Improvements to Generator Interconnection Procedures and Agreements

Federal RegisterSep 6, 2023

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM22-14-000; Order No. 2023]

Improvements to Generator Interconnection Procedures and Agreements

AGENCY:

Federal Energy Regulatory Commission, Department of Energy.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission or FERC) is adopting reforms to its

pro forma

Large Generator Interconnection Procedures,

pro forma

Small Generator Interconnection Procedures,

pro forma

Large Generator Interconnection Agreement, and

pro forma

Small Generator Interconnection Agreement to address interconnection queue backlogs, improve certainty, and prevent undue discrimination for new technologies. The reforms are intended to ensure that the generator interconnection process is just, reasonable, and not unduly discriminatory or preferential.

DATES:

This final rule is effective November 6, 2023.

FOR FURTHER INFORMATION CONTACT:

Tristan Kessler (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6608,

tristan.kessler@ferc.gov.

Franklin Jackson (Technical Information), Office of Energy Market Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-6464,

franklin.jackson@ferc.gov.

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

sarah.greenberg@ferc.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Numbers

I. Introduction 1

A. Historical Framework: Order Nos. 2003, 2006, and 845 11.

B. Regional Transmission Planning and Cost Allocation and Generator Interconnection Advance Notice of Proposed Rulemaking 18

C. Notice of Proposed Rulemaking 20

D. Joint Federal-State Task Force on Electric Transmission 25

II. Overall Need for Reform 27

A. NOPR 27

B. Comments 30

C. Commission Determination 37

III. Reforms 61

A. Reforms To Implement a First-Ready, First-Served Cluster Study Process 61

1. Interconnection Information Access 61

2. Cluster Study Process 165

3. Allocation of Cluster Study Costs 405

4. Allocation of Cluster Network Upgrade Costs 422

5. Shared Network Upgrades 468

6. Increased Financial Commitments and Readiness Requirements 490

7. Transition Process 814

B. Reforms To Increase the Speed of Interconnection Queue Processing 872

1. Elimination of the Reasonable Efforts Standard 872

2. Affected Systems 1026

3. Optional Resource Solicitation Study 1294

C. Reforms To Incorporate Technological Advancements Into the Interconnection Process 1324

1. Increasing Flexibility in the Generator Interconnection Process 1324

2. Incorporating the Enumerated Alternative Transmission Technologies Into the Generator Interconnection Process 1534

3. Modeling and Ride-Through Requirements for Non-Synchronous Generating Facilities 1621

D. Issues Beyond the Scope of this Rulemaking 1736

1. Comments 1736

2. Commission Determination 1743

IV. Compliance Procedures 1744

A. NOPR Proposal 1744

B. Comments 1747

1. Compliance Filing Deadline 1747

2. Regional Flexibility 1750

3. Reciprocity Tariffs 1759

4. Effective Date 1760

5. Miscellaneous 1761

C. Commission Determination 1762

V. Information Collection Statement 1772

VI. Environmental Analysis 1779

VII. Regulatory Flexibility Act 1780

VIII. Document Availability 1783

IX. Effective Date and Congressional Notification 1785

I. Introduction

1. This final rule requires all public utility transmission providers to adopt revised

pro forma

Large Generator Interconnection Procedures (LGIP),

pro forma

Small Generator Interconnection Procedures (SGIP),

pro forma

Large Generator Interconnection Agreements (LGIA), and

pro forma

Small Generator Interconnection Agreements (SGIA).

These revisions will ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, and will prevent undue discrimination.

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

pro forma

LGIP, the

pro forma

SGIP, the

pro forma

LGIA, and the

pro forma

SGIA.

See Standardization of Generator Interconnection Agreements & Procs.,

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

order on reh'g,

Order No. 2003-A, 69 FR 15932 (Mar. 5, 2004), 106 FERC ¶ 61,220,

order on reh'g,

Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ¶ 61,287 (2004),

order on reh'g,

Order No. 2003-C, 70 FR 37661 (July 18, 2005), 111 FERC ¶ 61,401 (2005),

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

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.

2. Twenty years ago the Commission issued Order No. 2003, in which the Commission required all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file standard procedures and a standard agreement for interconnecting generating facilities larger than 20 megawatts (MW) (called the

pro forma

LGIP and the

pro forma

LGIA).

The Commission stated its expectation that the changes would prevent undue discrimination, preserve reliability, increase energy supply, and lower wholesale prices for customers by increasing the amount and variety of new generation that would compete in the wholesale electricity market.

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

In Order No. 2006, the Commission adopted standard procedures and a standard agreement for interconnecting generating facilities no larger than 20 MW (called the

pro forma

SGIP and the

pro forma

SGIA), citing the same purposes outlined in Order No. 2003.

Order No. 2003, 104 FERC ¶ 61,103 at P 2.

Id.

P 1.

Id.

P 12.

Standardization of Small Generator Interconnection Agreements & Procs.,

Order No. 2006, 111 FERC ¶ 61,220, at PP 15, 35-36,

order on reh'g,

Order No. 2006-A, 70 FR 71760 (Dec. 30, 2005), 113 FERC ¶ 61,195 (2005),

order granting clarification,

Order No. 2006-B, 71 FR 42587 (July 27, 2006), 116 FERC ¶ 61,046 (2006).

3. The electricity sector has transformed significantly since the issuance of Order Nos. 2003 and 2006. The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources have created new challenges for the generator interconnection process. These new challenges are creating large interconnection queue

backlogs and uncertainty regarding the cost and timing of interconnecting to the transmission system, increasing costs for consumers. Backlogs in the generator interconnection process, in turn, can create reliability issues as needed new generating facilities are unable to come online in an efficient and timely manner. While the Commission recognized these issues and sought to address them in Order No. 845,

it is clear that further action is needed. Therefore, we believe that it is necessary to reform the Commission's standard interconnection procedures and agreements to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential.

See Reform of Generator Interconnection Procs. & Agreements,

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

order on reh'g,

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

order on reh'g,

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

4. Accordingly, we adopt reforms to the Commission's

pro forma

LGIP and

pro forma

LGIA. Specifically, as explained in detail in this final rule, we adopt reforms to: (1) implement a first-ready, first-served cluster study process;

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

A first-ready, first-served cluster study process improves efficiency in the interconnection study process by including the following elements: increased access to information prior to entering the queue; a mechanism to study interconnection requests in groups where all interconnection requests in the group are equally queued and of equal study priority; and increased financial commitments and readiness requirements to enter and proceed through the queue. In contrast, the existing first-come, first-served serial study process in the

pro forma

LGIA and LGIP provides limited information to interconnection customers prior to entering the queue, assigns interconnection requests an individual queue position based solely on the date of entry into the queue, and contains limited financial and readiness requirements.

5. First, in order to implement a first-ready, first-served cluster study process, this final rule requires: (1) transmission providers to publicly post available information pertaining to generator interconnection; (2) transmission providers to use cluster studies as the interconnection study method; (3) transmission providers to allocate cluster study costs on a pro rata and per capita basis; (4) transmission providers to allocate network upgrade costs based on a proportional impact method; (5) interconnection customers to pay study and commercial readiness deposits as part of the cluster study process; (6) interconnection customers to demonstrate site control at the time of submission of the interconnection request; and (7) transmission providers to impose withdrawal penalties on interconnection customers for withdrawing from the interconnection queue, with certain exceptions. We also require transmission providers to adopt a transition process to move from the existing serial interconnection process to the new cluster study process.

6. Second, in order to increase the speed of interconnection queue processing, this final rule: (1) eliminates the reasonable efforts standard for conducting interconnection studies and imposes a financial penalty on transmission providers that fail to meet interconnection study deadlines; and (2) establishes an affected system study process and associated

pro forma

affected system agreements.

7. Third, in order to incorporate technological advancements into the interconnection process, this final rule requires transmission providers to: (1) allow more than one generating facility to co-locate on a shared site behind a single point of interconnection and share a single interconnection request; (2) evaluate the proposed addition of a generating facility at the same point of interconnection prior to deeming such an addition a material modification if the addition does not change the originally requested interconnection service level; (3) allow interconnection customers to access the surplus interconnection service process once the original interconnection customer has an executed LGIA or requests the filing of an unexecuted LGIA; (4) use operating assumptions in interconnection studies that reflect the proposed charging behavior of an electric storage resource; and (5) evaluate the list of alternative transmission technologies enumerated in this final rule during the generator interconnection study process. This final rule also requires interconnection customers requesting to interconnect a non-synchronous generating facility to: (1) provide the transmission provider with the models needed for accurate interconnection studies; and (2) have the ability to maintain power production at pre-disturbance levels and provide dynamic reactive power to maintain system voltage during transmission system disturbances and within physical limits. Finally, this final rule requires that all newly interconnecting large generating facilities provide ride through capability consistent with any standards and guidelines that are applied to other generating facilities in the balancing authority area on a comparable basis.

8. We also adopt reforms to the

pro forma

SGIP and

pro forma

SGIA. Specifically, as explained in detail in this final rule, for small generating facilities we propose reforms to incorporate the enumerated alternative transmission technologies into the interconnection process, and to provide modeling and ride through requirements for non-synchronous generating facilities.

9. Many of the reforms adopted in this final rule track the notice of proposed rulemaking's

(NOPR) proposed reforms closely. However, as discussed more fully below, we have revised aspects of the reforms pertaining to the cluster study process, allocation of cluster study and network upgrade costs, increased financial commitments and readiness requirements, financial penalties for delayed interconnection studies, the affected system study process,

pro forma

affected system agreements, the material modification process, operating assumptions for interconnection studies, incorporating the enumerated alternative transmission technologies, and ride through requirements. Additionally, as discussed more fully below, we decline to adopt the NOPR proposals pertaining to informational interconnection studies, shared network upgrades, the optional resource solicitation study, and the alternative transmission technologies annual report.

Improvements to Generator Interconnection Procs. & Agreements,

87 FR 39934 (July 5, 2022), 179 FERC ¶ 61,194 (2022) (NOPR).

10. We recognize that transmission providers have undertaken efforts to address interconnection queue management issues. This final rule is not intended to divert or slow the potential progress represented by those efforts, and we encourage transmission providers to continue to innovate to remedy their identified interconnection queue management issues. We note that the compliance obligations that result from this final rule will be evaluated in light of the independent entity variation standard for regional transmission organizations (RTO) and independent system operators (ISO) and the consistent with or superior to standard for non-RTO/ISO transmission providers.

Order No. 2003, 104 FERC ¶ 61,103 at P 26;

see infra

section IV.

A. Historical Framework: Order Nos. 2003, 2006, and 845

11. In Order No. 2003, the Commission recognized a need for a

standard set of interconnection procedures for transmission providers and a single, uniformly applicable interconnection agreement for large generating facilities.

The Commission noted that generator interconnection is a “critical component of open access transmission service and thus is subject to the requirement that utilities offer comparable service under the [

pro forma

open access transmission tariff (tariff)].”

The Commission found that it was appropriate to establish a standard set of generator interconnection procedures to “minimize opportunities for undue discrimination and expedite the development of new generation, while protecting reliability and ensuring that rates are just and reasonable.”

To this end, the Commission adopted the

pro forma

LGIP and

pro forma

LGIA and amended its regulations to require all transmission providers to incorporate these standard procedures and agreement into their tariffs.

Order No. 2003, 104 FERC ¶ 61,103 at P 11. Large generating facilities are defined to mean “a Generating Facility having a Generating Facility Capacity of more than 20 MW.”

Pro forma

LGIP section 1.

Order No. 2003, 104 FERC ¶ 61,103 at P 9 (citing

Tenn. Power Co.,

90 FERC ¶ 61,238 (2000)).

Id.

P 11.

18 CFR 35.28(f)(1) (2022).

12. To initiate the generator interconnection process set forth in the Commission's

pro forma

LGIP,

the interconnection customer submits an interconnection request for its proposed generating facility that includes preliminary documentation of the site of the proposed generating facility, certain technical information about the proposed generating facility, and the expected commercial operation date of the proposed generating facility, along with a refundable deposit of $10,000.

After the transmission provider determines that the interconnection request is complete, the interconnection request enters the transmission provider's interconnection queue with other pending interconnection requests and is assigned a queue position based on the time and date of its receipt.

The queue position determines the order in which the transmission provider studies the interconnection requests in its interconnection queue.

While we provide a broad description of the process in the Commission's

pro forma

LGIP as background here, we recognize that many transmission providers have adopted (and the Commission has accepted) variations to many of the terms in the Commission's

pro forma

LGIP and

pro forma

LGIA. Consequently, some or many of the details of a particular transmission provider's generator interconnection procedures may vary considerably from the broad description provided here.

Order No. 2003, 104 FERC ¶ 61,103 at P 35;

pro forma

LGIP sections 3.1, 3.4.

Pro forma

LGIP section 4.1.

Id.

