modifying section 3.4.[1]2 of the pro forma LGIP so that the site control for state or federally controlled land must still be fully attained at the time of LGIA execution. For example, Tri-State states that in Colorado, a state land planning lease (which does not meet the Commission's proposed definition of site control) could be used with a financial deposit during the cluster study process, and a state land production lease (which does meet the Commission's proposed definition of site control) would be needed prior to LGIA execution.

573. APPA–LPPC argue that, if the NOPR proposal is adopted, at a minimum, the interconnection customer should be required to provide an affidavit from a company officer, a detailed explanation, and documentation justifying the proposed regulatory limitation exception and to demonstrate 100% site control as soon as possible after the generator interconnection request is submitted, and certainly prior to the facilities study stage, as the NOPR proposes. PPL contends that, while additional flexibility for interconnection customers that face regulatory limitation may be appropriate in the early stages of review, the Commission should require that full site control be demonstrated before proceeding to an LGIA.

574. A number of commenters oppose the NOPR's proposed option to allow deposits in lieu of site control where Federal or state regulatory limitations prohibit the interconnection customer from obtaining site control. Idaho Power argues that any allowance of a deposit must be accompanied by some evidence of achieving site control. APS asserts that speculative interconnection requests do not necessarily have financial limitations and extra deposits would not act as the same deterrent as requiring 100% site control; therefore, APS requests that the Commission not allow an exception for regulatory restrictions.

575. OSPA argues that requiring interconnection customers that face regulatory barriers to submit any deposits, including deposits in lieu of site control, will create insuperable barriers to renewable energy development by Native American Tribes and Tribal Energy Development Organizations on Tribal lands, stating that Tribes have limited access to capital and face other challenges that large developers do not share.

576. A few commenters support the proposed amounts for the deposit in lieu of site control. MISO agrees that the proposed deposit thresholds are sufficient, noting that the amount of the deposits under MISO's tariff are the same amounts the Commission proposed in the NOPR. Tri-State contends that the proposed deposit amounts would be sufficient to ensure advanced-stage interconnection requests are able to continue to move toward interconnection.

577. Several parties support a deposit in lieu of site control high enough to deter speculative interconnection requests that are unlikely to achieve site control. Avangrid argues that any deposit in lieu of site control should be proportionate to the size of the interconnection request, and “reflect collateral” while an interconnection customer works through site control agreements. Eversource similarly argues that the Commission should set the deposit so that the interconnection customer fully internalizes the risk of failing to obtain site control. Tri-State also argues that the deposit should not apply to interconnection study costs.

578. Some commenters provide alternative suggestions for the deposit in lieu of site control amounts. Longroad Energy argues that the Commission should consider requiring that such deposits be set as a multiple of the interconnection study deposit (such as three times the deposit amount), rather than as a dollar amount per MW of generating facility size, as proposed in the NOPR. NYTOs argue that the MW capacity of a generating facility is not necessarily relevant to determining the appropriate deposit requirement and that deposits should be more closely tied to the generating facility's potential impact on the interconnection process.

579. A number of entities argue that any deposits in lieu of site control should be non-refundable. Avangrid suggests that the deposit be non-refundable to avoid gaming by prospective interconnection customers. National Grid argues that absent circumstances outside the control of the interconnection customer, any deposit should be non-refundable, and any security should be able to be drawn upon in the event the interconnection customer withdraws or fails to demonstrate site control at the required time. National Grid contends that if the Commission intends to permit refunds or returns of a deposit in lieu of site control, such deposits should be provided only after deducting the actual costs and fees, e.g., escrow account initiation and maintenance fees, incurred by the transmission provider or RTOs/ISOs prior to the time of the withdrawal request or the demonstration of site control. National Grid also requests that the Commission clarify that withdrawal penalties are separate and may be deducted from the deposit amount.

580. Similarly, Longroad Energy suggests that to ensure that the proper incentives exist, the Commission may wish to evaluate if a security deposit in lieu of site control should become non-refundable if an interconnection customer withdraws at any point in the interconnection process or fails to achieve commercial operation. EEI argues that the Commission can further reduce potential risks by making deposits non-refundable, or if the Commission declines to do so, it should ensure that withdrawal penalties are significant enough to discourage speculative interconnection requests. On the other hand, NYTOs argue that regions should have the flexibility to determine whether, under certain circumstances, deposits should become fully non-refundable.

581. Xcel argues that in addition to requiring a deposit, interconnection customers facing regulatory limitations should be required to provide status updates to the transmission provider, and there should be sufficient penalties to ensure interconnection customers provide accurate information on the status of regulatory proceedings. Xcel contends that, if regulatory limitations prohibit an interconnection customer from obtaining site control, transmission providers should be allowed to propose constructs that facilitate interconnection, including the ultimate achievement of site control.

(c) Miscellaneous

582. Public Interest Organizations argue that it is unreasonable that the pro forma LGIP allows interconnection customers to propose a decrease to the generating facility's output of up to 60% without losing queue position while also requiring a demonstration of 100% site control upon entering the interconnection queue. Public Interest Organizations also argue that the NOPR proposal to require interconnection customers to remedy any change in site control within 10 days or have their interconnection request withdrawn is unreasonable. In addition, Public Interest Organizations argue that it is unduly discriminatory to allow interconnection customers proposing a thermal project to keep their queue position by downsizing the generating facility's turbines but not allow interconnection customers proposing wind generating facilities to keep their queue position if they lose part of a lease. Public Interest Organizations argue that the cure period should be long enough to allow for routine events that affect site control, such as the death of a landowner or the change of ownership at a commercial facility hosting a proposed generating facility.

iii. Commission Determination

583. As discussed herein, we adopt in part and modify in part the NOPR proposal to revise sections 1, 3.4.2, 7.5, 8.1, and 11.3 of the pro forma LGIP and Appendix B of the pro forma LGIA to add more stringency to the site control requirements and to help prevent speculative interconnection requests from entering the interconnection queue. We believe that, taken together, these reforms will help ensure that commercially viable interconnection requests with demonstrated site control or with demonstrated regulatory limitations will be able to enter the interconnection queue, thereby reducing the negative impacts of speculative interconnection requests.

(a) Definition and Reasonable Evidence of Site Control

584. We adopt the NOPR proposal to revise the definition of site control in section 1 of the pro forma LGIP with several modifications. As modified, the definition states that site control may be demonstrated by documentation establishing: “(1) ownership of, a leasehold interest in, or a right to develop a site of sufficient size to construct and operate the Generating Facility; (2) an option to purchase or acquire a leasehold site of sufficient size to construct and operate the Generating Facility; or (3) any other documentation that clearly demonstrates the right of Interconnection Customer to exclusively occupy a site of sufficient size to construct and operate the Generating Facility.” Additionally, we agree with commenters' observations that subpart (3) of the pro forma LGIP definition of site control proposed in the NOPR, which stated “site of sufficient size to construct and operate the Generating Facility,” was duplicative; therefore, we modify the NOPR proposal to delete this subpart and provide clarification that all three remaining, enumerated options to demonstrate site control require control of a site of sufficient size to construct and operate the generating facility or multiple generating facilities on a shared site.

585. To prevent multiple interconnection customers from leasing the same site in order to remain in the interconnection queue, we adopt the NOPR's proposed revisions to the pro forma LGIP that require an interconnection customer to demonstrate the exclusive land right to develop, construct, operate, and maintain its generating facility or, where facilities are co-located, to demonstrate a shared land use right to develop, construct, operate, and maintain co-located facilities. We further clarify that the right to “exclusively” occupy the site to develop, construct, operate, or maintain a generating facility means both that the right belongs solely to the interconnection customer (no other entity shares the right to use the site for those purposes), as well as that the right is solely for purposes of a single interconnection request. We find that an interconnection customer securing the exclusive land right necessary to construct its proposed generating facility (or for co-located generating facilities, demonstration of shared land use) is sufficient evidence of the interconnection customer's commitment to construct the generating facility.

586. We also modify section 3.4.2 of the pro forma LGIP to provide that site control for a generating facility that is co-located with one or more generating facilities on the same site and behind the same point of interconnection must be demonstrated by a contract or other agreement that allows for shared land use for all generating facilities that are co-located that meet the provisions of the site control definition. We clarify that interconnection customers are prohibited from submitting evidence of site control that uses the same land for multiple interconnection requests, unless the site is large enough to host multiple generating facilities. We note that section 3.4.2 of the pro forma LGIP that we adopt in this final rule permits shared land use for co-located generating facilities on the same site and behind the same point of interconnection, and we clarify below that transmission providers have flexibility to establish appropriate technology-specific acreage requirements for generating facilities. Permitting multiple interconnection requests to use the same land to demonstrate exclusive site control would inherently result in at least one commercially non-viable interconnection request entering the interconnection queue and thus would be insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. We also clarify that the interconnection customer is required to meet the technology-specific acreage requirement for its generating facility that is publicly posted by the transmission provider at the time it submits its interconnection request.

587. Likewise, in response to Enel, we clarify that the term “exclusive land rights” in the definition of site control applies only to the exclusivity required to develop, construct, operate, and maintain the interconnection customer's proposed generating facility; the term “exclusive land rights” does not restrict multi-use applications of the site in addition to its use for the generating facility, such as agriculture, ranching, etc. Similarly, in response to Cypress Creek, we clarify that a land right does not involve zoning approval.

588. In response to commenters, we further clarify that the adopted definition of site control permits an interconnection customer to demonstrate site control with lease options, instead of executed leases, provided that the interconnection customer is the exclusive holder of such a lease option(s). The adopted definition explicitly provides for such a lease option, by including the phrase, “an option to purchase or acquire a leasehold site.” However, evidence of active negotiations for a lease is not a sufficient demonstration of site control at any time during the interconnection process. Allowing active negotiations for a lease to serve as a demonstration of site control, as some commenters suggest, would allow speculative, commercially non-viable interconnection requests to proceed through the interconnection queue, which would be inconsistent with ensuring that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. Likewise, with respect to NRECA's request, we clarify that this final rule permits leases and lease options as sufficient evidence of site control as discussed above, and transmission providers have discretion to evaluate the content of such leases and lease options and any conditions contained therein to determine whether they sufficiently demonstrate site control.

589. Several commenters seek clarification as to whether the proposed pro forma LGIP definition of site control would allow certain types of generating facilities developed on lands owned or controlled by a government entity to demonstrate site control. We agree with commenters that offshore wind interconnection customers must make a substantial financial commitment to win a competitive auction and secure a lease from BOEM, and such generating facilities that have secured a lease agreement are not speculative. We therefore clarify that a lease agreement with BOEM to pursue development of an offshore wind generating facility can serve as a sufficient demonstration of site control under the site control definition adopted in this final rule. This clarification is consistent with our finding above that a variety of lease options satisfy the site control requirement. In response to MISO's concerns about allowing multiple offshore wind interconnection customers to submit an interconnection request for the same “Wind Energy Area” before it has been auctioned by BOEM, we find that the pro forma LGIP site control definition that we adopt herein appropriately limits such potentially speculative interconnection requests by requiring offshore wind interconnection customers to provide evidence of an exclusive right to develop a lease area to satisfy the site control requirements.

590. With respect to OSPA's concerns regarding the challenges of demonstrating site control on Tribal lands due to the nature of land ownership on Reservations and the need for the Bureau of Indian Affairs to approve certain leases, we clarify that under the site control definition, interconnection customers developing generating facilities on Tribal lands can demonstrate site control with a signed lease agreement with the applicable Tribe-owner. As discussed below in section III.A.6.b.iii.b, an interconnection customer with a demonstrated regulatory limitation, including those associated with obtaining a lease on Tribal lands, may submit a deposit in lieu of site control.

591. Similarly, in response to commenters' concerns about demonstrating site control for hydropower projects on sites owned or controlled by a government entity, we clarify that certain documentation can be used to demonstrate site control under the pro forma LGIP definition of site control. For interconnection customers developing generating facilities at non-powered dams, we clarify that a FERC license can serve as a demonstration of site control under subpart (3). However, we also clarify that neither a Memorandum of Agreement with the U.S. Army Corps of Engineers regarding a proposed hydropower project at a U.S. Army Corps of Engineers dam nor a preliminary permit for a pumped storage project or other hydropower generating facility to be located on Tribal lands would be sufficient to demonstrate site control because we do not have enough information in this record to determine that such documentation provides sufficient evidence of the interconnection customer's exclusive right to occupy a site of sufficient size to construct and operate a generating facility.

592. For hydropower projects that are not subject to the Commission's hydropower permitting jurisdiction, such as projects on Bureau of Reclamation lands, we clarify that a lease of power privilege can serve as a demonstration of site control under the site control definition. Finally, for hydropower projects that are small enough to be exempted from FERC licensing requirements, Hydropower Commenters explain that an exemption from FERC licensing provides an exclusive right to the recipient to develop a project at the site and the exemption is issued in perpetuity. Because such an exemption includes an exclusive right to develop, we clarify that providing a written statement as evidence of an exemption from licensing under the FPA can serve as a demonstration of site control under subpart (3) of the site control definition.

593. We note NV Energy's explanation that its previous efforts to allow interconnection customers to demonstrate site control by showing a draft preliminary plan of development, one of the earlier required documents in the BLM permitting process, have led to speculative interconnection requests that slow down the interconnection process. We agree, and we therefore decline to adopt commenters' proposal to modify the proposed pro forma LGIP definition of site control to allow interconnection customers to demonstrate site control by providing documentation indicating that they are pursuing the necessary permits with the appropriate government entity or entities. As with our finding that active negotiations for lease agreements are not sufficient to demonstrate site control, discussed above, we find that such an expansion of the site control definition could weaken the site control requirements included in the pro forma LGIP and could undermine the effectiveness of this reform in helping to prevent speculative interconnection requests.

