Improvements to Generator Interconnection Procedures and Agreements

Federal RegisterApr 16, 2024

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM22-14-001; Order No. 2023-A]

Improvements to Generator Interconnection Procedures and Agreements

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Order on rehearing and clarification.

SUMMARY:

In this order, the Federal Energy Regulatory Commission addresses arguments raised on rehearing, sets aside, in part, and clarifies Order No. 2023, which amended the Commission's regulations and its pro forma Large Generator Interconnection Procedures, pro forma Large Generator Interconnection Agreement, pro forma Small Generator Interconnection Procedures, and pro forma Small Generator Interconnection Agreement to address interconnection queue backlogs, improve certainty, and prevent undue discrimination for new technologies.

DATES:

This rule is effective May 16, 2024.

FOR FURTHER INFORMATION CONTACT:

Anne Marie Hirschberger (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8387,

annemarie.hirschberger@ferc.gov.

Sarah Greenberg (Legal Information), Office of the General Counsel, 888 First St. NE, Washington, DC 20426, (202) 502-6230,

sarah.greenberg@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.

Michael G. Henry, Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8583,

michael.henry@ferc.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Background

II. Discussion

A. Need for Reform

1. Order No. 2023

2. Requests for Rehearing and Clarification

3. Determination

B. Arguments Regarding Conflicts With Ongoing Queue Reform Efforts and Evaluation of Variations on Compliance

1. Order No. 2023 Requirements

2. Requests for Rehearing and Clarification

3. Determination

C. Reforms To Implement a First-Ready, First-Served Cluster Study Process

1. Public Interconnection Information

2. Cluster Study Process

3. Allocation of Cluster Network Upgrade Costs

4. Shared Network Upgrades

5. Increased Financial Commitments and Readiness Requirements

6. Transition Process

D. Reforms To Increase the Speed of Interconnection Queue Processing

1. Elimination of Reasonable Efforts Standard and Implementation of a Replacement Rate

2. Affected Systems

E. Reforms To Incorporate Technological Advancements Into the Interconnection Process

1. Increasing Flexibility in the Generation Interconnection Process

2. Incorporating the Enumerated Alternative Transmission Technologies Into the Generator Interconnection Process

3. Modeling and Ride Through Requirements for Non-Synchronous Generating Facilities

F. Compliance Procedures

1. Order No. 2023 Requirements

2. Requests for Rehearing and Clarification

3. Determination

III. Information Collection Statement

IV. Environmental Analysis

V. Regulatory Flexibility Act

VI. Document Availability

VII. Effective Date

I. Background

1. On July 28, 2023, the Federal Energy Regulatory Commission (Commission) issued Order No. 2023.

Order No. 2023 required all public utility transmission providers to adopt revised

pro forma

Large Generator Interconnection Procedures (LGIP),

pro forma

Large Generator Interconnection Agreements (LGIA),

pro forma

Small Generator Interconnection Procedures (SGIP), and

pro forma

Small Generator Interconnection Agreements (SGIA).

These revisions 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.

In Order No. 2023, the Commission adopted a comprehensive package of reforms in three general categories: (1) reforms to implement a first-ready, first-served cluster study process, (2) reforms to increase the speed of interconnection queue processing, and (3) reforms to incorporate technological advancements into the interconnection process.

Improvements to Generator Interconnection Procs. & Agreements,

Order No. 2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC ¶ 61,054 (2023).

Id.

P 1 n.1 (“Section 201(e) of the Federal Power Act (FPA) defines “public utility” to mean “any person who owns or operates facilities subject to the jurisdiction of the Commission under this subchapter.” 16 U.S.C. 824(e). A non-public utility that seeks voluntary compliance with the reciprocity condition of a tariff may satisfy that condition by filing a tariff, which includes the

pro forma

LGIP, the

pro forma

SGIP, the

pro forma

LGIA, and the

pro forma

SGIA.

See Standardization of Generator Interconnection Agreements & Procs.,

Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ¶ 61,103, at PP 1, 616 (2003),

order on reh'g,

Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ¶ 61,220,

order on reh'g,

Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), 109 FERC ¶ 61,287 (2004),

order on reh'g,

Order No. 2003-C, 70 FR 37661 (June 30, 2005), 111 FERC ¶ 61,401 (2005),

aff'd sub nom. Nat'l Ass'n of Regul. Util. Comm'rs

FERC,

475 F.3d 1277 (D.C. Cir. 2007) (

NARUC

FERC

). As stated in the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA, transmission provider “shall mean the public utility (or its designated agent) that owns, controls, or operates transmission or distribution facilities used for the transmission of electric energy in interstate commerce and provides transmission service under the [Transmission Provider's Tariff]. The term . . . should be read to include the Transmission Owner when the Transmission Owner is separate from the Transmission Provider.”

Pro forma

LGIP section 1;

pro forma

LGIA art. 1;

pro forma

SGIP attach. 1;

pro forma

SGIA attach. 1.”).

Order No. 2023, 184 FERC ¶ 61,054 at P 1.

2. To implement a first-ready, first served cluster study process, Order No. 2023: (1) required transmission providers to post public interconnection information in an interactive heatmap to provide interconnection customers information before they enter the queue; (2) eliminated individual serial feasibility and system impact studies and created a cluster study; (3) created a range of allowable allocations of cluster study costs; (4) required transmission providers to use a proportional impact method to assign network upgrade costs within a cluster; (5) required increased financial commitments and readiness requirements from interconnection customers, including increased study deposits, site control, commercial readiness deposits, an LGIA deposit, and required transmission providers to institute penalties for withdrawn interconnection requests; and (6) created a transition mechanism for moving to the cluster study process adopted in Order No. 2023 from the existing serial study process.

Id.

P 5.

3. To increase the speed of interconnection queue processing, Order No. 2023: (1) eliminated the reasonable efforts standard for completing interconnection studies and adopted study delay penalties applicable when transmission providers fail to complete interconnection studies

by the deadlines in their tariff; and (2) established a more detailed affected system study process in the

pro forma

LGIP, including

pro forma

affected system agreements and uniform modeling standards.

Id.

P 6.

4. To incorporate technological advancements into the interconnection process, Order No. 2023: (1) required transmission providers to 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) required transmission providers to evaluate the proposed addition of a generating facility to an existing interconnection request prior to deeming such an addition a material modification; (3) required transmission providers to 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) required transmission providers, at the request of the interconnection customer, to use operating assumptions in interconnection studies that reflect the proposed charging behavior of electric storage resources; (5) required transmission providers to evaluate an enumerated list of alternative transmission technologies during the study process; (6) required each interconnection customer requesting to interconnect a non-synchronous generating facility to submit to the transmission provider certain specific models of the generating facility; (7) established ride through requirements during abnormal frequency conditions and voltage conditions within the “no trip zone” defined by NERC Reliability Standard PRC-024-3 or successor mandatory ride through reliability standards; and (8) required that all newly interconnecting large generating facilities provide frequency and voltage 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.

Id.

P 6.

5. The Commission received 32 timely filed requests for rehearing and/or clarification, and two additional requests for clarification.

The rehearing requests raise issues related to nearly all reforms adopted in Order No. 2023.

Appendix A provides the short names of the entities that filed requests for rehearing or clarification. Shell filed an answer. Rule 713(d)(1) of the Commission's Rules of Practice and Procedure (18 CFR 385.713(d)) prohibits an answer to a request for rehearing. Accordingly, we deny Shell's motion to answer and reject its answer.

6. Pursuant to

Allegheny Defense Project

FERC,

the rehearing requests filed in this proceeding may be deemed denied by operation of law. However, as permitted by section 313(a) of the Federal Power Act (FPA),

we are modifying the discussion in Order No. 2023, setting aside the order, in part, and clarifying the order, as discussed below.

964 F.3d 1 (D.C. Cir. 2020) (en banc).

16 U.S.C. 825

(a) (“Until the record in a proceeding shall have been filed in a court of appeals, as provided in subsection (b), the Commission may at any time, upon reasonable notice and in such manner as it shall deem proper, modify or set aside, in whole or in part, any finding or order made or issued by it under the provisions of this chapter.”).

Allegheny Def. Project,

964 F.3d at 16-17. In Appendices C, D, E, and F, we provide the revisions to the provisions of the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA made in this order on rehearing and clarification. Additionally, these Appendices reflect several non-substantive corrections in these appendices to address stylistic inconsistencies or clerical errors in some of the new and revised

pro forma

provisions.

7. Specifically, we set aside the order, in part, to specify that: (1) where an interconnection customer is in the interconnection queue of a transmission provider that currently uses, or is transitioning to, a cluster study process and the transmission provider proposes on compliance to adopt new readiness requirements for its annual cluster study, the interconnection customer must comply with the transmission provider's new readiness requirements within 60 days of the Commission-approved effective date of the transmission provider's compliance filing, where such readiness requirements are applicable given the status of the individual interconnection customer in the queue; (2) a network upgrade that is required for multiple interconnection customers in a cluster may be considered a stand alone network upgrade if all such interconnection customers mutually agree to exercise the option to build; (3) transmission providers must complete their determination that an interconnection request is valid by the close of the cluster request window such that only interconnection customers with valid interconnection requests proceed to the customer engagement window; and (4) acceptable forms of security for the Commercial Readiness Deposit and deposits prior to the Transitional Serial Study, Transitional Cluster Study, Cluster Restudy and the Interconnection Facilities Study should include not only cash or an irrevocable letter of credit, but also surety bonds or other forms of financial security that are reasonably acceptable to the transmission provider.

8. Additionally, we grant several clarifications on the following topics, as further discussed below: (1) conflicts with ongoing queue reform efforts; (2) public interconnection information; (3) cluster study process; (4) allocation of cluster network upgrade costs; (5) shared network upgrades; (6) withdrawal penalties; (7) study delay penalty and appeal structure; (8) affected systems; (9) revisions to the material modification process to require consideration of generating facility additions; (10) availability of surplus interconnection service; (11) operating assumptions for interconnection studies; (12) consideration of the enumerated alternative transmission technologies in interconnection studies; and (13) ride-through requirements.

9. Finally, in light of the revisions made to the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA herein, we extend the deadline for transmission providers to submit compliance filings until the effective date of this order (

i.e.,

the new deadline for compliance with Order No. 2023 will be 30 days after the publication of this order in the

Federal Register

, and must include the further revisions reflected in this order).

II. Discussion

A. Need for Reform

1. Order No. 2023

10. The Commission stated that it found substantial evidence in the record to support the conclusion that the existing

pro forma

generator interconnection procedures and agreements were unjust, unreasonable, and unduly discriminatory or preferential.

Therefore, pursuant to FPA section 206, the Commission concluded that certain revisions to the

pro forma

open access transmission tariff and the Commission's regulations were necessary to ensure rates that are just, reasonable, and not unduly discriminatory or preferential. Specifically, the Commission found that the existing

pro forma

generator interconnection procedures and agreements were 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. The

Commission stated that, absent reform, the 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. The Commission explained that 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.

Order No. 2023, 184 FERC ¶ 61,054 at P 37.

11. The Commission cited recent data to support its findings 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.

This data indicated that, 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.

These interconnection requests and the generating facilities they represent amount to 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. The Commission explained that these trends are not exclusive to any specific region of the country; rather, every region, including regional transmission organizations (RTO), independent system operators (ISO), and non-RTOs/ISOs, 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. The Commission noted that 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%.

Id.

P 38 (citing Energy Markets & Policy- Berkeley Lab,

Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection,

7-8 (Apr. 2023) (Queued Up 2023),

https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf;

Appendix B to Order No. 2023, which provided an overview of recent data based on reporting by transmission providers in compliance with Order No. 845).

Id.

(citing Queued Up 2023).

12. The Commission also cited recent data 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.

Despite efforts to address these challenges, the Commission observed that 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 from 2.1 years for generating facilities built in 2000-2010 to roughly five years for generating facilities built in 2022.

Id.

P 39.