13. Transmission providers must schedule a scoping meeting with the interconnection customer to discuss possible points of interconnection for the proposed generating facility and exchange technical information, which is followed by a series of interconnection studies to evaluate the proposed interconnection in detail.

Transmission providers study interconnection requests in three phases: (1) the interconnection feasibility study (feasibility study);

(2) the interconnection system impact study (system impact study);

and (3) the interconnection facilities study (facilities study).

These studies contain the power flow, short circuit, and stability analyses necessary to: (1) identify any adverse impacts on the transmission providers' transmission system or any affected systems;

(2) determine the interconnection facilities and network upgrades

needed to reliably interconnect the generating facility; and (3) estimate the interconnection customer's cost responsibility for these facilities.

The

pro forma

LGIP requires that transmission providers use reasonable efforts to complete: (1) feasibility studies within 45 calendar days; (2) system impact studies within 90 calendar days; and (3) facilities studies within 90 or 180 calendar days, depending on the interconnection customer's requested accuracy margin.

Order No. 2003, 104 FERC ¶ 61,103 at P 36;

pro forma

LGIP sections 3.4.4, 6-8.

The

pro forma

LGIP defines a feasibility study as “a preliminary evaluation of the system impact and cost of interconnecting the Generating Facility to the Transmission Provider's Transmission System.” The scope of a feasibility study is described in section 6 of the

pro forma

LGIP.

Pro forma

LGIP sections 1, 6.

The

pro forma

LGIP defines a system impact study as “an engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of Transmission Provider's Transmission System and, if applicable, an Affected System.” In particular, a system impact study identifies and details “the system impacts that would result if the Generating Facility were interconnected without project modifications or system modifications, focusing on the Adverse System Impacts identified in the [feasibility study], or to study potential impacts, including but not limited to those identified in the Scoping Meeting.”

Id.

section 1.

The

pro forma

LGIP defines a facilities study as “a study conducted by the Transmission Provider or a third-party consultant for the Interconnection Customer to determine a list of facilities (including Transmission Provider's Interconnection Facilities and Network Upgrades as identified in the [system impact study]), the cost of those facilities, and the time required to interconnect the Generating Facility with the Transmission Provider's Transmission System.” The scope of a facilities study is described in section 8 of the

pro forma

LGIP.

Id.

sections 1, 8.

The

pro forma

LGIP defines an affected system as an electric system other than the transmission provider's transmission system that may be affected by the proposed interconnection.

Id.

section 1;

pro forma

LGIA art. 1.

For purposes of this final rule, unless otherwise noted, “network upgrades” refer to interconnection-related network upgrades. More specifically, the

pro forma

LGIP and

pro forma

LGIA provide that, “Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission Provider's Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission Provider's Transmission System to accommodate the interconnection of the Large Generating Facility to the Transmission Provider's Transmission System.”

Pro forma

LGIP section 1;

pro forma

LGIA art. 1.

Order No. 2003, 104 FERC ¶ 61,103 at PP 35-37;

pro forma

LGIP sections 6-8. The interconnection customer is responsible for the actual costs of interconnection studies and any necessary restudies.

Pro forma

LGIP section 13.3.

Pro forma

LGIP sections 6.3, 7.4, 8.3.

14. At the completion of the facilities study, the

pro forma

LGIP requires the transmission provider to issue a report on the best estimate of the costs to effectuate the requested interconnection and provide a draft generator interconnection agreement to the interconnection customer.

If the interconnection customer wishes to proceed, after negotiations, the interconnection customer enters into a generator interconnection agreement with the transmission provider or, in specific circumstances, requests that the transmission provider file the agreement with the Commission unexecuted.

The transmission provider is responsible for the construction of all network upgrades, but, as further discussed below, the interconnection customer has the option to build these facilities in certain circumstances.

Order No. 2003, 104 FERC ¶ 61,103 at P 38. Section 11.1 of the

pro forma

LGIP requires the transmission provider to tender a draft LGIA to the interconnection customer “in the form of Transmission Provider's FERC-approved standard form LGIA.”

If the transmission provider and interconnection customer execute an LGIA that conforms to the transmission provider's Commission-approved standard form LGIA, the agreement does not need to be filed with the Commission (if the transmission provider has such a standard form LGIA on file and submits an Electronic Quarterly Report). Alternatively, the transmission provider must file an LGIA with the Commission for review and approval if: (1) the interconnection customer determines that negotiations with the transmission provider over the terms of an LGIA are at an impasse and requests submission of the unexecuted LGIA with the Commission; or (2) the LGIA does not conform to the transmission provider's Commission-approved standard form LGIA.

See

Order No. 2003-A, 106 FERC ¶ 61,220 at P 201;

pro forma

LGIP sections 11.2-11.3.

Order No. 2003, 104 FERC ¶ 61,103 at PP 351-354;

pro forma

LGIA art. 5.1.3.

15. Similar to Order No. 2003, in Order No. 2006, the Commission recognized the need for standardized

interconnection procedures and agreements for small generating facilities with a capacity of 20 MW or less.

In addition to establishing a

pro forma

interconnection study process for small generating facilities similar to the process for large generating facilities established in Order No. 2003, the Commission included: (1) a “fast track process”

that uses technical screens to evaluate a certified small generating facility no larger than 2 MW; and (2) a “10 [kilowatt (kW)] inverter process”

that uses the same technical screens to evaluate a certified inverter-based small generating facility no larger than 10 kW.

The Commission later issued Order No. 792,

in which the Commission revised the

pro forma

SGIP and

pro forma

SGIA to provide for interconnection customers to receive point of interconnection information in advance of submitting an interconnection request, increase the threshold for participation in the fast track process to five MW, and to specifically include electric storage devices.

Order No. 2006, 111 FERC ¶ 61,220 at P 36.

Pro forma

SGIP section 2.1.

Id.

attach. 5.

Order No. 2006, 111 FERC ¶ 61,220 at PP 36, 38-39.

Small Generator Interconnection Agreements & Procs.,

Order No. 792, 78 FR 73240 (Dec. 5, 2013), 145 FERC ¶ 61,159 (2013),

clarifying,

Order No. 792-A, 146 FERC ¶ 61,214 (2014).

See

Order No. 792, 145 FERC ¶ 61,159 at P 1.

16. In response to concerns voiced to the Commission about interconnection queue management, in 2007, the Commission held a technical conference,

and later issued an order

addressing interconnection queue issues in RTOs/ISOs. In the order, the Commission noted that some transmission providers were not processing their interconnection queues within the timelines established in the

pro forma

LGIP, and in certain cases, were greatly exceeding them.

The Commission stated that, although it “may need to [impose solutions] if the RTOs and ISOs do not act themselves,” each RTO/ISO would have an opportunity to work with its stakeholders to develop its own solutions.

As further discussed below, following the order, multiple RTOs/ISOs submitted queue reform proposals to the Commission, some of which moved away from a so-called “first-come, first-served” approach (whereby interconnection requests are processed in the order they are received) to a so-called “first-ready, first-served” approach (whereby interconnection requests are processed based on when interconnection customers meet certain project development milestones).

The reason for this move was to allow interconnection customers with interconnection requests for generating facilities more likely to achieve commercial operation to move faster instead of being delayed by interconnection requests that were higher in the interconnection queue but making limited or no progress towards commercial operation and creating unreasonable queue delays.

Interconnection Queuing Practices,

Notice of Technical Conference, Docket No. AD08-2-000 (issued Nov. 2, 2007).

Interconnection Queuing Pracs.,

122 FERC ¶ 61,252 (2008) (2008 Technical Conference Order).

Id.

P 3.

Id.

P 8.

See, e.g., Sw. Power Pool, Inc.,

128 FERC ¶ 61,114 (2009);

Midwest Indep. Transmission Sys. Operator, Inc.,

124 FERC ¶ 61,183 (2008);

Cal. Indep. Sys. Operator Corp.,

124 FERC ¶ 61,292 (2008).

17. In 2018, the Commission issued Order No. 845, in which the Commission made the most comprehensive revisions to the

pro forma

LGIP and

pro forma

LGIA since their adoption in Order No. 2003. In Order No. 845, the Commission concluded that reforms to the

pro forma

LGIP and

pro forma

LGIA were needed to mitigate concerns regarding systemic inefficiencies, remedy discriminatory practices, and address recent developments, including changes in the resource mix and emergence of new technologies.

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

Order No. 845, 163 FERC ¶ 61,043 at P 7.

Id.

P 2.

B. Regional Transmission Planning and Cost Allocation and Generator Interconnection Advance Notice of Proposed Rulemaking

18. On July 15, 2021, the Commission issued an advance notice of proposed rulemaking (ANOPR) in Docket No. RM21-17-000, presenting potential reforms to the Commission's requirements governing the regional transmission planning and cost allocation and generator interconnection processes.

Specific to the generator interconnection process, the Commission sought comment on whether and which reforms may be necessary to ensure a more purposeful integration of the generator interconnection process with the regional transmission planning and cost allocation processes, establish a faster and more efficient interconnection queueing process, and promote a more efficient and cost-effective allocation of network upgrade costs.

For instance, the Commission noted that the cost of network upgrades can depend largely on both the timing of when the interconnection customer enters the interconnection queue and where the interconnection customer proposes to interconnect its generating facility. Therefore, the Commission noted, interconnection customers may submit multiple interconnection requests in an effort to determine the most favorable point of interconnection

that minimizes their network upgrade costs.

The Commission stated that this practice, in turn, may lead to late-stage withdrawals of the excess interconnection requests, which can then impede the transmission provider's ability to process its interconnection queue in an efficient manner. As a result, the Commission stated that it may be time to consider reforms to the generator interconnection process that would make it more efficient and ensure that generating facilities that are more “ready” than others are not unduly delayed in the interconnection queue.

Bldg. for the Future Through Elec. Reg'l Transmission Planning & Cost Allocation & Generator Interconnection,

86 FR 40266 (July 15, 2021), 176 FERC ¶ 61,024 (2021) (ANOPR).

Id.

P 5.

The

pro forma

LGIP defines point of interconnection as “the point, as set forth in Appendix A to the Standard Large Generator Interconnection Agreement, where the Interconnection Facilities connect to the Transmission Provider's Transmission System.”

Pro forma

LGIP section 1.

ANOPR, 176 FERC ¶ 61,024 at P 41.

19. On April 21, 2022, the Commission issued a notice of proposed rulemaking (Transmission Planning and Cost Allocation NOPR) proposing reforms to its existing regional transmission planning and cost allocation requirements in the same proceeding as it issued the ANOPR.

While the Transmission Planning and Cost Allocation NOPR did not address many of the concerns raised by the Commission in the ANOPR with respect to the generator interconnection queue process, the Commission noted in the Transmission Planning and Cost Allocation NOPR that it would continue to review the record and that it expected to address possible inadequacies through subsequent proceedings that propose reforms, as warranted, related to that topic.

The Commission took that next step with the reforms proposed

in the NOPR in this proceeding, many of which we adopt in this final rule.

Bldg. for the Future Through Elec. Reg'l Transmission Plan. & Cost Allocation & Generator Interconnection,

87 FR 26504 (May 4, 2022), 179 FERC ¶ 61,028 (2022).

Id.

P 10.

C. Notice of Proposed Rulemaking

20. On June 16, 2022, the Commission issued the NOPR, proposing reforms focused on improving aspects of the

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA. The Commission also sought comment on, but did not propose, tariff revisions on other issues.

21. First, the Commission proposed reforms focused on improving interconnection processes to ensure interconnection customers can proceed in an efficient and timely manner.

Among those, the Commission proposed to: (1) require transmission providers to offer an optional informational interconnection study to serve as additional information for prospective interconnection customers in deciding whether to submit an interconnection request and set minimum requirements for transmission providers to publicly post available information pertaining to generator interconnection;

(2) require transmission providers to implement a first-ready, first-served cluster study process that allocates costs associated with cluster studies and identified network upgrades consistent with the discussion below;

and (3) impose more stringent financial commitments and readiness requirements on interconnection customers, including increased study deposits, more stringent site control requirements, a commercial readiness framework, and higher withdrawal penalties.

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

NOPR, 179 FERC ¶ 61,194 at P 4.

Id.

PP 42-52.

Id.

PP 56-101.

Id.

PP 104-148.

Id.

PP 150-160.

22. Second, the Commission proposed three reforms to increase the speed of interconnection queue processing, including: (1) revisions to eliminate the reasonable efforts standard for interconnection study processing;

(2) revisions to establish an affected system study process, along with necessary

pro forma

affected system agreements;

and (3) revisions to establish an optional resource solicitation study.

Id.

PP 168-173.

Id.

PP 182-215.

Id.

PP 223-237.