(b) Site Control Demonstration and Deposits in Lieu of Site Control

594. We adopt the NOPR proposal, with modification, to revise section 3.4.2 of the pro forma LGIP to require interconnection customers to demonstrate site control at the time of submission of the interconnection request. However, we modify the proposal and require interconnection customers to provide evidence of 90% site control for the generating facility at the time of submission of the interconnection request and, pursuant to revised sections 8.1 and 11.3 of the pro forma LGIP, provide evidence of 100% site control for the generating facility at the time of execution of the facilities study agreement and when executing, or requesting the unexecuted filing of, the LGIA.

595. We decline to adopt the NOPR proposal to require technology-specific acreages to be listed in the transmission provider's tariff. As discussed below, instead, we require transmission providers to establish acreage requirements for each generating facility technology type and to publicly post these acreage requirements. We adopt the following aspects of the NOPR proposal to revise sections 3.4.2 and 11.3 of the pro forma LGIP to: (1) eliminate the option to provide a deposit in lieu of site control demonstration except in limited circumstances where an interconnection customer demonstrates a regulatory limitation to obtaining site control, as discussed below, and eliminate the option to post $250,000 of non-refundable security in lieu of site control at LGIA execution; and (2) require that interconnection customers that could not demonstrate the requisite level of site control at the relevant milestone of the interconnection process ( i.e., 90% for the cluster study and cluster restudy, and 100% for the interconnection facilities study and when executing, or requesting the unexecuted filing of, the LGIA) would have their interconnection request deemed withdrawn and could be subject to withdrawal penalties under certain circumstances, as discussed below.

596. We adopt the NOPR proposal to revise sections 3.4.2, 7.5 and 8.1 of the pro forma LGIP such that, after notifying the transmission provider of any change to the interconnection customer's site control demonstration, the transmission provider must give the interconnection customer 10 business days to demonstrate satisfaction with the applicable requirement. We find the adopted approach to require 90% site control at the time of the interconnection request and 100% site control at the time of the facilities study and when executing, or requesting the unexecuted filing of, the LGIA appropriately balances the concerns identified in the record. In particular, we find that it will provide sufficiently stringent site control requirements to help prevent interconnection customers from submitting interconnection requests for speculative, commercially non-viable proposed generating facilities, while accommodating development challenges faced by interconnection customers that may otherwise present unjust and unreasonable barriers to entering the interconnection queue. We believe that this approach appropriately recognizes that issues often arise in developing a generating facility, such that requiring a demonstration of 90% site control at the time of the interconnection request, rather than 100%, provides valuable flexibility for interconnection customers with viable prospective generating facilities to resolve those issues and continue through the interconnection process.

597. We are persuaded by commenters that contend that there are significant benefits to allowing interconnection customers to enter the cluster study process and potentially use the interconnection study results to better understand their generating facility configuration before obtaining 100% site control. We agree with commenters that allowing less than 100% site control at the interconnection request stage would provide interconnection customers flexibility to address the results of interconnection studies or other regulatory processes and afford flexibility for interconnection customers that are still actively negotiating with landowners close to the deadline for a cluster request window. Establishing a requirement for 90% site control at the time of an interconnection request allows an interconnection request to be submitted even if a few parcels of land are still in negotiation or where a different site configuration arises based on the scoping meeting with the transmission provider. Moreover, the adopted approach provides flexibility for interconnection customers to sign certain leases for particularly challenging parcels at a later point in time, reducing the exposure to risk of expiration of those leases. Additionally, we agree with commenters that shifting the 100% site control requirement until the execution of a facilities study agreement allows the interconnection customer to put less money at risk for obtaining particularly challenging land rights and to obtain a more meaningful understanding of what upgrade costs its generating facility may be assigned, for instance, from the cluster study report that is provided before the execution of the facilities study agreement.

598. At the same time, we believe that the approach adopted in this final rule, along with the other reforms adopted herein, is sufficiently stringent to help prevent speculative, commercially non-viable proposed generating facilities from entering and continuing through the interconnection queue. As an initial matter, we establish a more stringent requirement for site control at the time of submission of an interconnection request than required by the pro forma LGIP prior to this final rule. In particular, obtaining nearly all of the land rights necessary to develop a proposed generating facility prior to submitting the interconnection request entails a significant commitment, both financial and in terms of the time and resources required to negotiate with landowners. Moreover, the 100% site control requirement at the time of the execution of the facilities study agreement adds further stringency to ensure generating facilities that proceed through the interconnection queue are the most likely to be commercially viable.

599. We agree with commenters that requiring 100% site control at the time of submission of an interconnection request may not be compatible with the project development cycle, which includes stringent permitting requirements, and may disadvantage certain interconnection customers despite there being a path to full site control and commercial readiness. Further, requiring 100% site control at submission of the interconnection request would not allow for minor revisions to the generating facility plan if, upon meeting with the transmission provider at the scoping meeting, such revisions would facilitate an improved generating facility design. This could present a barrier to entry for interconnection customers with viable proposed generating facilities.

600. We decline to adopt commenters' suggestions that transmission providers be allowed to confirm site control throughout the interconnection process. The adopted site control requirements require site control demonstrations at three specific points in the interconnection process—submission of the interconnection request; at the time of execution of the facilities study agreement; and when executing, or requesting the unexecuted filing of, an LGIA. We find that these points are sufficient to help prevent interconnection customers with commercially non-viable interconnection requests from entering and proceeding through the interconnection queue.

601. With respect to eliminating the option for any interconnection customer to submit a deposit in lieu of site control, except in limited circumstances where an interconnection customer demonstrates a regulatory limitation, we find that, because a deposit in lieu of site control does not demonstrate that an interconnection customer has the exclusive right to develop a site, it does not indicate that an interconnection customer is ready to proceed with construction and commercial operation of the generating facility. As a result, we believe that allowing deposits in lieu of site control for all interconnection customers, as requested by some commenters, would not help to prevent speculative, commercially non-viable interconnection requests from entering the interconnection queue. Thus, we decline to include such an option in the pro forma LGIP.

602. We are persuaded by commenters that requiring transmission providers to publicly maintain per MW acreage requirements for each generating facility technology type is necessary to afford adequate transparency and certainty to interconnection customers. At the same time, we do not believe that such acreage requirements must be contained within transmission providers' tariffs; rather, we find that, consistent with the rule of reason, transmission providers may choose to maintain acreage requirements in their business practice manuals or may otherwise post them on a publicly accessible website. We find that acreage requirements are properly classified as implementation details that do not significantly affect rates, terms, and conditions of service, and we therefore do not require their inclusion in tariffs. This is consistent with previous Commission orders approving transmission providers' proposals to specify technology-specific acreage requirements for site control in their business practice manuals. This will also afford transmission providers more flexibility in updating acreage requirements to account for technological advancements without being required to make FPA section 205 filings each time they seek to modify the acreage requirements. On the other hand, to give the interconnection customer certainty, as noted above, we clarify that the interconnection customer is required to meet the technology-specific acreage requirement for its generating facility publicly posted by the transmission provider at the time it submits its interconnection request.

603. To provide clarity for interconnection customers and transmission providers, we modify the pro forma LGIP definition of “Generating Facility” to replace “device” with “device(s)” to clarify that this definition includes hybrid generating facilities. We believe this clarification is necessary to ensure that hybrid generating facilities have the same rights and responsibilities as other types of generating facilities under the pro forma LGIP and pro forma LGIA. In response to commenters and consistent with the modified definition of “Generating Facility,” we clarify that the transmission providers' per MW acreage requirements for each generating facility technology-type must include specific requirements for hybrid generating facilities. We also clarify that generating facilities that are co-located on the same site and behind the same point of interconnection are subject to the technology-specific acreage requirements based on the generating facilities' technology-type.

604. In response to requests for clarification as to whether the site control demonstration at the time of submission of the interconnection request applies to interconnection facilities as well as generating facilities, we clarify that the site control demonstration requirements apply only to the land needed for the generating facility. In the NOPR, the Commission did not propose site control requirements for interconnection facilities. Based on this clarification, we decline to address comments suggesting alternative site control requirements for interconnection facilities or network upgrades.

(c) Site Control Considerations for Interconnection Customers With Regulatory Limitations

605. We adopt the NOPR proposal, with modification, to revise section 3.4.2 of the pro forma LGIP to include a limited option for interconnection customers to submit a deposit in lieu of site control when they submit their interconnection request—only if qualifying regulatory limitations prohibit the interconnection customer from obtaining site control. We adopt the NOPR proposal to provide that interconnection customers with regulatory limitations may submit an initial deposit in lieu of site control of $10,000 per MW, subject to a floor of $500,000 and a ceiling of $2 million. As discussed below, this deposit shall be refundable but may not be applied toward interconnection studies or withdrawal penalties, if applicable. However, we decline to adopt the proposed requirement in the NOPR that an interconnection customer facing regulatory limitations must demonstrate 100% site control prior to the execution of a facilities study agreement. Instead, we modify the proposed requirement for an interconnection customer facing regulatory limitations to provide that a deposit in lieu of site control will be accepted and held by the transmission provider until the interconnection customer can demonstrate 90% site control prior to execution of the facilities study agreement or 100% site control at execution of the facilities study agreement or thereafter. Additionally, we modify the NOPR proposal to specify in Appendix B of the pro forma LGIA that interconnection customers facing qualifying regulatory limitations must demonstrate 100% site control within 180 calendar days of the effective date of the LGIA or the LGIA may be terminated per article 17 (Default) of the pro forma LGIA and the interconnection customer may be subject to withdrawal penalties per new pro forma LGIP section 3.7.1.1 (Calculation of the Withdrawal Penalty).

606. We adopt the NOPR proposal to revise section 3.4.2 of the pro forma LGIP to provide how interconnection customers may demonstrate regulatory limitations. Specifically interconnection customers must provide to the transmission provider: (1) a signed affidavit from an officer of the company indicating that site control is unobtainable due to regulatory limitations as such term is defined by the transmission provider; and (2) documentation sufficiently describing and explaining the source and effects of such regulatory limitations, including a description of any conditions that must be met to satisfy the regulatory limitations and the anticipated time by which the interconnection customer expects to satisfy the regulatory restrictions.

607. With respect to what qualifies as a regulatory limitation, we require transmission providers to define regulatory limitations relevant to their service territory, to publicly post the definition, and to provide a narrative description of how they define regulatory limitations as part of their compliance filings. While we decline to require a uniform definition of regulatory limitations for all transmission providers, we clarify that a regulatory limitation is generally a Federal, state, Tribal, or local law that makes it practically infeasible to obtain site control within the time frame detailed in the pro forma LGIP. We allow transmission providers flexibility on how to publicly post the definition, such as by including it in business practice manuals or posting on a publicly accessible website. We consider the definition of regulatory limitations to be an implementation detail appropriately housed outside of transmission providers' tariffs, consistent with the rule of reason. We expect that the appropriate scope of regulatory limitations may vary by region and is likely to need to be updated over time as relevant Federal, state, Tribal, or local laws change. For these reasons, we do not require transmission providers to include their definitions of regulatory limitations in their tariffs.

608. We believe that these requirements will ensure a transparent, consistent, and orderly process to facilitate demonstration of regulatory limitations by interconnection customers and will establish minimum requirements to provide transmission providers sufficient information to evaluate such demonstrations. We agree with commenters that transmission providers are best positioned to develop appropriate definitions of regulatory limitations to address the specific circumstances and unique regulatory limitations that interconnection customers in their regions may face. We believe that this approach preserves flexibility for transmission providers to account for regional diversity.

609. As noted above, we decline to adopt the proposed requirement in the NOPR that an interconnection customer facing regulatory limitations must demonstrate 100% site control prior to commencement of the facilities study. We agree with commenters that the requirement to demonstrate site control at the facilities study stage could act as a barrier for generating facilities faced with regulatory limitations in demonstrating site control because the permitting process may still be underway at the facilities study stage. To account for these barriers, we clarify that, in such circumstances, interconnection customers are permitted to proceed through the interconnection process and execute, or request the unexecuted filing of, an LGIA before obtaining site control, by providing documentation that demonstrates they are taking identifiable steps to secure the necessary regulatory approvals from the applicable Federal, state, and/or Tribal entities, as described above. Such interconnection customers must provide this documentation at the time of execution of the facilities study agreement and when executing, or requesting the unexecuted filing of, the LGIA, or alternatively, demonstrate site control in accordance with the requirements of the pro forma LGIP.

610. We acknowledge that certain interconnection customers developing generating facilities on sites owned or controlled by a government entity, such as those who site generating facilities on BLM lands, may not be able to demonstrate site control under the pro forma LGIP definition even by the later stages of the interconnection process because final permitting approval from BLM may not occur until after the facilities study stage. We believe the site control requirements included in the pro forma LGIP strike an appropriate balance between disincentivizing speculative interconnection requests and accommodating interconnection customers facing extensive permitting requirements by allowing such customers to submit a deposit in lieu of site control where they demonstrate a qualifying regulatory limitation.

611. In response to commenters' concerns that, without clarification, the regulatory limitations exception to the site control requirement may be interpreted broadly to allow interconnection customers to claim regulatory limitations when obtaining site control is simply impractical or expensive, we reiterate that transmission providers may exercise discretion when defining regulatory limitations—generally a Federal, state, Tribal, or local law that makes it practically infeasible to obtain site control within the time frame detailed in the pro forma LGIP—as appropriate for interconnection customers in their regions. We believe that allowing flexibility in defining regulatory limitations will enable transmission providers to account for any local, county, Tribal and state regulations in their respective region that may delay an interconnection customer's efforts to obtain site control.