13. The Commission explained that delays in the interconnection study process are an important contributor to interconnection queue backlogs nationwide.

The Commission cited recent interconnection study metrics transmission providers filed with the Commission, as required by Order No. 845, which showed that of the 2,179 interconnection studies completed in 2022, 68% were issued late. 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 most non-RTO/ISO transmission providers (14 of 38) reported pending delayed studies at the end of 2022.

Id.

P 40.

14. The Commission found that numerous factors have contributed to the increasing volume of interconnection requests, including a rapidly changing resource mix, market forces, and emerging technologies.

The Commission also found that available transmission capacity has been largely or fully used in many regions, creating situations where interconnection customers face significant network upgrade cost assignments to interconnect their proposed generating facilities. As an example, the Commission cited a U.S. DOE report that found 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.

The Commission also noted that other reports show similar cost increases in NYISO and PJM.

The Commission found that this combination of increased volume of interconnection requests and insufficient transmission capacity and therefore 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.

Id.

P 41.

Id.

(citing Joachim Seel et al.,

Generator Interconnection Cost Analysis in the Midcontinent Independent System Operator (MISO) Territory,

1, 4-5 (Oct. 2022),

https://emp.lbl.gov/interconnection_costs.

Id.

(citing Julia Mulvaney Kemp et al.,

Interconnection Cost Analysis in the NYISO Territory

(Mar. 2023),

https://emp.lbl.gov/publications/interconnection-cost-analysis-nyiso

(showing that costs have doubled for generating facilities studied since 2017, relative to costs for generating facilities studied from 2006 to 2016); Joachim Seel et al.,

Interconnection Cost Analysis in the PJM Territory

(Jan. 2023),

https://emp.lbl.gov/publications/interconnection-cost-analysis-pjm

(showing that costs for recent “complete” generating facilities have doubled on average relative to costs from 2000-2019)).

15. The Commission explained that interconnection queue backlogs and delays have created uncertainty for interconnection customers regarding the timing and cost of ultimately interconnecting to the transmission system, which may lead to an increase in costs to consumers.

The Commission stated that delayed interconnection study results or unexpected cost increases can disrupt numerous aspects of generating facility development and such uncertainty, either on the part of transmission providers or interconnection customers, is ultimately passed through to consumers through higher transmission or energy rates. The Commission explained that increases in energy rates may result from wholesale customers having limited access to new and more competitive supplies of generation and that, conversely, efficient interconnection queues and well-functioning wholesale markets deliver benefits to consumers by driving down wholesale electricity costs.

Id.

P 43.

16. Overall, due to continuing and increasing interconnection queue backlogs and study delays, the Commission found that the Commission's existing rules contained in the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA resulted in rates, terms, and conditions for Commission-jurisdictional services that are unjust, unreasonable, and unduly discriminatory or preferential.

The Commission found that 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, and

hindered the timely development of new generation, thereby stifling competition in the wholesale electric markets. Therefore, the Commission found that reform to the Commission's existing

pro forma

generator interconnection procedures and agreements was necessary.

Id.

P 44.

17. The Commission based its findings that the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA must be reformed on the following features: (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 Order No. 2023; and (5) the modeling or performance requirements (or lack thereof) for non-synchronous generating facilities, including wind, solar, and electric storage facilities.

The Commission further explained each of these five features.

Id.

P 45.

18. First, the Commission explained that, without 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, it is difficult for interconnection customers to assess the commercial viability of a specific proposed generating facility prior to entering the interconnection queue.

The Commission also found that the

pro forma

interconnection procedures and agreements failed to include meaningful financial commitments and readiness requirements to enter and stay in the interconnection queue and lacked stringent requirements to establish the commercial viability of proposed generating facilities. As a result, the Commission explained, interconnection customers often submit multiple interconnection requests for proposed generating facilities at various points of interconnection, knowing that not all of them 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.

Id.

P 46.

19. Second, the Commission explained that the existing serial first-come, first-served study process created 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: thus, the interconnection customers ultimately withdraw their interconnection requests from the interconnection queue, which triggers reassessments and possible restudies by the transmission provider that can delay the timing and increase the cost to interconnect for lower-queued interconnection requests. The Commission found that the lack of access to information about a specific location or point of interconnection prior to submitting an interconnection request, the lack of any 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, together incentivized 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.

Id.

P 47.

Id.

P 48.

20. The Commission also found that interconnection queue backlogs and delays, and the accompanying uncertainty, have been further compounded because transmission providers have limited incentive to perform interconnection studies in a timely manner.

The Commission stated that, despite pervasive delays in completing interconnection studies by transmission providers, transmission providers have faced few, if any, consequences for failing to meet their tariff-imposed study deadlines under the reasonable efforts standard. The Commission therefore found 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, resulting in Commission-jurisdictional rates that are unjust and unreasonable.

Id.

P 50.

21. Third, the Commission found that, without requirements for how and when transmission providers should complete affected system studies, those studies often lag behind those completed by the transmission provider to whose transmission system the interconnection customer proposes to interconnect (the 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 Commission found that those 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, the Commission found 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.

Id.

P 51.

22. Fourth, the Commission found that the Commission's

pro forma

LGIP failed to accommodate the operating characteristics and technical capabilities of electric storage resources when it comes to specific interconnection procedures and modeling.

The Commission noted that 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. The Commission noted that the existing

pro forma

generator interconnection procedures and agreements did not contemplate the operating characteristics or technical capabilities of electric storage resources, leading to electric storage resources being studied under inappropriate operating assumptions (

e.g.,

charging at full capacity during peak load conditions) that result in the assignment of unnecessary network upgrades which increase costs to interconnection customers. Therefore, the Commission found that the inability to modify

operating assumptions for electric storage resources pursuant to the

pro forma

LGIP resulted in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential.

Id.

P 52.

23. The Commission also found that the existing

pro forma

interconnection procedures regarding material modifications did not provide for consistent evaluation of technology additions to an existing interconnection request, and 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.

Id.

P 53.

24. Finally, the Commission found that the

pro forma

LGIP and

pro forma

SGIP failed to require the consideration of alternative transmission technologies that can be used as network upgrades and can be deployed more quickly and at a lower cost than, traditional network upgrades.

The Commission found that failing to require transmission providers to evaluate the enumerated list of alternative transmission technologies resulted in interconnection customers paying more than is just and reasonable to reliably interconnect new generating facilities, ultimately creating Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential.

Id.

P 54.

25. Fifth, the Commission found that the Commission's existing

pro forma

LGIP and

pro forma

SGIP did 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.

The Commission explained that interconnection customers must submit accurate and validated models, which will prevent study delays and ensure that transmission providers identify the necessary interconnection facilities and network upgrades to accommodate the interconnection request and thus allow the appropriate assignment of interconnection costs to the interconnection request. Therefore, the Commission found 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. Additionally, the Commission explained that 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 did not face a comparable requirement and many cease injecting current during system disturbances through “momentary cessation,” which creates reliability issues on the transmission system. The Commission stated that, without requirements for non-synchronous generating facilities to remain connected to and synchronized with the transmission system during system disturbances, 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, the Commission found 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.

Id.

P 55.

Id.

P 56.

26. The Commission further found that the reforms adopted in Order No. 2023 will improve the efficiency of study processes, reduce interconnection queue backlogs, and thereby ensure just, reasonable, and not unduly discriminatory or preferential rates.

The Commission explained that the majority of the individual reforms that the Commission adopted have already been implemented in one or more regions in order to improve the interconnection process, demonstrating incremental improvements. The Commission compiled a package of such reforms that, in their entirety, have not yet been adopted by any region, and will ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner.

Id.

P 59.

2. Requests for Rehearing and Clarification

27. Dominion seeks rehearing, asserting that the Commission exceeded its FPA section 206 authority by declaring all existing interconnection tariffs, including recently accepted reforms by PJM and Dominion Energy South Carolina (DESC), as unjust, unreasonable, and unduly discriminatory or preferential without substantial evidence.

Dominion asserts that the Commission did not establish a sufficient legal foundation to generically find that all tariffs are unjust and unreasonable.

Similarly, Indicated PJM TOs argue that the Commission arbitrarily and capriciously relied on inapposite and stale evidence to impose a generic replacement rate on early adopters of the cluster study approach.

PJM also argues that the generic findings underlying Order No. 2023 cannot apply to its Interconnection Process Reform Task Force (IPRTF) Tariff, which was filed and approved during the time period between issuance of the NOPR and Order No. 2023.

Therefore, PJM contends, the data underlying Order No. 2023 is stale as to PJM and its use does not constitute reasoned decision-making based on substantial evidence.

Dominion Rehearing Request at 2.

Id.

at 14 (citing

S.C. Pub. Serv. Auth.

FERC,

762 F.3d 71, 65 (D.C. Cir. 2014) (

S.C. Pub. Serv. Auth.

) (“To regulate a practice affecting rates pursuant to Section 206, the Commission must find that the existing practice is `unjust, unreasonable, unduly discriminatory or preferential,' and that the remedial practice it imposes is `just and reasonable.' These findings must be supported by `substantial evidence[.]'”);

Emera Me.

FERC,

854 F.3d 9, 25 (D.C. Cir. 2017) (

Emera Me.

) (“[A] finding that an existing rate is unjust and unreasonable is the `condition precedent' to FERC's exercise of its section 206 authority to change that rate. Section 206, therefore, imposes a `dual burden' on FERC. Without a showing that the existing rate is unlawful, FERC has no authority to impose a new rate.”)).

Indicated PJM TOs Rehearing Request at 7, 17.

PJM Rehearing Request at 25-26.

28. Dominion acknowledges that the Commission is able to rely on generic rulemakings to support an industry wide solution, but that Order No. 2023 goes beyond the limits of this authority.

Dominion argues that Order No. 2023's mandate is unlike the generic rulemaking upheld by the D.C. Circuit in

Transmission Access Policy Study Group

FERC

because the rule at issue in that case, Order No. 888, represented a paradigm shift for which a generic rulemaking is appropriate.

Dominion asserts that the other generic rulemakings upheld by the courts similarly involve more wholesale reform than Order No. 2023, such as the expansion and creation of new Order No. 1000 planning obligations upheld in

S.C. Pub. Serv. Auth.,

or the Order No. 637 requirement for gas pipelines to permit segmentation where

operationally feasible, upheld in

Interstate Natural Gas Association of America

FERC.

Dominion contends that the Commission's generic findings in Order No. 2023 are disproportionate to the evidence the Commission relies on. Similarly, Indicated PJM TOs assert that the Commission's generic finding is overbroad because many RTOs/ISOs have already adopted the core reforms in Order No. 2023.

Dominion Rehearing Request at 12.

Id.

(citing

Transmission Access Pol'y Study Grp.

FERC,

225 F.3d 667 (D.C. Cir. 2000) (

TAPS

aff'd sub nom. N. Y.

FERC,

535 U.S. 1 (2002));

see also Sacramento Mun. Util. Dist.

FERC,

428 F.3d 294, 296 (D.C. Cir. 2005) (explaining that utilities can deviate from the terms of the

pro forma

tariff if such deviations are consistent with or superior to the terms of the

pro forma

tariff).

48. In response to Indicated PJM TOs' contention that the Commission failed to grapple with the fact that many RTOs/ISOs already adopted the Commission's core substantive reforms before Order No. 2023 was issued, we acknowledge that many transmission providers have adopted many of the reforms in Order No. 2023. As explained above, that is not an accident. The Commission carefully examined recent queue reform proposals to identify best practices to implement nationwide. However, no transmission provider has yet adopted

all

of the reforms in Order No. 2023. For example, no transmission provider has eliminated the reasonable efforts standard for completing interconnection studies on time. We continue to believe that this broad suite of reforms, as a whole, is necessary 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.

Order No. 2023, 184 FERC ¶ 61,054 at P 59.

49. Regarding Indicated PJM TOs' argument that the Commission should have waited for recent queue reforms to be fully implemented before determining whether additional reforms are required, we disagree. Transmission providers across the country have been working on regional queue reform for well over a decade.

