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Rule2024-06563

Improvements to Generator Interconnection Procedures and Agreements

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Published

April 16, 2024

Effective

May 16, 2024

Issuing agencies

Energy DepartmentFederal Energy Regulatory Commission

Abstract

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

Full Text

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[Federal Register Volume 89, Number 74 (Tuesday, April 16, 2024)]
[Rules and Regulations]
[Pages 27006-27243]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-06563]

[[Page 27005]]

Vol. 89

Tuesday,

No. 74

April 16, 2024

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Improvements to Generator Interconnection Procedures and Agreements;
Rule

Federal Register / Vol. 89 , No. 74 / Tuesday, April 16, 2024 / Rules
and Regulations

[[Page 27006]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

Improvements to Generator Interconnection Procedures and
Agreements

AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on rehearing and clarification.

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

DATES: This rule is effective May 16, 2024.

FOR FURTHER INFORMATION CONTACT:
Anne Marie Hirschberger (Legal Information), Office of the General
Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8387,
<a href="/cdn-cgi/l/email-protection#3b5a55555e565a49525e15535249485853595e495c5e497b5d5e4958155c544d">[email&#160;protected]</a>.

Sarah Greenberg (Legal Information), Office of the General Counsel, 888
First St. NE, Washington, DC 20426, (202) 502-6230,
<a href="/cdn-cgi/l/email-protection#1d6e7c6f7c75337a6f7878737f786f7a5d7b786f7e337a726b">[email&#160;protected]</a>.

Franklin Jackson (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-6464,
<a href="/cdn-cgi/l/email-protection#88eefae9e6e3e4e1e6a6e2e9ebe3fbe7e6c8eeedfaeba6efe7fe">[email&#160;protected]</a>.
Michael G. Henry, Office of Energy Policy and Innovation, 888 First
Street NE, Washington, DC 20426, (202) 502-8583,
<a href="/cdn-cgi/l/email-protection#cca1a5afa4ada9a0e2a4a9a2beb58caaa9beafe2aba3ba">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Background
II. Discussion
A. Need for Reform
1. Order No. 2023
2. Requests for Rehearing and Clarification
3. Determination
B. Arguments Regarding Conflicts With Ongoing Queue Reform
Efforts and Evaluation of Variations on Compliance
1. Order No. 2023 Requirements
2. Requests for Rehearing and Clarification
3. Determination
C. Reforms To Implement a First-Ready, First-Served Cluster
Study Process
1. Public Interconnection Information
2. Cluster Study Process
3. Allocation of Cluster Network Upgrade Costs
4. Shared Network Upgrades
5. Increased Financial Commitments and Readiness Requirements
6. Transition Process
D. Reforms To Increase the Speed of Interconnection Queue
Processing
1. Elimination of Reasonable Efforts Standard and Implementation
of a Replacement Rate
2. Affected Systems
E. Reforms To Incorporate Technological Advancements Into the
Interconnection Process
1. Increasing Flexibility in the Generation Interconnection
Process
2. Incorporating the Enumerated Alternative Transmission
Technologies Into the Generator Interconnection Process
3. Modeling and Ride Through Requirements for Non-Synchronous
Generating Facilities
F. Compliance Procedures
1. Order No. 2023 Requirements
2. Requests for Rehearing and Clarification
3. Determination
III. Information Collection Statement
IV. Environmental Analysis
V. Regulatory Flexibility Act
VI. Document Availability
VII. Effective Date

I. Background

1. On July 28, 2023, the Federal Energy Regulatory Commission
(Commission) issued Order No. 2023.\1\ Order No. 2023 required all
public utility transmission providers to adopt revised pro forma Large
Generator Interconnection Procedures (LGIP), pro forma Large Generator
Interconnection Agreements (LGIA), pro forma Small Generator
Interconnection Procedures (SGIP), and pro forma Small Generator
Interconnection Agreements (SGIA).\2\ These revisions ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner, and
will prevent undue discrimination.\3\ In Order No. 2023, the Commission
adopted a comprehensive package of reforms in three general categories:
(1) reforms to implement a first-ready, first-served cluster study
process, (2) reforms to increase the speed of interconnection queue
processing, and (3) reforms to incorporate technological advancements
into the interconnection process.
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\1\ Improvements to Generator Interconnection Procs. &
Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC ]
61,054 (2023).
\2\ Id. P 1 n.1 (``Section 201(e) of the Federal Power Act (FPA)
defines ``public utility'' to mean ``any person who owns or operates
facilities subject to the jurisdiction of the Commission under this
subchapter.'' 16 U.S.C. 824(e). A non-public utility that seeks
voluntary compliance with the reciprocity condition of a tariff may
satisfy that condition by filing a tariff, which includes the pro
forma LGIP, the pro forma SGIP, the pro forma LGIA, and the pro
forma SGIA. See Standardization of Generator Interconnection
Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003),
104 FERC ] 61,103, at PP 1, 616 (2003), order on reh'g, Order No.
2003-A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ] 61,220, order on
reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), 109 FERC ] 61,287
(2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (June 30,
2005), 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of
Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007) (NARUC
v. FERC). As stated in the pro forma LGIP, pro forma LGIA, pro forma
SGIP, and pro forma SGIA, transmission provider ``shall mean the
public utility (or its designated agent) that owns, controls, or
operates transmission or distribution facilities used for the
transmission of electric energy in interstate commerce and provides
transmission service under the [Transmission Provider's Tariff]. The
term . . . should be read to include the Transmission Owner when the
Transmission Owner is separate from the Transmission Provider.'' Pro
forma LGIP section 1; pro forma LGIA art. 1; pro forma SGIP attach.
1; pro forma SGIA attach. 1.'').
\3\ Order No. 2023, 184 FERC ] 61,054 at P 1.
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2. To implement a first-ready, first served cluster study process,
Order No. 2023: (1) required transmission providers to post public
interconnection information in an interactive heatmap to provide
interconnection customers information before they enter the queue; (2)
eliminated individual serial feasibility and system impact studies and
created a cluster study; (3) created a range of allowable allocations
of cluster study costs; (4) required transmission providers to use a
proportional impact method to assign network upgrade costs within a
cluster; (5) required increased financial commitments and readiness
requirements from interconnection customers, including increased study
deposits, site control, commercial readiness deposits, an LGIA deposit,
and required transmission providers to institute penalties for
withdrawn interconnection requests; and (6) created a transition
mechanism for moving to the cluster study process adopted in Order No.
2023 from the existing serial study process.\4\
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\4\ Id. P 5.
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3. To increase the speed of interconnection queue processing, Order
No. 2023: (1) eliminated the reasonable efforts standard for completing
interconnection studies and adopted study delay penalties applicable
when transmission providers fail to complete interconnection studies

[[Page 27007]]

by the deadlines in their tariff; and (2) established a more detailed
affected system study process in the pro forma LGIP, including pro
forma affected system agreements and uniform modeling standards.\5\
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\5\ Id. P 6.
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4. To incorporate technological advancements into the
interconnection process, Order No. 2023: (1) required transmission
providers to allow more than one generating facility to co-locate on a
shared site behind a single point of interconnection and share a single
interconnection request; (2) required transmission providers to
evaluate the proposed addition of a generating facility to an existing
interconnection request prior to deeming such an addition a material
modification; (3) required transmission providers to allow
interconnection customers to access the surplus interconnection service
process once the original interconnection customer has an executed LGIA
or requests the filing of an unexecuted LGIA; (4) required transmission
providers, at the request of the interconnection customer, to use
operating assumptions in interconnection studies that reflect the
proposed charging behavior of electric storage resources; (5) required
transmission providers to evaluate an enumerated list of alternative
transmission technologies during the study process; (6) required each
interconnection customer requesting to interconnect a non-synchronous
generating facility to submit to the transmission provider certain
specific models of the generating facility; (7) established ride
through requirements during abnormal frequency conditions and voltage
conditions within the ``no trip zone'' defined by NERC Reliability
Standard PRC-024-3 or successor mandatory ride through reliability
standards; and (8) required that all newly interconnecting large
generating facilities provide frequency and voltage ride through
capability consistent with any standards and guidelines that are
applied to other generating facilities in the balancing authority area
on a comparable basis.\6\
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\6\ Id. P 6.
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5. The Commission received 32 timely filed requests for rehearing
and/or clarification, and two additional requests for clarification.\7\
The rehearing requests raise issues related to nearly all reforms
adopted in Order No. 2023.
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\7\ Appendix A provides the short names of the entities that
filed requests for rehearing or clarification. Shell filed an
answer. Rule 713(d)(1) of the Commission's Rules of Practice and
Procedure (18 CFR 385.713(d)) prohibits an answer to a request for
rehearing. Accordingly, we deny Shell's motion to answer and reject
its answer.
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6. Pursuant to Allegheny Defense Project v. FERC,\8\ the rehearing
requests filed in this proceeding may be deemed denied by operation of
law. However, as permitted by section 313(a) of the Federal Power Act
(FPA),\9\ we are modifying the discussion in Order No. 2023, setting
aside the order, in part, and clarifying the order, as discussed
below.\10\
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\8\ 964 F.3d 1 (D.C. Cir. 2020) (en banc).
\9\ 16 U.S.C. 825l(a) (``Until the record in a proceeding shall
have been filed in a court of appeals, as provided in subsection
(b), the Commission may at any time, upon reasonable notice and in
such manner as it shall deem proper, modify or set aside, in whole
or in part, any finding or order made or issued by it under the
provisions of this chapter.'').
\10\ Allegheny Def. Project, 964 F.3d at 16-17. In Appendices C,
D, E, and F, we provide the revisions to the provisions of the pro
forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA made
in this order on rehearing and clarification. Additionally, these
Appendices reflect several non-substantive corrections in these
appendices to address stylistic inconsistencies or clerical errors
in some of the new and revised pro forma provisions.
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7. Specifically, we set aside the order, in part, to specify that:
(1) where an interconnection customer is in the interconnection queue
of a transmission provider that currently uses, or is transitioning to,
a cluster study process and the transmission provider proposes on
compliance to adopt new readiness requirements for its annual cluster
study, the interconnection customer must comply with the transmission
provider's new readiness requirements within 60 days of the Commission-
approved effective date of the transmission provider's compliance
filing, where such readiness requirements are applicable given the
status of the individual interconnection customer in the queue; (2) a
network upgrade that is required for multiple interconnection customers
in a cluster may be considered a stand alone network upgrade if all
such interconnection customers mutually agree to exercise the option to
build; (3) transmission providers must complete their determination
that an interconnection request is valid by the close of the cluster
request window such that only interconnection customers with valid
interconnection requests proceed to the customer engagement window; and
(4) acceptable forms of security for the Commercial Readiness Deposit
and deposits prior to the Transitional Serial Study, Transitional
Cluster Study, Cluster Restudy and the Interconnection Facilities Study
should include not only cash or an irrevocable letter of credit, but
also surety bonds or other forms of financial security that are
reasonably acceptable to the transmission provider.
8. Additionally, we grant several clarifications on the following
topics, as further discussed below: (1) conflicts with ongoing queue
reform efforts; (2) public interconnection information; (3) cluster
study process; (4) allocation of cluster network upgrade costs; (5)
shared network upgrades; (6) withdrawal penalties; (7) study delay
penalty and appeal structure; (8) affected systems; (9) revisions to
the material modification process to require consideration of
generating facility additions; (10) availability of surplus
interconnection service; (11) operating assumptions for interconnection
studies; (12) consideration of the enumerated alternative transmission
technologies in interconnection studies; and (13) ride-through
requirements.
9. Finally, in light of the revisions made to the pro forma LGIP,
pro forma LGIA, pro forma SGIP, and pro forma SGIA herein, we extend
the deadline for transmission providers to submit compliance filings
until the effective date of this order (i.e., the new deadline for
compliance with Order No. 2023 will be 30 days after the publication of
this order in the Federal Register, and must include the further
revisions reflected in this order).

II. Discussion

A. Need for Reform

1. Order No. 2023
10. The Commission stated that it found substantial evidence in the
record to support the conclusion that the existing pro forma generator
interconnection procedures and agreements were unjust, unreasonable,
and unduly discriminatory or preferential.\11\ Therefore, pursuant to
FPA section 206, the Commission concluded that certain revisions to the
pro forma open access transmission tariff and the Commission's
regulations were necessary to ensure rates that are just, reasonable,
and not unduly discriminatory or preferential. Specifically, the
Commission found that the existing pro forma generator interconnection
procedures and agreements were insufficient to ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner,
thereby ensuring that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly
discriminatory or preferential. The

[[Page 27008]]

Commission stated that, absent reform, the interconnection process will
continue to cause interconnection queue backlogs, longer development
timelines, and increased uncertainty regarding the cost and timing of
interconnecting to the transmission system. The Commission explained
that these backlogs and delays, and the resulting timing and cost
uncertainty, hinder the timely development of new generation and
thereby stifle competition in the wholesale electric markets resulting
in rates, terms, and conditions that are unjust, unreasonable, and
unduly discriminatory or preferential.
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\11\ Order No. 2023, 184 FERC ] 61,054 at P 37.
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11. The Commission cited recent data to support its findings that
the dramatic increase in the number of interconnection requests and
limited transmission capacity are increasing interconnection queue
backlogs across all regions of the country.\12\ This data indicated
that, as of the end of 2022, there were over 10,000 active
interconnection requests in interconnection queues throughout the
United States, representing over 2,000 gigawatts (GW) of potential
generation and storage capacity.\13\ These interconnection requests and
the generating facilities they represent amount to the largest
interconnection queue size on record, more than four times the total
volume (in GW) of the interconnection queues in 2010, and a 40%
increase over the interconnection queue size from just the year prior.
The Commission explained that these trends are not exclusive to any
specific region of the country; rather, every region, including
regional transmission organizations (RTO), independent system operators
(ISO), and non-RTOs/ISOs, has faced an increase in both interconnection
queue size and the length of time interconnection customers are
spending in the interconnection queue prior to commercial operation in
recent years. The Commission noted that the uncertainty and delays in
the interconnection queues have resulted in fewer than 25% of
interconnection requests, by capacity, reaching commercial operation
between 2000 and 2017 in any region of the country--with some regions
as low as 8%.
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\12\ Id. P 38 (citing Energy Markets & Policy- Berkeley Lab,
Queued Up: Characteristics of Power Plants Seeking Transmission
Interconnection, 7-8 (Apr. 2023) (Queued Up 2023), <a href="https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf">https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf</a>;
Appendix B to Order No. 2023, which provided an overview of recent
data based on reporting by transmission providers in compliance with
Order No. 845).
\13\ Id. (citing Queued Up 2023).
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12. The Commission also cited recent data that interconnection
customers are waiting longer in the interconnection queue before
withdrawing their interconnection requests, even as overall
interconnection study timelines are increasing in many regions.\14\
Despite efforts to address these challenges, the Commission observed
that interconnection queue backlogs and delays have persisted and
worsened. For generating facilities built in 2022, wait times in the
interconnection queue saw a marked increase from 2.1 years for
generating facilities built in 2000-2010 to roughly five years for
generating facilities built in 2022.
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\14\ Id. P 39.
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13. The Commission explained that delays in the interconnection
study process are an important contributor to interconnection queue
backlogs nationwide.\15\ The Commission cited recent interconnection
study metrics transmission providers filed with the Commission, as
required by Order No. 845, which showed that of the 2,179
interconnection studies completed in 2022, 68% were issued late. At the
end of 2022, an additional 2,544 studies were delayed (i.e., ongoing
and past their deadline). All of the RTOs/ISOs except CAISO and most
non-RTO/ISO transmission providers (14 of 38) reported pending delayed
studies at the end of 2022.
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\15\ Id. P 40.
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14. The Commission found that numerous factors have contributed to
the increasing volume of interconnection requests, including a rapidly
changing resource mix, market forces, and emerging technologies.\16\
The Commission also found that available transmission capacity has been
largely or fully used in many regions, creating situations where
interconnection customers face significant network upgrade cost
assignments to interconnect their proposed generating facilities. As an
example, the Commission cited a U.S. DOE report that found that
interconnection costs in MISO doubled for generating facilities for
which the interconnection studies were completed between 2019 and 2021
as compared to those completed prior to 2019, and cost estimates
tripled for proposed generating facilities still active in the
interconnection queue between the same time periods.\17\ The Commission
also noted that other reports show similar cost increases in NYISO and
PJM.\18\ The Commission found that this combination of increased volume
of interconnection requests and insufficient transmission capacity and
therefore higher costs to interconnect, which can result in
interconnection request withdrawals, has resulted in longer
interconnection queue processing times and larger, more delayed
interconnection queues.
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\16\ Id. P 41.
\17\ Id. (citing Joachim Seel et al., Generator Interconnection
Cost Analysis in the Midcontinent Independent System Operator (MISO)
Territory, 1, 4-5 (Oct. 2022), <a href="https://emp.lbl.gov/interconnection_costs">https://emp.lbl.gov/interconnection_costs</a>.).
\18\ Id. (citing Julia Mulvaney Kemp et al., Interconnection
Cost Analysis in the NYISO Territory (Mar. 2023), <a href="https://emp.lbl.gov/publications/interconnection-cost-analysis-nyiso">https://emp.lbl.gov/publications/interconnection-cost-analysis-nyiso</a>
(showing that costs have doubled for generating facilities studied
since 2017, relative to costs for generating facilities studied from
2006 to 2016); Joachim Seel et al., Interconnection Cost Analysis in
the PJM Territory (Jan. 2023), <a href="https://emp.lbl.gov/publications/interconnection-cost-analysis-pjm">https://emp.lbl.gov/publications/interconnection-cost-analysis-pjm</a> (showing that costs for recent
``complete'' generating facilities have doubled on average relative
to costs from 2000-2019)).
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15. The Commission explained that interconnection queue backlogs
and delays have created uncertainty for interconnection customers
regarding the timing and cost of ultimately interconnecting to the
transmission system, which may lead to an increase in costs to
consumers.\19\ The Commission stated that delayed interconnection study
results or unexpected cost increases can disrupt numerous aspects of
generating facility development and such uncertainty, either on the
part of transmission providers or interconnection customers, is
ultimately passed through to consumers through higher transmission or
energy rates. The Commission explained that increases in energy rates
may result from wholesale customers having limited access to new and
more competitive supplies of generation and that, conversely, efficient
interconnection queues and well-functioning wholesale markets deliver
benefits to consumers by driving down wholesale electricity costs.
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\19\ Id. P 43.
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16. Overall, due to continuing and increasing interconnection queue
backlogs and study delays, the Commission found that the Commission's
existing rules contained in the pro forma LGIP, pro forma LGIA, pro
forma SGIP, and pro forma SGIA resulted in rates, terms, and conditions
for Commission-jurisdictional services that are unjust, unreasonable,
and unduly discriminatory or preferential.\20\ The Commission found
that the problems described above lead to an inability of
interconnection customers to interconnect to the transmission system in
a reliable, efficient, transparent, and timely manner, and