23. Finally, the Commission proposed three reforms to incorporate technological advancements into the interconnection study process. With these reforms, the Commission proposed to require transmission providers to: (1) increase flexibility in the generator interconnection process by allowing generating facilities to co-locate, allow the interconnection customer to request the addition of a generating facility to an existing interconnection request, increase the availability of surplus interconnection service, and allow interconnection customers to propose operating assumptions for their generating facilities;

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

and (3) list required modeling standards for inclusion in all interconnection requests that include inverter-based resources (IBRs), as well as require certain performance standards from IBRs during system disturbances.

Id.

PP 242-288.

Id.

PP 297-302.

Id.

PP 328-341.

24. In response to the NOPR, 189 comments were filed.

These comments have informed our determinations in this final rule.

Appendix A lists the entities that submitted comments on the NOPR and the shortened names used through this final rule to describe those entities.

D. Joint Federal-State Task Force on Electric Transmission

25. On June 17, 2021, the Commission established a Joint Federal-State Task Force on Electric Transmission (Task Force) to formally explore broad categories of transmission-related topics.

The Commission explained that the development of new transmission infrastructure implicated a host of different issues, including generator interconnection. The Task Force is comprised of all FERC Commissioners as well as representatives from 10 state commissions nominated by the National Association of Regulatory Utility Commissioners (NARUC), with two originating from each NARUC region.

The Task Force convenes for multiple formal meetings annually, which are open to the public. Since its creation and as of the date of issuance of this final rule, the Task Force has met seven times.

Joint Fed.-State Task Force on Elec. Transmission,

175 FERC ¶ 61,224, at PP 1, 6 (2021).

An up-to-date list of Task Force members, as well as additional information on the Task Force, is available on the Commission's website at:

https://www.ferc.gov/TFSOET.

Public materials related to the Task Force, including transcripts from public meetings, are available in the Commission's eLibrary in Docket No. AD21-15-000.

26. The discussion at the May 2022 meeting focused on interconnection issues, including generator interconnection queue processes and backlogs. The Task Force members discussed: the primary challenges preventing more efficient processing of interconnection queues; specific improvements to interconnection processes (such as tighter applicant requirements to enter and remain in the queue, clustering, fast tracking, tighter deadlines on transmission providers completing studies, and minimizing reiterative studies); and how to balance near-term improvements to the interconnection procedures with longer-term regional transmission planning and development.

Joint Fed.-State Task Force on Elec. Transmission,

Notice of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022).

II. Overall Need for Reform

A. NOPR

27. In the NOPR, the Commission noted that the serial first-come, first-served study process was adopted at a time when most interconnection requests were for large traditional generating facilities that would use readily available transmission capacity.

The Commission stated that the continued use of this process in the face of dramatic changes to the electric power industry, principally the surge in interconnection requests, the rapidly changing resource mix, evolving market forces, and the emergence of new technologies, has led to a growing backlog of interconnection requests and study delays for many transmission providers.

The Commission also stated that these interconnection queue backlogs and study delays create uncertainty and inhibit project developers' ability to interconnect generating facilities to the transmission system.

The Commission preliminarily found that the existing

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA may be insufficient to ensure that new generating facilities are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner and to thereby ensure that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly

discriminatory or preferential.

Further, because the interconnection queue backlogs and study delays afflicting generator interconnection service nationwide hinder the timely development of new generation and thereby stifle competition in the wholesale electric markets, the Commission also preliminarily found that the Commission's

pro forma

LGIP,

pro forma

LGIA,

pro forma

SGIP, and

pro forma

SGIA result in rates, terms, and conditions in the wholesale electric markets that are unjust, unreasonable, and unduly discriminatory or preferential.

NOPR, 179 FERC ¶ 61,194 at P 18.

Id.

PP 18-20.

Id.

P 19 (citing Joint Fed.-State Task Force on Elec. Transmission, Technical Conference, Docket No. AD21-15-000, Tr. 15:21-16:1 (Ted Thomas) (May 6, 2022) (May Joint Task Force Tr.) (“Houston, we have a problem. As stated in the NARUC ANOPR comments, existing methods for interconnecting new resources to the transmission grid are inadequate and inefficient because of the time necessary to interconnect new resources and the corresponding network upgrade costs.”)).

Id.

P 22 (citing May Joint Task Force Tr. 23:6-11 (Riley Allen) (“Ultimately, this system is not working efficiently now and those inefficiencies translate into costs. It's not just cost on the developers, but I find from my decades of experience that, if there are inefficiencies in the system, they ultimately have to be borne by the loads and ratepayer interests.”)).

28. The Commission stated that its preliminary findings were based on several features of the Commission's existing generator interconnection procedures and agreements that are of concern, specifically: (1) the information (or lack thereof) available to prospective interconnection customers and the commitments required of them to enter and progress through the interconnection queue; (2) the reliance on a serial first-come, first-served study process and the standard to which transmission providers are held for meeting interconnection study deadlines; (3) the protocols for affected systems studies; (4) the provisions for studying new or hybrid generation technologies and considering alternative transmission technologies; and (5) the performance requirements for non-synchronous generating facilities, including wind, solar, and electric storage facilities.

Id.

PP 23-36 (citing May Joint Task Force Tr. 70:20-71:6 (Matthew Nelson) (analogizing reiterative studies to going to the supermarket to buy ingredients for a recipe without knowing how much the ingredients cost, finding out at the register that they cost too much for your budget, and having to “go home, get a new recipe, and start it all over again”)).

29. The Commission found that some of the same issues persist in the small generating facility context and, therefore, proposed limited reforms to the

pro forma

SGIP and

pro forma

SGIA to incorporate alternative transmission technologies into the interconnection process and to provide modeling and performance requirements for non-synchronous generating facilities.

Id.

P 5.

B. Comments

30. The vast majority of commenters overwhelmingly agree with the Commission's preliminary conclusion that there is a need to reform the Commission's

pro forma

interconnection procedures and agreements to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential.

These commenters generally agree that the unprecedented volume of generation in the interconnection queue, which is almost equal to the current U.S. generation fleet, has resulted in severe backlogs in interconnection processes across the country.

For example, the Ohio Commission Consumer Advocate states that “there is an urgent need to clear the current generator interconnection queue backlog and to facilitate timely and economic interconnection of new resources in a way that responds to current and future market conditions.”

EEI recognizes that, despite many efforts underway across the country to fix individual transmission provider interconnection queue processes, there is still a need for the Commission to address backlogs and improve certainty in the interconnection queue process.

Several commenters assert that these interconnection backlogs have resulted in commercial uncertainty regarding both the magnitude of identified upgrade costs and the timeline for completion of interconnection studies, delayed project development, increased costs for consumers due to the prevention of new supply from reaching the market, and impaired reliability.

Senators Hickenlooper and King note that, in the past decade, 23% of proposed generating facilities reached commercial operation, while 72% were withdrawn.

ELCON and APPA-LPPC both argue that uncertainty, on the part of both transmission provider and generator project developer, inevitably leads to an increase in costs to consumers.

U.S. DOE submits a recent report published by the Lawrence Berkeley National Laboratory, which finds that interconnection costs in MISO have escalated as the number of interconnection requests has increased.

Specifically, the report finds that interconnection costs in MISO doubled for projects completed between 2019-2021 compared to projects completed prior to 2018, and cost estimates tripled for projects still active in the queue between the same time periods. Some commenters agree that the existing interconnection rules in the

pro forma

LGIP and

pro forma

LGIA create an incentive for interconnection customers to submit interconnection requests even if they are not prepared to

move forward with their projects, in order to secure a favorable position in the interconnection queue or in an attempt to obtain locations with available transmission capacity.

They assert that the withdrawal of each speculative interconnection request triggers reassessments and possible restudies by the transmission provider that can increase the timing and interconnection cost for lower-queued interconnection requests. Several commenters point to ambitious climate goals (such as the United States' commitment to reducing net greenhouse gas emissions by 50-52% by 2030 under the Paris Climate Agreement) and argue that: (1) these changes will likely spur greater investment in new generation and exacerbate the delays in processing interconnection requests; and/or (2) without an efficient and transparent interconnection process, none of the clean energy generating facilities intended to meet these goals can be effectively deployed.

Consumers Energy argues that delays in processing interconnection requests will exacerbate resource adequacy challenges.

ACE-NY Initial Comments at 2; ACE-NY Reply Comments at 5; AEE Initial Comments at 3, 5; AEE Reply Comments at 5; AES Initial Comments at 2; Affected Interconnection Customers Initial Comments at 2; Ameren Initial Comments at 2; APPA-LPPC Reply Comments at 2; Avangrid Initial Comments at 6, 8; Bonneville Initial Comments at 3; CESA Initial Comments at 3; CESA Reply Comments at 1; Clean Energy Associations Initial Comments at 8; Clean Energy Buyers Initial Comments at 3; Clean Energy States Initial Comments at 2-3; Colorado Commission Initial Comments at 1; Consumers Energy Initial Comments at 2; Cypress Creek Initial Comments at 1; Dominion Initial Comments at 4; EEI Initial Comments at 2; EEI Reply Comments at 3; EDF Renewables Initial Comments at 1-2; Enel Initial Comments at 2; Energy Keepers Initial Comments at 2; Evergreen Action Initial Comments at 1; Eversource Initial Comments at 2; Fervo Energy Initial Comments at 2; Google Initial Comments at 2; Guzman Energy Initial Comments at 2; Hannon Armstrong Initial Comments at 1; Hydropower Commenters Initial Comments at 5; Illinois Commission Initial Comments at 2-3, 5; Interwest Initial Comments at 3; Interwest Reply Comments at 2; ISO-NE Initial Comments at 2-3; MISO TOs Initial Comments at 2, 6; NARUC Initial Comments at 3; New Jersey Commission Initial Comments at 4-9; NY Commission and NYSERDA Initial Comments at 3; NV Energy Initial Comments at 3; Ohio Commission Consumer Advocate Initial Comments at 3-4; OMS Initial Comments at 2; Ørsted Initial Comments at 5; Pine Gate Initial Comments at 8; PJM Initial Comments at 1, 4; PJM Coalition Initial Comments at 1; RWE Renewables Initial Comments at 1; Senators Hickenlooper and King Initial Comments at 1-2; Shell Initial Comments at 5-6; State Agencies Initial Comments at 1-2; TAPS Initial Comments at 1; Union of Concerned Scientists Reply Comments at 1; UMPA Initial Comments at 1; WATT Coalition Initial Comments at 1; Xcel Initial Comments at 8.

AEE Initial Comments at 3; Apple Initial Comments at 1; Bonneville Initial Comments at 3; Clean Energy Buyers Initial Comments at 3; Colorado Commission Initial Comments at 2, 8-11; EDF Renewables Initial Comments at 2; Evergreen Action Initial Comments at 1; Eversource Initial Comments at 2; Interwest Initial Comments at 1-2; NV Energy Initial Comments at 2-3; Ohio Commission Consumer Advocate Initial Comments at 3-4; Ørsted Initial Comments at 2; Senators Hickenlooper and King Initial Comments at 1-2; U.S. Chamber of Commerce Initial Comments at 5; UMPA Initial Comments at 1.

Ohio Commission Consumer Advocate Initial Comments at 3-4.

EEI Reply Comments at 3.

ACE-NY Initial Comments at 2; AEE Initial Comments at 4; EDF Renewables Initial Comments at 2; ELCON Initial Comments at 2; Fervo Energy Initial Comments at 2; PJM Coalition Initial Comments at 2; Xcel Reply Comments at 1.

Senators Hickenlooper and King Initial Comments at 1 (citing Joseph Rand et al., Lawrence Berkeley Nat'l Lab.,

Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection

(Apr. 2022) (Queued Up 2022),

https://emp.lbl.gov/sites/default/files/queued_up_2021_04-13-2022.pdf

)).

ELCON Initial Comments at 2; APPA-LPPC Initial Comments at 2.

U.S. DOE Initial Comments at 1 (citing Joachim Seel et al., Lawrence Berkeley Nat'l Lab.,

Interconnection Cost Analysis in the MISO Territory

at 1 (Oct. 2022)).

Clean Energy Buyers Initial Comments at 3; Dominion Initial Comments at 4-5; PJM Initial Comments at 12; U.S. Chamber of Commerce Initial Comments at 4-5.