These proposals are filed at varying intervals, and at any given time, multiple transmission providers may be in the process of proposing or implementing new queue processes. By the time one or two particular transmission providers implement one set of queue reforms, it is likely that other transmission providers would be in the process of proposing or implementing their next queue reform. The Commission would

be waiting a very long time indeed if it could not issue a generic rulemaking while any individual transmission provider pursues its own regional queue reform.

Id.

P 16, n.39.

Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils.,

Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 FERC ¶ 61,051, at P 50 (2011) (finding that the need to generically establish rules addressing transmission planning, as well as the long lead times and complex problems associated with developing transmission facilities, made Commission action appropriate and prudent rather than allowing the noted transmission planning problems to persist).

50. Furthermore, we note that the Commission has historically taken a gradual approach to addressing problems with respect to interconnection queue backlogs. In Order No. 845, for instance, the Commission implemented a number of specific reforms, but held off on other reforms in favor of collecting further information from transmission providers.

In doing so, the Commission noted that “[t]his information could also be useful to the Commission in determining if additional action is required to address interconnection study delays.”

In Order No. 2023, the Commission determined that additional action was required to address interconnection study delays.

The reforms in Order No. 845 have not eliminated the problems of interconnection queue backlogs and delayed interconnection studies; rather, these problems have only grown, notwithstanding the Commission's previous reforms. We maintain that the reforms in Order No. 2023 are necessary 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.

Reform of Generator Interconnection Procs. & Agreements,

Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ¶ 61,043, at P 24 (2018),

order on reh'g,

Order No. 845-A, 84 FR 8156 (Mar. 6, 2019), 166 FERC ¶ 61,137 (2019),

order on reh'g,

Order No. 845-B, 168 FERC ¶ 61,092 (2019).

Order No. 845, 163 FERC ¶ 61,043 at P 309.

Order No. 2023, 184 FERC ¶ 61,054 at P 3.

B. Arguments Regarding Conflicts With Ongoing Queue Reform Efforts and Evaluation of Variations on Compliance

1. Order No. 2023 Requirements

51. The Commission addressed commenters' concerns regarding Order No. 2023's impact on early adopters of similar queue reforms or those queues currently in transition to a cluster study process. The Commission recognized that many of the individual reforms that the Commission adopted in Order No. 2023 are incremental improvements that one or more regions had already implemented.

The Commission explained that Order No. 2023 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.

Id.

P 59.

52. Additionally, the Commission rejected requests to presume that any transmission provider's tariff meets the requirements of Order No. 2023.

The Commission recognized that many transmission providers have adopted or are in the process of adopting similar reforms to those adopted in Order No. 2023 and clarified that the Commission did not intend to disrupt these ongoing transition processes or stifle further innovation.

The Commission emphasized that the provisions of Order No. 2023 are not intended to interfere with the timely completion of those in-progress cluster studies and transition processes.

The Commission explained that, on compliance, transmission providers can propose deviations from the requirements adopted in Order No. 2023, including deviations seeking to minimize interference with ongoing transition plans,

provided that the reason for the variation is sufficiently justified, and may continue to propose solutions to interconnection issues under FPA section 205.

Id.

P 1765.

Id.

PP 861, 1765.

Id.

P 861.

Id.

P 1765 (clarifying that transmission providers that have already adopted a cluster study process or are currently undergoing a transition to a cluster study process will not be required to implement a new transition process).

Id.

P 1767.

53. Therefore, consistent with Order Nos. 888, 890, 2003, 2006, and 845, the Commission adopted the NOPR proposal to continue to apply the consistent with or superior to standard when considering proposals from non-RTO/ISO transmission providers to deviate from the requirements of Order No. 2023.

Consistent with Order Nos. 2003, 2006, and 845, the Commission adopted the NOPR proposal to continue to use the “independent entity variation” standard when considering such proposals from RTOs/ISOs.

Consistent with Order Nos. 888, 890, 2003, 2006, and 845, the Commission adopted the NOPR proposal to continue to allow non-RTO/ISO transmission providers to use the regional differences rationale to seek variations made in response to established (

i.e.,

approved by the Applicable Reliability Council) reliability requirements.

The Commission explained that Order No. 2023 makes no changes to the standards used to judge requested variations, as described in Order Nos. 888, 890, 2003, 2006, and 845.

Id.

P 1764 (citing

Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Servs. By Pub. Utils,; Recovery of Stranded Costs by Pub. Utils. & Transmitting Utils.,

Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,769-770 (cross-referenced at 75 FERC ¶ 61,080);

Preventing Undue Discrimination & Preference in Transmission Serv.,

Order No. 890, 72 FR 12226 (Mar. 15, 2007), 118 FERC ¶ 61,119 at P 109 (2007) (“[W]e reiterate that any departures from the

pro forma

[open access transmission tariff] proposed by an ISO or an RTO must be `consistent with or superior to' the

pro forma

[open access transmission tariff] in this Final Rule.”); Order No. 2003, 104 FERC ¶ 61,103 at P 825; Order No. 2006, 111 FERC ¶ 61,220 at PP 546-547; Order No. 845, 163 FERC ¶ 61,043 at P 43 (explaining that a transmission provider that is not an RTO/ISO that seeks a variation from the requirements of the final rule must present its justification for the variation as consistent with or superior to the

pro forma

LGIA or

pro forma

LGIP)).

Id.

(citing Order No. 2003, 104 FERC ¶ 61,103 at P 826 (“[w]ith respect to an RTO or ISO . . . we will allow it to seek `independent entity variations' from the Final Rule . . . This is a balanced approach that recognizes that an RTO or ISO has different operating characteristics depending on its size and location and is less likely to act in an unduly discriminatory manner than a Transmission Provider that is a market participant.”); Order No. 2006, 111 FERC ¶ 61,220 at PP 447, 549; Order No. 845, 163 FERC ¶ 61,043 at P 556).

Id.

(citing Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,770; Order No. 890, 118 FERC ¶ 61,119 at P 109; Order No. 2003, 104 FERC ¶ 61,103 at P 826 (“if on compliance a non-RTO or ISO Transmission Provider offers a variation from the Final Rule LGIP and Final Rule LGIA, and the variation is in response to established (

i.e.,

approved by the Applicable Reliability Council) reliability requirements, then it may seek to justify its variation using the regional difference rationale.”); Order No. 2006, 111 FERC ¶ 61,220 at PP 546-547; Order No. 845, 163 FERC ¶ 61,043 at P 43).

2. Requests for Rehearing and Clarification

54. Several entities request clarification regarding the scope of the application of Order No. 2023 to transmission providers that have already transitioned to, or that are in the process of transitioning to, a cluster study process.

Clean Energy Associations Rehearing Request at 51-52; Dominion Rehearing Request at 17-18; IPP Coalition Rehearing Request at 10-13; PacifiCorp Rehearing Request at 15-20; PJM Rehearing Request at 1-3; Revised Early Adopters Coalition Rehearing Request at 2-7; WIRES Rehearing Request at 12.

55. Clean Energy Associations and IPP Coalition ask the Commission to clarify that

all

existing cluster study processes must comport with the requirements of Order No. 2023, whether the transmission provider currently operates a cluster study process or is currently undergoing a transition to a

cluster study process.

Clean Energy Associations and IPP Coalition argue that interconnection customers that are currently in a cluster study process should be required to satisfy the requirements of Order No. 2023, including site control requirements, within an identified time horizon (

e.g.,

60-90 days of the compliance filing) or withdraw from the interconnection queue without penalty.

100

Clean Energy Associations and IPP Coalition argue that, if some transmission providers are not required to transition to a process that is compliant with Order No. 2023, projects currently in the queue that are not ready to proceed will not face the increased readiness requirements and delay reforms to new queue requests, undermining the central purpose of Order No. 2023.

101

Clean Energy Associations Rehearing Request at 51; IPP Coalition Rehearing Request at 10-11.

100

Clean Energy Associations Rehearing Request at 51; IPP Coalition Rehearing Request at 11-12.

101

Clean Energy Associations Rehearing Request at 53; IPP Coalition Rehearing Request at 13.

56. Clean Energy Associations and IPP Coalition argue that, absent clarification, the Commission risks leaving in place a potentially problematic oversight.

102

Specifically, Clean Energy Associations and IPP Coalition assert that the notion that transmission providers that have adopted or are currently transitioning to a cluster study process will not be required to implement a new transition process runs counter to the requirement that transmission providers may seek approval, on a case-by-case basis, to maintain variations from the

pro forma

LGIP and

pro forma

LGIA.

103

According to Clean Energy Associations and IPP Coalition, the fact that a transmission provider has an existing cluster study does not exempt that provider from its compliance obligation or the need to update its process to reflect the material elements of Order No. 2023.

102

Clean Energy Associations Rehearing Request at 51; IPP Coalition Rehearing Request at 11.

103

Clean Energy Associations Rehearing Request at 51-52; IPP Coalition Rehearing Request at 11 (both citing Order No. 2023, 184 FERC ¶ 61,054 at P 1530).

57. NV Energy requests that the Commission clarify whether the new tariff changes are applicable to all interconnection customers, including those that currently participate in a cluster study process or have executed LGIAs.

104

Specifically, NV Energy requests that the Commission clarify if interconnection customers will be required to update their respective study deposits, provide commercial readiness deposits correlating to the amounts required at the various stages of the process, and update their site control documentation in order to remain in the queue.

105

NV Energy requests a one-time ability for existing interconnection customers of transmission providers who currently conduct cluster studies to withdraw penalty-free from the queue if they are unable to provide the updated study deposits, site control, commercial readiness deposits, etc.

104

NV Energy Rehearing Request at 2 (citing Order 2023, 184 FERC ¶ 61,054 at P 861). NV Energy states that Order No. 2023 did not mention grandfathering any of the existing interconnection agreements.

Id.

105

Id.

at 3.

58. NV Energy additionally requests clarification on whether a queued interconnection customer, whether in a current cluster study, with an executed facilities study agreement, or with an executed LGIA, must provide the heightened proof of site control by the effective date of the new tariff changes.

106

NV Energy seeks clarity on whether: (1) existing queued interconnection customers are required to provide 90% of site control if not impacted by a regulatory limitation and are currently within the cluster study phase of the process; (2) existing queued interconnection customers with executed facilities studies agreements are required to provide 100% of site control if the site is not impacted by a regulatory limitation; (3) existing queued interconnection customers who are impacted by a regulatory limitation are required to update their deposit in lieu of site control to the new deposit amounts; and (4) existing queued interconnection customers with executed LGIAs who are impacted by a regulatory limitation are required to provide site control within 180 days of executing their respective LGIAs.

106

Id.

59. EEI asks the Commission to clarify that Order No. 2023 does not require transmission providers to re-file and seek approval for portions of their existing LGIA and LGIP that have previously been approved by the Commission and are not directly impacted by Order No. 2023.

107

EEI argues that it would be inappropriate for the Commission to require transmission providers to re-file and seek approval for such portions of their existing LGIAs and LGIPs because the Commission provided no notice that it was going to review or reconsider every change it has previously approved for LGIAs and LGIPs, and thus transmission providers were not given an opportunity to defend previously approved changes.

108

EEI argues that it would be a significant administrative burden for transmission providers to re-justify every change that the Commission has already approved.

109

107

EEI Rehearing Request at 2-3, 16.

108

Id.

at 16.

109

EEI states that this would include changes that were approved by the Commission in response to other rulemakings, such as Order No. 845.

Id.

at 16-17.

60. PJM asks the Commission to provide a clearer signal as to how it will take into account recently approved reforms such as PJM's IPRTF.

110

PJM states that its recent queue reform meets the Commission's intent in promulgating Order No. 2023, substantially satisfies its requirements, and is superior for the PJM region.

111

PJM explains that there are differences between the implementation mechanisms in its IPRTF Tariff and Order No. 2023, but that these mechanisms serve the same goals and offer the same protections and benefits.