612. With respect to the amount of the deposit in lieu of site control for interconnection customers with regulatory limitations, we find that the amounts that we adopt in this final rule will help prevent speculative interconnection requests without placing an undue burden on interconnection customers. We are not persuaded by commenters that argue that the deposit amounts in lieu of site control for interconnection customers with regulatory limitations need to be even higher to deter interconnection requests that are not likely to achieve site control, particularly when considered in conjunction with the commercial readiness deposits and withdrawal penalties adopted in this final rule, discussed below. We also find that deposits in lieu of site control for interconnection customers with regulatory limitations should be refundable, but may not be applied toward interconnection studies or withdrawal penalties. We find that making these deposits in lieu of site control for interconnection customers with regulatory limitations non-refundable, as some commenters argue, may unduly burden certain interconnection customers facing regulatory limitations where certain regulatory constraints may be beyond their control.

c. Commercial Readiness

i. NOPR Proposal

613. In the NOPR, the Commission proposed to revise the pro forma LGIP to include a commercial readiness framework, which included commercial readiness demonstration options and commercial readiness deposits. The Commission explained that such a framework would encourage interconnection customers that are not ready to proceed to withdraw from the interconnection queue earlier in the study process while also providing them the flexibility to enter and remain in the interconnection queue without an off-take agreement; reduce the number of times an interconnection customer executes and suspends an LGIA for a speculative interconnection request, only to later withdraw the request, leading to the shifting of network upgrade costs to lower-queued interconnection customers; and reduce the strain on transmission providers and enable viable interconnection requests to progress more quickly through a less congested interconnection queue, thereby remedying the unjust and unreasonable Commission-jurisdictional rates discussed in section II of this final rule.

614. Therefore, the Commission proposed to establish the defined terms “commercial readiness demonstration and “commercial readiness deposit” in the pro forma LGIP. The Commission also proposed to add to sections 3.4.2, 7.5, and 8.1 of the pro forma LGIP the following options as acceptable forms of commercial readiness demonstration to enter into the cluster study and cluster restudy:

• An executed term sheet (or comparable evidence) related to a contract, binding upon the parties to the contract, for sale of (1) the constructed generating facility, (2) the generating facility's energy or capacity, or (3) the generating facility's ancillary services; where the term of sale is not less than five years;
• Reasonable evidence that the generating facility has been selected in a resource plan or resource solicitation process by or for a load-serving entity (LSE), is being developed by an LSE, or is being developed for purposes of a sale to a commercial, industrial, or other large end-use customer; or
• A provisional LGIA which has been filed at the Commission (executed or unexecuted), which is not suspended and includes a commitment to construct the generating facility.

615. The Commission also proposed to add to section 8.1 of the pro forma LGIP the following options to serve as forms of commercial readiness demonstration to enter the facilities study, to be provided with the executed facilities study agreement:

• An executed contract (as opposed to a term sheet), binding upon the parties to the contract, for sale of (1) the constructed generating facility, (2) the generating facility's energy or capacity, or (3) the generating facility's ancillary services; where the term of sale is not less than five years;
• Reasonable evidence that the generating facility has been selected in a resource plan or resource solicitation process by or for an LSE, is being developed by an LSE, or is being developed for purposes of a sale to a commercial, industrial, or other large end-use customer; or

• A provisional LGIA accepted for filing by the Commission, which is not suspended, with reasonable evidence that the generating facility and interconnection facilities have commenced design and engineering.

616. The Commission also proposed to require the interconnection customer to inform the transmission provider of any material change to its commercial readiness demonstration. The Commission proposed to require the transmission provider to give the interconnection customer 10 business days to demonstrate satisfaction with the applicable requirement after notification of a change to the interconnection request's commercial readiness demonstration. The Commission explained that the interconnection customer would have the option to submit a commercial readiness deposit within the 10-day cure period if the change to the commercial readiness demonstration meant that the interconnection request no longer satisfied the criteria.

617. The Commission preliminarily concluded that this approach was appropriate for all transmission providers and therefore proposed to allow interconnection customers the option to submit a commercial readiness deposit, in lieu of demonstrating commercial readiness through the commercial readiness demonstration options required to enter a cluster study, cluster restudy, and facilities study. The Commission noted that, outside of RTOs/ISOs, transmission providers may be able to provide certain contractual arrangements to their own generating facilities or other preferred interconnection customers, such as the term sheet option noted above, which could lead to unduly discriminatory behavior. The Commission stated that this deposit in lieu of demonstrating commercial readiness may potentially prevent any undue discrimination in the generator interconnection process, consistent with the adoption of a standard set of procedures in the first instance.

618. The Commission proposed to revise the pro forma LGIP to include a framework to allow interconnection customers to provide a commercial readiness deposit in lieu of meeting commercial readiness requirements in the following amounts:

• Two times the study deposit amount to enter the initial cluster study phase;
• Five times the study deposit amount after the initial cluster study phase and before the system impact restudy phase; and

• Seven times the study deposit amount after receipt of the facilities study agreement.

619. The Commission clarified that the proposed commercial readiness deposit is separate from the study deposit. The Commission stated that the commercial readiness deposit would be returned if the interconnection customer later makes a commercial readiness demonstration. If the interconnection customer withdraws from the interconnection queue, the Commission proposed that the commercial readiness deposit would be applied toward any incurred withdrawal penalties.

620. Additionally, the Commission proposed revisions to the list of development milestones in section 11.3 of the pro forma LGIP to clarify the following:

• A contract for the supply or transportation of fuel and a contract for the supply of cooling water will not be accepted for wind, storage, or solar photovoltaic resources;
• Comparable evidence of a contract for the sale of energy or capacity will be accepted; and

• Any of the commercial readiness demonstration options accepted to enter the facilities study will be accepted along with the executed LGIA or within 15 days of the Commission issuing an order on the unexecuted LGIA filing, while a commercial readiness deposit will not be accepted.

621. The Commission preliminarily found that this framework would allow interconnection customers to calculate the exact deposit that would be required prior to entering the interconnection queue, as it is based on multiples of the study deposit, and the study deposit is based on the size of the proposed generating facility, as chosen by the interconnection customer, leading to predictability in the deposit amount. The Commission explained that this increased transparency in the deposit amount early in the interconnection process would discourage speculative interconnection requests from entering the interconnection queue.

622. The Commission sought comment on whether the Commission should also establish, as other alternative demonstrations of commercial readiness, evidence of a commitment to participate in RTO/ISO markets, a site-specific purchase order for generating equipment specific to the interconnection request, or a statement signed by an officer or authorized agent of the interconnection customer attesting that the generating facility is to be supplied with major electric generating components (such as wind turbines) with a manufacturer's blanket purchase agreement to which the interconnection customer is a party.

ii. Comments

(a) Comments in Support

623. Several commenters support the commercial readiness framework because they believe that it will reduce the submission of exploratory or speculative interconnection requests. These commenters argue that requiring financial commitments and commercial readiness requirements early in the interconnection process, as the Commission proposed, is important to more efficiently allocate transmission provider resources to generating facilities that are more likely to achieve commercial operation and to enhance the certainty of interconnection study results, benefiting all interconnection customers. Pacific Northwest Utilities similarly assert that requiring commercial readiness at an appropriate point in the cluster study process minimizes the cost and inefficiency risk of restudies and increases the probability that planned network upgrades will be funded and constructed. Navajo Utility also supports the Commission's use of the commercial readiness requirements to discourage speculative interconnection requests from slowing the interconnection process.

624. Navajo Utility explains that, as an LSE that constructs generating facilities for the benefit of the Navajo Nation and to export clean energy to surrounding LSEs, it specifically supports the second criterion related to generating facilities developed by an LSE. NRECA contends that the proposed commercial readiness demonstration requirements protect generating facilities that have been committed to serve load from being hindered by interconnection requests for generating facilities that are still looking for off-takers, thereby helping reduce the pressure on transmission provider interconnection queues.

625. APPA–LPPC note that there may be power purchase agreements, asset sales agreements and competitive procurement programs that currently contemplate full knowledge of interconnection costs before deals may be finalized. However, APPA–LPPC argue that there is nothing inevitable about the structure and sequencing of these arrangements. APPA–LPPC state that, assuming the Commission moves ahead with a commercial readiness requirement, it is not hard to envision revisions to standard form power purchase agreements, asset sales agreements, and bids into power procurement programs that are contingent on specified assumptions regarding interconnection costs. APPA–LPPC contend that with improvements in the availability of interconnection costs, along with much-needed stability in the interconnection queues, it is reasonable to expect that interconnection costs will be substantially more predictable than is now the case.

626. SoCal Edison supports the proposals to require the interconnection customer to notify the transmission provider of any material change to its commercial readiness demonstration and to require the transmission provider to give the interconnection customer 10 business days to cure the commercial readiness deficiency.

(b) Comments in Opposition

627. Several commenters argue that the NOPR proposal is inconsistent with prevailing commercial practices (especially those in RTOs/ISOs), sets unreasonable standards for off-take agreements, and ignores the commercial reality of the competitive solicitation process, which could create an undue preference for self-build options in areas that rely on competitive solicitations and undue discrimination against merchant developers, thereby subverting competition in wholesale power markets. Some commenters contend that the proposed commercial readiness demonstration options are heavily weighted in favor of incumbent utility practices, such as evidence of a power purchase agreement or executed term sheet or evidence that a project has been selected in a resource plan or resource solicitation process by an LSE.

628. Enel argues that ratepayers and off-takers benefit from generating facilities being selected in competitive processes that consider both a generating facility's inherent characteristics and its interconnection costs and schedule, which cannot be done if off-take arrangements are made prior to applying for interconnection service. NextEra asserts that being part of the interconnection queue is an essential step in the competitive process, and Public Interest Organizations note that utilities conducting RFPs for their resource plans often require at least a position in an interconnection queue as a precondition of offering. Cypress Creek argues that commercial readiness demonstrations should not apply until an interconnection customer receives the results from the proposed initial cluster study, which may be required to bid into a resource solicitation. Cypress Creek contends that it is impractical to include the proposed demonstration requirements at early stages in the interconnection study process and that this construct is not workable in markets where merchant sales are common.

629. Enel, NextEra, and Public Interest Organizations argue that precluding entry into the interconnection queue due to lack of a demonstration of commercial readiness would be an anticompetitive measure favoring entities, such as incumbent transmission providers, that could favor their own proposed generating facilities ahead of others because of their enhanced ability to demonstrate their proposed generating facilities as commercially ready. For instance, CREA and NewSun assert that, unlike independent power producers, an incumbent, vertically integrated utility can easily meet the second prong of the readiness criteria to enter the interconnection queue and proceed to the facilities study by simply identifying its preferred resource in its own resource plan, selecting it as the winning bid in its own utility-run RFP, or just attesting that the utility is “developing” the generating facility.

630. CREA and NewSun claim that the commercial readiness proposal would drive most, if not all, independent power producers from the market, which would raise costs to consumers by eliminating competition and innovation. SEIA asserts that by proposing a commercial readiness demonstration framework that is nearly impossible for independent power producers to meet, the Commission is incorrectly implying that generating facilities developed by independent power producers are inherently not commercially viable. SEIA emphasizes that independent power producers play a critical role in bringing robust competition to markets by driving innovation and decreasing the cost of providing power.

631. Alliant Energy claims that requiring demonstration of commercial readiness prior to an interconnection customer entering the interconnection queue may do more harm than good. Alliant Energy argues that the commercial viability of a proposed generating facility depends heavily on the costs of network upgrades and interconnection facilities required to accommodate a generating facility's interconnection, which cannot be known prior to a generating facility receiving cost estimates that are dependable and enable interconnection customers to make decisions during the interconnection process.

632. Vistra argues that the proposed increase in study deposits, withdrawal penalties, and exclusive site control requirements will significantly reduce the number of speculative interconnection requests entering the interconnection queue, making the commercial readiness proposal redundant. Vistra notes that the Commission has relied on fact-specific showings to accept requirements to demonstrate commercial readiness thus far, and Vistra argues that the fact that the Commission has accepted a transmission provider's revised LGIP under FPA section 205 does not establish that the pro forma LGIP is unjust and unreasonable without the commercial readiness proposal.

633. Vistra states that, beyond simple timing concerns, procurement decisions and eligibility to enter the interconnection queue are interrelated in a way that creates a chicken-and-egg problem. Vistra explains that it is difficult for a generating facility to be shortlisted for procurement without line of sight to obtaining a signed interconnection agreement because the signed interconnection agreement brings more certainty to the generating facility's commercial operation date. Vistra expresses concern that the Commission's proposal to require an executed term sheet to enter the interconnection queue and an executed contract to enter the facilities study process will simply shift the burden of this chicken-and-egg problem to the procurement process. Vistra asserts that the status quo appropriately balances the inherent difficulty of coordinating procurement and interconnection.

634. Invenergy argues that the proposed requirements are inappropriate and should not be applied nationally because they are based on a small subset of transmission providers that have adopted “readiness” requirements with little evidence that they are effective, given the continuing interconnection queue reform efforts in some of those same regions. Invenergy adds that, if additional assurance of an interconnection customer's intent to pursue its interconnection request is needed, the Commission should consider a requirement to post a certain amount of security that becomes increasingly at risk to move through the interconnection queue, as is done in some RTO/ISO regions.

635. NextEra asserts that generating facilities may be fully viable based on criteria that are different from what the NOPR proposes. For example, NextEra states that it is possible that storage or other types of generating facilities entering the market will not require power purchase agreements or designation as network resources to be commercially viable.