[[Page 27009]]

hindered the timely development of new generation, thereby stifling
competition in the wholesale electric markets. Therefore, the
Commission found that reform to the Commission's existing pro forma
generator interconnection procedures and agreements was necessary.
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\20\ Id. P 44.
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17. The Commission based its findings that the pro forma LGIP, pro
forma LGIA, pro forma SGIP, and pro forma SGIA must be reformed on the
following features: (1) the information (or lack thereof) available to
prospective interconnection customers and the commitments required of
them to enter and progress through the interconnection queue; (2) the
reliance on a serial first-come, first-served study process and the
reasonable efforts standard that transmission providers are held to for
meeting interconnection study deadlines; (3) the protocols (or lack
thereof) for affected system studies; (4) the provisions for studying
new generating facility technologies and evaluating the list of
alternative transmission technologies enumerated in Order No. 2023; and
(5) the modeling or performance requirements (or lack thereof) for non-
synchronous generating facilities, including wind, solar, and electric
storage facilities.\21\ The Commission further explained each of these
five features.
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\21\ Id. P 45.
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18. First, the Commission explained that, without a process by
which an interconnection customer can obtain information about
potential interconnection costs at a specific location or point of
interconnection prior to submitting an interconnection request, it is
difficult for interconnection customers to assess the commercial
viability of a specific proposed generating facility prior to entering
the interconnection queue.\22\ The Commission also found that the pro
forma interconnection procedures and agreements failed to include
meaningful financial commitments and readiness requirements to enter
and stay in the interconnection queue and lacked stringent requirements
to establish the commercial viability of proposed generating
facilities. As a result, the Commission explained, interconnection
customers often submit multiple interconnection requests for proposed
generating facilities at various points of interconnection, knowing
that not all of them will reach commercial operation, as an exploratory
mechanism to obtain information to allow the interconnection customer
to choose to proceed with the interconnection request representing the
most favorable site in terms of potential interconnection-related
costs.
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\22\ Id. P 46.
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19. Second, the Commission explained that the existing serial
first-come, first-served study process created incentives for
interconnection customers to submit exploratory or speculative
interconnection requests pursuant to which interconnection customers
seek to secure valuable queue positions as early as possible, even if
they are not prepared to move forward with the proposed generating
facility.\23\ Such generating facilities are often not commercially
viable: thus, the interconnection customers ultimately withdraw their
interconnection requests from the interconnection queue, which triggers
reassessments and possible restudies by the transmission provider that
can delay the timing and increase the cost to interconnect for lower-
queued interconnection requests. The Commission found that the lack of
access to information about a specific location or point of
interconnection prior to submitting an interconnection request, the
lack of any meaningful financial commitments in the pro forma
interconnection procedures and agreements for interconnection customers
to enter and stay in the interconnection queue, as well as the existing
serial first-come, first-served study process, together incentivized
interconnection customers to submit speculative interconnection
requests that contribute to interconnection study backlogs, delays, and
uncertainty, and, in turn, unjust and unreasonable Commission-
jurisdictional rates.\24\
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\23\ Id. P 47.
\24\ Id. P 48.
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20. The Commission also found that interconnection queue backlogs
and delays, and the accompanying uncertainty, have been further
compounded because transmission providers have limited incentive to
perform interconnection studies in a timely manner.\25\ The Commission
stated that, despite pervasive delays in completing interconnection
studies by transmission providers, transmission providers have faced
few, if any, consequences for failing to meet their tariff-imposed
study deadlines under the reasonable efforts standard. The Commission
therefore found that the existing pro forma LGIP requirement for
transmission providers to make a reasonable effort to meet
interconnection study deadlines contributes to the interconnection
study backlogs, delays, and uncertainty that erects barriers to new
generation, resulting in Commission-jurisdictional rates that are
unjust and unreasonable.
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\25\ Id. P 50.
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21. Third, the Commission found that, without requirements for how
and when transmission providers should complete affected system
studies, those studies often lag behind those completed by the
transmission provider to whose transmission system the interconnection
customer proposes to interconnect (the host transmission provider) and
are sometimes completed very late in the interconnection process,
causing an additional round of delays and cost uncertainty for
interconnection customers.\26\ Additionally, for transmission providers
that have procedures for how to complete affected system studies in
their tariffs or other documents (e.g., business practice manuals or
joint operating agreements), the Commission found that those procedures
are not consistent, may be hard for interconnection customers to
locate, and may not represent the actual practices in use by the
transmission provider, thus still creating uncertainty for
interconnection customers. As a result, the Commission found that the
lack of consistent requirements for affected system modeling and
procedures results in Commission-jurisdictional rates that are unjust,
unreasonable, and unduly discriminatory or preferential.
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\26\ Id. P 51.
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22. Fourth, the Commission found that the Commission's pro forma
LGIP failed to accommodate the operating characteristics and technical
capabilities of electric storage resources when it comes to specific
interconnection procedures and modeling.\27\ The Commission noted that
interconnection queues predominantly consist of new technologies which
have operating characteristics that differ from synchronous resources
and were not anticipated when the Commission established the pro forma
generator interconnection procedures and agreements in Order Nos. 2003
and 2006. The Commission noted that the existing pro forma generator
interconnection procedures and agreements did not contemplate the
operating characteristics or technical capabilities of electric storage
resources, leading to electric storage resources being studied under
inappropriate operating assumptions (e.g., charging at full capacity
during peak load conditions) that result in the assignment of
unnecessary network upgrades which increase costs to interconnection
customers. Therefore, the Commission found that the inability to modify

[[Page 27010]]

operating assumptions for electric storage resources pursuant to the
pro forma LGIP resulted in Commission-jurisdictional rates that are
unjust, unreasonable, and unduly discriminatory or preferential.
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\27\ Id. P 52.
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23. The Commission also found that the existing pro forma
interconnection procedures regarding material modifications did not
provide for consistent evaluation of technology additions to an
existing interconnection request, and that automatically deeming a
request to add a generating facility to an existing interconnection
request to be a material modification creates a significant barrier to
access to the transmission system.\28\
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\28\ Id. P 53.
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24. Finally, the Commission found that the pro forma LGIP and pro
forma SGIP failed to require the consideration of alternative
transmission technologies that can be used as network upgrades and can
be deployed more quickly and at a lower cost than, traditional network
upgrades.\29\ The Commission found that failing to require transmission
providers to evaluate the enumerated list of alternative transmission
technologies resulted in interconnection customers paying more than is
just and reasonable to reliably interconnect new generating facilities,
ultimately creating Commission-jurisdictional rates that are unjust,
unreasonable, and unduly discriminatory or preferential.
---------------------------------------------------------------------------

\29\ Id. P 54.
---------------------------------------------------------------------------

25. Fifth, the Commission found that the Commission's existing pro
forma LGIP and pro forma SGIP did not include a modeling requirement
for non-synchronous generating facilities, which is necessary to enable
the transmission provider to assess and model the facility's ability to
respond appropriately to transmission system disturbances.\30\ The
Commission explained that interconnection customers must submit
accurate and validated models, which will prevent study delays and
ensure that transmission providers identify the necessary
interconnection facilities and network upgrades to accommodate the
interconnection request and thus allow the appropriate assignment of
interconnection costs to the interconnection request. Therefore, the
Commission found that the lack of a modeling requirement for non-
synchronous generating facilities in the pro forma LGIP and pro forma
SGIP results in rates that are unjust, unreasonable, and unduly
discriminatory or preferential. Additionally, the Commission explained
that the physical characteristics of synchronous generating facilities
allow them to continue to inject electric current during transmission
system disturbances, as required by the pro forma LGIA and pro forma
SGIA.\31\ However, non-synchronous generating facilities did not face a
comparable requirement and many cease injecting current during system
disturbances through ``momentary cessation,'' which creates reliability
issues on the transmission system. The Commission stated that, without
requirements for non-synchronous generating facilities to remain
connected to and synchronized with the transmission system during
system disturbances, interconnection studies may not accurately model
expected behavior and identify the appropriate interconnection
facilities and network upgrades to accommodate the interconnection
request, skewing the assignment of interconnection costs. As a result,
the Commission found that the lack of comparable requirements for non-
synchronous generating facilities to remain ``connected to and
synchronized with the [t]ransmission [s]ystem'' in the pro forma LGIA
and pro forma SGIA results in rates that are unjust, unreasonable, and
unduly discriminatory or preferential.
---------------------------------------------------------------------------

\30\ Id. P 55.
\31\ Id. P 56.
---------------------------------------------------------------------------

26. The Commission further found that the reforms adopted in Order
No. 2023 will improve the efficiency of study processes, reduce
interconnection queue backlogs, and thereby ensure just, reasonable,
and not unduly discriminatory or preferential rates.\32\ The Commission
explained that the majority of the individual reforms that the
Commission adopted have already been implemented in one or more regions
in order to improve the interconnection process, demonstrating
incremental improvements. The Commission compiled a package of such
reforms that, in their entirety, have not yet been adopted by any
region, and will ensure that interconnection customers are able to
interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner.
---------------------------------------------------------------------------

\32\ Id. P 59.
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
27. Dominion seeks rehearing, asserting that the Commission
exceeded its FPA section 206 authority by declaring all existing
interconnection tariffs, including recently accepted reforms by PJM and
Dominion Energy South Carolina (DESC), as unjust, unreasonable, and
unduly discriminatory or preferential without substantial evidence.\33\
Dominion asserts that the Commission did not establish a sufficient
legal foundation to generically find that all tariffs are unjust and
unreasonable.\34\ Similarly, Indicated PJM TOs argue that the
Commission arbitrarily and capriciously relied on inapposite and stale
evidence to impose a generic replacement rate on early adopters of the
cluster study approach.\35\ PJM also argues that the generic findings
underlying Order No. 2023 cannot apply to its Interconnection Process
Reform Task Force (IPRTF) Tariff, which was filed and approved during
the time period between issuance of the NOPR and Order No. 2023.\36\
Therefore, PJM contends, the data underlying Order No. 2023 is stale as
to PJM and its use does not constitute reasoned decision-making based
on substantial evidence.
---------------------------------------------------------------------------

\33\ Dominion Rehearing Request at 2.
\34\ Id. at 14 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
71, 65 (D.C. Cir. 2014) (S.C. Pub. Serv. Auth.) (``To regulate a
practice affecting rates pursuant to Section 206, the Commission
must find that the existing practice is `unjust, unreasonable,
unduly discriminatory or preferential,' and that the remedial
practice it imposes is `just and reasonable.' These findings must be
supported by `substantial evidence[.]'''); Emera Me. v. FERC, 854
F.3d 9, 25 (D.C. Cir. 2017) (Emera Me.) (``[A] finding that an
existing rate is unjust and unreasonable is the `condition
precedent' to FERC's exercise of its section 206 authority to change
that rate. Section 206, therefore, imposes a `dual burden' on FERC.
Without a showing that the existing rate is unlawful, FERC has no
authority to impose a new rate.'')).
\35\ Indicated PJM TOs Rehearing Request at 7, 17.
\36\ PJM Rehearing Request at 25-26.
---------------------------------------------------------------------------

28. Dominion acknowledges that the Commission is able to rely on
generic rulemakings to support an industry wide solution, but that
Order No. 2023 goes beyond the limits of this authority.\37\ Dominion
argues that Order No. 2023's mandate is unlike the generic rulemaking
upheld by the D.C. Circuit in Transmission Access Policy Study Group v.
FERC because the rule at issue in that case, Order No. 888, represented
a paradigm shift for which a generic rulemaking is appropriate.\38\
Dominion asserts that the other generic rulemakings upheld by the
courts similarly involve more wholesale reform than Order No. 2023,
such as the expansion and creation of new Order No. 1000 planning
obligations upheld in S.C. Pub. Serv. Auth., or the Order No. 637
requirement for gas pipelines to permit segmentation where

[[Page 27011]]

operationally feasible, upheld in Interstate Natural Gas Association of
America v. FERC.\39\ Dominion contends that the Commission's generic
findings in Order No. 2023 are disproportionate to the evidence the
Commission relies on. Similarly, Indicated PJM TOs assert that the
Commission's generic finding is overbroad because many RTOs/ISOs have
already adopted the core reforms in Order No. 2023.\40\
---------------------------------------------------------------------------

\37\ Dominion Rehearing Request at 12.
\38\ Id. (citing Transmission Access Pol'y Study Grp. v. FERC,
225 F.3d 667 (D.C. Cir. 2000) (TAPS), aff'd sub nom. N. Y. v. FERC,
535 U.S. 1 (2002)); see also Indicated PJM TOs Rehearing Request at
14.
\39\ Dominion Rehearing Request at 12-13 (citing S.C. Pub. Serv.
Auth., 762 F.3d at 67; Interstate Nat. Gas Ass'n of Am. v. FERC, 285
F.3d 18 (D.C. Cir. 2002) (INGAA)).
\40\ Indicated PJM TOs Rehearing Request at 7, 17-18 (citing PJM
Interconnection, L.L.C., 181 FERC ] 61,162 (2022)).
---------------------------------------------------------------------------

29. Dominion further argues that, while the courts have held that
the Commission can address case-by-case discrepancies between the
generic determination and specific tariffs during compliance filings,
this cannot be considered an unlimited way for the Commission to avoid
its obligation under the Administrative Procedure Act (APA) to rely on
substantial evidence when making FPA section 206 decisions.\41\
Dominion asserts that, because the Commission recently accepted
revisions to PJM's and DESC's tariffs to address the same issue that
Order No. 2023 attempts to address, the Commission must consider those
tariffs individually and may not sweep them up in a generic
determination based on evidence of queue backlogs made under previous
tariffs and regions.
---------------------------------------------------------------------------

\41\ Dominion Rehearing Request at 14 (citing INGAA, 285 F.3d at
37).
---------------------------------------------------------------------------