112

110

PJM Rehearing Request at 1-2.

111

Id.

at 1, 19-20.

112

Id.

at 19-23.

61. PJM states that it has begun its transition period, and unless the Commission provides more clarity as to how it will review recently approved queue reform processes in the Order No. 2023 compliance process, it will create substantial uncertainty that will distract from the effort to process the queue backlog.

113

PJM seeks clarification that it will not be required to implement Order No. 2023 in a manner that would modify or undermine the procedures recently accepted by the Commission, and that the Commission will review PJM's request for an independent entity variation holistically, by examining whether the package as a whole is consistent with or superior to the goals and requirements of Order No. 2023 rather than forcing PJM to engage in an item-by-item justification of every variation from the minutiae of Order No. 2023's requirements.

114

PJM explains that requiring it to overhaul its tariff or justify each difference from the new

pro forma

will risk that some elements will be retained while other balancing elements will be changed, upsetting the balance that led to stakeholder approval.

115

PJM states that proceeding element by element through compliance will also provide intervenors an opportunity to re-litigate issues on which they did not prevail, which is contrary to judicial principles and would be a poor use of time.

116

PJM also explains that the elements of its tariff are interdependent, such that a

piecemeal approach could undermine the entire tariff.

113

Id.

at 2, 10.

114

Id.

at 3, 15.

115

Id.

at 15.

116

Id.

at 16.

62. If the Commission does not provide the requested clarifications, PJM seeks rehearing because the Commission should have established a presumption that ongoing, recently approved interconnection queue reform packages comply with Order No. 2023.

117

PJM explains that Order No. 2023 is internally inconsistent because it seeks to expedite the interconnection queue, and recognizes the efforts of on-going queue reform, but refuses to grant a presumption, which will cause delay and inefficiency.

118

PJM argues that it would be arbitrary and capricious and inconsistent with reasoned decision-making to require modification of PJM's tariff based on a generic rulemaking.

119

PJM also argues that failure to grant this rehearing will undermine confidence in the use of stakeholder processes.

120

117

Id.

at 3, 25-26.

118

Id.

at 26.

119

Id.

at 3-4.

120

Id.

at 27.

63. To the extent that the Commission does not grant PJM's request to provide a clear signal on rehearing that it will consider whether the entire package of IPRTF reforms as a whole meets the goals of Order No. 2023 rather than forcing PJM to engage in an extensive justification of every variation from every detail in Order No. 2023, PJM requests rehearing.

121

Id.

at 24.

64. Dominion argues that the Commission should cure the deficiencies in Order No. 2023's approach to compliance for early adopters like DESC and PJM.

122

Dominion suggests that the Commission could simply not require entities that have already transitioned or are in the process of transitioning to a first-ready, first-served cluster study construct to file compliance filings. Dominion alternatively argues that the Commission could defer those entities' obligations to modify their tariffs, pending an appropriate period of time to gather evidence about whether their particular, Commission-approved reforms need to be further modified. Dominion asserts that this approach would be within the Commission's statutory bounds, is administratively efficient, and maintains the settled expectations of the stakeholders that worked diligently and collaboratively to develop transmission provider-specific reforms. Dominion asserts that the Commission has on several occasions directed entities to provide reports so that it can monitor situations before deciding it is necessary to take action.

123

Dominion argues that the Commission could then require such early adopters to provide an additional report after a period of time determined by the Commission, such as two full cluster cycles following the transition, that would update the Commission on processing time under the proposed rule.

122

Dominion Rehearing Request at 17.

123

Id.

at 17-18 (citing, for example,

One-Time Informational Reports on Extreme Weather Vulnerability Assessments Climate Change, Extreme Weather, & Elec. Sys. Reliability,

Order No. 897, 88 FR 41477 (June 27, 2023), 183 FERC ¶ 61,192, at P 25 (2023) (requiring one-time informational reports related to planning for the impacts of extreme weather on system reliability);

Hybrid Res.,

174 FERC ¶ 61,034, at P 1 (2021) (requiring RTOs and ISOs to submit information related to hybrid resources)).

65. Dominion argues that, if the reports demonstrate that early adopters' processes are not meeting the goals of Order No. 2023, the Commission would then have a sufficient record, through the reports, to determine whether to direct further changes to conform with Order No. 2023.

124

Dominion contends that this compliance path for early adopters is superior to Order No. 2023's proposal and would allow transmission providers to demonstrate that the desired aim of Order No. 2023—facilitating quicker, more efficient interconnection processes—is being achieved.

124

Id.

at 18.

66. Revised Early Adopter Coalition and PacifiCorp state that, to the extent a transmission provider does not seek or is not granted a variance for its existing interconnection reforms, such transmission provider appears to be required to immediately adopt the reforms in Order No. 2023 without any ability to start from a clean slate like other transmission providers utilizing a transition study process or to conclude any ongoing studies.

125

Revised Early Adopters Coalition and PacifiCorp argue that Order No. 2023 does not appear to allow early adopters of interconnection reforms an option to open the initial cluster request window under Order No. 2023 after the conclusion of the study of existing interconnection requests.

126

Revised Early Adopters Coalition and PacifiCorp assert that, because many early adopters are currently in the process of one or more cluster studies, not allowing such early adopters to use a transition cluster study process is both unworkable for such transmission providers and also contrary to Order No. 2023's assurance that “the provisions of this final rule are not intended to interfere with the timely completion of those in-progress cluster studies and transition processes.”

127

125

Revised Early Adopters Coalition Rehearing Request at 3; PacifiCorp Rehearing Request at 16.

126

Revised Early Adopters Coalition Rehearing Request at 4; PacifiCorp Rehearing Request at 16. Revised Early Adopters Coalition note that the initial cluster request window under Order No. 2023 would open “after the conclusion of the transition process set out in Section 5.1 of this LGIP.” Revised Early Adopters Coalition Rehearing Request at 3-4 (citing Order No. 2023, 184 FERC ¶ 61,054 at app. C,

pro forma

LGIP section 3.4.1).

127

Revised Early Adopters Coalition Rehearing Request at 4, 7; PacifiCorp Rehearing Request at 16 (both citing Order No. 2023, 184 FERC ¶ 61,054 at P 861).

67. Revised Early Adopters Coalition and PacifiCorp state that Order No. 2023 also appears to require early adopters to undertake an initial cluster request window prior to completion of cluster studies and/or restudies currently underway.

128

Revised Early Adopters Coalition and PacifiCorp argue that this would be an unexplained departure from prior precedent and the Commission's own statements in Order No. 2023.

129

Revised Early Adopters Coalition and PacifiCorp assert that this will also interfere with the timely completion of current cluster studies because it will divert already strained resources to preparing for and implementing Order No. 2023's new provisions. Revised Early Adopters Coalition and PacifiCorp further argue that this will put early adopters in the difficult, if not impossible, situation of having to undertake new cluster studies under Order No. 2023 that are reliant on outcomes of existing, not-yet-completed, cluster studies.

128

Revised Early Adopters Coalition Rehearing Request at 6; PacifiCorp Rehearing Request at 18.

129

Revised Early Adopters Coalition Rehearing Request at 2, 6; PacifiCorp Rehearing Request at 18 (both citing, for example,

Panhandle E. Pipe Line Co.

FERC,

196 F.3d 1273, 1275 (D.C. Cir. 1999) (

Panhandle

) (“if [FERC] wishes to depart from its prior policies, it must explain the reasons for its departure.”)).

68. Revised Early Adopters Coalition and PacifiCorp ask the Commission to clarify that early adopters of similar interconnection reforms, to the extent they do not seek or are not granted variances for their existing interconnection reforms, may conclude their pending/existing studies before transition to the new Order No. 2023 process.

130

Revised Early Adopters Coalition and PacifiCorp alternatively request that the Commission grant rehearing to permit such study flexibility for those transmission providers who have already adopted similar reforms to Order No. 2023. PacifiCorp argues that, without this flexibility, new cluster studies pursuant to Order No. 2023 may not be reliable as they will need to rely upon

assumptions, including “higher priority requests” that were studied in prior interconnection studies and assumed to be in service.

131

PacifiCorp emphasizes that this flexibility is imperative, given the size of its queue—326 active interconnection requests, accounting for over 59 gigawatts of requests.

130

Revised Early Adopters Coalition Rehearing Request at 2; PacifiCorp Rehearing Request at 15.

131

PacifiCorp Rehearing Request at 19.

69. Revised Early Adopters Coalition and PacifiCorp further assert that Order No. 2023 puts early adopters of interconnection reforms in a uniquely disadvantaged position of having to simultaneously administer two types of interconnection processes and, as a result, potentially expose them to greater likelihood of penalties than other transmission providers.

132

Revised Early Adopters Coalition asserts that exposing early adopters to such outsized risks would be arbitrary and capricious as well as discriminatory.

133

132

Id.;

Revised Early Adopters Coalition Rehearing Request at 2-3, 6 (citing 5 U.S.C. 706(2)(A);

Motor Vehicle Mfrs. Ass'n of the U.S., Inc.

State Farm Mut. Auto. Ins. Co.,

463 U.S. 29, 43 (1983) (

Motor Vehicle Manufacturers

) (explaining that to survive review under the arbitrary and capricious standard, an agency must examine the relevant data and articulate a satisfactory explanation for its action including a rational connection between the facts found and the choice made.') (internal citations omitted)).

133

Revised Early Adopters Coalition Rehearing Request at 6.

70. Revised Early Adopters Coalition and PacifiCorp explain that, if permitted the flexibility above, any transmission provider that currently has one or more ongoing cluster studies pursuant to its Commission-accepted cluster study processes, and who has not sought and received a variance, would commence new cluster studies only after all pending interconnection request cluster studies (or restudies) have concluded and only under updated tariff provisions that are consistent with or superior to Order No. 2023.

134

Revised Early Adopters Coalition and PacifiCorp state that allowing such providers to conclude their existing cluster studies before transition to the new

pro forma

study approach will preserve the interests of current interconnection customers that have been participating in the existing cluster study process as well as ease the administrative burden for such transmission providers.

134

Id.

at 6-7; PacifiCorp Rehearing Request at 19-20.

71. Revised Early Adopters Coalition and PacifiCorp also request, in the alternative, that the Commission allow early adopters to use a transition process similar to other transmission providers, if such a process better suits their needs and facilitates expedient queue processing.

135

Revised Early Adopters Coalition and PacifiCorp request that, either through clarification or rehearing, the Commission ensure that early adopters have the flexibility to choose either Order No. 2023's transition process or the ability to implement Order No 2023's reforms after completing any existing cluster studies and restudies.

135

Revised Early Adopters Coalition Rehearing Request at 7; PacifiCorp Rehearing Request at 20.

72. WIRES argues that Order No. 2023 also includes new requirements that need clarification or further consideration by the Commission.

136

WIRES states that it generally agrees that the shift from a serial study process to a cluster study process is likely to result in greater efficiency and provide more certainty but argues that the Commission has not explained how this new requirement will sync up with ongoing efforts that are already under way. WIRES requests that the Commission clarify how it plans to accommodate those ongoing efforts.

136

WIRES Rehearing Request at 12.

3. Determination

73. We clarify that all transmission providers, including those with existing cluster study processes, have a compliance obligation to review and modify their current

pro forma

interconnection procedures and

pro forma

interconnection agreements to comply with Order No. 2023. However, we continue to find that transmission providers that have already adopted a cluster study process or are currently undergoing a transition to a cluster study process will not be required to implement the transition process laid out in Order No. 2023,

137

and thus further clarify that such transmission providers are not required to file

pro forma

LGIP section 5 (Procedures for Interconnection Requests Submitted Prior to Effective Date of the Cluster Study) and the related appendices in their compliance filings.

137

Order No. 2023, 184 FERC ¶ 61,054 at P 861.