AEP Initial Comments at 2; Affected Interconnection Customers Initial Comments at 2; Allen Meyer Initial Comments at 1; Apple Initial Comments at 1; Bretton C Little Initial Comments at 1; Colorado Commission Initial Comments at 13-14; EDF Renewables Initial Comments at 2-3 (referencing Inflation Reduction Act, Pub. L. 117-169 (2022)); ELCON Initial Comments at 2; Evergreen Action Initial Comments at 2; GSCE Initial Comments at 5-6; Individual Signatories Initial Comments at 1-2; Interwest Comments at 1-2; National Grid Initial Comments at 2; Payton Alaama Reply Comments at 1; Pine Gate Reply Comments at 3-4; Rick K Lathrop Reply Comments at 1; Shell Initial Comments at 6; State Agencies Initial Comments at 8-9 (citing Int'l Energy Agency,

Net Zero by 2050: A Roadmap for the Global Energy Sector

(2021)

https://www.iea.org/reports/net-zero-by-2050; The United States' Nationally Determined Contribution

(2021),

https://www4.unfccc.int/sites/ndcstaging/PublishedDocuments/United%20States%20of%20America%20First/United%20States%20NDC%20April%2021%202021%20Final.pdf;

White House,

FACT SHEET: Biden Administration Jumpstarts Offshore Wind Energy Projects to Create Jobs

(Mar. 29, 2021),

https://www.whitehouse.gov/briefing-room/statements-releases/2021/03/29/fact-sheet-biden-administration-jumpstarts-offshore-wind-energy-projects-to-create-jobs/

); Sue Hilton Initial Comments at 1; Union of Concerned Scientists Reply Comments at 6; Vistra Initial Comments at 4.

Consumers Energy Initial Comments at 7.

31. A small subset of commenters, while supporting an overall need for reform, disagree with some of the Commission's preliminary conclusions about the need for reform.

A few other commenters claim that there is no basis for the Commission's preliminary conclusion that speculative projects that enter the interconnection queue and later withdraw, causing cascading restudies, are responsible for interconnection queue backlogs.

A few commenters assert that the Commission did not take into account pertinent factors affecting interconnection queue sizes, such as an increase in the development of smaller, more diverse generating facilities.

For instance, Affected Interconnection Customers disagree with the Commission's reference to a nationwide shortage of qualified engineers and contend that the Commission fails to support this conclusion with any evidence beyond statements made by CAISO and MISO. Affected Interconnection Customers Initial Comments at 14 (citing NOPR, 179 FERC ¶ 61,194 at P 20 n.67).

CREA and NewSun Initial Comments at 35-37 (countering that interconnection requests do not reach commercial operation due to other reasons such as permitting or financing difficulties); NextEra Initial Comments at 4; Public Interest Organizations Initial Comments at 1-7 (arguing that the rate of queue withdrawal has been consistent over the last decade); SEIA Reply Comments at 1.

AEE Initial Comments at 6-7; Pine Gate Reply Comments at 4; SEIA Reply Comments at 1.

32. Three comments note that various transmission providers use vastly different interconnection procedures from the

pro forma

procedures established in Order No. 2003 and argue that there is an insufficient legal foundation under FPA section 206 to demonstrate that all of these approved interconnection procedures are unjust, unreasonable, and unduly discriminatory or preferential.

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

Southern argues that the Commission based its proposed actions in the NOPR on conjecture and thus failed to provide substantial evidence or engage in reasoned decision-making to demonstrate that the current interconnection processes are unjust and unreasonable.

In addition, Southern contends that the Commission's proposals are arbitrary and capricious because they impose a broadly applicable remedy to a problem that does not exist uniformly.

Early Adopters Coalition Initial Comments at 1-2; PacifiCorp Initial Comments at 9; Southern Initial Comments at 10-11.

Southern Initial Comments at 10-12; Southern Reply Comments at 1, 4.

Southern Initial Comments at 10 (citing

Emera Me.

FERC,

854 F.3d 9, 24 (D.C. Cir. 2017)); Southern Reply Comments at 1, 4.

Southern Initial Comments at 11-12.

33. Southern further asserts that the Commission failed to provide any actual evidence that its proposals will reduce interconnection queue backlogs or increase certainty for interconnection customers.

Id.

at 10; Southern Reply Comments at 5.

34. Some commenters argue that the sum of the NOPR may actually slow study processes, increase backlogs, and may unintentionally increase costs to ratepayers.

For example, CAISO asserts that shortening study timelines results in rushed, unreliable studies which would ultimately require more iteration and longer interconnection queue processing times.

Additionally, NextEra argues that the NOPR provides few, if any, solutions relevant to those regions that have already implemented cluster studies yet continue to experience significant study delays.

Further, some commenters oppose any generic one-size-fits-all reform, arguing that queue reform is best left to the regional level.

CAISO Initial Comments at 3; Dominion Initial Comments at 7; New York State Department Initial Comments at 2; NextEra Reply Comments at 2; NRECA Initial Comments at 7.

CAISO Initial Comments at 3.

NextEra Reply Comments at 7.

Avangrid Initial Comments at 36-37; Southern Initial Comments at 14-15.

35. Several commenters generally support the suite of proposed reforms in their entirety.

As discussed in detail in each section below discussing individual reforms, most commenters either support specific proposals or suggest that the Commission prioritize certain proposed reforms. For instance, Consumers Energy supports reforms that increase the speed of interconnection queue processing because it claims that the reforms provide clarity for resource planners and interconnection customers as well as improve the reliability of the bulk electric system and the clean energy resource transformation.

Google urges the Commission to prioritize reforms that provide a level playing field for both utility-backed resources and independent power producer-developed resources.

Google also expresses concern that the layering of increased study deposits, more stringent site control requirements, the proposed commercial readiness requirements, and withdrawal penalties may place undue burden on interconnection customers if the Commission does not also adopt proposals for more publicly available interconnection information, firm study deadlines, and penalties for missed study deadlines.

APPA-LPPC Initial Comments at 2-3; APPA-LPPC Reply Comments at 2; Apple Initial Comments at 1; ACORE Initial Comments at 2; Amazon Initial Comments at 2; Evergreen Action Initial Comments at 1-4; Individual Signatories Initial Comments at 1; PJM Coalition Initial Comments at 2.

Consumers Energy Initial Comments at 10-11.

Google Initial Comments at 3.

Id.

at 16.

36. Some commenters support adopting most or all of the limited

reforms to the

pro forma

SGIP and

pro forma

SGIA proposed in the NOPR.

For instance, Microgrid Resources asserts that including the proposed reforms in the

pro forma

SGIP is necessary to reflect the operating assumptions of, and to provide equitable treatment for, microgrids and other behind-the-meter resources.

Microgrid Resources asserts that, if the Commission succeeds in expediting interconnections for large generating facilities, while small generating facility interconnections languish, it will bias the system against smaller local generating facilities that are the backbone of community resilience.

Bonneville Initial Comments at 24 (supporting applying some of the Commission's proposed reforms to the

pro forma

SGIP and

pro forma

SGIA (

e.g.,

commercial readiness requirements), but asking that transmission providers be granted flexibility to determine which reforms should be applicable to small generator procedures and agreements); IREC Initial Comments at 3 (stating that the

pro forma

SGIP lacks the necessary provisions to safely and reliably interconnect storage to the electric grid while enabling its unique operating characteristics); Microgrid Resources Initial Comments at 8-9; Xcel Initial Comments at 19 (supporting applying reforms to small generating facilities requesting energy only interconnection service).

Microgrid Resources Initial Comments at 8-9.

C. Commission Determination

37. Based on the record, including comments submitted in response to the NOPR, as discussed below, we find that there is substantial evidence to support the conclusion that the existing

pro forma

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

We therefore adopt the preliminary findings in the NOPR concerning the need for reform

and, pursuant to FPA section 206, conclude that certain revisions to the

pro forma

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

pro forma

generator interconnection procedures and agreements are insufficient to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. Absent reform, the current interconnection process will continue to cause interconnection queue backlogs, longer development timelines, and increased uncertainty regarding the cost

100

and timing of interconnecting to the transmission system. These backlogs and delays, and the resulting timing and cost uncertainty,

101

hinder the timely development of new generation and thereby stifle competition in the wholesale electric markets resulting in rates, terms, and conditions that are unjust, unreasonable, and unduly discriminatory or preferential.

16 U.S.C. 824e(a); 18 CFR 385.206 (2022).

NOPR, 179 FERC ¶ 61,194 at PP 18-36.

100

See

May Joint Task Force Tr. 74:9-21 (Andrew French) (stating that generator developers complain principally about cost certainty and cost sharing and that “cost certainty is the much bigger issue” given that “an essential element of being able to sell a product is to know what your inputs are so you can market it”).

101

See

May Joint Task Force Tr. 23:18-25 (Jason Stanek) (expressing frustration with the status quo and agreement that it is “no longer tenable” considering the inability of generators to interconnect in a timely manner,

e.g.,

there are “2,500 projects under study [in the MACRUC region] and about a half of them have been in the queue since at least 2001”).

38. Indeed, recent data support the Commission's preliminary findings in the NOPR that the dramatic increase in the number of interconnection requests and limited transmission capacity are increasing interconnection queue backlogs across all regions of the country.

102

As of the end of 2022, there were over 10,000 active interconnection requests in interconnection queues throughout the United States, representing over 2,000 gigawatts (GW) of potential generation and storage capacity.

103

This potential generation is the largest interconnection queue size on record, more than four times the total volume (in GW) of the interconnection queues in 2010, and a 40% increase over the interconnection queue size from just the year prior.

104

These trends are not exclusive to any one region of the country. Instead, every single region has faced an increase in both interconnection queue size and the length of time interconnection customers are spending in the interconnection queue prior to commercial operation in recent years.

105

This is true for RTO/ISO and non-RTO/ISO regions alike. The non-RTO/ISO west and southeast regions both have faced queue size increases ranging from tripling to a 12-fold increase while also seeing longer timelines between interconnection requests and commercial operation dates.

106

Furthermore, the uncertainty and delays in the interconnection queues have resulted in fewer than 25% of interconnection requests, by capacity, reaching commercial operation between 2000 and 2017 in

any

region of the country—with some regions as low as 8%.

107

102

Joseph Rand et al., Lawrence Berkeley Nat'l Lab.,

Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection,

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

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

Order No. 845, 163 FERC ¶ 61,043 at P 305 (requiring transmission providers to post interconnection study metrics).

See

appendix B to this final rule, which provides an overview of recent data based on reporting by transmission providers in compliance with Order No. 845.

103

Queued Up 2023 at 7-8.

104

Id.

at 10.

105

Id.

at 9, 32.

106

Id.

at 9, 32.

107

Id.

at 3, 21.

39. Additionally, recent data continue to show that interconnection customers are waiting longer in the interconnection queue before withdrawing their interconnection requests,

108

even as overall interconnection study timelines are increasing in many regions.

109

For example, AEE states that, as of February 2022, all 2,274 projects waiting for an interconnection agreement in the PJM interconnection queue had been waiting for a year or more; 33% (758 projects) had been waiting more than 500 days, 22% (497 projects) have been stuck for more than two years, and 7% (166 projects) have been waiting more than three years.

110

NV Energy explains that several western utilities that are not currently part of an RTO/ISO are experiencing an unprecedented high volume of requests in excess of the utility's peak load.

111

AEE notes that wait times for generating facilities in interconnection queues nationwide have increased from 2.1 years for generating facilities built in 2000-2010 to 3.7 years for those built in 2011-2021.

112

And despite efforts to address

these challenges,

113

interconnection queue backlogs and delays have persisted and worsened. For generating facilities built in 2022, wait times in the interconnection queue saw a marked increase to now roughly five years.

114

108

Id.

at 25 (reporting that, although the median withdrawal duration has been relatively consistent over time, the mean withdrawal duration and distributions have edged higher in recent years).

109

Id.

at 27.

110

AEE Initial Comments at 4 (citing Advanced Energy Economy, “In PJM, Renewable Energy Projects Are Getting Stuck” (February 2022),

https://blog.aee.net/in-pjm-renewable-energy-projects-are-getting-stuck

111

NV Energy Initial Comments at 2-3. NV Energy explains that it has a peak load of 9,400 MW with an interconnection queue backlog for projects totaling more than 27,000 MW; Idaho Power has a peak load of 3,751 MW with an interconnection queue backlog of over 18,000 MW; PacifiCorp has a peak load of 13,000 MW with an interconnection queue backlog of over 45,000 MW; and APS has a peak load of 7,600 MW with an interconnection queue backlog of over 50,000 MW.

112

AEE Initial Comments at 4 (citing Queued Up 2022);

See also

NARUC Initial Comments at 13 (stating “nearly all transmission providers across the country, including many transmission providers that have implemented queue reforms, regularly fail to meet interconnection study deadlines”).

138

See, e.g.,

Clean Energy Associations Initial Comments at 43-44 (stating that “[a]t present, there is no specific incentive for delivering on-time and accurate studies, and late or inaccurate studies bring few if any consequences”).

139

See, e.g.,

ACE-NY Initial Comments at 3 (“Project developers have strict deadlines they must adhere to in the interconnection process, with penalties that include the forced withdrawal of the project from the queue.”).

140

See, e.g.,

NARUC Initial Comments at 13-14 (contending that “the tendency to miss deadlines introduces uncertainty in a process that is important to bringing new generation online in a timely and cost-effective manner”).

51. Third, the

pro forma

LGIP includes no requirements regarding how or when transmission providers should complete affected system studies. Without requirements, affected system studies often lag behind those completed by the transmission provider to whose transmission system the interconnection customer proposes to interconnect (the so-called host transmission provider) and are sometimes completed very late in the interconnection process, causing an additional round of delays and cost uncertainty for interconnection customers.