30. Dominion argues that Order No. 2023 was arbitrary and
capricious because it relied on out-of-date data and ignored contrary
data.\42\ Dominion asserts that, although the Commission is not
required to rely on ``empirical evidence,'' the Commission must support
its findings with substantial, up-to-date, evidence and cannot ignore
new circumstances.\43\ Dominion asserts that Order No. 2023 does not
reflect reasoned decision-making as it relates to PJM and DESC because
it relies on queue delays and backlogs that predate PJM's and DESC's
revised interconnection reforms and it does not consider those
currently effective interconnection reforms. Indicated PJM TOs point
out that the Order No. 845 data the Commission relied on is stale
because it concerns PJM's previous serial study process, and the
Commission's reliance on that data is inconsistent with its decision to
omit SPP's data from its consideration.\44\
---------------------------------------------------------------------------

\42\ Id. at 2.
\43\ Id. at 10 (citing S.C. Pub. Serv. Auth., 762 F.3d at 64-
65).
\44\ Indicated PJM TOs Rehearing Request at 18 n.45. Indicated
PJM TOs specifically point to Order No. 2023's citation to Order No.
845 data showing the number of delayed studies as of the end of
2022, ``with the vast majority of these studies (2,211)'' coming
from PJM, as stale data the Commission used to support the new
obligations Order No. 2023 will impose. Id. at 17.
---------------------------------------------------------------------------

31. Dominion argues that the Commission ignored evidence that PJM
and DESC had recently adopted interconnection reforms to address the
same problem addressed by Order No. 2023.\45\ Indicated PJM TOs state
that the Commission points repeatedly to problems associated with a
serial study approach, which are irrelevant to regions that already
implemented cluster studies.\46\ Dominion and Indicated PJM TOs argue
that the Commission should have considered whether PJM's, DESC's, and
other similarly situated transmission providers' reforms are working or
even had a chance to be fully implemented.\47\ Dominion argues that the
Commission cited no evidence to demonstrate that PJM's tariff is unjust
and unreasonable, and that it would be difficult to do so because PJM's
transitional process began on July 10, 2023, so there is no data
available to determine whether it is successful.\48\ Similarly,
Dominion notes that DESC's transition process began on June 13, 2022,
was based on 12 months of stakeholder engagement, and includes many
components of Order No. 2023. Dominion contends that reasoned decision-
making should at least require the Commission to consider all relevant
information, including information about the efficacy of reforms in
existing tariffs that are attempting to address the same problem the
Commission is relying upon to make its FPA section 206
determination.\49\
---------------------------------------------------------------------------

\45\ Dominion Rehearing Request at 12.
\46\ Indicated PJM TOs Rehearing Request at 18.
\47\ Id.; Dominion Rehearing Request at 13.
\48\ Dominion Rehearing Request at 8-9.
\49\ Id. at 13 (citing Greater Bos. Television Corp. v. Fed.
Communications Comm'n, 444 F.2d 841, 851 (D.C. Cir. 1970) (an agency
must give ``reasoned consideration to all the material facts and
issues'' and ``engage[] in reasoned decision making''); Tarpon
Transmission Co. v. FERC, 860 F.2d 439, 442 (D.C. Cir. 1988) (``We
cannot accept an agency determination unless it is the result of
reasoned and principled decisionmaking that can be ascertained from
the record.''); ANR Pipeline Co., 71 F.3d 897, 901 (D.C. Cir. 1995)
(``[W]here an agency departs from established precedent without a
reasoned explanation, its decision will be vacated as arbitrary and
capricious.''); Tenneco Gas v. FERC, 969 F.2d 1187, 1214 (D.C. Cir.
1992) (``Subsumed in the substantial evidence requirement is the
expectation that agencies will treat fully each of the pertinent
factors and issues before them.'' (internal citations omitted))).
---------------------------------------------------------------------------

32. Dominion also states that Order No. 2023 directly acknowledges
that CAISO and some non-RTO/ISO transmission providers had no delayed
studies at the end of 2022.\50\ Dominion argues that, instead of
supporting the Commission's finding that all interconnection processes
are unjust and unreasonable, Order No. 2023 acknowledges that the
problem is not as widespread as suggested and that intervening reforms
similar to what Order No. 2023 requires may already be addressing the
problem used to justify the FPA section 206 finding.
---------------------------------------------------------------------------

\50\ Id. at 15-16 (citing Order No. 2023, 184 FERC ] 61,054 at P
40).
---------------------------------------------------------------------------

33. Dominion states that, where an industry-wide solution is
imposed for a problem that only exists in isolated pockets, ``the
disproportion of remedy to ailment would, at least at some point,
become arbitrary and capricious.'' \51\ Dominion states that the Order
No. 2023 compliance obligation essentially requires all existing
processes to re-prove the justness and reasonableness of their
processes, creating a remedy that is ``disproportionate'' to the
identified problem.\52\
---------------------------------------------------------------------------

\51\ Id. at 13 (citing Assoc. Gas Distribs. v. FERC, 824 F.2d
981, 1019 (D.C. Cir. 1987) (Assoc. Gas)).
\52\ Id. at 7-8 (citing Order No. 2023, 184 FERC ] 61,054 at PP
1762-1764).
---------------------------------------------------------------------------

34. Dominion asks the Commission to confirm that, if compliance
filings are required of early adopters like PJM and DESC, the
Commission has the burden under FPA section 206 to find that existing
processes recently adopted are unjust and unreasonable.\53\ Dominion
asserts that the Commission must hew to the constraints created by FPA
section 206 and cannot shift the burden to individual early adopters to
defend their current rates.
---------------------------------------------------------------------------

\53\ Id. at 16 (citing INGAA, 285 F.3d at 37-39).
---------------------------------------------------------------------------

3. Determination
35. We sustain our finding in Order No. 2023 \54\ that the existing
pro forma generator interconnection procedures and agreements are
unjust, unreasonable, and unduly discriminatory or preferential.\55\ We
also continue to find that Order No. 2023's 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.
---------------------------------------------------------------------------

\54\ Order No. 2023, 184 FERC ] 61,054 at P 37.
\55\ 16 U.S.C. 824e(a); 18 CFR 385.206.
---------------------------------------------------------------------------

36. We note that Dominion's rehearing request misstates the
Commission's generic finding as ``declaring all existing
interconnection tariffs, including recently accepted reforms by PJM and
DESC, as unjust, unreasonable, and unduly

[[Page 27012]]

discriminatory or preferential.'' \56\ The findings in Order No. 2023
relate to the Commission's existing pro forma generator interconnection
procedures and agreements, which, among other things, relied on a
serial first-come, first-served study process.\57\ The Commission did
not make any findings regarding specific transmission provider's
tariffs, and it was not required to do so under FPA section 206.\58\
Issues regarding the individual tariffs of specific transmission
providers that currently deviate from the existing pro forma generator
interconnection procedures and agreements will be addressed on an
individual basis on compliance.\59\
---------------------------------------------------------------------------

\56\ Dominion Rehearing Request at 2.
\57\ Order No. 2023, 184 FERC ] 61,054 at P 37.
\58\ See, e.g., TAPS, 225 F.3d at 687-88 (upholding Commission
action under FPA section 206 premised on general systemic conditions
rather than evidence regarding individual utilities); S.C. Pub.
Serv. Auth., 762 F.3d at 67 (``[T]he Commission may rely on
`generic' or `general' findings of a systemic problem to support
imposition of an industry-wide solution.'') (citing INGAA, 285 F.3d
at 37); Assoc. Gas, 824 F.2d at 1008 (``The Commission is not
required to make individual findings, however, if it exercises its
Natural Gas Act Sec. 5 authority by means of a generic rule.'').
\59\ Order No. 2023, 184 FERC ] 61,054 at P 1765.
---------------------------------------------------------------------------

37. We disagree with Dominion's argument that Order No. 2023 goes
beyond the limits of our authority to rely on a generic rulemaking to
support an industry-wide solution. As noted above, Order No. 2023
adopts reforms to the existing pro forma interconnection procedures and
agreements, which themselves were adopted as an industry-wide reform to
identified, industry-wide problems.\60\ All three of the cases Dominion
relies on support the Commission's authority to issue Order No. 2023.
---------------------------------------------------------------------------

\60\ See id. PP 8-12 (explaining the need for and adopting pro
forma interconnection agreements and procedures); see also NARUC v.
FERC, 475 F.3d at 1279 (explaining, at the outset, the structural
connection between the nationwide reforms in Order No. 888 and those
in Order No. 2003).
---------------------------------------------------------------------------

38. When the D.C. Circuit upheld Order No. 888 in TAPS, the court
specifically explained that the Commission can rely on general findings
of systemic conditions to impose an industry-wide remedy under FPA
section 206.\61\ The court agreed with the Commission that specific
evidence regarding individual utilities' behavior is not required under
FPA section 206. Similarly, when upholding Order No. 637 in INGAA, the
D.C. Circuit stated that ``our cases have long held that the Commission
may rely on `generic' or `general' findings of a systemic problem to
support imposition of an industry-wide solution.'' \62\ The D.C.
Circuit explicitly rejected an argument that the Commission
impermissibly shifted the burden of proof merely by requiring pro forma
filings.\63\ Several years later, when upholding Order No. 1000 in S.C.
Pub. Serv. Auth., the D.C. Circuit once again affirmed the Commission's
ability to promulgate nationwide rules, in lieu of case-by-case
adjudication, to solve a nationwide problem.\64\ The court explained
that, even though some regions had already satisfied some requirements
of the rule, the deficiencies identified by the Commission did not only
exist in ``isolated pockets,'' and ``[a]bsent such an extreme
`disproportion of remedy to ailment,' the Commission could reasonably
proceed to address a systemic problem with an industry-wide solution.''
\65\ Nothing in this precedent indicates that the Commission's
authority to promulgate generic rulemakings under FPA section 206
depends upon the rule representing a paradigm shift. Rather, the
precedent is clear that, where the Commission finds a systemic,
nationwide problem that renders the rates, terms, and conditions for
Commission-jurisdictional services unjust, unreasonable, unduly
discriminatory, or preferential, the Commission has authority to
implement a nationwide solution.\66\
---------------------------------------------------------------------------

\61\ TAPS, 225 F.3d at 687-88.
\62\ INGAA, 285 F.3d at 37.
\63\ Id. at 38.
\64\ S.C. Pub. Serv. Auth., 762 F.3d at 67.
\65\ Id.
\66\ S.C. Pub. Serv. Auth., 762 F.3d at 67; TAPS, 225 F.3d at
687-88; INGAA, 285 F.3d at 37.
---------------------------------------------------------------------------

39. Here, substantial evidence indicates that interconnection queue
delays and backlogs are a nationwide problem, not a problem that only
exists in isolated pockets. As explained in Order No. 2023,
interconnection queue backlogs are increasing across all regions of the
country, and ``every single region has faced an increase in both
interconnection queue size and the length of time interconnection
customers are spending in the interconnection queue prior to commercial
operation in recent years. This is true for RTO/ISO and non-RTO/ISO
regions alike.'' \67\ ``[T]he 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%.'' \68\ Appendix B to Order No. 2023 shows that most
transmission providers in the country were late in completing
interconnection studies in 2022.\69\ We acknowledge that the data
collected in compliance with Order No. 845 regarding PJM's queue
reflected PJM's previous study process, which was recently reformed.
However, excluding PJM's data would not change our overall conclusion
that interconnection queue backlogs and late interconnection studies
are a significant problem in most regions of the country. To the
contrary, we continue to find that ``the challenges being faced across
the country will be further compounded in the future,'' \70\ and that
the multiple factors contributing to interconnection queue backlogs,
longer development timelines, and increased uncertainty regarding the
cost and timing of interconnecting to the transmission system,
including increasing volume of interconnection requests, increased
complexity in interconnection studies, and insufficient transmission
capacity, are industry-wide challenges likely to persist and
potentially worsen in the future.\71\
---------------------------------------------------------------------------

\67\ Order No. 2023, 184 FERC ] 61,054 at P 38 (citing Queued Up
2023 at 7-9, 32).
\68\ Id. (citing Queued Up 2023 at 3, 21).
\69\ Id. at app. B.
\70\ Id. P 58.
\71\ Id. P 41.
---------------------------------------------------------------------------

40. Moreover, due to the early stages of PJM's reforms, the instant
record does not contain any information regarding the effects of such
reforms, including whether PJM is meeting all study deadlines on time,
the overall length of time to reach interconnection, or the portion of
interconnection customers reaching commercial operation. Nor does the
record support that any region, including PJM, is unaffected by the
underlying factors that are persistent and increasing drivers of
widespread interconnection queue delays and backlogs. Therefore, we
continue to find that the systemic problems identified in Order No.
2023 warrant a nationwide solution.
41. In response to Dominion's contention that the Commission
ignored evidence regarding recent queue reform efforts, we note that
Order No. 2023 specifically referenced these ongoing queue reform
efforts. The Commission stated:

We recognize that many transmission providers have adopted or
are in the process of adopting similar reforms to those adopted in
this final rule. We do not intend to disrupt these ongoing
transition processes or stifle further innovation. On compliance,
transmission providers can propose deviations from the requirements
adopted in this final rule--including deviations seeking to minimize
interference with ongoing transition plans--and demonstrate how
those deviations satisfy the standards \72\ discussed

[[Page 27013]]

above, which the Commission will consider on a case-by-case
basis.\73\
---------------------------------------------------------------------------

\72\ Specifically, where transmission providers propose
variations to the Order No. 2023 transition process, the Commission
will evaluate such proposals under the consistent with or superior
to standard for non-RTO transmission providers and the independent
entity variation standard for RTOs/ISOs.
\73\ Order No. 2023, 184 FERC ] 61,054 at P 1765.

In fact, in the NOPR underlying Order No. 2023, the Commission made
clear that it reviewed these recent queue reform efforts, learned from
them, and considered them in formulating a number of its proposals.\74\
---------------------------------------------------------------------------

\74\ Improvements to Generator Interconnection Procs. &
Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ] 61,194, at PP 86-
87, 112, 127, 132, 152-54 (2022) (NOPR).
---------------------------------------------------------------------------

42. However, as explained above, the Commission was not required to
make FPA section 206 findings specific to PJM or DESC's queue reforms.
The details of a specific transmission provider's tariff, and whether
its recent queue reform complies with the new requirements of Order No.
2023, are appropriately handled on an individual basis on compliance.
43. We disagree with Dominion's argument that Order No. 2023's
acknowledgement that some transmission providers had no delayed studies
in 2022 indicates that the problem is not as widespread as suggested.
The fact that a few transmission providers complete studies on time
does not mean that the problem exists only in isolated pockets. As the
D.C. Circuit explained in S.C. Pub. Serv. Auth., the fact that a
problem may not exist in every single region of the country ``is as
unastonishing as it is irrelevant, because petitioners have not shown
that the deficiencies identified by the Commission exist[] only in
isolated pockets.'' \75\
---------------------------------------------------------------------------

\75\ See S.C. Pub. Serv. Auth., 762 F.3d at 67 (citing Wis. Gas.
Co. v. FERC, 770 F.2d 1144, 1157 (D.C. Cir. 1985) (Wis. Gas.);
Assoc. Gas, 824 F.2d at 1019).
---------------------------------------------------------------------------

44. Moreover, substantial evidence indicates that these nationwide
interconnection queue delays and backlogs result in rates, terms, and
conditions in the wholesale electric markets that are unjust,
unreasonable, and unduly discriminatory or preferential.\76\
Interconnection queue delays and backlogs result in longer development
timelines, uncertainty regarding the cost and timing of interconnecting
to the transmission system, and ultimately higher rates, as ``wholesale
customers hav[e] limited access to new and more competitive supplies of
generation.'' \77\
---------------------------------------------------------------------------

\76\ Order No. 2023, 184 FERC ] 61,054 at PP 37, 44.
\77\ Id. PP 37, 43 (citing May Joint Task Force Tr. 74:9-21
(Andrew French) (stating that generator developers complain about
cost certainty); 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); Ameren Initial Comments at 2;
ELCON Initial Comments at 2; ELCON Initial Comments at 2; Xcel
Initial Comments at 8).
---------------------------------------------------------------------------

45. Further, we believe that the remedies adopted in Order No. 2023
are proportional to the issues identified. As explained in detail in
Order No. 2023, each of the reforms the Commission adopted are directly
related to the need to reform the pro forma generator 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, and will prevent undue
discrimination.\78\
---------------------------------------------------------------------------

\78\ Id. PP 45-56.
---------------------------------------------------------------------------

46. Further, we also believe that a generic, nationwide rulemaking
is justified by the need for consistent interconnection policies that
apply to all public utility transmission providers.\79\ We continue to
find that it is necessary to apply the reforms in Order No. 2023 on a
nationwide basis to ensure that interconnection customers are able to
interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner, and to prevent undue discrimination. We
further note that some of the critical reforms of Order No. 2023 could
only have been achieved through a nationwide rulemaking; for instance,
standardization of the affected systems study process requires rules
that apply to all jurisdictional transmission providers.
---------------------------------------------------------------------------