74. However, in response to the arguments raised by Revised Early Adopters Coalition and PacifiCorp, we note that Order No. 2023 does not prohibit such transmission providers from adopting the transition process established in Order No. 2023. Therefore, a transmission provider that does not seek or is not granted a variance for its existing cluster study process and adopts the reforms in Order No. 2023 would be able to use the Order No. 2023 transition process. Where transmission providers propose variations to the Order No. 2023 transition process, the Commission will evaluate such proposals under the consistent with or superior to standard for non-RTO transmission providers and the independent entity variation standard for RTOs/ISOs. A transmission provider currently conducting a cluster study process that does not propose to conduct an Order No. 2023 transition process must comply with the remaining requirements of Order No. 2023 other than the transition process.

75. We further grant clarification in response to requests seeking to clarify the applicability of the Order No. 2023 readiness requirements to a transmission provider currently conducting a cluster study process. On compliance, unless it proposes a variation, such a transmission provider must adopt the Order No. 2023 readiness requirements;

138

those new readiness requirements are then to be applied based on the interconnection customer's progress in the queue as of 60 calendar days after the Commission-approved effective date of the transmission provider's compliance filing. Within 60 calendar days of the Commission-approved effective date of the transmission provider's Order No. 2023 compliance filing, interconnection customers that have not executed an LGIA or requested an LGIA to be filed unexecuted with the Commission must meet the transmission provider's new readiness requirements for the relevant study phase, such as updating their respective study deposits, providing commercial readiness deposits correlating to the amounts required at the various stages of the process, and demonstrating site control. Interconnection customers that must meet the transmission provider's new readiness requirements may withdraw within the 60 days after the Commission-approved effective date of the transmission provider's Order No. 2023 compliance filing without being subject to Order No. 2023 withdrawal penalties. If the interconnection customer chooses to withdraw outside this 60-day timeline, the interconnection customer will be subject to the new withdrawal penalties. To reflect these clarifications, we set aside Order No. 2023, in part, and add new section 5.1.2 to the

pro forma

LGIP.

139

138

Id.

PP 490-813.

139

New

pro forma

LGIP section 5.1.2 (Transmission Providers with Existing Cluster Study Processes or Currently in Transition) states that if Transmission Provider is not conducting a transition process under Section 5.1.1, it will continue processing interconnection requests under its current Cluster Study Process. Within 60

calendar days of the Commission-approved effective date of Transmission Provider's Order No. 2023 compliance filing, Interconnection Customers that have not executed an LGIA or requested an LGIA to be filed unexecuted must meet the requirements of Sections 3.4.2, 7.5, or 8.1 of this LGIP, based on Interconnection Customer's Queue Position. Any Interconnection Customer that fails to meet these requirements within 60 calendar days of the Commission-approved effective date of this LGIP shall have its Interconnection Request deemed withdrawn by Transmission Provider pursuant to Section 3.7 of this LGIP. In such case, Transmission Provider shall not assess the Interconnection Customer any Withdrawal Penalty.

76. In response to NV Energy, we clarify that the requirement to meet the new site control requirements also requires that a queued interconnection customer, whether in a current cluster study or with an executed facilities study agreement (but not an interconnection customer with an executed LGIA or that has requested an LGIA to be filed unexecuted with the Commission), that is facing regulatory limitations must also submit the applicable deposit and information regarding the specific limitation within 60 days after the Commission-approved effective date of the transmission provider's compliance filing. An interconnection customer that withdraws within the 60-day period instead of submitting the applicable deposit and information will not be subject to Order No. 2023 withdrawal penalties.

77. We agree with EEI that transmission providers need only re-file and seek approval for previously approved variations where those provisions are modified by Order No. 2023. As the Commission explained in Order No. 2023, the Commission adopted requirements that are part of the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA and the Commission therefore only addressed the interaction of the requirements adopted with existing requirements that are part of the

pro forma

process and not variations thereto.

140

Transmission providers may seek variations from Order No. 2023's requirements on compliance provided the reason for the variation is sufficiently justified.

141

Transmission providers may also continue to propose interconnection process enhancements beyond Order No. 2023 through a separate filing under FPA section 205.

140

Order No. 2023, 184 FERC ¶ 61,054 at P 1530.

141

Id.

P 1767.

78. We reject requests to presume that any transmission provider's tariff meets the requirements of Order No. 2023.

142

As explained above, while the majority of reforms adopted herein are based on individual and incremental improvements that one or more regions have already implemented, no transmission provider has yet to adopt the entirety of Order No. 2023's broad suite of reforms.

143

Thus, we are unpersuaded by PJM's arguments on rehearing that ongoing, recently approved interconnection queue reform packages presumably already comply with Order No. 2023. Applying a presumption to transmission providers who recently adopted some similar reforms, but not all the reforms contained herein, will only result in incomplete change that fails to fulfill or further delays the comprehensive reform required by Order No. 2023. Additionally, because the Commission continues to find that the record supports a generic rulemaking,

144

the Commission reiterates that it did not need to make a finding specific to each transmission provider's tariff to require compliance with Order No. 2023.

145

Therefore, we also remain unpersuaded by Dominion's arguments on rehearing to defer the tariff modifications of, or to not require compliance filings from, transmission providers that have already transitioned or are in the process of transitioning to a cluster study process or to defer those entities' obligations to modify their tariffs.

142

Id.

P 1765.

143

Id.

P 59.

144

Order No. 2023, 184 FERC ¶ 61,054 at P 1766;

supra

section II.A.3.

145

See

Order No. 2023, 184 FERC ¶ 61,054 at P 1766 (citing

TAPS,

225 F.3d at 687-88).

79. In response to requests for clarification regarding how the Commission will review the compliance filings of entities that already adopted reforms, we continue to find, consistent with the Commission's statements in Order No. 2023, that transmission providers may explain specific circumstances on compliance and justify why any deviations from the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA are either consistent with or superior to the reforms adopted in Order No. 2023 for non-RTO transmission providers or merit an independent entity variation for RTOs/ISOs.

146

An item-by-item justification must be offered for each variation from the

pro forma

provisions modified in Order No. 2023; general statements alone are insufficient under the consistent with or superior to or the independent entity variation standard. Region-specific concerns like those raised by PJM and Dominion are appropriately addressed on compliance where the Commission will review the compliance filings on a case-by-case basis.

146

Id.

PP 1764-1765.

C. Reforms To Implement a First-Ready, First-Served Cluster Study Process

1. Public Interconnection Information

a. Order No. 2023 Requirements

80. In Order No. 2023, the Commission adopted section 6.1 (Publicly Posted Interconnection Information) of the

pro forma

LGIP 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 is produced in response to user-specified input about their prospective generating facility.

147

The table will 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 required transmission providers to post on their public website a heatmap of estimated incremental injection capacity (in MW) available at each point of interconnection to the whole transmission provider's footprint under N-1 conditions, as well as provide a table of results in response to a specific user's input showing the estimated impact of the addition of the 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 required that heatmaps be calculated under N-1 conditions and studied based on the power flow model of the transmission system used in the most recent cluster study or restudy, and 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). The Commission required transmission providers to

update their heatmaps within 30 calendars days after the completion of each cluster study and cluster restudy. Further, the Commission clarified that transmission providers are not required to make their heatmaps available until after their transition period.

148

147

Id.

P 135.

148

Id.

P 141.

b. Requests for Rehearing and Clarification

81. Clean Energy Associations ask the Commission to clarify that transmission providers may use ERIS or NRIS assumptions for their heatmaps, as appropriate for their particular region.

149

Clean Energy Associations argue that the requirement to use only NRIS assumptions fails to account for regional differences and could reduce the value of providing a heatmap. For example, Clean Energy Associations assert that in SPP and MISO, ERIS is the primary driver of determining network upgrades for new generation. If the Commission declines to grant clarification, Clean Energy Associations seek rehearing of the requirement to use NRIS assumptions for heatmaps.

149

Clean Energy Associations Rehearing Request at 48-49.

82. Non-RTO Providers request rehearing and modification of Order No. 2023's requirement that non-RTO/ISO transmission providers develop interactive heatmap websites.

150

Non-RTO Providers assert that the mandate is arbitrary and capricious and contrary to reasoned decision-making. Non-RTO Providers state that the Commission did not perform an adequate cost-benefit analysis to weigh the high cost and administrative burden on non-RTO transmission providers against the “limited and speculative benefits” of the heatmaps for non-RTO/ISO interconnection customers.

151

Non-RTO Providers assert that the mandate will require the 37 non-RTO/ISO regions

152

to each develop separate heatmap websites. Non-RTO Providers estimate that the cumulative upfront cost for these 37 heatmap websites is $7.4 million, and that the cumulative annual maintenance cost for the 37 heatmap websites is $666,000. Non-RTO Providers assert that the heatmaps will require regular attention from interconnection engineers who will otherwise be focused on transitioning to cluster studies. Non-RTO Providers contend that the heatmap requirement amounts to a penalty on non-RTO/ISO transmission providers, who cannot socialize the costs as broadly as RTOs/ISOs can.

153

Non-RTO Providers request that the Commission reverse the mandate on rehearing and (1) issue a modified version of section 6.1 of the

pro forma

LGIP for non-RTO regions that allows static public information postings of interconnection capacity based on cluster study results and (2) adopt a voluntary approach for the potential development and maintenance of interactive heatmaps in non-RTO regions.

150

Non-RTO Providers Rehearing Request at 1-2.

151

Id.

at 3.

152

Non-RTO Providers arrive at this number by subtracting the RTOs/ISOs from the 44 transmission providers estimated to be required to comply with Order No. 2023.

Id.

n.6.

153

Id.

at 4.

83. Non-RTO Providers note that the heatmap concept is a novel concept and that transmission providers have no special expertise in website development.

154

Non-RTO Providers contend that the legal question on rehearing is whether the benefits of a proposed reform can reasonably be said to outweigh the costs and assert that the Commission did not provide sufficient legal foundation under FPA section 206 to justify the mandate. Non-RTO Providers aver that the Commission did not acknowledge that interactive websites make financial sense only when done at scale. Therefore, Non-RTO Providers agree that the costs of the requirement are justified for RTO/ISO regions, which would require seven websites to serve approximately two-thirds of the nation's transmission system, but not for non-RTO/ISO regions, which would have to develop 37 websites to serve the remaining one-third of the transmission system. Non-RTO Providers explain that the Commission appears to prohibit non-RTO/ISO regions from developing joint, regional heatmaps to reduce the number of websites needed, which they claim demonstrates that the cost burden and administrative burden on engineering staff to non-RTO/ISO regions was not adequately considered.

155

154

Id.

at 4-5.

155

Id.

at 5-6.

84. Non-RTO Providers contend that the Commission wrongly relies on Clean Energy Associations' proposition that the heatmaps will be automated to conclude that engineering resources will not be strained by the heatmap requirement.

156

Non-RTO Providers state that such updates will require one or two full-time employees to prepare data for the first three weeks of a given 30-day update period and send the updated data to the vendor during the last week. Non-RTO Providers contend that the N-1 conditions reflected by the heatmap will offer no practical value to prospective interconnection customers but will result in five times as many engineering staff in non-RTOs/ISOs making heatmap updates compared to those in RTOs/ISOs.

157

Non-RTO Providers contend that the Commission did not adequately address these discrepancies in arguing that non-RTOs/ISOs have the technical capacity to create heatmaps.

156

Id.

at 6 (citing Order No. 2023, 184 FERC ¶ 61,054 at P 89).

157

Id.

at 6-7.

85. Further, Non-RTO Providers argue that the record does not demonstrate that the incremental rate increase to non-RTO/ISO regions from the heatmaps will be justified by meaningful overall queue efficiency improvements for non-RTO/ISO customers in the long run.

158

For example, Non-RTO Providers contend that the Commission failed to consider that heatmaps could increase speculative interconnection requests if many interconnection customers seek to interconnect at the same uncongested points reflected by the heatmap. For the above reasons, Non-RTO Providers argue that the connection between improving queue efficiency and benefits to transmission customers is too tenuous to support a FPA section 206 finding that the heatmap mandate is just and reasonable for non-RTO transmission providers.