141

Additionally, for transmission providers that have procedures for how to complete affected system studies in their tariffs or other documents (

e.g.,

business practice manuals or joint operating agreements), the procedures are not consistent, may be hard for interconnection customers to locate, and may not represent the actual practices in use by the transmission provider, thus still creating uncertainty for interconnection customers. As a result, we find that the lack of consistent requirements for affected system modeling and procedures results in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential.

141

See, e.g.,

MISO Initial Comments at 72 (stating that “the need to wait for affected systems studies is the cause of the majority of delays in the MISO study process”); May Joint Task Force Tr. 65:2-8 (Dan Scripps) (citing affected systems studies as “a growing source of delay and cost uncertainty for interconnection customers, both in terms of just the timelines involved and the difficulty in pinning those down”).

52. Fourth, we find that the Commission's

pro forma

LGIP fails to accommodate the operating characteristics and technical capabilities of electric storage resources when it comes to specific interconnection procedures and modeling. As stated above, the interconnection queues predominantly consist of new technologies which have operating characteristics that differ from synchronous resources and were not anticipated when the Commission established the

pro forma

generator interconnection procedures and agreements in Order Nos. 2003 and 2006. Specifically, electric storage resources can be charged and dispatched on a flexible, as-available basis, and are less likely than synchronous generating facilities to withdraw energy from the transmission system during peak load conditions or discharge during light load conditions.

142

However, the existing

pro forma

generator interconnection procedures and agreements do not contemplate these operating characteristics or technical capabilities of electric storage resources. As a result, we find that electric storage resources

(whether standalone, co-located generating facilities, or part of a hybrid generating facility), may be studied under inappropriate operating assumptions (

e.g.,

charging at full capacity during peak load conditions) that result in assigning unnecessary network upgrades and increased costs to interconnection customers. Therefore, we find that the Commission's

pro forma

LGIP's lack of ability to modify operating assumptions for electric storage resources results in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential.

142

See, e.g.,

Bonneville Initial Comments at 22-23 (stating that “storage resources are less likely to charge during peak load conditions or discharge during light load conditions, and . . . those considerations can be factored into assumptions used in interconnection studies”); NARUC Initial Comments at 37 (stating that “assuming that an energy storage device will withdraw energy during peak demand . . . fails to recognize that those resources are likely to be highly responsive to price signals from the transmission provider and can

improve

reliability”).

53. Additionally, the record supports a finding that the existing

pro forma

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

143

We find that the record demonstrates that automatically deeming a request to add a generating facility to an existing interconnection request to be a material modification creates a significant barrier to access to the transmission system.

144

As a result, we find the existing

pro forma

LGIP and

pro forma

LGIA results in Commission-jurisdictional rates that are unjust and unreasonable.

143

See, e.g.,

NARUC Initial Comments at 35 (stating that the “loss of queue position as a result of adding a generating facility that does not increase the requested service level or cause reliability issues . . . is an inefficient and discriminatory outcome”).

144

See, e.g.,

AEE Initial Comments at 40-41; Public Interest Organizations Initial Comments at 45-47; SEIA Initial Comments at 38-39.

54. Finally, the record supports a finding that the Commission's

pro forma

LGIP and

pro forma

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

145

In addition, commenters contend that some alternative transmission technologies could provide substantial benefits by resolving thermal overloads and avoiding voltage collapse, allowing for better use of the existing transmission system, improving reliability, and reducing interconnection request withdrawals, restudies, and overall interconnection delays.

146

We find that failing to require transmission providers to evaluate the list of alternative transmission technologies enumerated in this final rule results in interconnection customers paying more than is just and reasonable to reliably interconnect new generating facilities, resulting in Commission-jurisdictional rates that are unjust, unreasonable, and unduly discriminatory or preferential. Because the benefits of the enumerated alternative transmission technologies identified above are present across all interconnection processes, regardless of the size of the interconnection request, we find that the failure to evaluate the enumerated alternative transmission technologies results in both the

pro forma

LGIP and

pro forma

SGIP being unjust, unreasonable, and unduly discriminatory or preferential.

145

See, e.g.,

NARUC Initial Comments at 38 (stating that “failing to consider alternative transmission technologies that can be deployed both more quickly and at lower costs than network upgrades may render Commission-jurisdictional rates unjust and unreasonable”); OMS Initial Comments at 19 (agreeing that “failing to consider these alternative transmission technologies runs the risk of implementing longer lead-time network upgrades at a higher cost”).

146

See, e.g.,

AEE Initial Comments at 42 (stating that alternative transmission technologies “provide benefits beyond potential costs savings, including maximizing limited rights-of-way and potentially avooiding or minimizing environmental and property impacts taht can bog down siting and permitting proceedings”); Ohio Commission Consumer Advocate Initial Comments at 15 (stating that “[t]hese grid-enhancing technologies (‘GETs’) can improve opertations, enhance system reliability, contribute to capacity, and more” and “[s]ome [grid-enhancing technologies] could provide substantial benefits by resolving thermal overloads and avoiding voltage collapse, among other things”); WATT Coalition Initial Comments at 2 (referring to the report

Unlocking the Queue with Grid Enhancing Technologies

that showed that application of the three grid-enhancing technologies in the Kansas and Oklahoma transmission systems would enable twice as much renewable energy to interconnect out of the queues without any traditional transmission upgrades.).

55. Fifth, we find that the Commission's existing

pro forma

LGIP and

pro forma

SGIP do not include a modeling requirement for non-synchronous generating facilities, which is necessary to enable the transmission provider to assess and model the facility's ability to respond appropriately to transmission system disturbances. These modeling requirements include: (1) a validated, user-defined root mean square (RMS) positive sequence dynamic model; (2) an appropriately parameterized, generic library RMS positive sequence dynamic model; and (3) a validated electromagnetic transient (EMT) model, if the transmission provider performs an EMT study as part of the interconnection study process. Additionally, we find that accurate and validated models are necessary to address study delays and to ensure that transmission providers identify the necessary interconnection facilities and network upgrades to accommodate the interconnection request and appropriate assignment of interconnection costs. As a result, we find that the lack of a modeling requirement for non-synchronous generating facilities in the

pro forma

LGIP and

pro forma

SGIP results in rates that are unjust, unreasonable, and unduly discriminatory or preferential.

56. Furthermore, the physical characteristics of synchronous generating facilities allow them to continue to inject electric current during transmission system disturbances, as required by the

pro forma

LGIA and

pro forma

SGIA.

147

However, non-synchronous generating facilities do not face a comparable requirement and many cease injecting current through “momentary cessation,” which creates reliability issues on the transmission system.

148

Moreover, without requirements for non-synchronous generating facilities to remain connected to and synchronized with the transmission system, interconnection studies may not accurately model expected behavior and identify the appropriate interconnection facilities and network upgrades to accommodate the interconnection request, skewing the assignment of interconnection costs. As a result, we find that the lack of comparable requirements for non-synchronous generating facilities to remain “connected to and synchronized with the [t]ransmission [s]ystem” in the

pro forma

LGIA and

pro forma

SGIA results in rates that are unjust, unreasonable, and unduly discriminatory or preferential.

147

Pro forma

LGIA art. 9.7.3 and

pro forma

SGIA art. 1.5.7 require synchronous generating facilities to remain “connected to and synchronized with” the transmission system during system disturbances.

148

See, e.g.,

NERC Initial Comments at 9 (stating that “improper planning and operation of [non-synchronous resources] can pose a significant risk to . . . reliability” and adding that “risk mitigation measures . . . have been inconsistently adopted by industry”); MISO TOs Initial Comments at 32-33 (concurring with the Commission that “with more and more non-synchronous generation facilities entering the interconnection queue, the lack of a requirement for such resources to respond to system disturbances becomes `more consequential' ”).

57. In response to commenters that express broad opposition to the need for reform, we disagree with assertions that the existence of regional variation in interconnection procedures across the country creates an insufficient legal foundation under FPA section 206 to demonstrate that rates are unjust, unreasonable, and unduly discriminatory or preferential. Similarly, we disagree with assertions that reforms to the

pro forma

generator interconnection procedures and agreements are arbitrary and capricious because the problems identified herein do not exist uniformly. As an initial matter, the “Commission may rely on `generic' or `general' findings of a systemic problem to support imposition

of an industry-wide solution.”

149

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

150

The Commission may reasonably rely on rulemaking to address the systemic drivers leading to widespread interconnection queue backlogs and delays, notwithstanding regional variation among interconnection procedures.

149

S.C. Pub. Serv. Auth.

FERC,

762 F.3d 41, 67 (D.C. Cir. 2014) (quoting

Interstate Nat. Gas Ass'n of Am.

FERC,

285 F.3d 18, 37 (2002)).

150

Id.

(quoting

Wis. Gas

FERC,

770 F.2d 1144, 1157 (D.C. Cir. 1985)).

58. Moreover, as noted above, every region of the country is seeing an increase in both interconnection queue size and the length of time interconnection customers are spending in the interconnection queue prior to commercial operation in recent years.

151

Furthermore, the uncertainty and delays in the interconnection queues have resulted in fewer than 25% of interconnection requests, by capacity, reaching commercial operation between 2000 and 2017 in any region of the country—with some regions as low as 8%.

152

For example, only 10% of interconnection requests, by capacity, have reached commercial operation in the non-RTO/ISO southeast region between 2000 and 2017.

153

Additionally, the challenges being faced across the country will be further compounded in the future given the recent spikes in interconnection queue sizes. In the non-RTO/ISO southeast region, the interconnection queue size has more than tripled between 2014 and 2022, with the increase predominantly made up of solar, storage, and hybrid generating facilities, adding potential complexity to future interconnection queue study processes.

154

To the extent existing

pro forma

interconnection procedures, such as first-come, first-served study processes, have worked in the past for smaller or less complex queues, such experience is not indicative of what will be necessary in the future to ensure that a growing number of interconnection requests are processed in a reliable, efficient, transparent, and timely manner.

155

Finally, as recognized in Order No. 2003, interconnection queue delays may “provide[] an unfair advantage to utilities that own both transmission and generation facilities,”

156

making it exceedingly necessary that interconnection delays are addressed in all regions of the country, especially those where transmission providers continue to own both transmission and generation.

157

As discussed above, because interconnection queue backlogs and delays afflict generator interconnection service nationwide, which hinders the timely development of new generation and thereby stifles competition in the wholesale electric markets, reforms are necessary to ensure Commission-jurisdictional rates are just, reasonable, and not unduly discriminatory or preferential.

151

Queued Up 2023 at 9, 32.

152

Id.

at 3, 21.

153

Id.

at 21.

154

Id.

at 9.

155

See, e.g.,

Public Interest Organization Initial Comments at 17; R Street Initial Comments at 3.

156

Order No. 2003, 104 FERC ¶ 61,103 at P 11.

157

See, e.g.,

Pine Gate Initial Comments at 15; AEE Reply Comments at 22.

59. We are not persuaded by commenters' concerns that the reforms proposed in the NOPR, many of which we adopt in this final rule, will be counterproductive in addressing the need for reform. As discussed in more detail throughout this final rule, we believe that the reforms adopted herein, as a whole, will improve the efficiency of study processes, reduce interconnection queue backlogs, and thereby ensure just, reasonable, and not unduly discriminatory or preferential rates. We believe that, on balance, the reforms will produce efficiencies by, for example, reducing speculative interconnection requests and interconnection request withdrawals, which in turn will reduce the time and resources spent in interconnection studies and restudies thereby decreasing interconnection queue backlogs and delays. Additionally, the majority of the individual reforms that the Commission proposed in the NOPR and we adopt in this final rule have already been implemented in one or more regions in order to improve the interconnection process, demonstrating incremental improvements. This final rule uses some of these individual and incremental improvements as a basis for a broad suite of reforms that, in their entirety, have not yet been adopted by any region and we believe will ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner. In some cases, such as for the commercial readiness reforms adopted in this final rule, we have significantly modified the NOPR proposal based on comments received.

60. Having concluded that the existing

pro forma

generator interconnection procedures and agreements are unjust, unreasonable, and unduly discriminatory or preferential, we turn, as we are required to do under FPA section 206,

158

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

158

16 U.S.C. 824e(a);

see, e.g., FERC

Electric Power Supply Ass'n,

577 US 260, 277 (2016) (“If FERC sees a violation of [the just and reasonable] standard, it must take remedial action.”)

III. Reforms

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

1. Interconnection Information Access

a. Need for Reform

i. NOPR

61. The Commission noted its concern regarding the lack of information available to prospective interconnection customers regarding potential interconnection costs prior to submitting an interconnection request.