636. R Street argues that a key to efficient generating facility development is to enable parallel work flows. R Street claims that, by imposing extensive prerequisites to advance in the interconnection process, commercial readiness requirements would introduce greater process dependencies in generating facility development. R Street adds that granting non-RTO/ISO transmission providers discretion over commercial readiness requirements could lead to discriminatory behavior ( e.g., non-RTO/ISO transmission providers withholding off-take contracts to discriminate against other potential suppliers).

637. MISO states that it is concerned about the utility and impacts of the proposed commercial readiness framework. MISO explains that interconnection customers with commitments from off-takers can be commercially unready and often cause the greatest interconnection queue disruption by lingering the longest in the queue. As an example, MISO posits a proposed generating facility that would be commercially viable provided it does not incur network upgrade costs in excess of $5 million dollars. MISO argues that such a generating facility is likely to remain in the interconnection queue despite not having a viable business case, in the hopes that other interconnection customers will withdraw their requests and costs will decrease. MISO asserts that, to indicate commercial readiness, a term sheet or contract would need to show not only that there was an off-taker but also that the projected income for the proposed generating facility is sufficient to render the generating facility commercially viable, given estimated study and network upgrade costs, which would be exceedingly difficult to require from interconnection customers and nearly impossible for a transmission provider to evaluate and verify.

638. Anbaric claims that the proposed core readiness requirements do not align with the development trajectory of planned transmission projects for offshore wind generation.

639. NextEra asserts that commercial readiness requirements at the interconnection request stage are inappropriate. NextEra explains that interconnection customers do not have a simple test for distinguishing speculative interconnection requests from other interconnection requests. Rather, NextEra continues, successful generating facility development depends on whether the interconnection customer concludes that the interconnection arrangement is acceptable and whether the generating facility's location and costs are agreeable to its customers.

640. NextEra also argues that meeting any readiness milestones after the submission of an interconnection request ( e.g., when entering the facilities study phase) should be premised on the interconnection customer having received timely and accurate study results, including from affected systems. NextEra asserts that it is not just and reasonable to impose increasingly strict requirements on interconnection customers without devising means of accelerating interconnection queue processing by transmission providers and ensuring transmission providers comply with their tariffs.

641. Longroad recommends that the Commission clearly tie the interconnection customer's commitment to pay for network upgrades to a security deposit applied toward the costs thereof during the cluster study phases, and that the security deposits for network upgrades progressively increase at each stage of the cluster study process. Longroad asserts that in the initial cluster study, the security deposit should be a modest percentage of the allocated network upgrade cost and increase to, for example, 25% of the network upgrade cost allocation to enter the facilities study. Longroad contends that the interconnection customer should have the option to either fully fund the network upgrade as a milestone in the LGIA or to fund in advance the transmission provider's estimated quarterly spending towards engineering, procurement, and construction of the network upgrades.

(c) Comments on Specific Proposals

(1) Proposed Readiness Demonstrations

642. Commenters raise significant issues with the readiness demonstration options proposed in the NOPR. With respect to the first proposed readiness demonstration option, commenters argue that providing power purchase agreements or term sheets will be unworkable for most interconnection customers, particularly merchant developers, because: (1) developers do not have sufficient information about interconnection costs to move forward with a term sheet or power purchase agreement at the time they enter into the interconnection study process; and (2) the proposals to make more information available to interconnection customers prior to submitting an interconnection request will not provide sufficiently granular or certain information to overcome this barrier.

643. Commenters further note that the vast majority of power purchasers seek generating facilities with advanced interconnection queue positions (with preference for a finalized LGIA or SGIA) before signing a power purchase agreement or finalizing a state procurement. CREA and NewSun, as well as SEIA, argue that a contract for provision of ancillary services, is almost entirely foreclosed to many non-synchronous generating facilities because nearly every transmission provider bars non-synchronous generating facilities from providing ancillary services, either explicitly or through operating requirements.

644. Commenters also assert that, if independent power producers are forced to enter into contracts before costs are certain, then they would need to incorporate that uncertainty into the power purchase agreement offer, which would drive up the costs of these contracts, resulting in higher consumer costs. Commenters contend that, if the independent power producer does not reflect the costs of the network upgrades in its power purchase agreement price, either the independent power producer or the consumer may attempt to break the contract, which would lead to increased contractual litigation. Vistra adds that the purchaser will then need to start the procurement process over or choose to over-procure as insurance against potential contract termination, to the detriment of reliability and cost.

645. SoCal Edison argues that, in some regions, an executed contract option for entering the facilities study could unintentionally encourage LSEs to sign contracts with developers for more energy or capacity than they need to secure resources to meet their procurement targets. SoCal Edison contends that competition in certain areas for particular generation resources may be high, which may force other LSEs to prematurely enter into contracts with developers to secure generation without the benefit of the facilities study, which is currently relied on by LSEs to assess commercial viability of a generating facility before contracts are signed. AEE asserts that customers may ultimately bear the cost of the selection of generating facilities that may not be the least cost options in the market but are able to execute a term sheet or power purchase agreement regardless of the ultimate level of interconnection costs.

646. Commenters also assert that it is unreasonable to expect that a buyer and seller will be able to finalize negotiation of a contract between the time of the cluster restudy (or amendment of the restudy if additional interconnection customers withdraw upon receipt of the restudy results) and the time the facilities study agreement must be executed.

647. CAISO requests that the Commission describe in detail what would constitute a term sheet. CAISO states that in its experience with similar tariff provisions, interconnection customers frequently try to submit questionable or even misleading documentation to meet the tariff requirements.

648. Invenergy argues that, to the extent an off-take agreement or term sheet remains an option to demonstrate readiness, the Commission should clarify that transmission providers are not entitled or even permitted to review the commercial terms of the term sheet or agreement, which may be confidential and is not subject to the transmission provider's discretion.

649. GSCE does not dispute that readiness requirements are important but argues that basing them on contracting status is misguided for the following reasons: (1) it does not focus on early-stage developmental steps that drive generating facility viability and indicate true commercial readiness; (2) it provides incentives for interconnection customers that have not taken concrete steps toward readiness to bid low in competitive solicitations, creating fictional “contracted” capacity that may never prove viable; (3) the contracting landscape is evolving, and long-term contracting is no longer required for successful project financing or the emerging realities of capital markets, and with the inflationary environment, long-term contracts may currently be harder to finance than short-term contracts; and (4) a focus on contracting to enter the interconnection study process forces commercial negotiations to occur before generating facilities are studied and have sufficient cost certainty or development timeline assurances.

650. Commenters also point to significant issues with the second proposed readiness demonstration option. They argue that requiring evidence that a proposed generating facility is “selected in a resource plan or resource solicitation plan by or for [an LSE], is being developed by [an LSE], or is being developed for purposes of a sale to a commercial, industrial, or other a large end-use customer” is discriminatory and preferential without cause or reasonable support.

651. Several commenters argue that the option for interconnection customers to demonstrate commercial readiness by showing that the generating facility is being developed for purposes of a sale to an end-use customer suffers a timing challenge because it is nearly impossible for the independent power producer to price a sales contract to a retail customer, or the customer having much interest in discussing the transaction, without having reasonable certainty as to the generating facility's likely interconnection costs.

652. SoCal Edison recommends that the Commission clarify or give additional examples of reasonable evidence that a proposed generating facility has been selected in an LSE's resource solicitation process or allow a transmission provider to determine how this option can be met. SoCal Edison states that evidence that a proposed generating facility has been short-listed in an LSE request for offer should be considered reasonable evidence for moving into the facilities study.

653. Several commenters argue that the third readiness demonstration option, a provisional LGIA, is likely unworkable as well because it would require independent power producers to assume almost all the risk of the network upgrade costs without knowing those costs. On the other hand, CAISO asserts that interconnection customers could escape financial consequences and bypass the NOPR's requirements through the provisional LGIA option. CAISO argues that, at a minimum, the Commission should allow transmission providers to provide the provisional LGIA option where they believe it will work, but not require all transmission providers to enable interconnection customers to bypass commercial readiness through provisional LGIAs.

654. SoCal Edison and CAISO recommend that the Commission provide additional guidance on, or more clearly define, the term “provisional LGIA.” CAISO also states that it is unclear how interconnection customers that have yet to be studied could submit provisional LGIAs because LGIAs describe the network upgrades and facilities from interconnection studies. CAISO states that interconnection customers are likely to request provisional LGIAs because demonstrating commercial readiness in RTOs/ISOs is generally impossible until after studies are complete.

655. Commenters claim that the record does not support adopting the proposed commercial readiness framework within RTOs/ISOs, arguing that it would be unreasonable and unduly discriminatory. These commenters argue that the record in RTOs/ISOs does not support the NOPR's assertion that generating facilities are generally not constructed without some form of off-take agreement. They assert that the commercial readiness criteria should not be required at all in RTO/ISO regions (with locational marginal price-based markets), where generating facilities can move forward in many cases without a specific off-taker. Some commenters also argue that an RTO/ISO should not have to evaluate contracts for the sale of a generating facility's output or determine whether the generating facility has been selected in a resource plan or resource solicitation process in any of the potentially multiple states within its footprint.

656. Commenters argue that the proposed 10-business day cure period to resolve potential commercial readiness deficiencies is insufficient given the complicated business and technical decisions involved. Invenergy states the interconnection process often extends for several years and it is entirely possible that commercial arrangements may change during that time. Invenergy states that these changes may require additional negotiations, but should not call into question the customer's commitment to developing its project and risk being withdrawn from the interconnection queue. Ørsted requests a 30-business day cure period instead.

(2) Alternative Commercial Readiness Demonstrations

657. Some commenters argue that the Commission should consider expanding this list of proposed criteria to include other demonstrations of commercial readiness, such as completion of environmental, local, state, or Federal permitting processes. CREA and NewSun, as well as Northwest and Intermountain, ask the Commission to provide QFs a more relaxed readiness option than a fully executed power purchase agreement, especially when a transmission provider requires qualifying facilities to have a completed interconnection study result to obtain a draft power purchase agreement under its state Public Utility Regulatory Policies Act (PURPA) implementation programs ( e.g., PacifiCorp). CREA and NewSun suggest that the Commission could allow QFs to submit an affidavit from the interconnection customer, stating that the avoided cost rates offered are sufficient to finance and bring the QF into commercial operation if interconnection can be obtained. CREA and NewSun contend that this option is consistent with the Commission's obligation to adopt regulations that encourage development of QFs.

658. Comments are mixed on the potential additional demonstrations of commercial readiness on which the Commission requested comment in the NOPR. Several commenters support the three potential other readiness options suggested in the NOPR, or a combination thereof.

659. Other commenters oppose the various alternative demonstration options. With regard to the first—evidence of a commitment to participate in RTO/ISO markets—several commenters argue that the proposal would be essentially meaningless because practically all interconnection requests would qualify.

660. As for the second and third potential alternative demonstration options—a site specific purchase order for generating equipment specific to the interconnection request, or a statement signed by an officer or authorized agent of the interconnection customer attesting that the generating facility is to be supplied with major electric generating components (such as wind turbines) with a manufacturer's blanket purchase agreement to which the interconnection customer is a party—PacifiCorp and Ameren oppose these options. PacifiCorp argues that, although it originally adopted a similar provision in its initial interconnection queue reform process, in the course of administering its first two cluster studies, it determined that this readiness option set a low hurdle that speculative interconnection requests could easily overcome. Similarly, SPP does not support site-specific purchase orders or statements attesting to supply of major components as evidence of commercial readiness. Enel asserts that it is inappropriate to require procurement of major power equipment prior to an interconnection request or, in many cases, even before executing an LGIA. Enel contends that requiring procurement of specific generating equipment prior to applying for interconnection is detrimental to reliability because newer technologies procured after the execution of an LGIA often have advanced features that did not exist a few years earlier. Enel explains that it procures major wind, solar, and battery generation equipment between 12 and 24 months prior to energizing a new generating facility to the transmission system, typically after execution of an LGIA and a full investment review (including knowledge of interconnection costs and schedules) are complete. Enel adds that a generating facility without interconnection results carries too much risk for interconnection customers and investors to risk significant financial deposits to reserve site specific generation equipment. Similarly, Xcel states that interconnection customers want the flexibility to wait until the last minute to order equipment and start construction, which results in different equipment being ordered than initially expected.

661. Some commenters argue that the proposed commercial readiness requirements unduly discriminate against pumped storage projects, which often do not have the commercial pathways and timelines associated with other types of generating facilities. Those commenters explain that the development of a pumped storage project is an iterative process of assessment and de-risking that takes several years to complete, at a cost of tens of millions of dollars. They suggest that achieving one of the following three criteria would be sufficient evidence of commercial readiness for a pumped storage project: (1) a filing of notice of intent to apply for an original license and pre-application document with the Commission; (2) an executed memorandum of understanding, letter of intent, or an equivalent term sheet with a utility; or (3) selection of the project in an integrated resource plan (IRP) process. They add that, in lieu of having achieved one of these, a commercial readiness deposit of $2,000 per MW is appropriate. These commenters ask the Commission to add the receipt of a Commission license to the list of milestone developments in section 11.3 of the pro forma LGIP.

662. Commenters recommend several alternative bases to determine commercial readiness, including: (1) a 50% generator tie line site control requirement; (2) a project development plan to determine readiness; (3) documentation of developer due diligence, including available transmission capacity and modeling; (4) participating in and meeting the eligibility requirements for a state-mandated procurement program; and (5) an executed firm point-to-point transmission service agreement from the proposed point of interconnection to a point of consumption for the generating facility's output.