159

158

Id.

at 8.

159

Id.

at 9.

86. Non-RTO Providers claim that the Commission erred by failing to consider a non-interactive website alternative for the public information posting mandate in non-RTO regions.

160

Non-RTO Providers state that the Commission never explains why such information needs to be provided in an interactive heatmap format, rather than in static public information postings regarding system conditions after each cluster study or restudy.

160

Id.

87. In the alternative to granting rehearing, Non-RTO Providers propose that the Commission revise section 6.1 of the

pro forma

LGIP to allow static data postings and adopt a voluntary funding approach for heatmap development in non-RTO Regions.

161

In particular, Non-RTO Providers state that they are not opposed to providing increased public access to base case data after cluster studies have been performed that shows the estimated incremental injection capacity (in megawatts) available at each bus in the transmission provider's footprint under N-1 conditions in table format. Non-RTO Providers explain that data in this format could still be uniform and

standardized to the Commission's specifications.

162

Non-RTO Providers state that with the voluntary funding approach, website developers aligned with any of the relevant stakeholders, including transmission providers and prospective interconnection customers and even the Commission itself, would be free to develop their own voluntary interactive heatmaps based on this publicly available data.

161

Id.

at 10.

162

Id.

at 11.

88. NV Energy requests clarification on (1) whether the heatmap must include proposed network upgrades with capacity amounts to reflect the available transfer capacity or only the existing facilities and (2) when a heatmap must be made available and posted to OASIS by transmission providers that do not conduct a new transition period.

163

NV Energy asserts that, presently, the heatmap will provide limited value and will be consistently red

164

because interconnection requests greatly exceed the available capacity or load.

165

NV Energy asks if the heatmap requirement for transmission providers already conducting cluster studies could be implemented at the same time as study penalties (after the third cluster study cycle/three years), which would allow transmission providers to issue requests for proposals for the necessary heatmap software for implementation and would allow suspended projects to withdraw as well as remove from the queue those that fail to (1) submit complete applications, (2) meet various deadlines, and (3) reach commercial readiness.

163

NV Energy Rehearing Request at 4.

164

An “all red” heatmap would indicate no available interconnection capacity.

See

Order No. 2023, 184 FERC ¶ 61,054 at P 157.

165

NV Energy Rehearing Request at 4.

89. PacifiCorp likewise seeks clarification on when transmission providers will be required to submit heatmaps for those transmission providers that do not conduct a transition cluster study process because the Commission is not requiring transmission providers to submit heatmaps until

after

the transition period ends.

166

PacifiCorp Rehearing Request at 22-23 (citing Order No. 2023, 184 FERC ¶ 61,054 at P 141).

90. Public Interest Organizations assert that the Commission erred by not providing an adequate method for prospective interconnection customers to obtain information about potential interconnection costs at a specific location prior to submitting an interconnection request, and that the limited information publicly available to interconnection customers will lead to unjust, unreasonable, unduly discriminatory, and preferential rates.

167

Public Interest Organizations also note that the level of cost uncertainty for different interconnection customers is not balanced because transmission owner affiliates, particularly in non-RTO/ISO regions, have greater access to interconnection cost information relative to independent power producers. Public Interest Organizations contend that the Commission's decision to not adopt the proposed informational studies and optional solicitation studies make Order No. 2023's adopted reforms insufficient to remedy its finding that the

pro forma

interconnection procedures “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.”

168

Public Interest Organizations explain that both the informational studies and optional solicitation studies were specifically intended to provide additional cost information to prospective interconnection customers, while the public access information requirement was intended to provide high-level information to assist interconnection customers with comparing multiple points of interconnection and estimate congestion.

169

167

Public Interest Organizations Rehearing Request at 7.

168

Id.

at 8 (citing Order No. 2023, 184 FERC ¶ 61,054 at PP 46, 152).

169

Id.

(citing Order No. 2023, 184 FERC ¶ 61,054 at P 68).

91. Public Interest Organizations state that many parties suggested that the Commission add more data to the heatmap to provide information for interconnection customers to readily identify network upgrades, which would help them estimate the costs to interconnect their project before they join the interconnection queue.

170

Public Interest Organizations note, for example, that NextEra suggested including information on the circuit and ratings of equipment, and Public Interest Organizations argued that the heatmaps should include information on the number of megawatts that could be interconnected without substantial costs, among other suggestions. Public Interest Organizations argue that, without such additional data, interconnection customers continue to bear the burden of determining potential costs, and that not all interconnection customers possess the resources to use software or hire consultants to extract meaningful data from the heatmaps. Public Interest Organizations contend that the heatmap requirement ultimately falls short of providing a reasonable method for interconnection customers to predict potential network upgrade costs prior to entering the queue, leading interconnection customers to make the “rational” decision to submit multiple interconnection requests to obtain information, which contributes to study delays and withdrawals. For these reasons, Public Interest Organizations request the Commission revisit the record to evaluate and adopt requirements that transmission providers must also make available the additional data that will allow all customers to estimate the potential network upgrade costs using reasonable efforts.

170

Id.

at 9-10.

92. Public Interest Organizations further assert that the Commission's decision not to require more information be made publicly available to potential interconnection customers is arbitrary and capricious, contrary to the weight of the comments and record, and not based on substantial evidence.

171

Public Interest Organizations argue that the Commission's finding that adding any additional data requirements to assist interconnection customers is outweighed by the potential burden to transmission providers failed to consider countervailing evidence of the benefits of additional data. Public Interest Organizations assert that the benefits of providing cost information prior to interconnection customers submitting an interconnection request is clear: fewer speculative interconnection requests and therefore less backlogged queues. However, Public Interest Organizations contend that MISO's heatmap demonstrates that a heatmap alone is not enough. Public Interest Organizations also argue that the marginal burden on transmission providers to provide additional heatmap data is minimal as they can take advantage of automation.

171

Id.

at 10-12.

93. PJM seeks rehearing of Order No. 2023's blanket requirement to update the heatmap 30 calendar days after completion of each cluster study because PJM states that it is unreasonable for such a large, multi-state RTO like PJM with hundreds of expected interconnection requests in each cluster.

172

PJM states that publishing study results to its interconnection screening tool, queue scope, requires detailed, precise analysis using the latest inputs available at the time and would hold PJM to an unrealistically strict and expedited

schedule of updating data, tools, simulations, and results, and the fact that such publishing would be necessary several times a year is burdensome and adds to the scope of study work required, taking resources away from other processing efforts. PJM instead anticipates annually published studies. PJM also states that “the models” are already made available to interconnection customers via a Critical Energy Infrastructure Information (CEII) request and can provide information about points of interconnection.

172

PJM Rehearing Request at 23-24.

94. PJM requests rehearing of Order No. 2023's clarification in P 162, which it interprets as stating that transmission providers must absorb heatmap costs but are not barred from seeking recovery of them through their transmission rates (and paid by interconnection customers).

173

PJM states that interconnection customers, rather than transmission providers or transmission customers, benefit from heatmap posting, so there is no good reason that transmission providers must always charge the costs of maintaining and posting heatmaps to transmission service customers rather than considering other structures such as fees for prospective developers not yet in the queue. PJM states that this rule departs from the Commission's and judicial cost-causation principles, requiring that costs should be paid by those who benefit from their incurrence,

174

and it does so (by assigning heatmap costs to transmission providers or transmission customers) without explanation, presents free-ridership issues, and would be arbitrary and capricious.

175

PJM asserts that not granting rehearing of this item would set a precedent that transmission providers must absorb or pass on to transmission customers costs that are caused by or that benefit interconnection customers only.

173

Id.

at 42-43.

174

Id.

at 43 (citing

Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils.,

Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132 at P 578). PJM includes an excerpt from Commissioner Christie's concurrence to Order No. 2023, which states, “Commission policy may dictate that interconnection queue efficiency benefits transmission customers; however, that should not result in the costs of a requirement that best benefits interconnection customers, and really prospective interconnection customers that may ultimately not seek to interconnect, being recovered from consumers through transmission rates carte blanche. The Commission simply cannot ask retail consumers to foot the bill for every single “efficiency,” especially where many of these “efficiencies” largely benefit generation developers and then get folded into transmission rates and receive an ROE.” Order No. 2023, concur op. (Comm'r Christie) at P 22.

175

PJM Rehearing Request at 43-44 (citing

Motor Vehicle Manufacturers,

463 U.S. at 57;

Sw. Airlines Co.

FERC,

926 F.3d 851, 858 (D.C. Cir. 2019);

Panhandle,

196 F.3d at 1275).

c. Determination

95. We deny Clean Energy Associations' request for the Commission to clarify that transmission providers may use ERIS or NRIS assumptions for their public heatmaps. As the Commission explained in Order No. 2023, generating facilities seeking NRIS are generally subject to more stringent study requirements.

176

Therefore, requiring transmission providers to produce heatmap results that approximate NRIS assumptions will provide actionable information on the viability of a given proposed generating facility to both ERIS and NRIS customers. On the other hand, requiring heatmaps to approximate ERIS assumptions would not be helpful to NRIS customers. Even in regions where ERIS may be more commonly selected or lead to a greater number of network upgrades, we find that the use of stricter NRIS assumptions would more consistently alert prospective interconnection customers to the possibility of required network upgrades compared to ERIS assumptions. We therefore find that using NRIS assumptions as a baseline would prevent false negatives, in which the heatmap incorrectly indicates to prospective interconnection customers that their projects would not trigger network upgrades. This finding reasonably balances the resources required of transmission providers in making heatmaps available with the value of providing non-binding system impact information to all prospective interconnection customers ahead of entering the interconnection queue. We note, however, that Order No. 2023 states that “if transmission providers find value in providing additional or different information [than required by Order No. 2023], they may propose such variations on compliance.”

177

Therefore, if a transmission provider believes that it would be informative to interconnection customers, it may propose on compliance an option for heatmap users to view results using ERIS assumptions in addition to NRIS assumptions. As such, we reiterate that “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).”

178

For the same reasons noted above, we are unpersuaded by the arguments raised in Clean Energy Associations' alternative request for rehearing.

176

Order No. 2023, 184 FERC ¶ 61,054 at P 148.

177

Id.

P 156.

178

Id.

P 135.

96. We are also unpersuaded by Non-RTO Providers' argument that the Commission failed to properly evaluate the costs and benefits of the heatmap requirement for non-RTO/ISO regions and that they cannot socialize the costs as broadly as RTOs/ISOs. First, without a comparison to estimated heatmap costs for RTO/ISO regions, Non-RTO Providers' cost estimates do not support its assertion that the cost of developing interactive heatmaps is more burdensome for non-RTO/ISO regions.

179

While RTO/ISO regions do have larger customer bases from which to recover costs, their heatmaps will also reflect larger and potentially more complex power systems and need to accommodate a larger pool of users and, therefore, may cost more.

179

See, e.g., Ill. Commerce Comm'n

FERC,

721 F.3d 764, 775 (7th Cir. 2013) (stating that not all benefits can be calculated in advance, and if FERC cannot quantify the benefits to a particular utility or utilities but “has an articulable and plausible reason to believe that the benefits are at least roughly commensurate with those utilities' total electricity sales in [the] region,” then the Commission can approve the pricing scheme on that basis) (internal citations omitted).

97. We further disagree that the labor requirements Non-RTO Providers refer to will be overly burdensome relative to RTO/ISO regions. First, as the Commission clarified in Order No. 2023, transmission providers are not required to update their heatmaps on a rolling 30-day basis, but rather within 30 days of the completion of a cluster study or restudy.

180

Thus, transmission providers will likely update their heatmaps at most two times per year, accounting for one cluster study and one cluster restudy.

180

Order No. 2023, 184 FERC ¶ 61,054 at P 141.

98. Second, to Non-RTO Providers' argument that annual heatmap maintenance would divert attention from interconnection engineers who would otherwise be focused on transitioning to cluster studies, we reiterate that transmission providers are not required to make heatmaps available until

after

their transition period, which will help ensure that transmission providers' implementation of this final rule, beginning with the transition period, has begun to reduce backlogged interconnection queues.