\79\ See Order No. 2003, 104 FERC ] 61,103 at P 11 (``[T]here is
a pressing need for a single set of [interconnection] procedures . .
. [which] will minimize opportunities for undue discrimination and
expedite the development of new generation, while protecting
reliability and ensuring that rates are just and reasonable.'').
---------------------------------------------------------------------------

47. For the reasons stated above, we disagree with Dominion's
argument that the Commission bears the burden on compliance to find
that recently adopted existing processes that deviate from the pro
forma generator interconnection procedures and agreements are unjust
and unreasonable.\80\ We reiterate that the findings in Order No. 2023
relate to the Commission's existing pro forma generator interconnection
procedures and agreements.\81\ We note that, on compliance, the
Commission will apply the consistent with or superior to standard for
non-RTO transmission providers and the independent entity variation
standard for RTOs/ISOs when analyzing deviations from the Commission's
pro forma LGIP, pro forma LGIA, pro forma SGIP and/or pro forma
SGIA.\82\
---------------------------------------------------------------------------

\80\ Elsewhere in this order, the Commission clarifies that
transmission providers need only re-file and seek approval for
previously approved variations where those provisions are modified
by Order No. 2023. See infra P 77.
\81\ Order No. 2023, 184 FERC ] 61,054 at P 37.
\82\ See Xcel Energy Servs. Inc. v. FERC, 41 F.4th 548, 557
(D.C. Cir. 2022) (``The Commission has used its discretion and
expertise to craft the ``consistent with or superior to'' test for
deviations from its pro forma rules.'') (citing Order No. 2003, 104
FERC ] 61,103 at P 826); see also Sacramento Mun. Util. Dist. v.
FERC, 428 F.3d 294, 296 (D.C. Cir. 2005) (explaining that utilities
can deviate from the terms of the pro forma tariff if such
deviations are consistent with or superior to the terms of the pro
forma tariff).
---------------------------------------------------------------------------

48. In response to Indicated PJM TOs' contention that the
Commission failed to grapple with the fact that many RTOs/ISOs already
adopted the Commission's core substantive reforms before Order No. 2023
was issued, we acknowledge that many transmission providers have
adopted many of the reforms in Order No. 2023. As explained above, that
is not an accident. The Commission carefully examined recent queue
reform proposals to identify best practices to implement nationwide.
However, no transmission provider has yet adopted all of the reforms in
Order No. 2023. For example, no transmission provider has eliminated
the reasonable efforts standard for completing interconnection studies
on time. We continue to believe that this broad suite of reforms, as a
whole, is necessary to ensure that interconnection customers are able
to interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner, thereby ensuring that rates, terms, and
conditions for Commission-jurisdictional services are just, reasonable,
and not unduly discriminatory or preferential.\83\
---------------------------------------------------------------------------

\83\ Order No. 2023, 184 FERC ] 61,054 at P 59.
---------------------------------------------------------------------------

49. Regarding Indicated PJM TOs' argument that the Commission
should have waited for recent queue reforms to be fully implemented
before determining whether additional reforms are required, we
disagree. Transmission providers across the country have been working
on regional queue reform for well over a decade.\84\ These proposals
are filed at varying intervals, and at any given time, multiple
transmission providers may be in the process of proposing or
implementing new queue processes. By the time one or two particular
transmission providers implement one set of queue reforms, it is likely
that other transmission providers would be in the process of proposing
or implementing their next queue reform. The Commission would

[[Page 27014]]

be waiting a very long time indeed if it could not issue a generic
rulemaking while any individual transmission provider pursues its own
regional queue reform.\85\
---------------------------------------------------------------------------

\84\ Id. P 16, n.39.
\85\ Transmission Plan. & Cost Allocation by Transmission Owning
& Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11,
2011), 136 FERC ] 61,051, at P 50 (2011) (finding that the need to
generically establish rules addressing transmission planning, as
well as the long lead times and complex problems associated with
developing transmission facilities, made Commission action
appropriate and prudent rather than allowing the noted transmission
planning problems to persist).
---------------------------------------------------------------------------

50. Furthermore, we note that the Commission has historically taken
a gradual approach to addressing problems with respect to
interconnection queue backlogs. In Order No. 845, for instance, the
Commission implemented a number of specific reforms, but held off on
other reforms in favor of collecting further information from
transmission providers.\86\ In doing so, the Commission noted that
``[t]his information could also be useful to the Commission in
determining if additional action is required to address interconnection
study delays.'' \87\ In Order No. 2023, the Commission determined that
additional action was required to address interconnection study
delays.\88\ The reforms in Order No. 845 have not eliminated the
problems of interconnection queue backlogs and delayed interconnection
studies; rather, these problems have only grown, notwithstanding the
Commission's previous reforms. We maintain that the reforms in Order
No. 2023 are necessary to ensure that interconnection customers are
able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner, thereby ensuring that rates,
terms, and conditions for Commission-jurisdictional services are just,
reasonable, and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

\86\ Reform of Generator Interconnection Procs. & Agreements,
Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ] 61,043, at P 24
(2018), order on reh'g, Order No. 845-A, 84 FR 8156 (Mar. 6, 2019),
166 FERC ] 61,137 (2019), order on reh'g, Order No. 845-B, 168 FERC
] 61,092 (2019).
\87\ Order No. 845, 163 FERC ] 61,043 at P 309.
\88\ Order No. 2023, 184 FERC ] 61,054 at P 3.
---------------------------------------------------------------------------

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

1. Order No. 2023 Requirements
51. The Commission addressed commenters' concerns regarding Order
No. 2023's impact on early adopters of similar queue reforms or those
queues currently in transition to a cluster study process. The
Commission recognized that many of the individual reforms that the
Commission adopted in Order No. 2023 are incremental improvements that
one or more regions had already implemented.\89\ The Commission
explained that Order No. 2023 uses some of these individual and
incremental improvements as a basis for a broad suite of reforms that,
in their entirety, have not yet been adopted by any region.
---------------------------------------------------------------------------

\89\ Id. P 59.
---------------------------------------------------------------------------

52. Additionally, the Commission rejected requests to presume that
any transmission provider's tariff meets the requirements of Order No.
2023.\90\ The Commission recognized that many transmission providers
have adopted or are in the process of adopting similar reforms to those
adopted in Order No. 2023 and clarified that the Commission did not
intend to disrupt these ongoing transition processes or stifle further
innovation.\91\ The Commission emphasized that the provisions of Order
No. 2023 are not intended to interfere with the timely completion of
those in-progress cluster studies and transition processes.\92\ The
Commission explained that, on compliance, transmission providers can
propose deviations from the requirements adopted in Order No. 2023,
including deviations seeking to minimize interference with ongoing
transition plans,\93\ provided that the reason for the variation is
sufficiently justified, and may continue to propose solutions to
interconnection issues under FPA section 205.\94\
---------------------------------------------------------------------------

\90\ Id. P 1765.
\91\ Id. PP 861, 1765.
\92\ Id. P 861.
\93\ Id. P 1765 (clarifying that transmission providers that
have already adopted a cluster study process or are currently
undergoing a transition to a cluster study process will not be
required to implement a new transition process).
\94\ Id. P 1767.
---------------------------------------------------------------------------

53. Therefore, consistent with Order Nos. 888, 890, 2003, 2006, and
845, the Commission adopted the NOPR proposal to continue to apply the
consistent with or superior to standard when considering proposals from
non-RTO/ISO transmission providers to deviate from the requirements of
Order No. 2023.\95\ Consistent with Order Nos. 2003, 2006, and 845, the
Commission adopted the NOPR proposal to continue to use the
``independent entity variation'' standard when considering such
proposals from RTOs/ISOs.\96\ Consistent with Order Nos. 888, 890,
2003, 2006, and 845, the Commission adopted the NOPR proposal to
continue to allow non-RTO/ISO transmission providers to use the
regional differences rationale to seek variations made in response to
established (i.e., approved by the Applicable Reliability Council)
reliability requirements.\97\ The Commission explained that Order No.
2023 makes no changes to the standards used to judge requested
variations, as described in Order Nos. 888, 890, 2003, 2006, and 845.
---------------------------------------------------------------------------

\95\ Id. P 1764 (citing Promoting Wholesale Competition Through
Open Access Non-Discriminatory Transmission Servs. By Pub. Utils,;
Recovery of Stranded Costs by Pub. Utils. & Transmitting Utils.,
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,769-770 (cross-
referenced at 75 FERC ] 61,080); Preventing Undue Discrimination &
Preference in Transmission Serv., Order No. 890, 72 FR 12226 (Mar.
15, 2007), 118 FERC ] 61,119 at P 109 (2007) (``[W]e reiterate that
any departures from the pro forma [open access transmission tariff]
proposed by an ISO or an RTO must be `consistent with or superior
to' the pro forma [open access transmission tariff] in this Final
Rule.''); Order No. 2003, 104 FERC ] 61,103 at P 825; Order No.
2006, 111 FERC ] 61,220 at PP 546-547; Order No. 845, 163 FERC ]
61,043 at P 43 (explaining that a transmission provider that is not
an RTO/ISO that seeks a variation from the requirements of the final
rule must present its justification for the variation as consistent
with or superior to the pro forma LGIA or pro forma LGIP)).
\96\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at P 826
(``[w]ith respect to an RTO or ISO . . . we will allow it to seek
`independent entity variations' from the Final Rule . . . This is a
balanced approach that recognizes that an RTO or ISO has different
operating characteristics depending on its size and location and is
less likely to act in an unduly discriminatory manner than a
Transmission Provider that is a market participant.''); Order No.
2006, 111 FERC ] 61,220 at PP 447, 549; Order No. 845, 163 FERC ]
61,043 at P 556).
\97\ Id. (citing Order No. 888, FERC Stats. & Regs. ] 31,036, at
31,770; Order No. 890, 118 FERC ] 61,119 at P 109; Order No. 2003,
104 FERC ] 61,103 at P 826 (``if on compliance a non-RTO or ISO
Transmission Provider offers a variation from the Final Rule LGIP
and Final Rule LGIA, and the variation is in response to established
(i.e., approved by the Applicable Reliability Council) reliability
requirements, then it may seek to justify its variation using the
regional difference rationale.''); Order No. 2006, 111 FERC ] 61,220
at PP 546-547; Order No. 845, 163 FERC ] 61,043 at P 43).
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
54. Several entities request clarification regarding the scope of
the application of Order No. 2023 to transmission providers that have
already transitioned to, or that are in the process of transitioning
to, a cluster study process.\98\
---------------------------------------------------------------------------

\98\ Clean Energy Associations Rehearing Request at 51-52;
Dominion Rehearing Request at 17-18; IPP Coalition Rehearing Request
at 10-13; PacifiCorp Rehearing Request at 15-20; PJM Rehearing
Request at 1-3; Revised Early Adopters Coalition Rehearing Request
at 2-7; WIRES Rehearing Request at 12.
---------------------------------------------------------------------------

55. Clean Energy Associations and IPP Coalition ask the Commission
to clarify that all existing cluster study processes must comport with
the requirements of Order No. 2023, whether the transmission provider
currently operates a cluster study process or is currently undergoing a
transition to a

[[Page 27015]]

cluster study process.\99\ Clean Energy Associations and IPP Coalition
argue that interconnection customers that are currently in a cluster
study process should be required to satisfy the requirements of Order
No. 2023, including site control requirements, within an identified
time horizon (e.g., 60-90 days of the compliance filing) or withdraw
from the interconnection queue without penalty.\100\ Clean Energy
Associations and IPP Coalition argue that, if some transmission
providers are not required to transition to a process that is compliant
with Order No. 2023, projects currently in the queue that are not ready
to proceed will not face the increased readiness requirements and delay
reforms to new queue requests, undermining the central purpose of Order
No. 2023.\101\
---------------------------------------------------------------------------

\99\ Clean Energy Associations Rehearing Request at 51; IPP
Coalition Rehearing Request at 10-11.
\100\ Clean Energy Associations Rehearing Request at 51; IPP
Coalition Rehearing Request at 11-12.
\101\ Clean Energy Associations Rehearing Request at 53; IPP
Coalition Rehearing Request at 13.
---------------------------------------------------------------------------

56. Clean Energy Associations and IPP Coalition argue that, absent
clarification, the Commission risks leaving in place a potentially
problematic oversight.\102\ Specifically, Clean Energy Associations and
IPP Coalition assert that the notion that transmission providers that
have adopted or are currently transitioning to a cluster study process
will not be required to implement a new transition process runs counter
to the requirement that transmission providers may seek approval, on a
case-by-case basis, to maintain variations from the pro forma LGIP and
pro forma LGIA.\103\ According to Clean Energy Associations and IPP
Coalition, the fact that a transmission provider has an existing
cluster study does not exempt that provider from its compliance
obligation or the need to update its process to reflect the material
elements of Order No. 2023.
---------------------------------------------------------------------------

\102\ Clean Energy Associations Rehearing Request at 51; IPP
Coalition Rehearing Request at 11.
\103\ Clean Energy Associations Rehearing Request at 51-52; IPP
Coalition Rehearing Request at 11 (both citing Order No. 2023, 184
FERC ] 61,054 at P 1530).
---------------------------------------------------------------------------

57. NV Energy requests that the Commission clarify whether the new
tariff changes are applicable to all interconnection customers,
including those that currently participate in a cluster study process
or have executed LGIAs.\104\ Specifically, NV Energy requests that the
Commission clarify if interconnection customers will be required to
update their respective study deposits, provide commercial readiness
deposits correlating to the amounts required at the various stages of
the process, and update their site control documentation in order to
remain in the queue.\105\ NV Energy requests a one-time ability for
existing interconnection customers of transmission providers who
currently conduct cluster studies to withdraw penalty-free from the
queue if they are unable to provide the updated study deposits, site
control, commercial readiness deposits, etc.
---------------------------------------------------------------------------

\104\ NV Energy Rehearing Request at 2 (citing Order 2023, 184
FERC ] 61,054 at P 861). NV Energy states that Order No. 2023 did
not mention grandfathering any of the existing interconnection
agreements. Id.
\105\ Id. at 3.
---------------------------------------------------------------------------

58. NV Energy additionally requests clarification on whether a
queued interconnection customer, whether in a current cluster study,
with an executed facilities study agreement, or with an executed LGIA,
must provide the heightened proof of site control by the effective date
of the new tariff changes.\106\ NV Energy seeks clarity on whether: (1)
existing queued interconnection customers are required to provide 90%
of site control if not impacted by a regulatory limitation and are
currently within the cluster study phase of the process; (2) existing
queued interconnection customers with executed facilities studies
agreements are required to provide 100% of site control if the site is
not impacted by a regulatory limitation; (3) existing queued
interconnection customers who are impacted by a regulatory limitation
are required to update their deposit in lieu of site control to the new
deposit amounts; and (4) existing queued interconnection customers with
executed LGIAs who are impacted by a regulatory limitation are required
to provide site control within 180 days of executing their respective
LGIAs.
---------------------------------------------------------------------------

\106\ Id.
---------------------------------------------------------------------------

59. EEI asks the Commission to clarify that Order No. 2023 does not
require transmission providers to re-file and seek approval for
portions of their existing LGIA and LGIP that have previously been
approved by the Commission and are not directly impacted by Order No.
2023.\107\ EEI argues that it would be inappropriate for the Commission
to require transmission providers to re-file and seek approval for such
portions of their existing LGIAs and LGIPs because the Commission
provided no notice that it was going to review or reconsider every
change it has previously approved for LGIAs and LGIPs, and thus
transmission providers were not given an opportunity to defend
previously approved changes.\108\ EEI argues that it would be a
significant administrative burden for transmission providers to re-
justify every change that the Commission has already approved.\109\
---------------------------------------------------------------------------

\107\ EEI Rehearing Request at 2-3, 16.
\108\ Id. at 16.
\109\ EEI states that this would include changes that were
approved by the Commission in response to other rulemakings, such as
Order No. 845. Id. at 16-17.
---------------------------------------------------------------------------

60. PJM asks the Commission to provide a clearer signal as to how
it will take into account recently approved reforms such as PJM's
IPRTF.\110\ PJM states that its recent queue reform meets the
Commission's intent in promulgating Order No. 2023, substantially
satisfies its requirements, and is superior for the PJM region.\111\
PJM explains that there are differences between the implementation
mechanisms in its IPRTF Tariff and Order No. 2023, but that these
mechanisms serve the same goals and offer the same protections and
benefits.\112\
---------------------------------------------------------------------------