663. To address the Commission's concerns while maintaining the commercial viability of planned transmission projects for offshore wind, Anbaric asks the Commission to consider requiring such projects to make the following demonstrations to satisfy the commercial readiness requirements: (1) site control of property near the point of interconnection suitable for a converter station of a specified size (expressed in MWs) needed to enable high voltage direct current (HVDC) lines carrying offshore wind energy to be put onto the regional transmission system; (2) site control of a property at a coastline location suitable for the transition from seabed to terrestrial routes sufficient to move the specified amount of MWs identified in interconnection requests; and (3) a state procurement policy or goal to procure a defined amount of offshore wind generation associated with a planned transmission project within a defined time frame.

664. Eversource supports the Commission's proposed commercial readiness framework but asks the Commission to strengthen it by requiring the interconnection customer to demonstrate project financing (along with the current proposed requirements). Eversource also asks the Commission to require interconnection customers to provide a preliminary project schedule that identifies all key milestones and timelines.

665. Fervo Energy argues that, for cluster study and restudy processes, the proposed framework should allow the interconnection customer to demonstrate readiness by using a combination of options, such as executed term sheets for a portion of the facility plus deposits on a $/MW basis calculated from the quotient of the study deposit amount and the proposed generating facility size.

666. ENGIE and SEIA ask the Commission to make the commercial readiness demonstration a requirement for entering into an LGIA. ENGIE and SEIA assert that a later-stage commercial readiness demonstration will allow independent power producers to make rational business decisions based on reasonably certain network upgrade costs.

(3) Deposit in Lieu of Readiness

667. Some commenters contend that the proposal to allow interconnection customers to provide a deposit in lieu of demonstrating commercial readiness does not cure the potential for undue discrimination that results from retaining commercial readiness options that are easily attained by incumbent, vertically integrated utilities but infeasible for independent power producers. These commenters claim that, because it is nearly impossible for an independent power producer to make any of the commercial readiness demonstrations currently proposed, the deposit in lieu of meeting the commercial readiness requirements would not be an “option” for independent power producers but rather would be the only path forward in the interconnection process.

668. Some commenters support the deposit in lieu of readiness option, as proposed. For instance, SoCal Edison asserts that an increased financial requirement via a deposit in lieu of demonstrating commercial readiness should help to identify those interconnection requests that are economically viable and to which the transmission provider should focus its resources. Northwest and Intermountain state that providing interconnection customers with an option to demonstrate commercial readiness through a deposit is essential to ensuring a competitive market for generation by providing a way for independent power producers to enter the interconnection queue. MISO supports the concept of commercial readiness deposits, with the first one due at the time of submission of an interconnection request, which would then be forfeited if the interconnection request does not result in an LGIA, and a second, higher deposit due at the time of execution of an LGIA, to be refunded upon a generating facility achieving commercial operation. MISO also supports the Commission's proposal to make these deposits separate from, and in addition to, study deposits, as well as MISO's existing milestone requirements in its interconnection study process. MISO believes that these proposals could be a useful deterrent to speculative or unviable interconnection requests entering into or lingering in MISO's interconnection queue.

669. MISO TOs argue that, in keeping with the overall theme of flexibility and respect for regional differences, the Commission should afford transmission providers flexibility to adopt readiness requirements and deposit amounts that are appropriate for their regions. MISO suggests deposits could consist of two components: (1) a minimum amount per interconnection request, regardless of proposed service levels, and (2) a per MW amount. MISO asks that the commercial readiness deposit increase the pool of money available to offset cost shifts, and any additional monies be utilized to defray the study costs of interconnection customers that actually reach commercial operation.

670. Some commenters argue that allowing deposits and security to be posted in lieu of demonstrating commercial readiness may not be sufficient to accomplish the NOPR's goals, and may, in fact, hinder the NOPR's goals. APPA–LPPC assert that the financial commitments proposed in the NOPR, while not insignificant, do not reflect the potentially substantial cost of continuing to tolerate the ongoing uncertainty. APS claims that, in its experience, speculative interconnection requests are well-funded but may not be commercially viable. Tri-State asserts that the fact that all 53 applicants in its 2022 interconnection queue elected to provide additional financial security at phase 1 in its study process, instead of one of three readiness milestones, demonstrates that deposits are not effective at deterring unready interconnection requests from entering the interconnection queue.

671. Other commenters recommend changes to the Commission's proposal. For instance, North Dakota Commission recommends either removing the deposits in lieu of demonstrating readiness or increasing readiness deposit amounts to an amount that provides a quantifiable, evidence-based reduction in speculative interconnection requests.

672. PacifiCorp states that its interconnection process also allows an interconnection customer to make a payment of $3,000/MW in lieu of meeting commercial readiness demonstration requirements. PacifiCorp expresses concern that the NOPR proposal would reduce the payment obligation (in comparison to what is required today under PacifiCorp's LGIP), thus lowering the bar for more speculative interconnection requests to enter the interconnection queue and increasing risks for further study delays.

673. CAISO contends that the Commission's proposed deposit requirements are low, such that any modern interconnection customer could meet them. CAISO questions whether the deposit requirements (or any deposit requirements) would deter uncompetitive interconnection requests or reduce interconnection queue sizes. CAISO argues that using arbitrary figures to set deposit requirements is unlikely to yield meaningful results. CAISO urges the Commission to gather more data or hold a technical conference to develop meaningful deposit amounts, based on data provided by transmission providers.

674. EEI and NRECA suggest further reducing potential risks of speculative interconnection requests by making deposits non-refundable. NRECA argues that the deposit in lieu of readiness should only be refunded when the interconnection customer has provided an appropriate commercial readiness demonstration or achieves commercial operation, adding that allowing any other refund of this deposit dilutes the effectiveness of this readiness requirement. EEI and NYTOs assert that a deposit in lieu of readiness should only be allowed in limited circumstances.

675. Commenters urge the Commission to decline to adopt a commercial readiness standard that is tied to the status of an interconnection customer's off-take arrangements and instead to adopt an increasingly “at-risk” readiness deposit framework, similar to what has been accepted in various RTOs/ISOs. They contend that more directly associating readiness deposits to the estimated costs and likely impact to other interconnection customers if an interconnection customer withdraws would provide greater accountability for interconnection customers and transmission providers.

676. PJM and Omaha Public Power assert that the Commission should consider basing the readiness deposit amount on an average cost of network upgrades in the region determined during previous studies, as this method would be based on a less arbitrary valuation than as proposed. SEIA urges the Commission to set the value of the deposit amount as a percentage of the estimated network upgrade costs, which should be capped at $2 million. rPlus recommends a commercial readiness deposit of $2,000/MW, noting that this figure is common in industry practice.

677. Some commenters contend that the level of the proposed readiness deposits is too high and should be significantly revised. Pattern Energy requests that the Commission clarify if these deposits are additive or whether they would require an interconnection customer to have available seven times the study deposit amount by the time the interconnection request reaches the facilities study phase. Pattern Energy states that if the payments are additive, then the Commission would be requiring an interconnection customer to have 14 times its initial study deposit on hand by the time the interconnection customer reaches the LGIA milestone, which Pattern Energy contends would be unreasonable.

678. Invenergy argues that depositing as much as $3.5 million before learning how much must be spent on network upgrades is not reasonable. ACE–NY argues that the deposit values for the second cluster and beyond should be limited to just two times the study deposit amount. CREA and NewSun contend that the hefty deposits will bar smaller companies with less access to capital from competing and entering the interconnection study process. CREA and NewSun argue that the NOPR's deposit levels are purely arbitrary and appear aimed at driving interconnection customers out of the interconnection process rather than measurably improving the process.

679. National Grid requests clarification that transmission providers may deduct from a to-be-returned deposit any expenses incurred by the transmission provider in administering the respective escrow account.

680. Pattern Energy contends that the Commission must clarify that deposits will be applied toward future security obligations if a generating facility reduces its size as it progresses through the interconnection process. Pattern Energy states that if the size of an interconnection request is reduced, in accordance with allowable reduction amounts, then: (1) future deposits should be based on the new generating facility size; and (2) previous deposits should be credited toward future deposits based on the portion of those previous deposits that are associated with the reduced MW quantity.

(d) Requests for Flexibility

681. Several commenters generally support the proposed commercial readiness requirements but ask the Commission to provide flexibility to allow transmission providers to determine the detailed readiness and deposit criteria for their footprint. These commenters argue that such measures need to be carefully balanced to avoid overly burdening interconnection customers with legitimate interconnection requests that are delayed for reasons out of their control. For example, NY Commission and NYSERDA explain that, in New York, renewable energy certificates procured by NYSERDA could demonstrate commercial readiness, and a similar state agency certificate could be used in a different state.

682. Pacific Northwest Utilities claim that it would be difficult for transmission providers to implement the commercial readiness proposal in regions such as the Northwest without reforming RFP processes and coordinating amongst multiple transmission owners and LSEs. Pacific Northwest Utilities explain that many generating facilities in the Pacific Northwest use interconnection and transmission services crossing multiple balancing authority areas, which require coordination of timelines, milestones, and off-ramps in both the RFPs and interconnection queues.

(e) Miscellaneous

683. Enel supports the proposed modification to pro forma LGIP section 11.3 to require submission of the development milestones concurrently with returning the executed LGIA so that the interconnection customer cannot avoid the demonstration required by pro forma LGIP section 11.3 by suspending its LGIA. However, Enel notes that it is important for the Commission to retain (and reinstitute where removed by specific transmission providers) the ability for interconnection customers to suspend work under their LGIAs for up to three years.

684. Arizona Commission generally supports the prioritization of commercially ready projects and agrees with the proposed readiness criteria, but also encourages the Commission to consider the possibility of allowing market forces to provide discipline to the interconnection process, such as by allowing transmission owners to prioritize generation projects through the use of competitive solicitations.

685. The Colorado Commission generally supports prioritizing commercially ready interconnection requests and agrees with the proposed readiness criteria. However, the Colorado Commission emphasizes that the NOPR does not include a mechanism to prioritize among the many viable, and competing, interconnection requests when interconnection service capacity is scarce. The Colorado Commission argues that, under existing RTO/ISO interconnection processes as well as the proposed revised pro forma LGIP, there is limited ability in the interconnection process to consider the generating facility's broader attributes from a system perspective, including cost, timing, location, and resource type. The Colorado Commission asserts that new proposed generating facilities would likely be stuck in cluster studies with no clear or timely prioritization that ensures that the lowest cost or highest value generating facilities come online quickly and at a reasonable cost. The Colorado Commission contends that prioritizing native load and end-use customers and third-party owned generating facilities through competitive bid processes is the most logical criteria to maintain a reliable system at reasonable cost. To accomplish this, and help the system rationally move forward in a timely manner, the Colorado Commission suggests adding the following additional language to the commercial readiness section: “RTOs and Transmission Providers shall have the ability to create a separate cluster study process or other mechanisms to prioritize executed contracts that serve and benefit native load in accordance with local load-serving resources needs and priorities as determined through equitable competitive bid processes.”

686. AEE, on the other hand, responds to the Colorado Commission by arguing that allowing transmission providers to prioritize generating facilities that are selected through IRP processes or utility procurements and that benefit native load could allow vertically integrated utilities to push preferred generating facilities through the interconnection process and therefore comes with a risk of discrimination.

687. CESA argues that proposals to prioritize and favor certain generating facilities and interconnection customers must be rejected as violating the Commission's long-standing policies on open access and non-discriminatory interconnection procedures. CESA contends that the Colorado Commission's proposal is therefore unduly discriminatory and also goes well beyond what the Commission contemplated in the NOPR.

688. Clean Energy Associations state that they support the Commission's instead accepting regionally specific proposals that would align the interconnection process with competitive procurements associated with resource planning, rather than placing them at odds. Clean Energy Associations state that projects selected though competitive procurement processes are ready projects, and these processes attempt to consider the transmission (interconnection service and transmission service) costs and the production-related costs. Clean Energy Associations state that one way to accomplish this might be to grant resource solicitation clusters a queue position distinct from other clustered projects, but that concept could be extended to ensure more certainty to the bidder and the resource planning entity of the interconnection and delivery requirements and associated rights.

689. Bonneville sees value in applying commercial readiness requirements to the pro forma SGIP and SGIA and contends that failing to do so could create a perverse incentive for interconnection customers to break up large projects into smaller projects to avoid stringent commercial readiness requirements under the pro forma LGIP.

iii. Commission Determination

690. We adopt a modified NOPR proposal to revise sections 3.4.2, 7.5, 8.1, and 11.3 of the pro forma LGIP, insofar as they require interconnection customers to submit commercial readiness deposits, and we do not adopt the NOPR proposal insofar as it included non-financial commercial readiness demonstrations in the pro forma LGIP. To effectuate the requirements that we adopt in this final rule, we modify the proposed revisions to sections 3.4.2, 7.5, and 8.1 to remove the proposed readiness demonstrations and to require that the interconnection customer submit the commercial readiness deposit at the beginning of each study in the cluster study process ( i.e., the initial cluster study, the cluster restudy, and the facilities study). For the commercial readiness deposit submitted to enter the cluster restudy and the commercial readiness deposit to enter the facilities study, we also modify the NOPR proposal to move from commercial readiness deposits based on study deposit amounts to commercial readiness deposits based on percentages of the interconnection customer's identified network upgrade costs. We also modify proposed section 11.3 of the pro forma LGIP to remove the language providing that one of the proposed readiness demonstrations can be provided when the interconnection customer returns the executed LGIA or requests that the LGIA be filed unexecuted. We also adopt the definition of commercial readiness deposit but do not adopt the definition of commercial readiness demonstration. We discuss each in turn.