99. Third, Non-RTO Providers' cost estimates are based on an extrapolation of one transmission provider's initial estimate, and Non-RTO Providers do not describe any assumptions of this estimate beyond the assertion that, after each cluster study or restudy, it would take two full-time engineers several weeks to “prepare the data” before having a vendor update the heatmap.

181

We are unpersuaded by this assertion because, as Order No. 2023 states, transmission providers must use the results of their most recent cluster study or restudy to update the heatmap.

182

Therefore, to update their heatmaps, little additional analysis should be required beyond what transmission providers have already completed for their cluster studies and restudies. We recognize that engineering labor will likely be required during heatmap website development, either directly, in developing the software and processes, or in consultation with the firm developing the heatmap. However, we believe that it is feasible for transmission providers, or their heatmap developers, to develop their heatmap websites to accept their base case files as inputs for each update such that little to no modification of the base case files and data is necessary. To that point, and Non-RTO Providers' concern that transmission providers have no special expertise in website development, we note that Order No. 2023 does not require transmission providers themselves to develop the requisite software and processes, and they may contract with firms whose expertise includes website development and data management. Further, Order No. 2023 does not preclude transmission providers from proposing on compliance to develop joint, regional heatmaps.

181

Non-RTO Providers Rehearing Request at 6.

182

Order No. 2023, 184 FERC ¶ 61,054 at PP 139-140.

100. Finally, we disagree that Non-RTO Providers' proposal to require that transmission providers post only static data and allow other entities to voluntarily develop heatmaps accomplishes the goals outlined in Order No. 2023. The purpose of the heatmap requirement is, in part, to provide comparable information to all interconnection customers, prior to entering the queue, regardless of the transmission provider. Non-RTO Providers' proposal would not ensure such comparability, but rather would favor interconnection customers that have more resources to devote towards modeling and favor some transmission providers' own proposed generation. Thus, interconnection customers that cannot afford to process the static data Non-RTO Providers propose to post would still need to submit speculative interconnection requests to obtain information. Further, the voluntary funding approach Non-RTO Providers propose would not ensure that non-RTO/ISO regions have public interconnection information available and therefore would discriminate against interconnection customers seeking to interconnect outside of RTO/ISO regions.

101. In response to NV Energy's request for clarification on whether heatmaps must include proposed network upgrades or only existing facilities, we reiterate that heatmaps must be based on the power flow model and base case assumptions used in the most recent cluster study or restudy. Therefore, heatmaps will incorporate in-service network upgrades and network upgrades proposed for clusters higher queued than the most recent cluster study or restudy, as the base case and power flow models for any cluster will include proposed network upgrades for higher queued clusters.

102. We agree with NV Energy and PacifiCorp on the need for clarification regarding when heatmaps must be made available by transmission providers that do not conduct transition processes. We therefore clarify that transmission providers that do not conduct transition periods do not need to make their heatmap available until 360 calendar days after the Commission-approved effective date of the transmission provider's Order No. 2023 compliance filing. This timeline will give transmission providers that do not conduct transition periods the same amount of time as transitioning transmission providers (

i.e.,

completion of the transitional cluster study within 360 days after the Commission-approved effective date of the compliance filing) to develop their heatmaps. Further, while we agree that heatmaps for some transmission providers may initially appear as all red, which indicates no available interconnection capacity, we reiterate our finding that an all red heatmap still “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.”

183

We are therefore unpersuaded that such a result necessitates delaying the posting of the interactive heatmap.

183

Id.

P 157.

103. We are also unpersuaded by NV Energy's request for clarification that transmission providers that do not conduct transition processes because they already use cluster studies should be required to post publicly available heatmaps only after three cluster cycles, similar to the transition to study delay penalties. This would delay transmission providers already using cluster studies, and their potential interconnection customers, from realizing the benefits of a heatmap (

e.g.,

a reduced volume of speculative interconnection requests) for more than twice as long as those transmission providers who do conduct a transition process and their potential interconnection customers.

104. We are unpersuaded by Public Interest Organizations' assertion that the Commission erred in not requiring transmission providers to include additional data in their heatmaps that would assist interconnection customers in estimating interconnection costs at potential points of interconnection. We further disagree with Public Interest Organizations' contention that the Commission did not fully consider the record on this matter in coming to its decision. On the contrary, as numerous commenters explain—and as the Commission stated in Order No. 2023—cost estimates produced prior to an interconnection customer entering the queue would be highly uncertain and subject to a high degree of change depending on the actions of other interconnection customers in the queue and study results, and therefore would provide little to no value to interconnection customers in terms of improving cost certainty.

184

We believe this to be true regardless of whether the transmission provider or the interconnection customer produces those cost estimates. Further, Public Interest Organizations do not argue that cost estimates should be directly incorporated into transmission providers' heatmaps, but rather that transmission providers should include additional information in their heatmaps that would allow interconnection customers to ascertain information about potential costs at points of interconnection. At the same time, however, Public Interest Organizations argue that many interconnection customers lack the resources to develop cost estimates based on transmission providers' heatmaps. Thus, Public Interest Organizations' proposal would not only increase the burden on transmission providers but require interconnection

customers themselves to dedicate more resources towards developing cost estimates that are likely to change once they enter the queue. We therefore continue to find that the heatmap requirements set forth in Order No. 2023 strike a reasonable balance between the burden on transmission providers to develop and maintain heatmaps and the benefit of providing interconnection customers with sufficient information to identify viable points of interconnection, given that cost estimates produced prior to entering the queue would be unreliable. We note, however, that, consistent with the Commission's statements in Order No. 2023, 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.

185

184

See id.

P 138.

185

Id.

P 1764.

105. We are unpersuaded by PJM's request to modify the requirement for transmission providers to update their heatmaps within 30 calendar days of completing a cluster study or restudy. We find PJM's argument regarding its queue scope tool to be inapposite. As the Commission explained in Order No. 2023, because the heatmap should use the results of the most recent cluster study or restudy, the heatmap requirement should require minimal additional analysis beyond the cluster study or restudy and should not necessitate detailed analysis.

186

Transmission providers must simply make the data and assumptions used in the analyses they already completed available in a public, interactive form. Updating heatmaps within 30 calendar days of completion of a cluster study or restudy will also ensure that interconnection customers can use the heatmap during the customer engagement window to determine whether to proceed in the queue or withdraw. Finally, we disagree that interconnection customers' ability to request CEII achieves the same goal as the heatmap requirement. The heatmaps are intended to improve transparency and ease the burden of producing interconnection-related information for prospective interconnection customers. On the other hand, requests for CEII typically require an entity to submit certain identifying information and/or legal documents like non-disclosure agreements and require the transmission provider to review and verify such information, and weigh the need for the information against the potential harm of its release, before potentially granting access to a protected part of its website or OASIS portal.

187

Reliance on such a process would impose an unnecessary burden on the prospective interconnection customer, the transmission provider, and other interested stakeholders because, as commenters explain, the information to be published in transmission providers' heatmaps does not raise CEII concerns.

188

186

Id.

PP 139-140.

187

PJM's CEII request process, for example, includes all these process components.

See https://www.pjm.com/library/request-access.

188

Order No. 2023, 184 FERC ¶ 61,054 at P 144.

106. Further, we are unpersuaded by PJM's request to modify the finding in Order No. 2023 that transmission providers must bear the costs associated with their heatmaps or recover them through transmission rates to the extent they are recoverable consistent with Commission accounting and ratemaking policy. First, transmission providers already maintain interconnection information and other related information online for the purposes of transparency and facilitating participation amongst various stakeholders. Thus, we disagree with PJM's requested modification because transmission providers may recover the costs associated with heatmaps through transmission rates to the extent they are recoverable consistent with Commission accounting and ratemaking policy. Second, we disagree that interconnection customers are the sole or primary beneficiaries of the heatmap requirement, and that transmission providers themselves do not benefit from it. The heatmap requirement will reduce the number of speculative interconnection requests submitted to transmission providers by providing prospective interconnection customers with information to evaluate the viability of their potential interconnection requests, thus improving overall queue efficiency for the benefit of both transmission providers and prospective interconnection customers.

2. Cluster Study Process

a. Order No. 2023 Requirements

107. In Order No. 2023, the Commission revised the

pro forma

LGIP and

pro forma

LGIA to require transmission providers to study interconnection requests in clusters.

189

The Commission adopted numerous revisions to the

pro forma

LGIP and

pro forma

LGIA to effectuate this change. Specifically, and as relevant here, the Commission revised the definitions of material modification and stand alone network upgrades, and defined interconnection facilities study report.

190

The Commission adopted section 3.1.2 (Submission) of the

pro forma

LGIP to require an interconnection customer to select a definitive point of interconnection when executing the cluster study agreement.

191

The Commission adopted section 3.4.1 (Cluster Request Window), section 3.4.4 (Deficiencies in Interconnection Request), and section 3.4.5 (Customer Engagement Window) of the

pro forma

LGIP to provide a process for interconnection customers to submit a cluster study interconnection request.

192

The Commission adopted section 3.4.6 (Cluster Study Scoping Meetings) of the

pro forma

LGIP to require transmission providers to hold a scoping meeting with interconnection customers in the cluster.

193

The Commission revised section 3.5.2 (Requirement to Post Interconnection Study Metrics) of the

pro forma

LGIP to require transmission providers to post metrics for cluster study and restudy processing time.

194

189

Id.

P 177.

190

Id.

P 192.

191

Id.

P 200.

192

Id.

P 223.

193

Id.

P 245.

194

Id.

P 259.

108. The Commission adopted several revisions to the

pro forma

LGIP related to the process by which interconnection customers can make an interconnection request. The Commission revised section 4.1 (Queue Position) of the

pro forma

LGIP to provide that all interconnection requests within a cluster be considered equally queued and accordingly modified the definition of queue position.

195

The Commission renamed and revised section 4.2 (General Study Process) of the

pro forma

LGIP to require transmission providers to perform interconnection studies within the cluster study process.

196

The Commission revised section 4.4 (Modifications) of the

pro forma

LGIP to provide that moving a point of interconnection shall result in the loss of a queue position if it is deemed a material modification by the transmission provider.

197

The Commission also revised section 4.4.1 of the

pro forma

LGIP to incorporate the material modification process as part of the cluster study process.

198

The Commission revised section 4.4.5 of the

pro forma

LGIP to 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.

199

195

Id.

PP 277, 283.

196

Id.

P 278.

197

Id.

P 283.

198

Id.

P 285.

199

Id.

P 293.

109. The Commission adopted revisions to the

pro forma

LGIP to implement several cluster study provisions. The Commission replaced section 6 (Interconnection Feasibility Study) of the

pro forma

LGIP with the new public interconnection information requirements as discussed in section II.C.1 of Order No. 2023.

200

The Commission revised section 7 (Cluster Study) of the

pro forma

LGIP to set out the requirements and scope of the cluster study agreement, as well as the cluster study and restudy procedures.

201

The Commission revised section 7.4 (Cluster Study Procedures) of the

pro forma

LGIP to permit transmission providers to use subgroups in their cluster study process if they so choose.

202

The Commission revised section 8.5 (Restudy) of the

pro forma

LGIP to make clear that restudies can be triggered by the withdrawal or modification by a higher- or equally-queued interconnection requests.

203

The Commission revised sections 11.1 (Tender) and 11.3 (Execution and Filing) of the

pro forma

LGIP regarding the tendering, execution, and filing of the LGIA to incorporate the site control demonstrations and LGIA deposit requirements of Order No. 2023.

204

200

Id.

P 316.

201

Id.

P 317.

202

Id.

P 363.

203

Id.

P 335.

204

Id.

P 344.

b. Requests for Rehearing and Clarification

110. Clean Energy Associations contend that the Commission acted arbitrarily and capriciously and failed to engage in reasoned decision-making by changing the definition of stand alone network upgrades such that only “single customers” are eligible to build them.