\110\ PJM Rehearing Request at 1-2.
\111\ Id. at 1, 19-20.
\112\ Id. at 19-23.
---------------------------------------------------------------------------

61. PJM states that it has begun its transition period, and unless
the Commission provides more clarity as to how it will review recently
approved queue reform processes in the Order No. 2023 compliance
process, it will create substantial uncertainty that will distract from
the effort to process the queue backlog.\113\ PJM seeks clarification
that it will not be required to implement Order No. 2023 in a manner
that would modify or undermine the procedures recently accepted by the
Commission, and that the Commission will review PJM's request for an
independent entity variation holistically, by examining whether the
package as a whole is consistent with or superior to the goals and
requirements of Order No. 2023 rather than forcing PJM to engage in an
item-by-item justification of every variation from the minutiae of
Order No. 2023's requirements.\114\ PJM explains that requiring it to
overhaul its tariff or justify each difference from the new pro forma
will risk that some elements will be retained while other balancing
elements will be changed, upsetting the balance that led to stakeholder
approval.\115\ PJM states that proceeding element by element through
compliance will also provide intervenors an opportunity to re-litigate
issues on which they did not prevail, which is contrary to judicial
principles and would be a poor use of time.\116\ PJM also explains that
the elements of its tariff are interdependent, such that a

[[Page 27016]]

piecemeal approach could undermine the entire tariff.
---------------------------------------------------------------------------

\113\ Id. at 2, 10.
\114\ Id. at 3, 15.
\115\ Id. at 15.
\116\ Id. at 16.
---------------------------------------------------------------------------

62. If the Commission does not provide the requested
clarifications, PJM seeks rehearing because the Commission should have
established a presumption that ongoing, recently approved
interconnection queue reform packages comply with Order No. 2023.\117\
PJM explains that Order No. 2023 is internally inconsistent because it
seeks to expedite the interconnection queue, and recognizes the efforts
of on-going queue reform, but refuses to grant a presumption, which
will cause delay and inefficiency.\118\ PJM argues that it would be
arbitrary and capricious and inconsistent with reasoned decision-making
to require modification of PJM's tariff based on a generic
rulemaking.\119\ PJM also argues that failure to grant this rehearing
will undermine confidence in the use of stakeholder processes.\120\
---------------------------------------------------------------------------

\117\ Id. at 3, 25-26.
\118\ Id. at 26.
\119\ Id. at 3-4.
\120\ Id. at 27.
---------------------------------------------------------------------------

63. To the extent that the Commission does not grant PJM's request
to provide a clear signal on rehearing that it will consider whether
the entire package of IPRTF reforms as a whole meets the goals of Order
No. 2023 rather than forcing PJM to engage in an extensive
justification of every variation from every detail in Order No. 2023,
PJM requests rehearing.\121\
---------------------------------------------------------------------------

\121\ Id. at 24.
---------------------------------------------------------------------------

64. Dominion argues that the Commission should cure the
deficiencies in Order No. 2023's approach to compliance for early
adopters like DESC and PJM.\122\ Dominion suggests that the Commission
could simply not require entities that have already transitioned or are
in the process of transitioning to a first-ready, first-served cluster
study construct to file compliance filings. Dominion alternatively
argues that the Commission could defer those entities' obligations to
modify their tariffs, pending an appropriate period of time to gather
evidence about whether their particular, Commission-approved reforms
need to be further modified. Dominion asserts that this approach would
be within the Commission's statutory bounds, is administratively
efficient, and maintains the settled expectations of the stakeholders
that worked diligently and collaboratively to develop transmission
provider-specific reforms. Dominion asserts that the Commission has on
several occasions directed entities to provide reports so that it can
monitor situations before deciding it is necessary to take action.\123\
Dominion argues that the Commission could then require such early
adopters to provide an additional report after a period of time
determined by the Commission, such as two full cluster cycles following
the transition, that would update the Commission on processing time
under the proposed rule.
---------------------------------------------------------------------------

\122\ Dominion Rehearing Request at 17.
\123\ Id. at 17-18 (citing, for example, One-Time Informational
Reports on Extreme Weather Vulnerability Assessments Climate Change,
Extreme Weather, & Elec. Sys. Reliability, Order No. 897, 88 FR
41477 (June 27, 2023), 183 FERC ] 61,192, at P 25 (2023) (requiring
one-time informational reports related to planning for the impacts
of extreme weather on system reliability); Hybrid Res., 174 FERC ]
61,034, at P 1 (2021) (requiring RTOs and ISOs to submit information
related to hybrid resources)).
---------------------------------------------------------------------------

65. Dominion argues that, if the reports demonstrate that early
adopters' processes are not meeting the goals of Order No. 2023, the
Commission would then have a sufficient record, through the reports, to
determine whether to direct further changes to conform with Order No.
2023.\124\ Dominion contends that this compliance path for early
adopters is superior to Order No. 2023's proposal and would allow
transmission providers to demonstrate that the desired aim of Order No.
2023--facilitating quicker, more efficient interconnection processes--
is being achieved.
---------------------------------------------------------------------------

\124\ Id. at 18.
---------------------------------------------------------------------------

66. Revised Early Adopter Coalition and PacifiCorp state that, to
the extent a transmission provider does not seek or is not granted a
variance for its existing interconnection reforms, such transmission
provider appears to be required to immediately adopt the reforms in
Order No. 2023 without any ability to start from a clean slate like
other transmission providers utilizing a transition study process or to
conclude any ongoing studies.\125\ Revised Early Adopters Coalition and
PacifiCorp argue that Order No. 2023 does not appear to allow early
adopters of interconnection reforms an option to open the initial
cluster request window under Order No. 2023 after the conclusion of the
study of existing interconnection requests.\126\ Revised Early Adopters
Coalition and PacifiCorp assert that, because many early adopters are
currently in the process of one or more cluster studies, not allowing
such early adopters to use a transition cluster study process is both
unworkable for such transmission providers and also contrary to Order
No. 2023's assurance that ``the provisions of this final rule are not
intended to interfere with the timely completion of those in-progress
cluster studies and transition processes.'' \127\
---------------------------------------------------------------------------

\125\ Revised Early Adopters Coalition Rehearing Request at 3;
PacifiCorp Rehearing Request at 16.
\126\ Revised Early Adopters Coalition Rehearing Request at 4;
PacifiCorp Rehearing Request at 16. Revised Early Adopters Coalition
note that the initial cluster request window under Order No. 2023
would open ``after the conclusion of the transition process set out
in Section 5.1 of this LGIP.'' Revised Early Adopters Coalition
Rehearing Request at 3-4 (citing Order No. 2023, 184 FERC ] 61,054
at app. C, pro forma LGIP section 3.4.1).
\127\ Revised Early Adopters Coalition Rehearing Request at 4,
7; PacifiCorp Rehearing Request at 16 (both citing Order No. 2023,
184 FERC ] 61,054 at P 861).
---------------------------------------------------------------------------

67. Revised Early Adopters Coalition and PacifiCorp state that
Order No. 2023 also appears to require early adopters to undertake an
initial cluster request window prior to completion of cluster studies
and/or restudies currently underway.\128\ Revised Early Adopters
Coalition and PacifiCorp argue that this would be an unexplained
departure from prior precedent and the Commission's own statements in
Order No. 2023.\129\ Revised Early Adopters Coalition and PacifiCorp
assert that this will also interfere with the timely completion of
current cluster studies because it will divert already strained
resources to preparing for and implementing Order No. 2023's new
provisions. Revised Early Adopters Coalition and PacifiCorp further
argue that this will put early adopters in the difficult, if not
impossible, situation of having to undertake new cluster studies under
Order No. 2023 that are reliant on outcomes of existing, not-yet-
completed, cluster studies.
---------------------------------------------------------------------------

\128\ Revised Early Adopters Coalition Rehearing Request at 6;
PacifiCorp Rehearing Request at 18.
\129\ Revised Early Adopters Coalition Rehearing Request at 2,
6; PacifiCorp Rehearing Request at 18 (both citing, for example,
Panhandle E. Pipe Line Co. v. FERC, 196 F.3d 1273, 1275 (D.C. Cir.
1999) (Panhandle) (``if [FERC] wishes to depart from its prior
policies, it must explain the reasons for its departure.'')).
---------------------------------------------------------------------------

68. Revised Early Adopters Coalition and PacifiCorp ask the
Commission to clarify that early adopters of similar interconnection
reforms, to the extent they do not seek or are not granted variances
for their existing interconnection reforms, may conclude their pending/
existing studies before transition to the new Order No. 2023
process.\130\ Revised Early Adopters Coalition and PacifiCorp
alternatively request that the Commission grant rehearing to permit
such study flexibility for those transmission providers who have
already adopted similar reforms to Order No. 2023. PacifiCorp argues
that, without this flexibility, new cluster studies pursuant to Order
No. 2023 may not be reliable as they will need to rely upon

[[Page 27017]]

assumptions, including ``higher priority requests'' that were studied
in prior interconnection studies and assumed to be in service.\131\
PacifiCorp emphasizes that this flexibility is imperative, given the
size of its queue--326 active interconnection requests, accounting for
over 59 gigawatts of requests.
---------------------------------------------------------------------------

\130\ Revised Early Adopters Coalition Rehearing Request at 2;
PacifiCorp Rehearing Request at 15.
\131\ PacifiCorp Rehearing Request at 19.
---------------------------------------------------------------------------

69. Revised Early Adopters Coalition and PacifiCorp further assert
that Order No. 2023 puts early adopters of interconnection reforms in a
uniquely disadvantaged position of having to simultaneously administer
two types of interconnection processes and, as a result, potentially
expose them to greater likelihood of penalties than other transmission
providers.\132\ Revised Early Adopters Coalition asserts that exposing
early adopters to such outsized risks would be arbitrary and capricious
as well as discriminatory.\133\
---------------------------------------------------------------------------

\132\ Id.; Revised Early Adopters Coalition Rehearing Request at
2-3, 6 (citing 5 U.S.C. 706(2)(A); Motor Vehicle Mfrs. Ass'n of the
U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)
(Motor Vehicle Manufacturers) (explaining that to survive review
under the arbitrary and capricious standard, an agency must examine
the relevant data and articulate a satisfactory explanation for its
action including a rational connection between the facts found and
the choice made.') (internal citations omitted)).
\133\ Revised Early Adopters Coalition Rehearing Request at 6.
---------------------------------------------------------------------------

70. Revised Early Adopters Coalition and PacifiCorp explain that,
if permitted the flexibility above, any transmission provider that
currently has one or more ongoing cluster studies pursuant to its
Commission-accepted cluster study processes, and who has not sought and
received a variance, would commence new cluster studies only after all
pending interconnection request cluster studies (or restudies) have
concluded and only under updated tariff provisions that are consistent
with or superior to Order No. 2023.\134\ Revised Early Adopters
Coalition and PacifiCorp state that allowing such providers to conclude
their existing cluster studies before transition to the new pro forma
study approach will preserve the interests of current interconnection
customers that have been participating in the existing cluster study
process as well as ease the administrative burden for such transmission
providers.
---------------------------------------------------------------------------

\134\ Id. at 6-7; PacifiCorp Rehearing Request at 19-20.
---------------------------------------------------------------------------

71. Revised Early Adopters Coalition and PacifiCorp also request,
in the alternative, that the Commission allow early adopters to use a
transition process similar to other transmission providers, if such a
process better suits their needs and facilitates expedient queue
processing.\135\ Revised Early Adopters Coalition and PacifiCorp
request that, either through clarification or rehearing, the Commission
ensure that early adopters have the flexibility to choose either Order
No. 2023's transition process or the ability to implement Order No
2023's reforms after completing any existing cluster studies and
restudies.
---------------------------------------------------------------------------

\135\ Revised Early Adopters Coalition Rehearing Request at 7;
PacifiCorp Rehearing Request at 20.
---------------------------------------------------------------------------

72. WIRES argues that Order No. 2023 also includes new requirements
that need clarification or further consideration by the
Commission.\136\ WIRES states that it generally agrees that the shift
from a serial study process to a cluster study process is likely to
result in greater efficiency and provide more certainty but argues that
the Commission has not explained how this new requirement will sync up
with ongoing efforts that are already under way. WIRES requests that
the Commission clarify how it plans to accommodate those ongoing
efforts.
---------------------------------------------------------------------------

\136\ WIRES Rehearing Request at 12.
---------------------------------------------------------------------------

3. Determination
73. We clarify that all transmission providers, including those
with existing cluster study processes, have a compliance obligation to
review and modify their current pro forma interconnection procedures
and pro forma interconnection agreements to comply with Order No. 2023.
However, we continue to find that transmission providers that have
already adopted a cluster study process or are currently undergoing a
transition to a cluster study process will not be required to implement
the transition process laid out in Order No. 2023,\137\ and thus
further clarify that such transmission providers are not required to
file pro forma LGIP section 5 (Procedures for Interconnection Requests
Submitted Prior to Effective Date of the Cluster Study) and the related
appendices in their compliance filings.
---------------------------------------------------------------------------

\137\ Order No. 2023, 184 FERC ] 61,054 at P 861.
---------------------------------------------------------------------------

74. However, in response to the arguments raised by Revised Early
Adopters Coalition and PacifiCorp, we note that Order No. 2023 does not
prohibit such transmission providers from adopting the transition
process established in Order No. 2023. Therefore, a transmission
provider that does not seek or is not granted a variance for its
existing cluster study process and adopts the reforms in Order No. 2023
would be able to use the Order No. 2023 transition process. Where
transmission providers propose variations to the Order No. 2023
transition process, the Commission will evaluate such proposals under
the consistent with or superior to standard for non-RTO transmission
providers and the independent entity variation standard for RTOs/ISOs.
A transmission provider currently conducting a cluster study process
that does not propose to conduct an Order No. 2023 transition process
must comply with the remaining requirements of Order No. 2023 other
than the transition process.
75. We further grant clarification in response to requests seeking
to clarify the applicability of the Order No. 2023 readiness
requirements to a transmission provider currently conducting a cluster
study process. On compliance, unless it proposes a variation, such a
transmission provider must adopt the Order No. 2023 readiness
requirements; \138\ those new readiness requirements are then to be
applied based on the interconnection customer's progress in the queue
as of 60 calendar days after the Commission-approved effective date of
the transmission provider's compliance filing. Within 60 calendar days
of the Commission-approved effective date of the transmission
provider's Order No. 2023 compliance filing, interconnection customers
that have not executed an LGIA or requested an LGIA to be filed
unexecuted with the Commission must meet the transmission provider's
new readiness requirements for the relevant study phase, such as
updating their respective study deposits, providing commercial
readiness deposits correlating to the amounts required at the various
stages of the process, and demonstrating site control. Interconnection
customers that must meet the transmission provider's new readiness
requirements may withdraw within the 60 days after the Commission-
approved effective date of the transmission provider's Order No. 2023
compliance filing without being subject to Order No. 2023 withdrawal
penalties. If the interconnection customer chooses to withdraw outside
this 60-day timeline, the interconnection customer will be subject to
the new withdrawal penalties. To reflect these clarifications, we set
aside Order No. 2023, in part, and add new section 5.1.2 to the pro
forma LGIP.\139\
---------------------------------------------------------------------------

\138\ Id. PP 490-813.
\139\ New pro forma LGIP section 5.1.2 (Transmission Providers
with Existing Cluster Study Processes or Currently in Transition)
states that if Transmission Provider is not conducting a transition
process under Section 5.1.1, it will continue processing
interconnection requests under its current Cluster Study Process.
Within 60 calendar days of the Commission-approved effective date of
Transmission Provider's Order No. 2023 compliance filing,
Interconnection Customers that have not executed an LGIA or
requested an LGIA to be filed unexecuted must meet the requirements
of Sections 3.4.2, 7.5, or 8.1 of this LGIP, based on
Interconnection Customer's Queue Position. Any Interconnection
Customer that fails to meet these requirements within 60 calendar
days of the Commission-approved effective date of this LGIP shall
have its Interconnection Request deemed withdrawn by Transmission
Provider pursuant to Section 3.7 of this LGIP. In such case,
Transmission Provider shall not assess the Interconnection Customer
any Withdrawal Penalty.