691. We believe that, along with the other reforms adopted in this final rule, the commercial readiness deposits we require will address the need for reform underlying this section by helping reduce the submission of speculative, commercially non-viable interconnection requests into interconnection queues. Further, because the interconnection customer's total commercial readiness deposit held by the transmission provider increases as the interconnection process proceeds, we find that this approach will encourage interconnection customers not ready to proceed through the interconnection process—or whose projects become commercially non-viable during the interconnection process—to withdraw earlier in the process, thereby lessening the incidence of late-stage withdrawals that result in delays and restudies. Similarly, by basing the cluster restudy and the facilities study commercial readiness deposits on the interconnection customer's identified network upgrade cost assignment, an interconnection customer will be subject to the cost consequences of its estimated network upgrades earlier. As a result, this approach will encourage interconnection customers to withdraw earlier in the interconnection process if they face large network upgrade initial cost assignments or encounter other concerns that cause their interconnection request to be uneconomic. By reducing the number of speculative interconnection requests submitted into the interconnection queue and the number of late-stage withdrawals of interconnection requests, we believe that the commercial readiness deposit requirements that we adopt herein will also enable commercially viable interconnection requests to progress more quickly through the interconnection process. Transmission providers will be able to focus their resources on those interconnection requests most likely to achieve commercial operation, to the benefit of all interconnection customers.

692. The commercial readiness deposit amounts proposed in the NOPR are tied to generating facility size, as they are based on the initial study deposit, which is likewise tied to generating facility size. We adopt the NOPR proposal for the initial commercial readiness deposit, where the interconnection customer pays a deposit of two times the study deposit to enter the cluster study. Basing the initial commercial readiness deposit on the size of the generating facility aligns the size of the deposit roughly with any impact from a withdrawal of the interconnection request, as generally, all else equal, increasing the size of the generating facility increases the likelihood of larger, more costly network upgrades and a greater change in interconnection study inputs.

693. However, we are persuaded by several commenters that commercial readiness deposits should be based on assigned network upgrade costs. Therefore, we modify the remaining commercial readiness deposits ( i.e., the second and third commercial readiness deposits) such that, rather than relying on multiples of the initial study deposit, once estimates of network upgrade costs are available, the commercial readiness deposits equate to increasing percentages of the interconnection customer's identified network upgrade cost assignment. Specifically, we adopt a deposit structure where the commercial readiness deposit to enter the cluster restudy is the amount required to bring the total amount of the interconnection customer's commercial readiness deposit to 5% of the interconnection customer's network upgrade cost assignment identified in the cluster study, and the commercial readiness deposit to enter the facilities study is the amount required to bring the total amount of the interconnection customer's commercial readiness deposit to 10% of the interconnection customer's network upgrade cost assignment identified in the cluster study or restudy, as applicable. We find that tying the commercial readiness deposits to the network upgrade cost estimate requires the interconnection customer to deposit an amount that corresponds to its network upgrade cost estimates earlier and, thereby, can incentivize interconnection customers with large network upgrade cost estimates to withdraw at earlier points in the interconnection process to the extent the network upgrade cost assignment causes the interconnection request to no longer be viable. This approach achieves the Commission's goals of ensuring that interconnection customers are able to interconnect in a reliable, efficient, transparent, and timely manner.

694. We decline to adopt the non-financial commercial readiness demonstrations proposed in the NOPR. We find that the non-financial commercial readiness demonstrations are not necessary to address the subject of these reforms—providing additional deterrence of speculative, commercially non-viable interconnection requests—given the significant, increasing commercial readiness deposits we adopt instead.

695. We are also persuaded by commenters who express concerns that the non-financial commercial readiness demonstrations in the NOPR proposal may not necessarily serve as appropriate indicators of a proposed generating facility's commercial viability on a national basis. In some instances, the proposed non-financial commercial readiness demonstrations may be unavailable to interconnection customers with commercially viable projects. For example, this may be true as a result of a misalignment of the timing between resource procurement decisions and interconnection study processes or inconsistency with a relevant local commercial practice, rather than because the proposed generating facilities lack commercial viability.

696. As commenters note, resource procurement efforts across the country all have different timelines, and the timeline to demonstrate commercial readiness proposed in the NOPR was not tailored to meet the timelines of multiple state procurement efforts. As commenters explain, an interconnection queue position is often a precondition of offering into a resource solicitation. We agree that, absent a regionally tailored tariff process pursuant to which commercial readiness criteria could be aligned with applicable resource solicitation processes, the commercial readiness criteria proposed in the NOPR may not be workable in markets where merchant sales are common, and this generally applicable final rule is not an appropriate forum to dictate regionally tailored solutions.

697. We are further concerned that there may be trade-offs entailed in requiring the proposed non-financial commercial readiness demonstrations, which are more appropriately assessed on a regional, rather than national basis. We agree with Enel that ratepayers may benefit from generating facilities being selected in competitive processes that consider the facilities' interconnection costs and schedule, which cannot be done if off-take arrangements are made prior to applying for interconnection service.

698. In addition, we are concerned that the proposed non-financial commercial readiness demonstrations could incentivize power purchasers in some regions to execute purchase contracts with interconnection customers whose generating facilities will later be determined to be commercially non-viable. As commenters note, this could lead to purchasers having to start the procurement process over or choose to over-procure as insurance against potential contract termination, to the detriment of reliability and cost.

699. Therefore, we are persuaded to adopt a framework that requires a commercial readiness deposit for all interconnection customers, similar to what the Commission has accepted in various RTO/ISO regions. We find that requiring deposits in amounts substantial enough to demonstrate commitment to reaching commercial operation at progressive milestones throughout the interconnection process will be a sufficient deterrent to speculative behavior—especially when considered as part of the comprehensive package of reform, including increased site control requirements, increased study deposits, and withdrawal penalties, established by this final rule.

700. In the NOPR, the Commission acknowledged the potential that certain non-financial commercial readiness demonstrations could provide an unduly discriminatory or preferential advantage to projects being developed by transmission providers or their affiliates. As summarized above, several commenters have raised—and elaborated on—those concerns. Because we find that the commercial readiness deposits that we adopt in this final rule are sufficient to address the relevant need for reform, and therefore do not adopt the proposed non-financial commercial readiness demonstrations, we need not further address those concerns in this final rule.

701. We recognize that the Commission has previously accepted proposals that include commercial readiness demonstration requirements similar to those proposed in the NOPR. Although we find that commercial readiness deposits are sufficient to address the need for reform in this proceeding, this finding does not preclude transmission providers from adopting non-financial commercial readiness demonstrations, provided they meet the relevant standards when requesting a variation, as discussed above.

702. Some commenters suggest that the Commission could add government and environmental permits as commercial readiness demonstrations as an indicator of commercial readiness that is viable both for independent power producers and for transmission providers and their affiliates. Although the record provides some support for this, we are concerned that permits and studies may expire due to the length of the interconnection process, and those re-permitting and restudy efforts are still at risk of rejection or failure, which could lead to late-stage withdrawals. We are also concerned about the possible administrative burden placed on transmission providers, as they must determine which types of permits should be accepted as commercial readiness demonstrations and evaluate the validity of different permits submitted by interconnection customers.

703. Pattern Energy requests that the Commission clarify whether the commercial readiness deposits are additive, meaning that, as each phase of the interconnection process is reached, the full amount of each new readiness deposit must be added on top of the full amounts of earlier readiness deposits (as opposed to merely increasing the total amount of the aggregate readiness deposit to match the level specified for that phase). In response, we clarify that, as modified, the commercial readiness deposits in sections 7.5 and 8.1 of the pro forma LGIP make clear that for the second and third commercial readiness deposits, the interconnection customer is only required to submit an additional deposit that brings the total commercial readiness deposit to the amount specified in sections 7.5 and 8.1 of the pro forma LGIP (5% of the interconnection customer's identified network upgrade cost estimate and 10% of the interconnection customer's identified network upgrade cost estimate, respectively).

704. In response to comments on the magnitude of commercial readiness deposits ( e.g., too high or too low), we reiterate that the commercial readiness deposits are part of a package of reforms meant to deter speculative behavior that also includes site control requirements and withdrawal penalties. Thus, the commercial readiness deposits are not intended to be of such magnitude to alone prevent speculative behavior as they are intended to work together with other reforms adopted in this final rule, such as site control and withdrawal penalties. We believe that the deposits should not be so high that viable projects from smaller developers are unable to enter the queue. At the same time, they will only achieve the aims if they are sufficiently high to serve as some deterrent, in concert with the other relevant reforms adopted in this final rule. In response to National Grid's request that the final rule provide for the deduction from a to-be-returned deposit of any expenses incurred by the transmission provider or RTO/ISO in administering the respective escrow account, we note that Order No. 2003 required the collection of various deposits without addressing this type of administrative expense. We find, in this instance, that there is no need to deviate from Order No. 2003, and we decline to adopt tariff revisions to address the management of an escrow account.

705. In response to Pattern Energy's request for clarification of the commercial readiness deposit amounts in the event that an interconnection customer reduces the size of a proposed generating facility, we clarify that because the modified commercial readiness deposit structure is based on network upgrade cost estimates, a size reduction to a proposed generating facility may or may not impact the remaining commercial readiness deposits, depending on whether the size reduction reduces the interconnection customer's assigned network upgrade costs. This is consistent with the requirements for entering the cluster restudy and facilities study adopted in pro forma LGIP sections 7.5 and 8.1, respectively, which require commercial readiness deposits based on percentages of the interconnection customer's identified network upgrade costs.

706. Pattern Energy's request to require that previous deposits be credited towards future deposits based on the portion of those previous deposits that are associated with the reduced MW quantity therefore represents the modified commercial readiness deposit framework we adopt. Under this modified framework, an interconnection customer's previous commercial readiness deposits are effectively credited when it pays later commercial readiness deposits ( i.e., the second and third commercial readiness deposits); it pays the required amount of a commercial readiness deposit less the amounts paid for through earlier commercial readiness deposits.

707. We also decline to adopt Bonneville's suggestion to add the commercial readiness provisions to the SGIP because the record does not demonstrate a need for such reform at this time. Because we are not adopting the proposed non-financial commercial readiness demonstrations, we do not address comments proposing revisions or clarifications to those demonstrations. Additionally, several commenters provide additional suggestions for the NOPR proposal, including: (1) addressing the Commission's rules for suspending an LGIA; (2) addressing queue priority; and (3) better supporting competitive procurement processes. We find these comments to be outside the scope of the NOPR.

d. LGIA Deposit

i. NOPR Proposal

708. In the NOPR, the Commission proposed to require interconnection customers to submit a deposit equal to nine times the amount of its study deposit when executing the LGIA or requesting the filing of an unexecuted LGIA. The Commission explained that this deposit would be fully refunded once the generating facility achieves commercial operation, but if the interconnection customer withdraws after executing the LGIA or after requesting the filing of an unexecuted LGIA, this deposit would be refunded subject to the withdrawal penalty. The Commission also sought comment on whether to adopt additional provisions or a different framework that would require larger proposed generating facilities to provide a higher deposit amount—such as a per MW framework.

ii. Comments

709. MISO supports the proposal to require interconnection customers to submit a deposit equal to nine times the amount of its study deposit at LGIA execution because MISO believes it is necessary to continue the commercial readiness deposit and withdrawal penalty framework until the interconnection request achieves commercial operation. Shell supports the security deposit obligations used in MISO's and SPP's generator interconnection processes, which include a deposit at LGIA execution.

710. Invenergy argues that requiring more security at LGIA execution, in addition to the other proposed burdens on interconnection customers in the NOPR, goes beyond the goal of disincentivizing speculative interconnection requests to creating potentially prohibitive burdens on all interconnection customers, including those with commercially viable proposed generating facilities. Invenergy contends that, while a deposit based on study costs may make sense in earlier stages of the study process when assigned network upgrade costs are not yet known, it is not appropriate after an LGIA is executed and assigned network upgrade costs are known and memorialized. ACE–NY and AES oppose any additional deposits due from an interconnection customer at the signing of the LGIA that are not tied to network upgrade costs. AES asserts that in many RTOs/ISOs, interconnection customers have to post security for a portion, if not all, of the assigned network upgrade costs associated with an interconnection request, and such posted security is a sufficient incentive to keep an interconnection customer engaged so that they will complete a generating facility after the LGIA is executed.

711. Several commenters argue that the Commission's LGIA deposit proposal is excessive and potentially exposes ratepayers to unjust and unreasonable costs. Ørsted would support a lower amount, such as two times the study deposit, because it believes that the current proposal would not necessarily accurately estimate the costs of required network upgrades. PJM contends that the Commission should allow transmission providers to adopt security amounts and structures that are rationally related to relevant costs. Cypress Creek asks the Commission to provide a non-arbitrary basis for its proposed security deposit of nine times the study deposit. Shell argues that the LGIA deposit appears to be a security deposit and adds that MISO and SPP use a separate security deposit obligation that the Commission should consider.

712. Several commenters argue that study deposits should be refunded in certain circumstances. Invenergy argues that any deposit due at LGIA execution should be subject to a $2 million cap and that deposit should be released dollar for dollar as the interconnection customer posts security or makes required payments under the LGIA. Invenergy asks that the Commission also clarify that, in the event a proposed generating facility does not achieve commercial operation, any deposit forfeited under this proposal offsets, and is not in addition to, any withdrawal penalties that may be imposed. Invenergy adds that it is unreasonable to require that additional deposits be provided when an interconnection customer asks that the LGIA be filed unexecuted, and if the Commission does nonetheless require interconnection customers to post the deposit as a condition of having the LGIA filed unexecuted, the deposit should be refundable if the interconnection customer elects to withdraw within 30 days of the date of the Commission's order in the applicable docket. Ørsted and Shell assert that, for interconnection customers withdrawing after executing the LGIA, all deposits should be refunded in the event that the interconnection customer withdraws as a result of circumstances outside of its control and the withdrawal does not harm any other entity. AES argues that all study deposits should be refunded at the time of LGIA execution, and opposes any additional deposits not tied to network upgrade costs.