159

The Commission stated that, without this information, it is difficult for interconnection customers to assess the viability of a specific proposed generating facility. Subsequently, interconnection customers submit multiple speculative interconnection requests in an attempt to obtain information through the system impact study process about the costs associated with various project configurations. The Commission preliminarily found that the Commission's

pro forma

LGIP and

pro forma

LGIA are unjust, unreasonable, and unduly discriminatory or preferential and that reforms are needed to allow interconnection customers to interconnect in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services are just, reasonable, and not unduly discriminatory or preferential.

160

159

NOPR, 179 FERC ¶ 61,194 at P 40.

160

Id.

P 39.

ii. Comments

62. Several commenters contend that it is a rational response to a lack of pre-interconnection queue information for interconnection customers to submit multiple interconnection requests to gain information on which interconnection sites are favorable and hedge risks, which leads to withdrawals that exacerbate unmanageable interconnection queue backlogs.

161

ELCON and Environmental Defense

Fund argue that the lack of sufficient information and unexpected cost escalation are the primary reasons interconnection requests are withdrawn, leading to delays and inefficiencies.

162

161

AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; Clean Energy Buyers Initial Comments at 5-6; CREA and NewSun Initial Comments at 45; Environmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 3; Northwest and Intermountain Initial Comments at 5; Public Interest Organizations Initial Comments at 18.

162

Environmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 4.

63. Many commenters agree with the goal of providing additional information prior to entering the interconnection queue.

163

Some commenters state that additional information prior to entering the interconnection queue is beneficial,

164

in particular access to information on potential network upgrades and the cost and time to interconnect.

165

Many commenters expect that potential interconnection customers' access to additional information prior to entering the interconnection queue will reduce speculative interconnection requests, thus promoting reliability and cost savings by encouraging more optimal interconnection requests that can be processed more efficiently and at lower overall cost.

166

163

ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP Initial Comments at 12; AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; APS Initial Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial Comments at 15; MISO Initial Comments at 20-21; NARUC Initial Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial Comments at 13; PJM Initial Comments at 45; Puget Sound Initial Comments at 5; WAPA Initial Comments at 5.

164

AEP Initial Comments at 12; APS Initial Comments at 4.

165

EEI Reply Comments at 7-8; New Jersey Commission Initial Comments at 23; NV Energy Initial Comments at 13.

166

Affected Interconnection Customers Initial Comments at 30; Clean Energy States Initial Comments at 3; Duke Southeast Utilities Initial Comments at 6; Environmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 3-4; Fervo Energy Initial Comments at 2-3; Google Initial Comments at 4-5; NARUC Initial Comments at 4-5; NESCOE Reply Comments at 3; New Jersey Commission Initial Comments at 20-22; New York State Department Initial Comments at 8; Pacific Northwest Utilities Initial Comments at 13; Public Interest Organizations Initial Comments at 18; Puget Sound Initial Comments at 5; SDG&E Initial Comments at 3-4.

64. Several commenters note the importance of additional interconnection information access in light of the other reforms proposed in the NOPR. AES contends that it would be inequitable for the Commission to increase security deposits to stay in the interconnection queue under the NOPR proposal to increase study and LGIA deposits without requiring transmission providers to provide sufficient information to interconnection customers.

167

Vistra asserts that the proposals to provide additional information will complement the exclusive site control proposals and provide an avenue for prospective interconnection customers to select the most viable sites on which to obtain rights and develop a location, which is a costly and time-consuming process, before entering the interconnection queue.

168

Northwest and Intermountain argue that, in order for the other proposed reforms in the NOPR to be effective, potential interconnection customers must have a solution to the problem of identifying optimal interconnection locations and configurations that is timely, cost-effective, and accurate.

169

167

AES Initial Comments at 13.

168

Vistra Initial Comments at 4.

169

Northwest and Intermountain Initial Comments at 9.

65. Google contends that pre-queue information is necessary because there is an extreme information asymmetry between independent power producers and transmission owners and their generating affiliates, which have greater access to planning information, including load growth, relative cost of interconnecting at different points, points of chronic congestion where upgrades might be needed, and planned local upgrades.

170

Google asserts that this information asymmetry is particularly pronounced in the non-RTO/ISO regions, and allows transmission owners and their affiliates to identify the best locations for interconnection more quickly than independent power producers.

170

Google Initial Comments at 3-4.

66. On the other hand, Dominion argues that there is no evidence in the record that a lack of information is slowing down the interconnection queue process or that transmission providers are not engaged in good faith reviews of interconnection requests.

171

According to Dominion, the Commission should focus on making the interconnection process more efficient and speedier, and the best way to achieve these goals is through the first-ready, first-served cluster study reform. While APPA-LPPC support transparency in the generator interconnection process and share the Commission's view that the availability of transmission system information should reduce the incentive to submit speculative interconnection requests, they argue that sufficient information is currently publicly available.

172

171

Dominion Reply Comments at 8-9.

172

APPA-LPPC Initial Comments at 11.

iii. Commission Determination

67. We find that, absent reforms to require transmission providers to provide additional interconnection information, which can be used by interconnection customers prior to submitting an interconnection request, speculative interconnection requests will likely remain at current levels and continue to contribute to interconnection study delays and add costs to the interconnection process. Although submitting multiple interconnection requests to gain information may be a rational response to a lack of pre-interconnection queue information, this practice increases interconnection study delays.

173

We also agree with commenters that additional access to interconnection information is a valuable goal

174

as it can increase the likelihood that an interconnection request is viable when submitted. We disagree with commenters that current information requirements are sufficient.

175

While certain information is currently available through the feasibility study process, as part of our reforms discussed below, we eliminate the feasibility study. Therefore, we find it necessary to provide a means for interconnection customers to obtain additional information prior to entering the interconnection queue. We concur with comments that additional access to interconnection information prior to entering the interconnection queue is important for interconnection customers to make informed decisions, particularly given the increased requirements for interconnection customers adopted in this final rule, such as increased study deposits and site control, as discussed

below.

176

We also agree that commenters raise a valid concern that an information asymmetry exists between independent power producers and transmission owner affiliates, in particular in non-RTO/ISO regions.

177

173

See

AES Initial Comments at 3; Affected Interconnection Customers Initial Comments at 30; Clean Energy Buyers Initial Comments at 5-6; CREA and NewSun Initial Comments at 45; Enviornmental Defense Fund Initial Comments at 3; ELCON Initial Comments at 3; Northwest and Intermountain Initial Comments at 5; Public Interest Organizations Initial Comments at 18.

174

Comments at 13; PJM Initial Comments at 45; Puget Sound Initial Comments at 5; WAPA Initial Comments at 5.

175

APPA-LPPC Initial Comments at 9.

176

AES Initial Comments at 13; Northwest and Intermountain Initial Comments at 9; Vistra Initial Comments at 4.

177

Google Initial Comments at 3-5.

b. Informational Interconnection Study

i. NOPR Proposal

68. In the NOPR, the Commission proposed to revise the Commission's

pro forma

LGIP to require transmission providers to offer an informational interconnection study for prospective interconnection customers.

178

The Commission proposed that the informational interconnection study would provide cost estimates for the transmission provider's interconnection facilities and network upgrade costs specific to the interconnection scenario detailed in the study agreement. The Commission also proposed to include new definitions for an informational interconnection study and informational interconnection study agreement.

178

NOPR, 179 FERC ¶ 61,194 at P 42.

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

179

The Commission explained that each configuration of an interconnection request would require a separate informational interconnection study. The Commission proposed that the informational interconnection study would be at the interconnection customer's expense, and each study would require a $10,000 deposit, subject to a true-up based on actual study costs.

179

Id.

P 43.

70. The Commission proposed that, within seven business days of the receipt of a prospective interconnection customer's request for an informational interconnection study, the transmission provider would have to provide the prospective interconnection customer with an informational interconnection study agreement.

180

The Commission explained that the informational interconnection study agreement would specify the technical data that the prospective interconnection customer must provide and an estimate of the expected costs of the study, including, to the extent known by the transmission provider, an estimate of the study costs expected to be incurred by any relevant affected systems. Under the proposal, the prospective interconnection customer would have 10 business days to execute the agreement and deliver it to the transmission provider, along with the relevant technical data and study deposit, after which the transmission provider would have 45 calendar days to complete the study.

180

Id.

P 44.

71. The Commission proposed that the informational interconnection study would consist of a sensitivity analysis based on the assumptions specified in the informational interconnection study agreement.

181

Under the proposal, the informational interconnection study would identify potential interconnection facilities and network upgrades that may be required to interconnect the prospective interconnection customer's proposed generating facility, including an approximation of the costs of such interconnection facilities and network upgrades. The Commission noted that the transmission provider would also coordinate with affected systems that may be impacted by the prospective interconnection customer's request to provide information on affected systems-related issues.

181

Id.

P 45.

72. The Commission proposed an informational interconnection study agreement form, which explains that the informational interconnection study is performed solely for informational purposes and is not binding on either party.

182

The proposed agreement also requires the study report to provide specific information, including, at a minimum: (1) preliminary identification of any circuit breaker short circuit capability limits exceeded; (2) preliminary identification of any thermal overload or voltage limit violations; and (3) estimated network upgrade costs related to the identified overloads and violations.

182

Id.

P 46.

73. The Commission sought comment on: (1) whether the informational interconnection study, as proposed, would provide prospective interconnection customers with sufficient and timely information to inform decision-making prior to submitting an interconnection request; (2) whether transmission providers should be required to establish a request window of a limited number of days each year in which potential interconnection customers can request an optional informational interconnection study; and (3) the burdens on transmission providers of conducting informational studies and whether other options, such as the proposal discussed below for public interconnection information, might strike a better balance of providing interconnection customers with useful information while making efficient use of transmission provider resources.

183

Id.

PP 47-48.

74. Additionally, the Commission proposed to add new section 3.1.2 to the

pro forma

LGIP, which provides that interconnection customers evaluating different options (such as different sizes, sites, or voltages) are encouraged but not required to use the new informational interconnection study proposed in the NOPR before entering the cluster study.

184

Id.

P 66.

ii. Comments

(a) Comments in Support

75. Several commenters support the NOPR proposal to require transmission providers to offer an informational interconnection study to prospective interconnection customers.

185

Several commenters agree that the informational interconnection study proposal could reduce the number of speculative or other interconnection requests

186

and improve the efficiency of siting decisions.

187

Some commenters expect that these changes will have other benefits for the interconnection process, including cost savings from fewer and more viable interconnection requests,

188

a reduced need for project withdrawals and queue restudies,

189

and reduced burden on transmission providers, which will result in fewer interconnection study delays.

190

185

Affected Interconnection Customers Initial Comments at 30; Clean Energy States Initial Comments at 4; Consumers Energy Initial Comments at 3; Duke Southeast Utilities Initial Comments at 6; Evergreen Action Initial Comments at 3; Fervo Energy Initial Comments at 2; Illinois Commission Initial Comments at 6; Interwest Initial Comments at 4, 7; NESCOE Reply Comments at 2; Public Interest Organizations Initial Comments at 18; Southern Initial Comments at 28; Tesla Initial Comments at 4; Tri-State Initial Comments at 5.

186

Fervo Energy Initial Comments at 2-3; Google Initial Comments at 4; NRECA Initial Comments at 13; NY Commission and NYSERDA Initial Comments at 6-8.

187

Duke Southeast Utilities Initial Comments at 6-7; ISO-NE Initial Comments at 18; NARUC Initial Comments at 5; NRECA Initial Comments at 13; Pine Gate Initial Comments at 13-14; Tesla Initial Comments at 4.

188

Evergreen Action Initial Comments at 3; NARUC Initial Comments at 5.

189

Evergreen Action Initial Comments at 3; NRECA Initial Comments at 13.

190

Google Initial Comments at 4.

76. MISO and Fervo Energy state that it is helpful for a prospective interconnection customer to compare how various MW sizes, points of interconnection, or other scenarios could affect costs, especially for prospective interconnection customers that cannot perform such analysis in house, and that the NOPR's

informational interconnection study proposal would assist in these goals.

191

Pacific Northwest Organizations argue that, without upfront interconnection cost information, independent power producers may be discouraged from entering the interconnection queue if they are subjected to higher withdrawal fees, which may result in preventing them from being considered in request for proposals (RFPs) in the Pacific Northwest.

192

191

Fervo Energy Initial Comments at 2; MISO Initial Comments at 22.

192

Pacific Northwest Organizations Initial Comments at 3-4.

77. Some commenters stress the importance of the informational interconnection study in light of the other reforms proposed in the NOPR. For instance, Northwest and Intermountain aver that the informational study will be the primary resource for interconnection customers to demonstrate the feasibility and cost effectiveness of their interconnection plan and will serve as the foundation for subsequent negotiations for the documents that will establish commercial readiness of their project for the cluster study process.

193

Pacific Northwest Organizations assert that the NOPR's proposed commercial readiness framework would be problematic in the region without something like the informational interconnection study to discover costs before entering the queue.

194

193

Northwest and Intermountain Initial Comments at 6-7.