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[[Page 27018]]

76. In response to NV Energy, we clarify that the requirement to
meet the new site control requirements also requires that a queued
interconnection customer, whether in a current cluster study or with an
executed facilities study agreement (but not an interconnection
customer with an executed LGIA or that has requested an LGIA to be
filed unexecuted with the Commission), that is facing regulatory
limitations must also submit the applicable deposit and information
regarding the specific limitation within 60 days after the Commission-
approved effective date of the transmission provider's compliance
filing. An interconnection customer that withdraws within the 60-day
period instead of submitting the applicable deposit and information
will not be subject to Order No. 2023 withdrawal penalties.
77. We agree with EEI that transmission providers need only re-file
and seek approval for previously approved variations where those
provisions are modified by Order No. 2023. As the Commission explained
in Order No. 2023, the Commission adopted requirements that are part of
the pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA
and the Commission therefore only addressed the interaction of the
requirements adopted with existing requirements that are part of the
pro forma process and not variations thereto.\140\ Transmission
providers may seek variations from Order No. 2023's requirements on
compliance provided the reason for the variation is sufficiently
justified.\141\ Transmission providers may also continue to propose
interconnection process enhancements beyond Order No. 2023 through a
separate filing under FPA section 205.
---------------------------------------------------------------------------

\140\ Order No. 2023, 184 FERC ] 61,054 at P 1530.
\141\ Id. P 1767.
---------------------------------------------------------------------------

78. We reject requests to presume that any transmission provider's
tariff meets the requirements of Order No. 2023.\142\ As explained
above, while the majority of reforms adopted herein are based on
individual and incremental improvements that one or more regions have
already implemented, no transmission provider has yet to adopt the
entirety of Order No. 2023's broad suite of reforms.\143\ Thus, we are
unpersuaded by PJM's arguments on rehearing that ongoing, recently
approved interconnection queue reform packages presumably already
comply with Order No. 2023. Applying a presumption to transmission
providers who recently adopted some similar reforms, but not all the
reforms contained herein, will only result in incomplete change that
fails to fulfill or further delays the comprehensive reform required by
Order No. 2023. Additionally, because the Commission continues to find
that the record supports a generic rulemaking,\144\ the Commission
reiterates that it did not need to make a finding specific to each
transmission provider's tariff to require compliance with Order No.
2023.\145\ Therefore, we also remain unpersuaded by Dominion's
arguments on rehearing to defer the tariff modifications of, or to not
require compliance filings from, transmission providers that have
already transitioned or are in the process of transitioning to a
cluster study process or to defer those entities' obligations to modify
their tariffs.
---------------------------------------------------------------------------

\142\ Id. P 1765.
\143\ Id. P 59.
\144\ Order No. 2023, 184 FERC ] 61,054 at P 1766; supra section
II.A.3.
\145\ See Order No. 2023, 184 FERC ] 61,054 at P 1766 (citing
TAPS, 225 F.3d at 687-88).
---------------------------------------------------------------------------

79. In response to requests for clarification regarding how the
Commission will review the compliance filings of entities that already
adopted reforms, we continue to find, consistent with the Commission's
statements in Order No. 2023, that transmission providers may explain
specific circumstances on compliance and justify why any deviations
from the pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma
SGIA are either consistent with or superior to the reforms adopted in
Order No. 2023 for non-RTO transmission providers or merit an
independent entity variation for RTOs/ISOs.\146\ An item-by-item
justification must be offered for each variation from the pro forma
provisions modified in Order No. 2023; general statements alone are
insufficient under the consistent with or superior to or the
independent entity variation standard. Region-specific concerns like
those raised by PJM and Dominion are appropriately addressed on
compliance where the Commission will review the compliance filings on a
case-by-case basis.
---------------------------------------------------------------------------

\146\ Id. PP 1764-1765.
---------------------------------------------------------------------------

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

1. Public Interconnection Information
a. Order No. 2023 Requirements
80. In Order No. 2023, the Commission adopted section 6.1 (Publicly
Posted Interconnection Information) of the pro forma LGIP to require
transmission providers to maintain and make publicly available an
interactive visual representation of available interconnection capacity
(commonly known as a ``heatmap'') as well as a table of relevant
interconnection metrics that is produced in response to user-specified
input about their prospective generating facility.\147\ The table will
allow prospective interconnection customers to see certain estimates of
a potential generating facility's effect on the transmission provider's
transmission system. Specifically, the Commission required transmission
providers to post on their public website a heatmap of estimated
incremental injection capacity (in MW) available at each point of
interconnection to the whole transmission provider's footprint under N-
1 conditions, as well as provide a table of results in response to a
specific user's input showing the estimated impact of the addition of
the proposed project (based on the user-specified MW amount, voltage
level, and point of interconnection) for each monitored facility
impacted by the proposed project on: (1) the distribution factor; (2)
the MW impact (based on the proposed project size and the distribution
factor); (3) the percentage impact on the monitored facility (based on
the MW values of the proposed project and the monitored facility
rating); (4) the percentage of power flow on the monitored facility
before the proposed project; and (5) the percentage power flow on the
monitored facility after the injection of the proposed project. The
Commission required that heatmaps be calculated under N-1 conditions
and studied based on the power flow model of the transmission system
used in the most recent cluster study or restudy, and with the transfer
simulated from each point of interconnection to the whole transmission
provider's footprint (to approximate NRIS), and with the incremental
capacity at each point of interconnection decremented by the existing
and queued generation at that location (based on the existing or
requested interconnection service limit of such generation). The
Commission required transmission providers to

[[Page 27019]]

update their heatmaps within 30 calendars days after the completion of
each cluster study and cluster restudy. Further, the Commission
clarified that transmission providers are not required to make their
heatmaps available until after their transition period.\148\
---------------------------------------------------------------------------

\147\ Id. P 135.
\148\ Id. P 141.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
81. Clean Energy Associations ask the Commission to clarify that
transmission providers may use ERIS or NRIS assumptions for their
heatmaps, as appropriate for their particular region.\149\ Clean Energy
Associations argue that the requirement to use only NRIS assumptions
fails to account for regional differences and could reduce the value of
providing a heatmap. For example, Clean Energy Associations assert that
in SPP and MISO, ERIS is the primary driver of determining network
upgrades for new generation. If the Commission declines to grant
clarification, Clean Energy Associations seek rehearing of the
requirement to use NRIS assumptions for heatmaps.
---------------------------------------------------------------------------

\149\ Clean Energy Associations Rehearing Request at 48-49.
---------------------------------------------------------------------------

82. Non-RTO Providers request rehearing and modification of Order
No. 2023's requirement that non-RTO/ISO transmission providers develop
interactive heatmap websites.\150\ Non-RTO Providers assert that the
mandate is arbitrary and capricious and contrary to reasoned decision-
making. Non-RTO Providers state that the Commission did not perform an
adequate cost-benefit analysis to weigh the high cost and
administrative burden on non-RTO transmission providers against the
``limited and speculative benefits'' of the heatmaps for non-RTO/ISO
interconnection customers.\151\ Non-RTO Providers assert that the
mandate will require the 37 non-RTO/ISO regions \152\ to each develop
separate heatmap websites. Non-RTO Providers estimate that the
cumulative upfront cost for these 37 heatmap websites is $7.4 million,
and that the cumulative annual maintenance cost for the 37 heatmap
websites is $666,000. Non-RTO Providers assert that the heatmaps will
require regular attention from interconnection engineers who will
otherwise be focused on transitioning to cluster studies. Non-RTO
Providers contend that the heatmap requirement amounts to a penalty on
non-RTO/ISO transmission providers, who cannot socialize the costs as
broadly as RTOs/ISOs can.\153\ Non-RTO Providers request that the
Commission reverse the mandate on rehearing and (1) issue a modified
version of section 6.1 of the pro forma LGIP for non-RTO regions that
allows static public information postings of interconnection capacity
based on cluster study results and (2) adopt a voluntary approach for
the potential development and maintenance of interactive heatmaps in
non-RTO regions.
---------------------------------------------------------------------------

\150\ Non-RTO Providers Rehearing Request at 1-2.
\151\ Id. at 3.
\152\ Non-RTO Providers arrive at this number by subtracting the
RTOs/ISOs from the 44 transmission providers estimated to be
required to comply with Order No. 2023. Id. n.6.
\153\ Id. at 4.
---------------------------------------------------------------------------

83. Non-RTO Providers note that the heatmap concept is a novel
concept and that transmission providers have no special expertise in
website development.\154\ Non-RTO Providers contend that the legal
question on rehearing is whether the benefits of a proposed reform can
reasonably be said to outweigh the costs and assert that the Commission
did not provide sufficient legal foundation under FPA section 206 to
justify the mandate. Non-RTO Providers aver that the Commission did not
acknowledge that interactive websites make financial sense only when
done at scale. Therefore, Non-RTO Providers agree that the costs of the
requirement are justified for RTO/ISO regions, which would require
seven websites to serve approximately two-thirds of the nation's
transmission system, but not for non-RTO/ISO regions, which would have
to develop 37 websites to serve the remaining one-third of the
transmission system. Non-RTO Providers explain that the Commission
appears to prohibit non-RTO/ISO regions from developing joint, regional
heatmaps to reduce the number of websites needed, which they claim
demonstrates that the cost burden and administrative burden on
engineering staff to non-RTO/ISO regions was not adequately
considered.\155\
---------------------------------------------------------------------------

\154\ Id. at 4-5.
\155\ Id. at 5-6.
---------------------------------------------------------------------------

84. Non-RTO Providers contend that the Commission wrongly relies on
Clean Energy Associations' proposition that the heatmaps will be
automated to conclude that engineering resources will not be strained
by the heatmap requirement.\156\ Non-RTO Providers state that such
updates will require one or two full-time employees to prepare data for
the first three weeks of a given 30-day update period and send the
updated data to the vendor during the last week. Non-RTO Providers
contend that the N-1 conditions reflected by the heatmap will offer no
practical value to prospective interconnection customers but will
result in five times as many engineering staff in non-RTOs/ISOs making
heatmap updates compared to those in RTOs/ISOs.\157\ Non-RTO Providers
contend that the Commission did not adequately address these
discrepancies in arguing that non-RTOs/ISOs have the technical capacity
to create heatmaps.
---------------------------------------------------------------------------

\156\ Id. at 6 (citing Order No. 2023, 184 FERC ] 61,054 at P
89).
\157\ Id. at 6-7.
---------------------------------------------------------------------------

85. Further, Non-RTO Providers argue that the record does not
demonstrate that the incremental rate increase to non-RTO/ISO regions
from the heatmaps will be justified by meaningful overall queue
efficiency improvements for non-RTO/ISO customers in the long run.\158\
For example, Non-RTO Providers contend that the Commission failed to
consider that heatmaps could increase speculative interconnection
requests if many interconnection customers seek to interconnect at the
same uncongested points reflected by the heatmap. For the above
reasons, Non-RTO Providers argue that the connection between improving
queue efficiency and benefits to transmission customers is too tenuous
to support a FPA section 206 finding that the heatmap mandate is just
and reasonable for non-RTO transmission providers.\159\
---------------------------------------------------------------------------

\158\ Id. at 8.
\159\ Id. at 9.
---------------------------------------------------------------------------

86. Non-RTO Providers claim that the Commission erred by failing to
consider a non-interactive website alternative for the public
information posting mandate in non-RTO regions.\160\ Non-RTO Providers
state that the Commission never explains why such information needs to
be provided in an interactive heatmap format, rather than in static
public information postings regarding system conditions after each
cluster study or restudy.
---------------------------------------------------------------------------

\160\ Id.
---------------------------------------------------------------------------

87. In the alternative to granting rehearing, Non-RTO Providers
propose that the Commission revise section 6.1 of the pro forma LGIP to
allow static data postings and adopt a voluntary funding approach for
heatmap development in non-RTO Regions.\161\ In particular, Non-RTO
Providers state that they are not opposed to providing increased public
access to base case data after cluster studies have been performed that
shows the estimated incremental injection capacity (in megawatts)
available at each bus in the transmission provider's footprint under N-
1 conditions in table format. Non-RTO Providers explain that data in
this format could still be uniform and

[[Page 27020]]

standardized to the Commission's specifications.\162\ Non-RTO Providers
state that with the voluntary funding approach, website developers
aligned with any of the relevant stakeholders, including transmission
providers and prospective interconnection customers and even the
Commission itself, would be free to develop their own voluntary
interactive heatmaps based on this publicly available data.
---------------------------------------------------------------------------

\161\ Id. at 10.
\162\ Id. at 11.
---------------------------------------------------------------------------

88. NV Energy requests clarification on (1) whether the heatmap
must include proposed network upgrades with capacity amounts to reflect
the available transfer capacity or only the existing facilities and (2)
when a heatmap must be made available and posted to OASIS by
transmission providers that do not conduct a new transition
period.\163\ NV Energy asserts that, presently, the heatmap will
provide limited value and will be consistently red \164\ because
interconnection requests greatly exceed the available capacity or
load.\165\ NV Energy asks if the heatmap requirement for transmission
providers already conducting cluster studies could be implemented at
the same time as study penalties (after the third cluster study cycle/
three years), which would allow transmission providers to issue
requests for proposals for the necessary heatmap software for
implementation and would allow suspended projects to withdraw as well
as remove from the queue those that fail to (1) submit complete
applications, (2) meet various deadlines, and (3) reach commercial
readiness.
---------------------------------------------------------------------------

\163\ NV Energy Rehearing Request at 4.
\164\ An ``all red'' heatmap would indicate no available
interconnection capacity. See Order No. 2023, 184 FERC ] 61,054 at P
157.
\165\ NV Energy Rehearing Request at 4.
---------------------------------------------------------------------------

89. PacifiCorp likewise seeks clarification on when transmission
providers will be required to submit heatmaps for those transmission
providers that do not conduct a transition cluster study process
because the Commission is not requiring transmission providers to
submit heatmaps until after the transition period ends.\166\
---------------------------------------------------------------------------

\166\ PacifiCorp Rehearing Request at 22-23 (citing Order No.
2023, 184 FERC ] 61,054 at P 141).
---------------------------------------------------------------------------

90. Public Interest Organizations assert that the Commission erred
by not providing an adequate method for prospective interconnection
customers to obtain information about potential interconnection costs
at a specific location prior to submitting an interconnection request,
and that the limited information publicly available to interconnection
customers will lead to unjust, unreasonable, unduly discriminatory, and
preferential rates.\167\ Public Interest Organizations also note that
the level of cost uncertainty for different interconnection customers
is not balanced because transmission owner affiliates, particularly in
non-RTO/ISO regions, have greater access to interconnection cost
information relative to independent power producers. Public Interest
Organizations contend that the Commission's decision to not adopt the
proposed informational studies and optional solicitation studies make
Order No. 2023's adopted reforms insufficient to remedy its finding
that the pro forma interconnection procedures ``fail[ ] to contain a
process by which an interconnection customer can obtain information
about potential interconnection costs at a specific location or point
of interconnection prior to submitting an interconnection request.''
\168\ Public Interest Organizations explain that both the informational
studies and optional solicitation studies were specifically intended to
provide additional cost information to prospective interconnection
customers, while the public access information requirement was intended
to provide high-level information to assist interconnection customers
with comparing multiple points of interconnection and estimate
congestion.\169\
---------------------------------------------------------------------------

\167\ Public Interest Organizations Rehearing Request at 7.
\168\ Id. at 8 (citing Order No. 2023, 184 FERC ] 61,054 at PP
46, 152).
\169\ Id. (citing Order No. 2023, 184 FERC ] 61,054 at P 68).
---------------------------------------------------------------------------

91. Public Interest Organizations state that many parties suggested
that the Commission add more data to the heatmap to provide information
for interconnection customers to readily identify network upgrades,
which would help them estimate the costs to interconnect their project
before they join the interconnection queue.\170\ Public Interest
Organizations note, for example, that NextEra suggested including
information on the circuit and ratings of equipment, and Public
Interest Organizations argued that the heatmaps should include
information on the number of megawatts that could be interconnected
without substantial costs, among other suggestions. Public Interest
Organizations argue that, without such additional data, interconnection
customers continue to bear the burden of determining potential costs,
and that not all interconnection customers possess the resources to use
software or hire consultants to extract meaningful data from the
heatmaps. Public Interest Organizations contend that the heatmap
requirement ultimately falls short of providing a reasonable method for
interconnection customers to predict potential network upgrade costs
prior to entering the queue, leading interconnection customers to make
the ``rational'' decision to submit multiple interconnection requests
to obtain information, which contributes to study delays and
withdrawals. For these reasons, Public Interest Organizations request
the Commission revisit the record to evaluate and adopt requirements
that transmission providers must also make available the additional
data that will allow all customers to estimate the potential network
upgrade costs using reasonable efforts.
---------------------------------------------------------------------------