713. Southern, on the other hand, argues that making deposits refundable may not be stringent enough and therefore may not accomplish the goals set forth in the NOPR. NRECA also believes that the Commission should consider whether to make these study deposits non-refundable in the case of withdrawal, as a further disincentive for speculative interconnection requests to enter the interconnection queue.

iii. Commission Determination

714. We adopt, with modification, the NOPR proposal to revise new section 11.3 of the pro forma LGIP to require interconnection customers to submit a deposit when executing the LGIA, or requesting the filing of an unexecuted LGIA,and add the new term “LGIA deposit” to section 1 of the pro forma LGIP. Specifically, we modify the NOPR proposal to require interconnection customers to provide a deposit that will increase the total commercial readiness deposit paid to be equal to 20% of the estimated network upgrade costs identified in the LGIA, rather than providing a deposit equal to nine times the amount of the interconnection customer's study deposit, as proposed in the NOPR. Additionally, revised section 11.3 of the pro forma LGIP requires that interconnection customers submit the LGIA deposit when returning the executed LGIA to the transmission provider, or within 10 business days of the interconnection customer requesting that the LGIA be filed unexecuted at the Commission.

715. In the NOPR, the Commission sought comment on whether to adopt additional provisions or a different framework for deposits, including the LGIA deposit. In response, commenters provided suggestions, including suggestions to base deposits on network upgrade costs. We agree that tying the LGIA deposit to the network upgrade cost estimate sends a more accurate cost signal to the interconnection customer and better aligns the LGIA deposit to its function of ensuring that network upgrades are paid for and constructed than the NOPR proposal. We also agree with commenters that a deposit based on the study deposit amount may make sense in the early stage of the cluster study process when assigned network upgrade costs are not yet estimated, but later in the process, when network upgrade cost estimates are available, the use of percentages of network upgrade cost estimates more closely indicates interconnection request viability. This approach also addresses comments that the LGIA deposit, as proposed, may have been arbitrary, excessive, and unreasonable.

716. The NOPR proposed that this deposit would be fully refunded once the generating facility achieves commercial operation, but we are modifying the NOPR proposal to remove that statement from pro forma LGIP section 11.3, and as explained further below, this deposit will be used as part of the security the interconnection customer must provide for the construction of network upgrades and transmission provider's interconnection facilities. However, this LGIA deposit could be refunded, subject to the withdrawal penalty, if the interconnection customer withdraws after executing the LGIA or after requesting the filing of an unexecuted LGIA.

717. We also revise the pro forma LGIP and pro forma LGIA, as suggested by Invenergy, to treat the LGIA deposit as part of the security the interconnection customer must provide for the construction of network upgrades and transmission provider's interconnection facilities. Article 11.5 (Provision of Security) of the pro forma LGIA requires that, 30 calendar days prior to the commencement of construction under its LGIA, the interconnection customer must provide security for a discrete portion of network upgrades and transmission provider's interconnection facilities, as specified in its LGIA. We revise section 11.3 of the pro forma LGIP and article 11.5 of the pro forma LGIA to require the transmission provider to use the LGIA deposit, in its entirety, before requiring the interconnection customer to submit additional security for construction of network upgrades and transmission provider's interconnection facilities. By allowing the transmission provider to draw down this LGIA deposit as construction proceeds, the construction of network upgrades and transmission provider's interconnection facilities can commence quickly thereby streamlining the interconnection process. With this revision, requiring the LGIA deposit to be returned at commercial operation is now unnecessary as there will be no deposit remaining to return; therefore, we decline to adopt the NOPR proposal to do so.

718. We also revise article 11.5 of the pro forma LGIA to require transmission providers to draft Appendix B (Milestones) of the interconnection customer's LGIA to clearly explain and estimate at which point of construction the interconnection customer's LGIA deposit will be depleted, and the interconnection customer must provide additional financial security. In the event the interconnection customer requests suspension of the LGIA under article 5.16 of its LGIA prior to the commencement of construction, the transmission provider is prohibited from using the LGIA deposit to commence construction until the interconnection customer requests to exit suspension and resume construction, unless there is a need for the transmission provider to use a portion of the LGIA deposit to ensure its system is left in a reliable condition during the period of suspension.

719. We do not adopt the suggestion of Ørsted and Shell that, for interconnection customers withdrawing their interconnection requests after executing an LGIA, all deposits should be refunded if withdrawal is the result of circumstances outside the interconnection customer's control and the withdrawal does not harm other entities. We believe that the exceptions to the application of withdrawal penalties discussed in the section III.A.6.e below appropriately balance the need to deter withdrawals with the reality that withdrawal is not always due to circumstances within interconnection customers' control.

720. In response to Southern's comments that making both study and LGIA deposits refundable may not be stringent enough and therefore may not disincentivize speculative interconnection requests, we reiterate that, as adopted, the deposits serve different functions. In this instance, the LGIA deposit serves as a credit towards the security the interconnection customer must provide for network upgrades and transmission provider's interconnection facilities. To the extent the LGIA deposit pays for the construction of network upgrades, such a deposit would be refunded through transmission credits in regions that follow the pro forma LGIA provisions on crediting.

e. Withdrawal Penalties

i. NOPR Proposal

721. The Commission preliminarily found that withdrawal penalties are needed to account for the harms that can occur when interconnection customers withdraw from the interconnection queue. The Commission proposed to revise the pro forma LGIP to require transmission providers to assess withdrawal penalties to interconnection customers in certain circumstances. Specifically, the Commission proposed to revise the pro forma LGIP to require transmission providers to assess withdrawal penalties to interconnection customers that choose to withdraw at any point in the interconnection process or do not otherwise reach commercial operation, unless: (1) the withdrawal does not delay the timing of other proposed generating facilities in the same cluster; (2) the withdrawal does not increase the cost of network upgrades for other proposed generating facilities in the same cluster; (3) the interconnection customer withdraws after receiving the most recent cluster study report and the costs assigned to the interconnection customer have increased 25% compared to the previous cluster study report; or (4) the interconnection customer withdraws after receiving the individual facilities study report and the costs assigned to the interconnection customer have increased by more than 100% compared to costs identified in the cluster study report. Thus, the Commission proposed that interconnection customers would be exempt from a withdrawal penalty if the withdrawal does not harm other interconnection customers or if the withdrawal follows a significant unanticipated increase in network upgrade cost estimates.

722. The Commission proposed that the withdrawal penalty would increase as the interconnection customer moves through the study process and would also increase if an interconnection customer provides a commercial readiness deposit in lieu of a demonstration of commercial readiness. For an interconnection customer that provides a commercial readiness deposit in lieu of a demonstration of commercial readiness, the Commission proposed that its withdrawal penalty would be higher and increase as the interconnection customer progresses in the interconnection process.

723. The Commission proposed that the withdrawal penalty for an interconnection customer that provides a commercial readiness deposit in lieu of a demonstration of commercial readiness will be the greater of the study deposit or: (1) two times the study cost if the customer withdraws during the cluster study or after receipt of a cluster study report, capped at $1 million; (2) three times the study cost if the customer withdraws during the cluster restudy or after receipt of any applicable restudy reports, capped at $1.5 million; (3) five times the study cost if the customer withdraws during the facilities study, after receipt of the individual facilities study report, or after receipt of the draft LGIA, capped at $2 million; or (4) nine times the study costs if the customer withdraws before achieving commercial operation and after executing the LGIA or filing an unexecuted LGIA. The Commission also proposed that the withdrawal penalty revenues be used to fund studies conducted under the cluster study process.

724. The table below summarizes the proposed withdrawal penalty structure for both interconnection requests that have demonstrated commercial readiness and those that have not (by instead submitting a deposit in lieu of demonstrating commercial readiness).

725. The Commission also proposed to add the defined term “withdrawal penalty” to the pro forma LGIP. The Commission sought comment on: (1) how to define the circumstances in which a withdrawal is deemed to have delayed the timing or increased the cost of network upgrades for other proposed generating facilities in the same cluster, including what criteria should be used to determine whether the withdrawal caused the delay or increased cost, and whether to establish a threshold for when a delay or increase in cost will trigger a withdrawal penalty (and if so, what that threshold should be); (2) whether the Commission should consider exceptions to the proposed withdrawal penalties beyond those proposed in the NOPR; (3) whether withdrawal penalties that increase with proposed generating facility size (as measured by MW) would more effectively deter withdrawals that cause the greatest harm; and (4) whether a correlation exists between the size of a withdrawing proposed generating facility and the relative level of harm (in terms of delays and increased cost) to other interconnection customers as a result of the withdrawal.

ii. Comments

(a) Comments in Support

726. Multiple commenters generally support the Commission's proposed withdrawal penalties and view the proposal as appropriate to reduce the volume of speculative interconnection requests. Environmental Defense Fund states that, if adopted with certain of the other NOPR proposals, the Commission's proposed withdrawal penalties are appropriate to address the delays and costs caused by speculative interconnection requests. Eversource states that properly calibrated withdrawal penalties are essential to dissuade withdrawals and reduce study process delays.

727. MISO supports the Commission's proposal to impose a withdrawal penalty on withdrawing interconnection customers, a penalty that MISO suggests should be secured by the commercial readiness deposit. That said, MISO asserts that the study cost for interconnection requests is not that substantial, and MISO does not believe that paying a withdrawal penalty in the amount of only the study costs would be a sufficient deterrent to prevent speculative interconnection requests from entering or remaining in the interconnection queue.

(b) Comments in Opposition

728. Many commenters oppose the withdrawal penalty proposal. CREA and NewSun encourage instead better cost certainty for interconnection customers earlier in the study process. CREA and NewSun suggest that the Commission incorrectly assumes that the interconnection customer has adequate visibility into likely interconnection costs, and thus the financial viability of its proposed generating facility before entering the interconnection queue and becoming liable for these penalties. CREA and NewSun state that the NOPR provides no realistic path to know likely interconnection costs prior to entering the interconnection queue.

729. ENGIE does not support the implementation of withdrawal penalties and notes that withdrawal penalties without meaningful opportunity for interconnection customers to exit the interconnection process are unlikely to incentivize withdrawal. New York State Department is skeptical that a withdrawal penalty program will be beneficial to ratepayers.

730. Pacific Northwest Organizations claim that, without access to interconnection cost information and with larger withdrawal penalties, independent power producers may be discouraged from entering the interconnection queue. Some commenters claim that withdrawal penalties (including in a transitional cluster study process) can result in the potential for discrimination against independent power producers. These commenters assert that LSEs can recover withdrawal penalties they incur from their retail ratepayers, whereas independent power producers must absorb these costs and risks in their solicitation process bids. Interwest also suggests that the proposed withdrawal penalties are less likely to apply to LSEs than to independent power producers because LSEs will likely be able to use the proposed commercial readiness demonstration path, as opposed to paying the deposits in lieu of demonstrating commercial readiness, and would thus not be subject to the harsher withdrawal penalties. Interwest urges the Commission to require waiver of, or a substantial reduction in, withdrawal penalties from the transition cluster or resource solicitation cluster if the interconnection customer participated in an RFP or other competitive solicitation process but was not ultimately selected, or if a permit becomes unavailable due to some regulatory or regime change.

731. R Street claims that the proposal risks imposing severe anti-competitive barriers to entry. New York State Department makes similar anti-competitive impact arguments. R Street asserts that imposing financial commitments and readiness requirements can create regulatory barriers to entry if they deter interconnection requests for commercially viable generating facilities or increase financing costs. R Street argues that the proposal is misguided because it would add another administrative process that increases implementation complications and costs. R Street suggests that the Commission should instead use a simple loss of deposit as its financial lever.

732. rPlus argues that withdrawal penalties, particularly when coupled with the proposed study deposit requirements and study cost allocations, are unduly discriminatory or punitive to pumped storage as compared to other renewable technologies. rPlus and Hydropower Commenters claim that, under these proposals, a large capacity pumped storage project (ranging from 400 MW to over 1,000 MW in size, according to rPlus) would expect to hit the maximum deposit and/or penalty in every stage of the interconnection process. rPlus claims that the high cost of entry and the liability associated with withdrawal may give large utilities an unfair advantage in commercial negotiations.

733. Shell calls for a reconsideration of the withdrawal penalties proposed in the NOPR, claiming that the proposal could disrupt project development when paired with the proposed commercial readiness requirements and financial commitments (for deposits and site control). Shell suggests that the Commission adopt withdrawal penalties modeled on MISO's framework, which encourages interconnection customers to withdraw from the interconnection queue with refunded deposits rather than penalizing interconnection customers for making justifiable decisions. Shell contends that there should only be a large penalty for late-stage withdrawals. Shell contends that, otherwise, the Commission is sending the wrong signal and driving out competition without linking the underlying issue of unexpected network upgrade costs that typically come from affected system studies that are provided very late in the study process.

734. Some commenters contend that increasing the amount of money at stake for an interconnection customer without providing off-ramps from the interconnection process at reasonable decision points where previously unavailable information is supplied does not necessarily incentivize interconnection customers to exit the interconnection queue. CREA and NewSun suggest that the proposed withdrawal penalties may incentivize an interconnection customer to remain in the interconnection queue waiting for other interconnection customers to withdraw, and the penalty those interconnection customers pay will eventually be distributed to the remaining interconnection customers in the cluster, or interconnection customers may elect to remain in the interconnection queue in the hopes that others in the cluster withdraw to the point where the cost of network upgrades become more palatable.