194

Pacific Northwest Organizations Initial Comments at 3.

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

195

or (2) request specific changes to the proposal.

196

195

Idaho Power Initial Comments at 3 (stating that it only supports the proposal if the informational interconnection study requirements are less prescriptive and allow for more flexibility); NRECA Initial Comments at 8 (stating that it does not oppose the proposal as long as the final rule includes a larger package of reforms to reduce speculative interconnection requests and speed up interconnection queues as well as affords reasonable flexibility on compliance); Ohio Commission Consumer Advocate Initial Comments at 6 (stating that informational studies should not interfere with other interconnection studies).

196

ACE-NY Initial Comments at 10; Avangrid Initial Comments at 21; Clean Energy Buyers Initial Comments at 7; ELCON Initial Comments at 4-5; NY Commission and NYSERDA Initial Comments at 6-7; Pattern Energy Initial Comments at 20; Pine Gate Initial Comments at 11-13; Southern Initial Comments at 28.

(b) Comments in Opposition

79. Many commenters oppose the NOPR proposal to require transmission providers to offer an informational interconnection study to prospective interconnection customers.

197

Many commenters argue that the informational interconnection study proposal could be a burden or divert resources,

198

which they contend would increase delays for the interconnection queue and other studies.

199

Dominion insists that the decision as to whether to offer informational interconnection studies should be the transmission provider's and must have limits.

200

Longroad Energy states that transmission-interconnected generating facilities are typically complex facilities with unique operating characteristics which would be poorly approximated in simplified studies.

201

Environmental Defense Fund states that, while it supported the informational interconnection studies proposal in its initial comments, after review of the other comments submitted, it recommends that the Commission reconsider the proposal and ensure that any informational interconnection study reform not delay other interconnection processes.

202

197

AECI Initial Comments at 3; AEP Initial Comments at 7; AEP Reply Comments at 2; APPA-LPPC Initial Comments at 3; Avangrid Initial Comments at 21; Bonneville Initial Comments at 3; CAISO Initial Comments at 5; Clean Energy Associations Initial Comments at 13; Dominion Reply Comments at 5; EEI Initial Comments at 11; EEI Reply Comments at 7-8; Enel Initial Comments at 9; ENGIE Initial Comments at 2; Eversource Initial Comments at 5; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at 14; Longroad Energy Reply Comments at 3; NextEra Initial Comments at 5; NextEra Reply Comments at 8; North Dakota Commission Initial Comments at 3-4; NV Energy Initial Comments at 14; OMS Initial Comments at 5; Ørstead Initial Comments at 7; PG&E Initial Comments at 9; PJM Initial Comments at 45; PPL Initial Comments at 4; SEIA Initial Comments at 3; SPP Initial Comments at 2, 3-4; Vermont Electric and Vermont Transco Initial Comments at 3; WIRES Initial Comments at 8.

198

AECI Initial Comments at 3; AEE Reply Comments at 5-6; AEP Initial Comments at 7-8; AEP Reply Comments at 2; AES Initial Comments at 4; Alliant Energy Initial Comments at 4; APPA-LPPC Initial Comments at 9; APS Initial Comments at 5; Bonneville Initial Comments at 3; CAISO Initial Comments at 6; Clean Energy Buyers Initial Comments at 6; Clean Energy States Initial Comments at 4; Dominion Reply Comments at 5-6; Environmental Defense Fund Reply Comments at 5; EEI Initial Comments at 11-12; EEI Reply Comments at 8-9; ELCON Initial Comments at 4-5; Enel Initial Comments at 9; ENGIE Initial Comments at 2; Eversource Initial Comments at 5; Google Initial Comments at 5; Idaho Power Initial Comments at 3; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at 14; Longroad Energy Reply Comments at 4-5; MISO Reply Comments at 17; National Grid Initial Comments at 9; NESCOE Reply Comments at 2; NextEra Reply Comments at 8-9, 11-12; New Jersey Commission Initial Comments at 21; North Dakota Commission Initial Comments at 3-4; NRECA Initial Comments at 14; NV Energy Initial Comments at 14; NYISO Initial Comments at 16; OMS Initial Comments at 5; Pine Gate Initial Comments at 12; PPL Initial Comments at 4-6; SDG&E Initial Comments at 3-4; SEIA Initial Comments at 3; SEIA Reply Comments at 4; SoCal Edison Initial Comments at 12; Tesla Initial Comments at 4; Vermont Electric and Vermont Transco Initial Comments at 3; WIRES Initial Comments at 8.

199

AECI Initial Comments at 3; AEP Initial Comments at 7-8; AEP Reply Comments at 2-3; AES Initial Comments at 4; Alliant Energy Initial Comments at 4; APS Initial Comments at 4; Bonneville Initial Comments at 3; CAISO Initial Comments at 6; Dominion Initial Comments at 9; Duke Southeast Utilities Initial Comments at 7-8; Environmental Defense Fund Reply Comments at 5; EEI Initial Comments at 11; ELCON Initial Comments at 4-5; Eversource Initial Comments at 5-6; Google Initial Comments at 5; Idaho Power Initial Comments at 3; Indicated PJM TOs Initial Comments at 13; MISO Reply Comments at 17; National Grid Initial Comments at 7, 10-11; NESCOE Reply Comments at 2; NextEra Reply Comments at 8; New Jersey Commission Initial Comments at 21; North Dakota Commission Initial Comments at 3-4; NRECA Initial Comments at 14; NYISO Initial Comments at 16-19; OMS Initial Comments at 5; Pennsylvania Commission Initial Comments at 11; PG&E Initial Comments at 9; PG&E Reply Comments at 5; Pine Gate Initial Comments at 12; PJM Initial Comments at 45; PPL Initial Comments at 4; SEIA Initial Comments at 4; SoCal Edison Initial Comments at 12; Tesla Initial Comments at 4.

200

Dominion Reply Comments at 5.

201

Longroad Energy Reply Comments at 7.

202

Environmental Defense Fund Reply Comments at 5.

80. Several commenters contend that the informational interconnection study proposal would not likely be valuable.

203

Clean Energy Associations assert that the proposed informational interconnection study would provide no information related to stability-driven network upgrades, rendering it near-useless in areas where stability limits are most typically the driver of network upgrades.

204

APPA-LPPC warn that informational interconnection studies could engender controversy because prospective interconnection customers would, notwithstanding the informational nature of the studies, likely rely upon the study results in

making investment decisions, even though the informational study results would inevitably diverge from the actual interconnection study results.

205

203

AEE Initial Comments at 9-10; AEE Reply Comments at 5-6; AEP Initial Comments at 7; AEP Reply Comments at 2; Alliant Energy Initial Comments at 4; CAISO Initial Comments at 5-6; Clean Energy Associations Initial Comments at 14; CREA and NewSun Initial Comments at 42; Dominion Reply Comments at 5; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial Comments at 9; ENGIE Initial Comments at 2; Eversource Initial Comments at 5-6; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at 14; ISO-NE Initial Comments at 19; Longroad Energy Reply Comments at 3; MISO Initial Comments at 20-21; MISO Reply Comments at 17-18; NextEra Initial Comments at 5, 10-11; NextEra Reply Comments at 9; North Dakota Commission Initial Comments at 4; NRECA Initial Comments at 14; NV Energy Initial Comments at 14; NYISO Initial Comments at 17; OMS Initial Comments at 5; Pacific Northwest Utilities Initial Comments at 8 n.13; PG&E Initial Comments at 9; PG&E Reply Comments at 4; PJM Initial Comments at 45; SDG&E Initial Comments at 3-4; SEIA Initial Comments at 3; SEIA Reply Comments at 3; SoCal Edison Initial Comments at 11-12; WIRES Initial Comments at 8.

204

Clean Energy Associations Initial Comments at 14.

205

APPA-LPPC Initial Comments at 12.

81. Several commenters argue that the proposal is not an improvement over the status quo.

206

National Grid and NextEra assert that it is unclear how the proposal would save any time compared to the status quo, and that the best way for an interconnection customer to obtain the necessary information is by entering and proceeding through the interconnection queue with transmission providers focusing on actual studies.

207

NextEra adds that the proposed informational interconnection study is only informative in extreme cases, such as very limited capacity available on a transmission line, which the interconnection customer should be able to identify themselves.

208

206

National Grid Initial Comments at 9; New Jersey Commission Initial Comments at 21; Vermont Electric and Vermont Transco Initial Comments at 3.

207

National Grid Initial Comments at 9; NextEra Initial Comments at 12.

208

NextEra Initial Comments at 12.

82. CREA and NewSun express concern that the NOPR proposal places too much reliance on the usefulness of the informational interconnection study in order to justify the financial readiness and commitment NOPR proposals.

209

They assert that the informational interconnection study is not a useful replacement for the feasibility study, which takes into account the impact of other interconnection customers in the interconnection queue cluster. Therefore, CREA and NewSun ask the Commission to instead retain the feasibility study as part of the cluster study process to allow interconnection customers to obtain cluster-level information on likely costs and network upgrades before proceeding further with major deposits and irretrievable commitments.

209

CREA and NewSun Initial Comments at 46-47.

83. Several commenters point to the experience with similar studies in SPP and MISO as evidence that the optional informational interconnection study proposal will be little-used in practice.

210

SPP reports that its interconnection customers explained that their time could be more effectively spent working on the more definitive system impact studies, that the feasibility and preliminary impact studies did not provide results that could be relied on in making business decisions, and that this same outcome would be true of the proposed informational interconnection study.

211

210

AEE Initial Comments at 10; AEP Initial Comments at 8,12; Clean Energy Associations Initial Comments at 14; Enel Initial Comments at 9-10; Longroad Energy Reply Comments at 3-4; MISO Initial Comments at 21; NextEra Reply Comments at 8; Omaha Public Power Initial Comments at 3; SEIA Reply Comments at 3; SPP Initial Comments at 3. NextEra argues that transmission providers with large numbers of interconnection requests have tried optional interconnection studies and have not found them to be useful. NextEra Reply Comments at 10.

211

SPP Initial Comments at 3.

84. Several commenters point to the inability of the informational interconnection studies to provide reliable cost estimates

212

and believe that the information provided in these studies will be quickly outdated.

213

The New Jersey Commission is concerned that this approach may not materially reduce the uncertainty interconnection customers currently face.

214

In particular, many commenters contend that the informational interconnection study is not meaningful in the context of a cluster interconnection

212

AEP Initial Comments at 8; Ameren Initial Comments at 5; CAISO Initial Comments at 5; Clean Energy Associations Initial Comments at 14; CREA and NewSun Initial Comments at 43; Cyprus Creek Initial Comments at 13; Enel Initial Comments at 9; Interwest Initial Comments at 7-8; NextEra Initial Comments at 5; NRECA Initial Comments at 14; PJM Initial Comments at 45; SoCal Edison Initial Comments at 11-12.

213

AEP Initial Comments at 8; Alliant Energy Initial Comments at 4; Dominion Initial Comments at 10; Enel Initial Comments at 9; Eversource Initial Comments at 9; Interwest Initial Comments at 7-8; PJM Initial Comments at 45; PJM TOs Initial Comments at 13; SEIA Reply Comments at 4.

214

New Jersey Commission Initial Comments at 21.

process.

215

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

216

215

Id.;

AEE Initial Comments at 9-10; Avangrid Initial Comments at 23-24; Clean Energy Associations Initial Comments at 14; CREA and NewSun Initial Comments at 43; Dominion Reply Comments at 6; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial Comments at 9; Eversource Initial Comments at 9-10; ISO-NE Initial Comments at 18-19; MISO Initial Comments at 21; NRECA Initial Comments at 14; NV Energy Initial Comments at 14; PJM Initial Comments at 45; PPL Initial Comments at 5; SEIA Initial Comments at 4-5; SEIA Reply Comments at 3-4; SoCal Edison Initial Comments at 12; SPP Initial Comments at 2-3.

216

AEE Initial Comments at 9-10; CAISO Initial Comments at 5-6; CREA and NewSun Initial Comments at 44; Dominion Initial Comments at 10; Duke Southeast Utilities Initial Comments at 7; EEI Reply Comments at 8; Indicated PJM TOs Initial Comments at 13; ISO-NE Initial Comments at 18-19; MISO Initial Comments at 22; NextEra Initial Comments at 11-12; New Jersey Commission Initial Comments at 21; PG&E Reply Comments at 5; PPL Initial Comments at 5; SEIA Reply Comments at 3-4; SoCal Edison Initial Comments at 12.

85. Some commenters expect the proposal will work against the Commission's goal of faster interconnection queue processing.

217

Some commenters state that any reduction in speculative interconnection requests will be offset by an increase in speculative informational interconnection requests, which would require transmission providers to shift their focus from the actual interconnection queue to this more burdensome informational interconnection process, which is outside of their interconnection study process.

218

NRECA states that, if the proposal is included in the final rule, the Commission should ensure that it is limited and is not expanded into an elaborate serial study process prior to the cluster study process.