\170\ Id. at 9-10.
---------------------------------------------------------------------------

92. Public Interest Organizations further assert that the
Commission's decision not to require more information be made publicly
available to potential interconnection customers is arbitrary and
capricious, contrary to the weight of the comments and record, and not
based on substantial evidence.\171\ Public Interest Organizations argue
that the Commission's finding that adding any additional data
requirements to assist interconnection customers is outweighed by the
potential burden to transmission providers failed to consider
countervailing evidence of the benefits of additional data. Public
Interest Organizations assert that the benefits of providing cost
information prior to interconnection customers submitting an
interconnection request is clear: fewer speculative interconnection
requests and therefore less backlogged queues. However, Public Interest
Organizations contend that MISO's heatmap demonstrates that a heatmap
alone is not enough. Public Interest Organizations also argue that the
marginal burden on transmission providers to provide additional heatmap
data is minimal as they can take advantage of automation.
---------------------------------------------------------------------------

\171\ Id. at 10-12.
---------------------------------------------------------------------------

93. PJM seeks rehearing of Order No. 2023's blanket requirement to
update the heatmap 30 calendar days after completion of each cluster
study because PJM states that it is unreasonable for such a large,
multi-state RTO like PJM with hundreds of expected interconnection
requests in each cluster.\172\ PJM states that publishing study results
to its interconnection screening tool, queue scope, requires detailed,
precise analysis using the latest inputs available at the time and
would hold PJM to an unrealistically strict and expedited

[[Page 27021]]

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

\172\ PJM Rehearing Request at 23-24.
---------------------------------------------------------------------------

94. PJM requests rehearing of Order No. 2023's clarification in P
162, which it interprets as stating that transmission providers must
absorb heatmap costs but are not barred from seeking recovery of them
through their transmission rates (and paid by interconnection
customers).\173\ PJM states that interconnection customers, rather than
transmission providers or transmission customers, benefit from heatmap
posting, so there is no good reason that transmission providers must
always charge the costs of maintaining and posting heatmaps to
transmission service customers rather than considering other structures
such as fees for prospective developers not yet in the queue. PJM
states that this rule departs from the Commission's and judicial cost-
causation principles, requiring that costs should be paid by those who
benefit from their incurrence,\174\ and it does so (by assigning
heatmap costs to transmission providers or transmission customers)
without explanation, presents free-ridership issues, and would be
arbitrary and capricious.\175\ PJM asserts that not granting rehearing
of this item would set a precedent that transmission providers must
absorb or pass on to transmission customers costs that are caused by or
that benefit interconnection customers only.
---------------------------------------------------------------------------

\173\ Id. at 42-43.
\174\ Id. at 43 (citing Transmission Plan. & Cost Allocation by
Transmission Owning & Operating Pub. Utils., Order No. 1000-A, 77 FR
32184 (May 31, 2012), 139 FERC ] 61,132 at P 578). PJM includes an
excerpt from Commissioner Christie's concurrence to Order No. 2023,
which states, ``Commission policy may dictate that interconnection
queue efficiency benefits transmission customers; however, that
should not result in the costs of a requirement that best benefits
interconnection customers, and really prospective interconnection
customers that may ultimately not seek to interconnect, being
recovered from consumers through transmission rates carte blanche.
The Commission simply cannot ask retail consumers to foot the bill
for every single ``efficiency,'' especially where many of these
``efficiencies'' largely benefit generation developers and then get
folded into transmission rates and receive an ROE.'' Order No. 2023,
concur op. (Comm'r Christie) at P 22.
\175\ PJM Rehearing Request at 43-44 (citing Motor Vehicle
Manufacturers, 463 U.S. at 57; Sw. Airlines Co. v. FERC, 926 F.3d
851, 858 (D.C. Cir. 2019); Panhandle, 196 F.3d at 1275).
---------------------------------------------------------------------------

c. Determination
95. We deny Clean Energy Associations' request for the Commission
to clarify that transmission providers may use ERIS or NRIS assumptions
for their public heatmaps. As the Commission explained in Order No.
2023, generating facilities seeking NRIS are generally subject to more
stringent study requirements.\176\ Therefore, requiring transmission
providers to produce heatmap results that approximate NRIS assumptions
will provide actionable information on the viability of a given
proposed generating facility to both ERIS and NRIS customers. On the
other hand, requiring heatmaps to approximate ERIS assumptions would
not be helpful to NRIS customers. Even in regions where ERIS may be
more commonly selected or lead to a greater number of network upgrades,
we find that the use of stricter NRIS assumptions would more
consistently alert prospective interconnection customers to the
possibility of required network upgrades compared to ERIS assumptions.
We therefore find that using NRIS assumptions as a baseline would
prevent false negatives, in which the heatmap incorrectly indicates to
prospective interconnection customers that their projects would not
trigger network upgrades. This finding reasonably balances the
resources required of transmission providers in making heatmaps
available with the value of providing non-binding system impact
information to all prospective interconnection customers ahead of
entering the interconnection queue. We note, however, that Order No.
2023 states that ``if transmission providers find value in providing
additional or different information [than required by Order No. 2023],
they may propose such variations on compliance.'' \177\ Therefore, if a
transmission provider believes that it would be informative to
interconnection customers, it may propose on compliance an option for
heatmap users to view results using ERIS assumptions in addition to
NRIS assumptions. As such, we reiterate that ``heatmaps must be
calculated under N-1 conditions and studied based on the power flow
model of the transmission system with the transfer simulated from each
point of interconnection to the whole transmission provider's footprint
(to approximate NRIS), and with the incremental capacity at each point
of interconnection decremented by the existing and queued generation at
that location (based on the existing or requested interconnection
service limit of such generation).'' \178\ For the same reasons noted
above, we are unpersuaded by the arguments raised in Clean Energy
Associations' alternative request for rehearing.
---------------------------------------------------------------------------

\176\ Order No. 2023, 184 FERC ] 61,054 at P 148.
\177\ Id. P 156.
\178\ Id. P 135.
---------------------------------------------------------------------------

96. We are also unpersuaded by Non-RTO Providers' argument that the
Commission failed to properly evaluate the costs and benefits of the
heatmap requirement for non-RTO/ISO regions and that they cannot
socialize the costs as broadly as RTOs/ISOs. First, without a
comparison to estimated heatmap costs for RTO/ISO regions, Non-RTO
Providers' cost estimates do not support its assertion that the cost of
developing interactive heatmaps is more burdensome for non-RTO/ISO
regions.\179\ While RTO/ISO regions do have larger customer bases from
which to recover costs, their heatmaps will also reflect larger and
potentially more complex power systems and need to accommodate a larger
pool of users and, therefore, may cost more.
---------------------------------------------------------------------------

\179\ See, e.g., Ill. Commerce Comm'n v. FERC, 721 F.3d 764, 775
(7th Cir. 2013) (stating that not all benefits can be calculated in
advance, and if FERC cannot quantify the benefits to a particular
utility or utilities but ``has an articulable and plausible reason
to believe that the benefits are at least roughly commensurate with
those utilities' total electricity sales in [the] region,'' then the
Commission can approve the pricing scheme on that basis) (internal
citations omitted).
---------------------------------------------------------------------------

97. We further disagree that the labor requirements Non-RTO
Providers refer to will be overly burdensome relative to RTO/ISO
regions. First, as the Commission clarified in Order No. 2023,
transmission providers are not required to update their heatmaps on a
rolling 30-day basis, but rather within 30 days of the completion of a
cluster study or restudy.\180\ Thus, transmission providers will likely
update their heatmaps at most two times per year, accounting for one
cluster study and one cluster restudy.
---------------------------------------------------------------------------

\180\ Order No. 2023, 184 FERC ] 61,054 at P 141.
---------------------------------------------------------------------------

98. Second, to Non-RTO Providers' argument that annual heatmap
maintenance would divert attention from interconnection engineers who
would otherwise be focused on transitioning to cluster studies, we
reiterate that transmission providers are not required to make heatmaps
available until after their transition period, which will help ensure
that transmission providers' implementation of this final rule,
beginning with the transition period, has begun to reduce backlogged
interconnection queues.

[[Page 27022]]

99. Third, Non-RTO Providers' cost estimates are based on an
extrapolation of one transmission provider's initial estimate, and Non-
RTO Providers do not describe any assumptions of this estimate beyond
the assertion that, after each cluster study or restudy, it would take
two full-time engineers several weeks to ``prepare the data'' before
having a vendor update the heatmap.\181\ We are unpersuaded by this
assertion because, as Order No. 2023 states, transmission providers
must use the results of their most recent cluster study or restudy to
update the heatmap.\182\ Therefore, to update their heatmaps, little
additional analysis should be required beyond what transmission
providers have already completed for their cluster studies and
restudies. We recognize that engineering labor will likely be required
during heatmap website development, either directly, in developing the
software and processes, or in consultation with the firm developing the
heatmap. However, we believe that it is feasible for transmission
providers, or their heatmap developers, to develop their heatmap
websites to accept their base case files as inputs for each update such
that little to no modification of the base case files and data is
necessary. To that point, and Non-RTO Providers' concern that
transmission providers have no special expertise in website
development, we note that Order No. 2023 does not require transmission
providers themselves to develop the requisite software and processes,
and they may contract with firms whose expertise includes website
development and data management. Further, Order No. 2023 does not
preclude transmission providers from proposing on compliance to develop
joint, regional heatmaps.
---------------------------------------------------------------------------

\181\ Non-RTO Providers Rehearing Request at 6.
\182\ Order No. 2023, 184 FERC ] 61,054 at PP 139-140.
---------------------------------------------------------------------------

100. Finally, we disagree that Non-RTO Providers' proposal to
require that transmission providers post only static data and allow
other entities to voluntarily develop heatmaps accomplishes the goals
outlined in Order No. 2023. The purpose of the heatmap requirement is,
in part, to provide comparable information to all interconnection
customers, prior to entering the queue, regardless of the transmission
provider. Non-RTO Providers' proposal would not ensure such
comparability, but rather would favor interconnection customers that
have more resources to devote towards modeling and favor some
transmission providers' own proposed generation. Thus, interconnection
customers that cannot afford to process the static data Non-RTO
Providers propose to post would still need to submit speculative
interconnection requests to obtain information. Further, the voluntary
funding approach Non-RTO Providers propose would not ensure that non-
RTO/ISO regions have public interconnection information available and
therefore would discriminate against interconnection customers seeking
to interconnect outside of RTO/ISO regions.
101. In response to NV Energy's request for clarification on
whether heatmaps must include proposed network upgrades or only
existing facilities, we reiterate that heatmaps must be based on the
power flow model and base case assumptions used in the most recent
cluster study or restudy. Therefore, heatmaps will incorporate in-
service network upgrades and network upgrades proposed for clusters
higher queued than the most recent cluster study or restudy, as the
base case and power flow models for any cluster will include proposed
network upgrades for higher queued clusters.
102. We agree with NV Energy and PacifiCorp on the need for
clarification regarding when heatmaps must be made available by
transmission providers that do not conduct transition processes. We
therefore clarify that transmission providers that do not conduct
transition periods do not need to make their heatmap available until
360 calendar days after the Commission-approved effective date of the
transmission provider's Order No. 2023 compliance filing. This timeline
will give transmission providers that do not conduct transition periods
the same amount of time as transitioning transmission providers (i.e.,
completion of the transitional cluster study within 360 days after the
Commission-approved effective date of the compliance filing) to develop
their heatmaps. Further, while we agree that heatmaps for some
transmission providers may initially appear as all red, which indicates
no available interconnection capacity, we reiterate our finding that an
all red heatmap still ``sends a valuable signal to interconnection
customers regarding where proposed generating facilities may be more or
less economic to interconnect prior to entering the interconnection
queue.'' \183\ We are therefore unpersuaded that such a result
necessitates delaying the posting of the interactive heatmap.
---------------------------------------------------------------------------

\183\ Id. P 157.
---------------------------------------------------------------------------

103. We are also unpersuaded by NV Energy's request for
clarification that transmission providers that do not conduct
transition processes because they already use cluster studies should be
required to post publicly available heatmaps only after three cluster
cycles, similar to the transition to study delay penalties. This would
delay transmission providers already using cluster studies, and their
potential interconnection customers, from realizing the benefits of a
heatmap (e.g., a reduced volume of speculative interconnection
requests) for more than twice as long as those transmission providers
who do conduct a transition process and their potential interconnection
customers.
104. We are unpersuaded by Public Interest Organizations' assertion
that the Commission erred in not requiring transmission providers to
include additional data in their heatmaps that would assist
interconnection customers in estimating interconnection costs at
potential points of interconnection. We further disagree with Public
Interest Organizations' contention that the Commission did not fully
consider the record on this matter in coming to its decision. On the
contrary, as numerous commenters explain--and as the Commission stated
in Order No. 2023--cost estimates produced prior to an interconnection
customer entering the queue would be highly uncertain and subject to a
high degree of change depending on the actions of other interconnection
customers in the queue and study results, and therefore would provide
little to no value to interconnection customers in terms of improving
cost certainty.\184\ We believe this to be true regardless of whether
the transmission provider or the interconnection customer produces
those cost estimates. Further, Public Interest Organizations do not
argue that cost estimates should be directly incorporated into
transmission providers' heatmaps, but rather that transmission
providers should include additional information in their heatmaps that
would allow interconnection customers to ascertain information about
potential costs at points of interconnection. At the same time,
however, Public Interest Organizations argue that many interconnection
customers lack the resources to develop cost estimates based on
transmission providers' heatmaps. Thus, Public Interest Organizations'
proposal would not only increase the burden on transmission providers
but require interconnection

[[Page 27023]]

customers themselves to dedicate more resources towards developing cost
estimates that are likely to change once they enter the queue. We
therefore continue to find that the heatmap requirements set forth in
Order No. 2023 strike a reasonable balance between the burden on
transmission providers to develop and maintain heatmaps and the benefit
of providing interconnection customers with sufficient information to
identify viable points of interconnection, given that cost estimates
produced prior to entering the queue would be unreliable. We note,
however, that, consistent with the Commission's statements in Order No.
2023, transmission providers may explain specific circumstances on
compliance and justify why any deviations are either consistent with or
superior to the pro forma LGIP or merit an independent entity variation
in the context of RTOs/ISOs.\185\
---------------------------------------------------------------------------

\184\ See id. P 138.
\185\ Id. P 1764.
---------------------------------------------------------------------------

105. We are unpersuaded by PJM's request to modify the requirement
for transmission providers to update their heatmaps within 30 calendar
days of completing a cluster study or restudy. We find PJM's argument
regarding its queue scope tool to be inapposite. As the Commission
explained in Order No. 2023, because the heatmap should use the results
of the most recent cluster study or restudy, the heatmap requirement
should require minimal additional analysis beyond the cluster study or
restudy and should not necessitate detailed analysis.\186\ Transmission
providers must simply make the data and assumptions used in the
analyses they already completed available in a public, interactive
form. Updating heatmaps within 30 calendar days of completion of a
cluster study or restudy will also ensure that interconnection
customers can use the heatmap during the customer engagement window to
determine whether to proceed in the queue or withdraw. Finally, we
disagree that interconnection customers' ability to request CEII
achieves the same goal as the heatmap requirement. The heatmaps are
intended to improve transparency and ease the burden of producing
interconnection-related information for prospective interconnection
customers. On the other hand, requests for CEII typically require an
entity to submit certain identifying information and/or legal documents
like non-disclosure agreements and require the transmission provider to
review and verify such information, and weigh the need for the
information against the potential harm of its release, before
potentially granting access to a protected part of its website or OASIS
portal.\187\ Reliance on such a process would impose an unnecessary
burden on the prospective interconnection customer, the transmission
provider, and other interested stakeholders because, as commenters
explain, the information to be published in transmission providers'
heatmaps does not raise CEII concerns.\188\
---------------------------------------------------------------------------

\186\ Id. PP 139-140.
\187\ PJM's CEII request process, for example, includes all
these process components. See <a href="https://www.pjm.com/library/request-access">https://www.pjm.com/library/request-access</a>.
\188\ Order No. 2023, 184 FERC ] 61,054 at P 144.
---------------------------------------------------------------------------