(c) Comments on Specific Proposal

(1) Withdrawal Penalty Amounts

735. Several commenters oppose the proposed withdrawal penalty amounts. AEE argues that the Commission's proposed withdrawal penalty amounts are overly punitive, especially for those interconnection customers that submit a deposit in lieu of demonstrating commercial readiness, which many interconnection customers will be forced to do under the Commission's proposed commercial readiness requirements. AEE and Clean Energy Associations assert that the Commission's proposed withdrawal penalty amounts also appear arbitrary, with no basis in the costs of conducting studies or other relevant factors. AEE argues that the Commission should reduce these amounts and tie them more closely to its objectives and to the study costs that transmission providers are expected to incur, which it asserts will avoid turning the penalties into a punitive measure that provides a profit opportunity for transmission providers. AEE contends that the withdrawal penalty frameworks and time frames should be designed to discipline the decisions of interconnection customers rather than being punitive. Google does not support the proposal to impose higher withdrawal penalties on interconnection customers that submit a deposit in lieu of demonstrating commercial readiness.

736. Interwest argues that some of the proposed withdrawal penalties—those in the range of five to nine times the study costs—far exceed reasonableness, especially in the face of the potential for a myriad of ways in which an LSE can bias the bid review process and slow the cluster study process under existing rules without stringent oversight. Interwest argues that the NOPR does not sufficiently acknowledge the need to reform study processes to prevent inaccurate studies, which create widely different results from one study to another. Interwest suggests that these inaccurate studies, along with delayed affected system study results, lead to withdrawals, strengthening the case that withdrawal penalties should not increase dramatically toward the end of the study process and around execution of an LGIA without appropriate recourse for the interconnection customer. Interwest argues that a 25% increase in study costs from one study to another should be a sufficient basis for withdrawal without incurring withdrawal penalties, as part of a tariff with incentives for transmission providers to provide accurate estimates of network upgrade costs. Interwest argues that, for these reasons, withdrawal penalties are redundant and punitive when combined with increasingly large at-risk deposits as proof of commercial readiness.

737. SDG&E asserts that a withdrawal penalty of nine times the study deposit amount will provide a disincentive for late-stage withdrawals in certain cases, but that a penalty alone should not be relied on in lieu of other financial security mechanisms. SDG&E maintains that a more reasonable amount for a withdrawal penalty may be the greater of nine times the study deposit and a CAISO-style financial security posting that is based on factors such as network upgrade and interconnection facilities costs.

738. Some commenters argue that the Commission should adopt the RTO/ISO model of financial readiness milestones that are tied to network upgrade costs. Clean Energy Associations submit that tying deposits and penalties to network upgrade costs allocated to the interconnection customer is superior because network upgrade costs are a better indicator of the harm that may be caused by a withdrawal than generating facility size.

739. AES contends that tying the withdrawal penalty to the percentage of network upgrade deposit at risk provides a better incentive for interconnection customers with proposed generating facilities with high network upgrade costs to withdraw earlier in the interconnection process, rather than risk losing their posted security. Invenergy suggests that any withdrawal penalty imposed after LGIA execution should be tied to assigned network upgrade costs and should be subject to a $2 million cap to avoid unnecessarily punitive penalties, as the LGIA may impose additional financial obligations for construction of the assigned upgrades. CAISO argues that network upgrade-based financial requirements are far more effective than the withdrawal penalties proposed in the NOPR because network upgrade-based requirements are tied to the project's actual interconnection costs, which correlate with its competitiveness to obtain a power purchase agreement and therefore its likelihood to remain in the queue.

740. NYISO argues that the withdrawal penalty amounts proposed in the NOPR, which are tied to study costs, are unlikely to provide sufficient capital to cover the costs of constructing the network upgrades of withdrawn generating facilities on which other interconnection customers are relying. SoCal Edison suggests that, instead of using study costs as the basis for the withdrawal penalty amount, which would not be known until completion of the interconnection studies, the Commission should require that withdrawal penalties be calculated based on increasing multiples of the study deposits, which are known and serve as a proxy of the study costs.

(2) Proposed Withdrawal Penalty Exemptions

741. Some commenters support the NOPR proposal to exempt interconnection customers from withdrawal penalties in certain instances, stating that the proposal achieves a workable balance between the needs of interconnection customers and transmission providers. For example, MISO agrees that interconnection requests that experience significant cost increases should be able to withdraw without a penalty. Omaha Public Power states that the four scenarios proposed in the NOPR for interconnection customers to qualify for exemptions to withdrawal penalties seem to properly acknowledge instances where other interconnection customers are not negatively impacted by a withdrawal, or when it is no longer economically viable for the interconnection customer to move forward with the generating facility due to drastically increased network upgrade costs.

742. On the other hand, SEIA contends that, although the NOPR proposal exempts interconnection customers from withdrawal penalties if there is no impact to other generating facilities in the same cluster, withdrawals almost always impact other generating facilities in the cluster, such that withdrawal penalties are likely unavoidable. Pine Gate states that the proposed list of withdrawal penalty exemptions is not reflective of an appropriate balance between interconnection customer and transmission provider accountability because it increases the burden on interconnection customers without any increase to accountability for transmission providers. Pattern Energy disagrees with a standard tied to a potential delay of a lower-queued interconnection customer, given the Commission's proposed transition to a cluster study approach. Pattern Energy contends that the only impact that should be relevant to granting an exemption is a financial impact.

743. NRECA supports including the 100% cost increase exemption in the final rule, which would apply where there is a large late-stage cost increase, making the interconnection request's success economically challenging. Pattern Energy, on the other hand, claims that the Commission's proposal incentivizes transmission providers to overestimate costs in cluster studies for fear that there will be later, unexpected cost increases in the facilities study, which Pattern Energy argues presents a barrier to entry. Pine Gate also claims that requiring a 100% increase in costs between the facilities study phase and the previous cluster study phase in order to allow for penalty-free withdrawal exposes interconnection customers to withdrawal penalties in instances where costs increase dramatically due to no fault of the interconnection customer. Several commenters recommend that the Commission ensure that any penalties for withdrawal account for unanticipated cost increases.

744. Xcel recommends that the Commission allow an interconnection request, submitted by a resource planning entity as agent for an interconnection customer, that is withdrawn by the resource planning entity because it was not picked in a resource solicitation process, to be exempt from withdrawal penalties, as the withdrawal was due to no fault of the interconnection customer. Xcel states that, other than this exemption, the Commission should not expand the exemptions from withdrawal penalties beyond those proposed in the NOPR.

745. NextEra and Northwest and Intermountain argue that interconnection customers should be exempt from withdrawal penalties if the transmission provider's or affected system operator's studies or posted information are untimely.

746. NextEra contends that the NOPR does not explain why there are different withdrawal penalty levels for interconnection customers demonstrating commercial readiness via the proposed non-financial demonstration options and those submitting a deposit in lieu of demonstrating commercial readiness.

747. Several commenters argue that the proposed exemptions require clarification. For one, CAISO claims that the exemption criteria, as written in the NOPR, are not workable. CAISO argues that the Commission's description of the exemptions is problematic due to the use of “or,” which suggests meeting any criterion would relieve the interconnection customer of withdrawal penalties. CAISO posits that, under the Commission's criteria, a withdrawal could not affect the timing of other generating facilities but still increase their costs; however, the interconnection customer would meet the first exemption and not be subject to withdrawal penalties. CAISO argues that withdrawals would never delay the timing of generating facilities in the same cluster. CAISO states that a cluster's upgrades are a package, and the construction schedule would not change simply because one interconnection customer that is sharing upgrades withdraws. CAISO suggests that the Commission clarify that, to be exempt from withdrawal penalties, each interconnection customer must meet (1) both criterion one and two, and (2) criterion three or four.

748. Invenergy proposes that the list of exemptions to withdrawal penalties be revised to include: (1) the withdrawal does not directly cause material delays in the timing of other interconnection requests within the same cluster, as determined at the time of withdrawal by the transmission provider; or (2) the withdrawal does not directly cause a material increase in the costs assigned to other interconnection requests within the same cluster, as determined at the time of withdrawal by the transmission provider.

749. Omaha Public Power contends that the exemption to withdrawal penalties cannot be applied to the interconnection process as it currently functions for those transmission providers that allow for overlapping studies ( e.g., when a cluster study is being studied prior to the conclusion of the preceding cluster study). Omaha Public Power claims that overlapping studies lead to baseline costs in the subsequent cluster studies that are inherently wrong and do not factor in the previously existing unfinished cluster studies. Omaha Public Power claims that this inaccurate starting point for costs is likely higher than what is accurate, and any subsequent restudy will likely lead to identification of network upgrades that fall below the exemption threshold, subjecting interconnection customers to wrongful withdrawal penalties. Omaha Public Power argues that, until an interconnection process can be conducted without overlapping studies, these exemptions will be woefully misapplied. Southern raises similar concerns.

750. Yet other commenters believe that the NOPR proposal is too lenient. NRECA suggests that transmission providers should be afforded flexibility whether to adopt exemptions to withdrawal penalties related to: (1) not delaying the timing of other interconnection requests in the same cluster; (2) not increasing the cost of network upgrades for other interconnection requests in the same cluster; and (3) withdrawing if the most recent cluster study report shows a cost increase of at least 25% compared to the previous cluster study report. NRECA asserts that these exemptions may or may not be needed for a particular transmission provider and potentially may allow withdrawals that trigger time-consuming restudy processes. SDG&E generally opposes exemptions to withdrawal penalties and claims that material modification provisions in the pro forma LGIP already address impacts to other interconnection customers. SDG&E argues that, regardless of the impact to other interconnection customers, there are still costs and resources committed between all entities to study and assess proposed generating facilities. SDG&E believes that withdrawal penalties should apply for all generating facilities, and any exemptions should be sparing.

(3) How To Determine if a Withdrawal Has Delayed or Increased the Cost of Network Upgrades for Other Generating Facilities in the Same Cluster

751. Some commenters argue that it would be difficult to define the circumstances under which a withdrawal is deemed to have delayed the timing or increased the cost of network upgrades for other interconnection requests in the same cluster. APS and Bonneville argue that attempting to do so would create an undue burden on transmission providers, and that the withdrawal of an interconnection request could have an impact on generating facilities in a subsequent cluster. NextEra suggests that one test to determine whether a withdrawal delays other interconnection requests could be whether the withdrawal delays the planned in-service date of other interconnection requests in the same cluster. However, NextEra acknowledges that even this assessment could be difficult to calculate, as delays could not manifest themselves for months or years, other factors could cause delays, and interconnection customers could seek to delay their generating facilities for commercial reasons. Pattern Energy asserts that the Commission must clearly define the standard for timing delays and increasing the cost of network upgrades for other interconnection customers.

752. Bonneville suggests that, similar to the method used to assess a material modification under the pro forma LGIP and pro forma SGIP, the Commission could provide a non-exhaustive list of examples that would be deemed as delaying the timing or increasing the costs of network upgrades. Bonneville suggests that transmission providers could be given discretion to determine whether other withdrawal situations that are not listed should fall under this category by considering whether the withdrawal has delayed the timing or increased the cost of network upgrades for other interconnection requests in a cluster.

753. Invenergy argues that transmission providers should not be permitted to simply assume that withdrawals cause some harm to other interconnection requests and that there should be a requirement for transmission providers to perform an analysis to determine whether a withdrawal results in material harm to other interconnection requests, which interconnection customers could review. Invenergy states that the analysis of whether a withdrawal causes a cost increase or delays the timing for other interconnection requests should be performed at each phase of the study process.

754. Invenergy requests that the Commission clarify that a withdrawal will not delay the timing of another interconnection request or increase its network upgrade costs if the withdrawal simply requires the transmission provider to account for the withdrawal. Invenergy requests that the Commission clarify that any delay or cost increase analysis must be based on a reasonable analysis and show a direct relationship between the withdrawal and the asserted impact on another interconnection request.

755. MISO encourages the Commission to impose the withdrawal penalty whenever an interconnection request withdraws from the interconnection queue. MISO argues that even if after restudy it turns out that the withdrawal of an interconnection request did not actually increase network upgrade costs to other interconnection customers in the cluster, the withdrawal still negatively impacts the interconnection queue by increasing uncertainty for other interconnection customers, prompting further withdrawals and adding administrative cost and burden that impede efficient interconnection queue processing. Pattern Energy likewise argues that the withdrawal of any interconnection request from the interconnection queue results in some form of delay, such as the time taken by a transmission provider to perform a review of the potential impacts of the withdrawal, which could be interpreted as causing a delay because the withdrawal impact analysis could delay the receipt of final study results and agreements. PJM makes similar arguments.

756. Xcel contends that, if a withdrawal results in a restudy of a cluster or subsequent clusters, that restudy will delay the receipt of study results, LGIA execution, and the construction of required network upgrades. Therefore, Xcel argues that any withdrawal that results in a restudy should not be exempt from a withdrawal penalty unless the commercial operation dates of other impacted interconnection requests in the same or subsequent cluster are not impacted. Xcel asserts that delaying LGIA execution may negatively impact off-take agreements and should also be considered harm to equally or lower-queued interconnection customers. Xcel notes that harm is not limited to the reallocation of interconnection costs to equally or lower-queued interconnection requests. Xcel contends that delays, resulting in clogged interconnection queues, can impact resource decisions and thus harm interconnection requests not yet in the interconnection queue. Xcel argues that, if the withdrawal causes restudy, but the restudy does not impact the timing discussed above, then the restudy results should be used to determine the impact on costs allocated to equally or lower-queued interconnection requests.