219

Avangrid notes that some transmission providers have recently eliminated interconnection studies to reduce interconnection queue processing time.

220

Pennsylvania Commission asserts that the Commission should assess the results of the NOPR's proposed reforms before requiring any new study processes that may further slow the interconnection queue process.

221

217

AEE Reply Comments at 6; AEP Initial Comments at 11; Avangrid Initial Comments at 22-23; CAISO Initial Comments at 6; Dominion Reply Comments at 6-7; National Grid Initial Comments at 7; NESCOE Reply Comments at 2; NV Energy Initial Comments at 14; Pennsylvania Commission Initial Comments at 11-12.

218

AECI Initial Comments at 4; AEP Initial Comments at 11; APPA-LPPC Initial Comments at 11-12; Bonneville Initial Comments at 3 (citing NOPR, 179 FERC ¶ 61,194 at PP 20, 22, 166); Clean Energy Buyers Initial Comments at 6; Dominion Reply Comments at 6; NextEra Initial Comments at 12; NYISO Initial Comments at 17; Pennsylvania Commission Initial Comments at 11 (explaining that because the informational study is not binding on any party, the study does not move projects through the interconnection queue).

219

NRECA Initial Comments at 14.

220

Avangrid Initial Comments at 23 (citing NOPR, 179 FERC ¶ 61,194 at P 56 n.111).

221

Pennsylvania Commission Initial Comments at 11-12.

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

222

Id.

at 11; AEP Initial Comments at 10-11; APPA-LPPC Initial Comments at 12; Avangrid Initial Comments at 22-23; Bonneville Initial Comments at 5; Eversource Initial Comments at 5-6; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at 14; LADWP Initial Comments at 2; OMS Initial Comments at 5.

87. Several commenters urge the Commission to weigh the benefits against the burdens to determine whether to adopt the informational interconnection study proposal.

223

WAPA states that, while it agrees that it is important to provide prospective interconnection customers with additional information, it has concerns about the proposed timelines and penalties, the potential amount of informational interconnection study requests it could receive, and its ability to process up to five simultaneous informational interconnection study requests per interconnection customer.

224

According to Vermont Electric and Vermont Transco, even if the informational interconnection studies envisioned by the NOPR provide interconnection customer benefits, the burdens of providing informational interconnection studies with cost estimates under the NOPR's short proposed time frames and low deposit amounts would be considerable especially for smaller companies such as Vermont Electric and Vermont Transco.

225

Other commenters contend that the informational interconnection study proposal has insufficient benefits.

226

223

Ameren Initial Comments at 5; R Street Initial Comments at 9; Xcel Initial Comments at 20.

224

WAPA Initial Comments at 4-5.

225

Vermont Electric and Vermont Transco Initial Comments at 3.

226

Id.;

AEP Initial Comments at 7; AES Initial Comments at 4; EEI Initial Comments at 11; ENGIE Initial Comments at 2; NextEra Initial Comments at 10-11; Ørstead Initial Comments at 7; PJM Initial Comments at 45; SEIA Initial Comments at 3.

88. Given PJM's opposition to the informational interconnect study, it recommends modifying the proposed new section 3.1.2 to the

pro forma

LGIP to encourage, but not require, interconnection customers evaluating different project characteristics to use a prescreening tool, such as the queue scope tool PJM is developing, prior to submitting an interconnection request.

227

PJM Initial Comments at 19 (explaining that the queue scope is an interactive prescreening tool that will allow interconnection customers to screen potential points of interconnection and assess grid capacity (head room) based on a given amount of MW injection or withdrawal at a given point of interconnection and that the tool will be available at no charge). PJM's proposed section 3.1.2 of the

pro forma

LGIP would read: “Interconnection Customers evaluating different options . . . to use the prescreening tool (Section 6.1 of this LGIP) before entering the Cluster Study.”

iii. Commission Determination

89. We decline to adopt the NOPR proposal to modify the

pro forma

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

90. We also find persuasive comments that the informational interconnection study requirement proposed in the NOPR is not the most effective way to provide interconnection customers with the needed pre-interconnection queue information. At the same time, we continue to believe that there is a lack of information available to prospective interconnection customers prior to entering the interconnection queue, especially given other interconnection customer-related reforms adopted in this final rule.

228

Therefore, as discussed below, we adopt the NOPR proposal to set minimum requirements for transmission providers to publicly post available information pertaining to generator interconnection.

229

We find that the posting of this information provides a better balance between the benefits of additional information for prospective interconnection customers and the burdens on transmission providers.

228

See

Northwest and Intermountain Initial Comments at 6-7.

229

See infra

section III.A.1.c.iii.

91. In response to commenters that support the informational interconnection study NOPR proposal, below we explain how several of the NOPR proposals that we adopt in this final rule address their specific concerns. To address commenters' concerns with the number of speculative interconnection requests,

230

we adopt more stringent site control requirements and increased commercial readiness deposit requirements,

231

which we believe will better address these concerns than the informational interconnection study proposal. Additionally, we find that the minimum requirements for transmission providers to publicly post available information pertaining to generator interconnection

232

and the existing requirements in section 2.3 of the

pro forma

LGIP for transmission providers to post up-to-date base case study models on their Open Access Same-time Information System (OASIS) or other password-protected websites will improve the efficiency of siting decisions

233

and will provide interconnection customers with information about the feasibility of their interconnection plans.

234

230

Fervo Energy Initial Comments at 2-3; Google Initial Comments at 4; NRECA Initial Comments at 13; NY Commission and NYSERDA Initial Comments at 6-8.

231

See infra

sections III.A.6.b.iii, III.A.6.c.iii.

232

See infra

section III.A.1.c.iii.

233

234

Northwest and Intermountain Initial Comments at 6-7; Pacific Northwest Organizations Initial Comments at 3.

92. We are not persuaded that the informational interconnection study proposal would benefit the interconnection process through: (1) cost savings from fewer, more feasible interconnection requests;

235

(2) a reduced need for interconnection request withdrawals and restudies;

236

and (3) accurate upfront interconnection cost information.

237

On the contrary, the Commission's adoption of the cluster study reforms in this final rule

238

means that the serial nature of the informational interconnection study would fail to reflect the outcome of the cluster study, and thus would provide minimal, if any, benefits to interconnection customers.

239

We also no longer believe that adopting the informational interconnection study

proposal would reduce burdens on transmission providers.

240

This is because the record overwhelmingly demonstrates that the proposal would result in additional burdens on transmission providers and would likely cause transmission providers to divert resources from their cluster study process to conduct informational interconnection studies,

241

thus increasing study delays and costs. Similarly, we decline CREA and NewSun's request that the Commission retain the feasibility study instead of the informational interconnection study. As we discuss below, the feasibility study was required for the serial study process but is no longer relevant for the cluster study process.

242

We believe that our requirement for transmission providers to publicly post certain interconnection information will provide interconnection customers with the information they need prior to entering the interconnection queue, and therefore decline to adopt CREA and NewSun's request to maintain the feasibility study.

235

Evergreen Action Initial Comments at 3; NARUC Initial Comments at 5.

236

Evergreen Action Initial Comments at 3; NRECA Initial Comments at 13.

237

Fervo Energy Initial Comments at 2; MISO Initial Comments at 22; Pacific Northwest Organizations Initial Comments at 3-4.

238

See infra

section III.A.2.

239

See

AEE Initial Comments at 9-10; Avangrid Initial Comments at 23-24; Clean Energy Associations Initial Comments at 14; CREA and NewSun Initial Comments at 43; Dominion Reply Comments at 6; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial Comments at 9; Eversource Initial Comments at 9-10; ISO-NE Initial Comments at 18-19; MISO Initial Comments at 21; New Jersey Commission Initial Comments at 21; NRECA Initial Comments at 14; NV Energy Initial Comments at 14; PJM Initial Comments at 45; PPL Initial Comments at 5; SEIA Initial Comments at 4-5; SEIA Reply Comments at 3-4; SoCal Edison Initial Comments at 12; SPP Initial Comments at 2-3.

240

See

Google Initial Comments at 5 (arguing that the informational interconnection study requirement alone would likely increase the burden on transmission providers in a way that would lengthen delays).

241

Id.;

AECI Initial Comments at 3; AEE Reply Comments at 5-6; AEP Initial Comments at 7-8; AEP Reply Comments at 2; AES Initial Comments at 4; Alliant Energy Initial Comments at 4; APPA-LPPC Initial Comments at 9; APS Initial Comments at 5; Bonneville Initial Comments at 3; CAISO Initial Comments at 6; Clean Energy Buyers Initial Comments at 6; Clean Energy States Initial Comments at 4; Dominion Reply Comments at 5-6; Environmental Defense Fund Reply Comments at 5; EEI Initial Comments at 11-12; EEI Reply Comments at 8-9; ELCON Initial Comments at 4-5; Enel Initial Comments at 9; ENGIE Initial Comments at 2; Eversource Initial Comments at 5; Idaho Power Initial Comments at 3; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at 14; Longroad Energy Reply Comments at 4-5; MISO Reply Comments at 17; National Grid Initial Comments at 9; NESCOE Reply Comments at 2; New Jersey Commission Initial Comments at 21; NextEra Reply Comments at 8-9, 11-12; North Dakota Commission Initial Comments at 3-4; NRECA Initial Comments at 14; NV Energy Initial Comments at 14; NYISO Initial Comments at 16; OMS Initial Comments at 5; Pine Gate Initial Comments at 12; PPL Initial Comments at 4-6; SDG&E Initial Comments at 3-4; SEIA Initial Comments at 3; SEIA Reply Comments at 4; SoCal Edison Initial Comments at 12; Tesla Initial Comments at 4; Vermont Electric and Vermont Transco Initial Comments at 3; WIRES Initial Comments at 8.

242

See infra

section III.A.2.f.iii.

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

pro forma

LGIP to encourage interconnection customers to use the informational interconnection study.

c. Public Interconnection Information

i. NOPR Proposal

94. In the NOPR, the Commission proposed to require transmission providers to maintain and make publicly available an interactive visual representation of available interconnection capacity (commonly known as a “heatmap”) as well as a table of relevant interconnection metrics that allow prospective interconnection customers to see certain estimates of a potential generating facility's effect on the transmission provider's transmission system.

243

Specifically, the Commission proposed to revise section 6.4 of the

pro forma

LGIP to require transmission providers to post on their public website a heatmap of estimated incremental injection capacity (in MW) available at each bus in the transmission provider's footprint under N-1 conditions, as well as provide a table of results showing the estimated impact of the addition of a proposed project (based on the user-specified MW amount, voltage level, and point of interconnection) for each monitored facility impacted by the proposed project on: (1) the distribution factor; (2) the MW impact (based on the proposed project size and the distribution factor); (3) the percentage impact on the monitored facility (based on the MW values of the proposed project and the monitored facility rating); (4) the percentage of power flow on the monitored facility before the proposed project; and (5) the percentage power flow on the monitored facility after the injection of the proposed project. The Commission explained that these metrics would be calculated based on the power flow model of the cluster study or restudy with the transfer simulated from each bus to the whole transmission provider's footprint (to approximate Network Resource Interconnection Service (NRIS)), and with the incremental capacity at each bus decremented by the existing and queued generation in the cluster (based on the existing or requested interconnection service limit of the generation). The Commission proposed to require transmission providers to update this information within 30 days after the completion of each cluster study and restudy.

243

NOPR, 179 FERC ¶ 61,194 at P 51.

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

244

Id.

P 52.

ii. Comments

(a) Comments in Support

96. Many commenters express support for the NOPR's proposal to require transmission providers to provide public interconnection information.

245

Several commenters agree that the NOPR proposal will provide valuable information to interconnection customers before they enter the interconnection queue.

246

Several commenters aver that the proposal could reduce the number of interconnection requests withdrawn

247

and therefore could reduce costs for all parties.

248

Alliant Energy and Clean Energy Associations also see value in the standardized format of the proposed

public interconnection information.

249

R Street states that a properly done visual representation of interconnection capacity can be a “powerful decentralized self-screening tool.”

250

R Street states that better information and simpler deliverability requirements shift congestion performance risk to generating facilities while reducing barriers to entry.

251

The Ohio Commission Consumer Advocate states that the visual map of available interconnection capacity would be useful both to transmission providers and interconnection customers and would encourage information sharing on transmission system congestion during the interconnection process.

252

Google argues that making these data publicly available to consumers would allow buyers to make informed choices regarding power procurement.

253

Additionally, Google asserts that there needs to be a standard of reasonable care applied to ensure that the publicly available information is reasonably current and useful to avoid exploratory interconnection requests.

254

SEIA argues that greater transparency will increase competition between merchant and utility developed generating facilities, benefiting consumers.

255

Illinois Commission contends that, if properly implemented, the NOPR proposal will increase the pace at which new generating facilities can connect to the transmission s

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