205

Clean Energy Associations claim that, when considered with the shift to a cluster study process and other stated goals for the sharing of network upgrade costs amongst interconnection customers, the revised definition effectively forecloses the opportunity for any future interconnection customer to exercise their discretion to build stand alone network upgrades or identified transmission provider interconnection facilities. Additionally, Clean Energy Associations aver that the revisions ignore the relationship of the option to build to the project sponsor, nearly eliminating the benefits of the option to build, such as controlling project schedules.

206

Finally, Clean Energy Associations assert that the Commission's reasoning is based on a hypothetical situation which has not occurred since Order No. 845, or possibly ever.

205

Clean Energy Associations Rehearing Request at 8-9.

206

Id.

at 9-10.

111. Clean Energy Associations argue that the Commission's assertion that “confusion and potentially lengthy negotiations and/or disputes” would result without revisions to the definition of stand alone network upgrades is unsupported by the record of this proceeding.

207

Clean Energy Associations note that transmission providers already using cluster studies have operated for years under the Order No. 845 definition, demonstrating that the revisions were not necessary. Clean Energy Associations explain that Order No. 2023 neither cites previous instances of confusion or lengthy disputes regarding the construction of stand alone network upgrades, nor any other facts or evidence that would support a finding that the current definition is insufficient or inadequate. Clean Energy Associations also note that one transmission provider using cluster studies supported the concept of allowing stand alone network upgrades to be shared among interconnection customers.

208

207

Id.

at 10 (citing Order No. 2023, 184 FERC ¶ 61,054 at P 193).

208

Id.

at 11-12 (citing Order No. 2023, 184 FERC ¶ 61,054 at P 185).

112. Clean Energy Associations contend that this aspect of Order No. 2023 is arbitrary and capricious because the Commission fails to acknowledge or adequately explain departures from its precedent.

209

Clean Energy Associations note that Order No. 845 explains that the option to build benefits the interconnection process by giving interconnection customers more control and certainty, and that interconnection customers are in the best position to determine if the option to build in their interest. However, Clean Energy Associations assert that the revised definition removes interconnection customers' ability to exercise their discretion regarding the option to build for the majority of network upgrades identified in a cluster study, and modifies th

e status quo

by reducing the number of network upgrades that would qualify as stand alone network upgrades because the proportional impact method of cost allocation will reduce the likelihood of finding a single customer 100% responsible for a network upgrade.

210

Clean Energy Associations contend that this renders the Order No. 845 policy moot and is inconsistent with the Commission's intent in Order No. 2023 to maintain the status quo.

209

Id.

at 12-13.

210

Id.

at 13-14.

113. Clean Energy Associations state that the Commission can redress this error on rehearing by (1) reversing its decision to revise the definition of stand alone network upgrade, and (2) requiring transmission providers to address, in their compliance filings and OATTs, the process through which interconnection customers with shared network upgrades that qualify as stand alone network upgrades can exercise their option to build.

211

Alternatively, Clean Energy Associations suggest that the Commission require transmission providers to allow the interconnection customers amongst whom a stand alone network upgrade was shared to unanimously exercise the option to build and, then, to either select a third party to construct the upgrade or to determine responsibility for doing so amongst themselves. Clean Energy Associations assert that this would prevent the concern of disputes among interconnection customers within a cluster. Clean Energy Associations state that both of these options would be consistent with, and would preserve, the policy set forth in Order No. 845, while also addressing the Commission's concerns that disputes or confusion may arise and further delay the interconnection process, while striking an appropriate balance between the Commission's policy and efforts in Order No. 845 and Order No. 2023, honoring both efforts and further enhancing and benefiting the interconnection process.

211

Id.

at 14-15.

114. Clean Energy Associations state that the Commission erred in finding that modifications to project size can only be made during the customer engagement window and that interconnection customers must select a single, definitive point of interconnection at that time.

212

Clean Energy Associations assert that the record does not support the conclusion that the customer engagement window is sufficient for the interconnection customer to enter the cluster study with confidence in its project size and definitive point of interconnection and, thus, this timeline does not reflect an appropriate balance that will reduce the need for restudies and delays. Clean Energy Associations assert the

opposite—that the record indicates that failure to provide flexibility to interconnection customers to modify project size and point of interconnection after receipt of initial cluster study results will increase the likelihood of withdrawals and cascading restudies by not allowing interconnection customers to make beneficial adjustments earlier in the interconnection process that could be determinative in a project's decision to stay in the cluster or withdraw. Clean Energy Associations disagree with the Commission's conclusion that the extended 60 calendar day customer engagement window is sufficient to provide interconnection customers with “time to consider information collected during this period of engagement with the transmission provider,”

213

which will allow customers to determine when to withdraw their interconnection requests and avoid penalties while improving queue efficiency due to fewer late-stage cluster study withdrawals. Clean Energy Associations assert that, prior to the cluster study, it is difficult for an interconnection customer to make any informed conclusion about expected costs of potential network upgrades and such costs' impact on project viability, which the interconnection customer must learn from the cluster study.

212

Id.

at 15-16.

213

Id.

at 17-18 (citing Order No. 2023, 184 FERC ¶ 61,054 at P 233).

115. The 60-day customer engagement window, Clean Energy Associations assert, only provides interconnection customers 46 calendar days to evaluate publicly posted information and make any potential project modifications prior to entering the cluster study, and any such early-acquired information will be incomplete, lacking modeling data, new model sets, and other study assumptions such as confidential merit order dispatch lists used by transmission providers to set up power transfers from new generators, despite publicly posted information by transmission providers.

214

Clean Energy Associations state that substantial information gained through the study process may necessitate a change in point of interconnection, making choosing a single point of interconnection implausible. They claim that not requiring transmission owners to attend scoping meetings further limits an interconnection customer's access to information. Clean Energy Associations assert that an interconnection customer will not have sufficient time and information to evaluate project viability during the customer engagement window or modify project size and location in response to pre-study information obtained during that window.

214

Id.

at 18-19.

116. Clean Energy Associations assert that limiting post-initial cluster study entry modifications to the interconnection request to those the transmission provider deems not to be material ignores record evidence that this practice will not result in a more reliable, efficient, transparent, and timely interconnection process.

215

Clean Energy Associations assert that allowing flexibility in project size reductions through the initial cluster study will allow for optimization of projects based on official study results, resulting in fewer withdrawals due to increased project viability and contribution to reliability through reduced impacts to the transmission provider's system, which it asserts will be less disruptive to the interconnection process than a full withdrawal. Clean Energy Associations state that, likewise, inability to change the point of interconnection or to submit an alternate point of interconnection could cause delays and can trigger the restudy of an entire cluster. Clean Energy Associations assert that the record demonstrates that interconnection customers lack sufficient time or information to optimize project characteristics prior to entering the initial cluster study, and that flexibility to make beneficial modifications after receipt of initial study results would reduce rather than increase uncertainty, restudy, and administrative burden.

215

Id.

at 19-20.

117. Clean Energy Associations further state that the option to instead pursue a material modification exemption does not provide sufficient flexibility because: (1) it leaves this determination to the discretion of the transmission provider; and (2) it ignores that minor project modifications that could have slight impacts on other interconnection customers in the same cluster might nonetheless be far less disruptive than project withdrawal.

216

Clean Energy Associations argue that the material modification review is often based on “opaque assumptions” available only to the transmission provider and may divert resources at a relatively more intense part of the study process.

216

Id.

at 21-22.

118. Clean Energy Associations note that SPP, PJM, and MISO have adopted provisions allowing 50%-100% reduction allowance and minor point of interconnection changes, and also permit smaller size adjustments similar to that found in

pro forma

LGIP section 4.4.2 through the initial cluster restudy, which Clean Energy Associations state belie the Commission's assertion that the timing for modifications in Order No. 2023 reflects a natural translation of the timing for modification in the existing serial study process to a cluster study process.

217

Clean Energy Associations therefore request that the Commission grant rehearing and modify the language in revised

pro forma

LGIP section 4.4.1 to allow modifications to project size (specifically, up to a 60% size reduction) prior to entering the cluster restudy, and to allow minor modifications to project size (specifically, up to a 15% size reduction) after the receipt of a cluster restudy but prior to the start of the facilities study. Clean Energy Associations further request that the Commission grant rehearing and allow interconnection customers the option to present a primary and alternative definitive point of interconnection in an electrically proximate area, provided that the transmission provider and transmission owner verify the alternative as acceptable during the customer engagement window and prior to the scoping meeting.

217

Id.

at 22.

119. IPP Coalition also asks the Commission to reconsider its requirement that customers identify a single point of interconnection and, instead, allow for an electrically proximate alternative point of interconnection that is verified as acceptable by the transmission provider during the cluster study customer engagement window and listed in the cluster study agreement.

218

IPP Coalition asserts that electrically proximate point of interconnection locations can be effectively implemented within a study process without materially impacting a study process, and that this general standard should be applied consistently to a potential change, whether it is sought by an interconnection customer as part of the interconnection request or ultimately required on the basis of a public policy decision.

218

IPP Coalition Rehearing Request at 7-8.

120. Ørsted requests that the Commission clarify that, in circumstances where state or federal agency policy or regulation requires a change to the point of interconnection, projects should be restudied based upon the new regulatory or statutory requirements.

219

Alternatively, Ørsted requests that the Commission clarify that, in such circumstances, the transmission provider, the state, or the

interconnection customer may request a waiver of applicable tariff and LGIA/LGIP provisions that might be affected in order to comply with the federal or state regulatory requirement.

219

Ørsted Rehearing Request at 11.

121. Clean Energy Associations state that the Commission should grant rehearing and amend Order No. 2023 to stipulate that, if an interconnection customer submits an interconnection request at least 15 business days prior to the close of the cluster request window, and if failure by the transmission provider to issue a deficiency notice within five business days of receipt results in the interconnection customer having fewer than 10 business days to respond to the deficiency notice prior to the close of the customer request window, the interconnection customer shall still be granted a full 10 business days to respond prior to facing the consequences outlined in revised

pro forma

LGIP section 3.4.4.

220

Clean Energy Associations state that, to ensure a full 10 business days to respond, an interconnection customer would have to submit its interconnection request more than 15 business days before the close of the cluster request window to account for the five business day window for the transmission provider to issue a deficiency notice, and that even if an interconnection customer submitted its interconnection request more than 15 business days before the close of the cluster window, the interconnection customer may be left with fewer than 10 business days to provide a response in the event that the transmission provider failed to meet the five business day notification requirement. Clean Energy Associations state that, because of this oversight, an interconnection customer may, through no fault of its own, have as little as one day to respond to a deficiency notice. Clean Energy Associations argue that revised

pro forma

LGIP section 3.4.4 includes significant consequences for interconnection customers that fail to meet the 10 business-day deadline, but no consequences for transmission providers that fail to meet the five-business day deficiency notice deadline. Clean Energy Associations argue that the Commission acted arbitrarily and capriciously and failed to engage in reasoned decision-making by failing to account for potential delay on the part of the transmission provider.

220

Clean Energy Associations Rehearing Request at 25-26.

122. Clean Energy Associations and Ørsted argue that the Commission acted arbitrarily and capriciously and failed to engage in reasoned decision-making when it declined to require transmission owners to attend scoping meetings.

221

Clean Energy Associations and Ørsted state that requiring transmission owners to attend may help RTOs/ISOs address potential challenges sooner, avoiding penalties caused by transmission owner delays. Clean Energy Associations and Ørsted assert that the purpose of the customer engagement window is to provide interconnection customers with information to help them determine the viability of their proposed generating facilities earlier in the process, and without transmission owners in these meetings, interconnection customers are deprived of critical information necessary to determine the costs and commercial viability of their projects.

222

Ørsted additionally states that transmission owners are fully responsible for design of network upgrades, including both substation and system network upgrades, as well as play an important role in informing point of interconnection decisions by providing information about the existing grid conditions and capabilities as well as information related to interco

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