106. Further, we are unpersuaded by PJM's request to modify the
finding in Order No. 2023 that transmission providers must bear the
costs associated with their heatmaps or recover them through
transmission rates to the extent they are recoverable consistent with
Commission accounting and ratemaking policy. First, transmission
providers already maintain interconnection information and other
related information online for the purposes of transparency and
facilitating participation amongst various stakeholders. Thus, we
disagree with PJM's requested modification because transmission
providers may recover the costs associated with heatmaps through
transmission rates to the extent they are recoverable consistent with
Commission accounting and ratemaking policy. Second, we disagree that
interconnection customers are the sole or primary beneficiaries of the
heatmap requirement, and that transmission providers themselves do not
benefit from it. The heatmap requirement will reduce the number of
speculative interconnection requests submitted to transmission
providers by providing prospective interconnection customers with
information to evaluate the viability of their potential
interconnection requests, thus improving overall queue efficiency for
the benefit of both transmission providers and prospective
interconnection customers.
2. Cluster Study Process
a. Order No. 2023 Requirements
107. In Order No. 2023, the Commission revised the pro forma LGIP
and pro forma LGIA to require transmission providers to study
interconnection requests in clusters.\189\ The Commission adopted
numerous revisions to the pro forma LGIP and pro forma LGIA to
effectuate this change. Specifically, and as relevant here, the
Commission revised the definitions of material modification and stand
alone network upgrades, and defined interconnection facilities study
report.\190\ The Commission adopted section 3.1.2 (Submission) of the
pro forma LGIP to require an interconnection customer to select a
definitive point of interconnection when executing the cluster study
agreement.\191\ The Commission adopted section 3.4.1 (Cluster Request
Window), section 3.4.4 (Deficiencies in Interconnection Request), and
section 3.4.5 (Customer Engagement Window) of the pro forma LGIP to
provide a process for interconnection customers to submit a cluster
study interconnection request.\192\ The Commission adopted section
3.4.6 (Cluster Study Scoping Meetings) of the pro forma LGIP to require
transmission providers to hold a scoping meeting with interconnection
customers in the cluster.\193\ The Commission revised section 3.5.2
(Requirement to Post Interconnection Study Metrics) of the pro forma
LGIP to require transmission providers to post metrics for cluster
study and restudy processing time.\194\
---------------------------------------------------------------------------

\189\ Id. P 177.
\190\ Id. P 192.
\191\ Id. P 200.
\192\ Id. P 223.
\193\ Id. P 245.
\194\ Id. P 259.
---------------------------------------------------------------------------

108. The Commission adopted several revisions to the pro forma LGIP
related to the process by which interconnection customers can make an
interconnection request. The Commission revised section 4.1 (Queue
Position) of the pro forma LGIP to provide that all interconnection
requests within a cluster be considered equally queued and accordingly
modified the definition of queue position.\195\ The Commission renamed
and revised section 4.2 (General Study Process) of the pro forma LGIP
to require transmission providers to perform interconnection studies
within the cluster study process.\196\ The Commission revised section
4.4 (Modifications) of the pro forma LGIP to provide that moving a
point of interconnection shall result in the loss of a queue position
if it is deemed a material modification by the transmission
provider.\197\ The Commission also revised section 4.4.1 of the pro
forma LGIP to incorporate the material modification process as part of
the cluster study process.\198\ The Commission revised section 4.4.5 of
the pro forma LGIP to require that interconnection customers receive an

[[Page 27024]]

extension of fewer than three cumulative years of the generating
facility's commercial operation date without requiring them to request
such an extension from the transmission provider.\199\
---------------------------------------------------------------------------

\195\ Id. PP 277, 283.
\196\ Id. P 278.
\197\ Id. P 283.
\198\ Id. P 285.
\199\ Id. P 293.
---------------------------------------------------------------------------

109. The Commission adopted revisions to the pro forma LGIP to
implement several cluster study provisions. The Commission replaced
section 6 (Interconnection Feasibility Study) of the pro forma LGIP
with the new public interconnection information requirements as
discussed in section II.C.1 of Order No. 2023.\200\ The Commission
revised section 7 (Cluster Study) of the pro forma LGIP to set out the
requirements and scope of the cluster study agreement, as well as the
cluster study and restudy procedures.\201\ The Commission revised
section 7.4 (Cluster Study Procedures) of the pro forma LGIP to permit
transmission providers to use subgroups in their cluster study process
if they so choose.\202\ The Commission revised section 8.5 (Restudy) of
the pro forma LGIP to make clear that restudies can be triggered by the
withdrawal or modification by a higher- or equally-queued
interconnection requests.\203\ The Commission revised sections 11.1
(Tender) and 11.3 (Execution and Filing) of the pro forma LGIP
regarding the tendering, execution, and filing of the LGIA to
incorporate the site control demonstrations and LGIA deposit
requirements of Order No. 2023.\204\
---------------------------------------------------------------------------

\200\ Id. P 316.
\201\ Id. P 317.
\202\ Id. P 363.
\203\ Id. P 335.
\204\ Id. P 344.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
110. Clean Energy Associations contend that the Commission acted
arbitrarily and capriciously and failed to engage in reasoned decision-
making by changing the definition of stand alone network upgrades such
that only ``single customers'' are eligible to build them.\205\ Clean
Energy Associations claim that, when considered with the shift to a
cluster study process and other stated goals for the sharing of network
upgrade costs amongst interconnection customers, the revised definition
effectively forecloses the opportunity for any future interconnection
customer to exercise their discretion to build stand alone network
upgrades or identified transmission provider interconnection
facilities. Additionally, Clean Energy Associations aver that the
revisions ignore the relationship of the option to build to the project
sponsor, nearly eliminating the benefits of the option to build, such
as controlling project schedules.\206\ Finally, Clean Energy
Associations assert that the Commission's reasoning is based on a
hypothetical situation which has not occurred since Order No. 845, or
possibly ever.
---------------------------------------------------------------------------

\205\ Clean Energy Associations Rehearing Request at 8-9.
\206\ Id. at 9-10.
---------------------------------------------------------------------------

111. Clean Energy Associations argue that the Commission's
assertion that ``confusion and potentially lengthy negotiations and/or
disputes'' would result without revisions to the definition of stand
alone network upgrades is unsupported by the record of this
proceeding.\207\ Clean Energy Associations note that transmission
providers already using cluster studies have operated for years under
the Order No. 845 definition, demonstrating that the revisions were not
necessary. Clean Energy Associations explain that Order No. 2023
neither cites previous instances of confusion or lengthy disputes
regarding the construction of stand alone network upgrades, nor any
other facts or evidence that would support a finding that the current
definition is insufficient or inadequate. Clean Energy Associations
also note that one transmission provider using cluster studies
supported the concept of allowing stand alone network upgrades to be
shared among interconnection customers.\208\
---------------------------------------------------------------------------

\207\ Id. at 10 (citing Order No. 2023, 184 FERC ] 61,054 at P
193).
\208\ Id. at 11-12 (citing Order No. 2023, 184 FERC ] 61,054 at
P 185).
---------------------------------------------------------------------------

112. Clean Energy Associations contend that this aspect of Order
No. 2023 is arbitrary and capricious because the Commission fails to
acknowledge or adequately explain departures from its precedent.\209\
Clean Energy Associations note that Order No. 845 explains that the
option to build benefits the interconnection process by giving
interconnection customers more control and certainty, and that
interconnection customers are in the best position to determine if the
option to build in their interest. However, Clean Energy Associations
assert that the revised definition removes interconnection customers'
ability to exercise their discretion regarding the option to build for
the majority of network upgrades identified in a cluster study, and
modifies the status quo by reducing the number of network upgrades that
would qualify as stand alone network upgrades because the proportional
impact method of cost allocation will reduce the likelihood of finding
a single customer 100% responsible for a network upgrade.\210\ Clean
Energy Associations contend that this renders the Order No. 845 policy
moot and is inconsistent with the Commission's intent in Order No. 2023
to maintain the status quo.
---------------------------------------------------------------------------

\209\ Id. at 12-13.
\210\ Id. at 13-14.
---------------------------------------------------------------------------

113. Clean Energy Associations state that the Commission can
redress this error on rehearing by (1) reversing its decision to revise
the definition of stand alone network upgrade, and (2) requiring
transmission providers to address, in their compliance filings and
OATTs, the process through which interconnection customers with shared
network upgrades that qualify as stand alone network upgrades can
exercise their option to build.\211\ Alternatively, Clean Energy
Associations suggest that the Commission require transmission providers
to allow the interconnection customers amongst whom a stand alone
network upgrade was shared to unanimously exercise the option to build
and, then, to either select a third party to construct the upgrade or
to determine responsibility for doing so amongst themselves. Clean
Energy Associations assert that this would prevent the concern of
disputes among interconnection customers within a cluster. Clean Energy
Associations state that both of these options would be consistent with,
and would preserve, the policy set forth in Order No. 845, while also
addressing the Commission's concerns that disputes or confusion may
arise and further delay the interconnection process, while striking an
appropriate balance between the Commission's policy and efforts in
Order No. 845 and Order No. 2023, honoring both efforts and further
enhancing and benefiting the interconnection process.
---------------------------------------------------------------------------

\211\ Id. at 14-15.
---------------------------------------------------------------------------

114. Clean Energy Associations state that the Commission erred in
finding that modifications to project size can only be made during the
customer engagement window and that interconnection customers must
select a single, definitive point of interconnection at that time.\212\
Clean Energy Associations assert that the record does not support the
conclusion that the customer engagement window is sufficient for the
interconnection customer to enter the cluster study with confidence in
its project size and definitive point of interconnection and, thus,
this timeline does not reflect an appropriate balance that will reduce
the need for restudies and delays. Clean Energy Associations assert the

[[Page 27025]]

opposite--that the record indicates that failure to provide flexibility
to interconnection customers to modify project size and point of
interconnection after receipt of initial cluster study results will
increase the likelihood of withdrawals and cascading restudies by not
allowing interconnection customers to make beneficial adjustments
earlier in the interconnection process that could be determinative in a
project's decision to stay in the cluster or withdraw. Clean Energy
Associations disagree with the Commission's conclusion that the
extended 60 calendar day customer engagement window is sufficient to
provide interconnection customers with ``time to consider information
collected during this period of engagement with the transmission
provider,'' \213\ which will allow customers to determine when to
withdraw their interconnection requests and avoid penalties while
improving queue efficiency due to fewer late-stage cluster study
withdrawals. Clean Energy Associations assert that, prior to the
cluster study, it is difficult for an interconnection customer to make
any informed conclusion about expected costs of potential network
upgrades and such costs' impact on project viability, which the
interconnection customer must learn from the cluster study.
---------------------------------------------------------------------------

\212\ Id. at 15-16.
\213\ Id. at 17-18 (citing Order No. 2023, 184 FERC ] 61,054 at
P 233).
---------------------------------------------------------------------------

115. The 60-day customer engagement window, Clean Energy
Associations assert, only provides interconnection customers 46
calendar days to evaluate publicly posted information and make any
potential project modifications prior to entering the cluster study,
and any such early-acquired information will be incomplete, lacking
modeling data, new model sets, and other study assumptions such as
confidential merit order dispatch lists used by transmission providers
to set up power transfers from new generators, despite publicly posted
information by transmission providers.\214\ Clean Energy Associations
state that substantial information gained through the study process may
necessitate a change in point of interconnection, making choosing a
single point of interconnection implausible. They claim that not
requiring transmission owners to attend scoping meetings further limits
an interconnection customer's access to information. Clean Energy
Associations assert that an interconnection customer will not have
sufficient time and information to evaluate project viability during
the customer engagement window or modify project size and location in
response to pre-study information obtained during that window.
---------------------------------------------------------------------------

\214\ Id. at 18-19.
---------------------------------------------------------------------------

116. Clean Energy Associations assert that limiting post-initial
cluster study entry modifications to the interconnection request to
those the transmission provider deems not to be material ignores record
evidence that this practice will not result in a more reliable,
efficient, transparent, and timely interconnection process.\215\ Clean
Energy Associations assert that allowing flexibility in project size
reductions through the initial cluster study will allow for
optimization of projects based on official study results, resulting in
fewer withdrawals due to increased project viability and contribution
to reliability through reduced impacts to the transmission provider's
system, which it asserts will be less disruptive to the interconnection
process than a full withdrawal. Clean Energy Associations state that,
likewise, inability to change the point of interconnection or to submit
an alternate point of interconnection could cause delays and can
trigger the restudy of an entire cluster. Clean Energy Associations
assert that the record demonstrates that interconnection customers lack
sufficient time or information to optimize project characteristics
prior to entering the initial cluster study, and that flexibility to
make beneficial modifications after receipt of initial study results
would reduce rather than increase uncertainty, restudy, and
administrative burden.
---------------------------------------------------------------------------

\215\ Id. at 19-20.
---------------------------------------------------------------------------

117. Clean Energy Associations further state that the option to
instead pursue a material modification exemption does not provide
sufficient flexibility because: (1) it leaves this determination to the
discretion of the transmission provider; and (2) it ignores that minor
project modifications that could have slight impacts on other
interconnection customers in the same cluster might nonetheless be far
less disruptive than project withdrawal.\216\ Clean Energy Associations
argue that the material modification review is often based on ``opaque
assumptions'' available only to the transmission provider and may
divert resources at a relatively more intense part of the study
process.
---------------------------------------------------------------------------

\216\ Id. at 21-22.
---------------------------------------------------------------------------

118. Clean Energy Associations note that SPP, PJM, and MISO have
adopted provisions allowing 50%-100% reduction allowance and minor
point of interconnection changes, and also permit smaller size
adjustments similar to that found in pro forma LGIP section 4.4.2
through the initial cluster restudy, which Clean Energy Associations
state belie the Commission's assertion that the timing for
modifications in Order No. 2023 reflects a natural translation of the
timing for modification in the existing serial study process to a
cluster study process.\217\ Clean Energy Associations therefore request
that the Commission grant rehearing and modify the language in revised
pro forma LGIP section 4.4.1 to allow modifications to project size
(specifically, up to a 60% size reduction) prior to entering the
cluster restudy, and to allow minor modifications to project size
(specifically, up to a 15% size reduction) after the receipt of a
cluster restudy but prior to the start of the facilities study. Clean
Energy Associations further request that the Commission grant rehearing
and allow interconnection customers the option to present a primary and
alternative definitive point of interconnection in an electrically
proximate area, provided that the transmission provider and
transmission owner verify the alternative as acceptable during the
customer engagement window and prior to the scoping meeting.
---------------------------------------------------------------------------

\217\ Id. at 22.
---------------------------------------------------------------------------

119. IPP Coalition also asks the Commission to reconsider its
requirement that customers identify a single point of interconnection
and, instead, allow for an electrically proximate alternative point of
interconnection that is verified as acceptable by the transmission
provider during the cluster study customer engagement window and listed
in the cluster study agreement.\218\ IPP Coalition asserts that
electrically proximate point of interconnection locations can be
effectively implemented within a study process without materially
impacting a study process, and that this general standard should be
applied consistently to a potential change, whether it is sought by an
interconnection customer as part of the interconnection request or
ultimately required on the basis of a public policy decision.
---------------------------------------------------------------------------

\218\ IPP Coalition Rehearing Request at 7-8.
---------------------------------------------------------------------------

120. [Oslash]rsted requests that the Commission clarify that, in
circumstances where state or federal agency policy or regulation
requires a change to the point of interconnection, projects should be
restudied based upon the new regulatory or statutory requirements.\219\
Alternatively, [Oslash]rsted requests that the Commission clarify that,
in such circumstances, the transmission provider, the state, or the

[[Page 27026]]

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

\219\ [Oslash]rsted Rehearing Request at 11.
---------------------------------------------------------------------------

121. Clean Energy Associations state that the Commission should
grant rehearing and amend Order No. 2023 to stipulate that, if an
interconnection customer submits an interconnection request at least 15
business days prior to the close of the cluster request window, and if
failure by the transmission provider to issue a deficiency notice
within five business days of receipt results in the interconnection
customer having fewer than 10 business days to respond to the
deficiency notice prior to the close of the customer request window,
the interconnection customer shall still be granted a full 10 business
days to respond prior to facing the consequences outlined in revised
pro forma LGIP section 3.4.4.\220\ Clean Energy Associations state
that, to ensure a full 10 business days to respond, an interconnection
customer would have to submit its interconnection request more than 15
business days before the close of the cluster request window to account
for the five business day window for the transmission provider to issue
a deficiency notice, and that even if an interconnection customer
submitted its interconnection request more than 15 business days before
the close of the cluster window, the interconnection customer may be
left with fewer than 10 business days to provide a response in the
event that the transmission provider failed to meet the five business
day notification requirement. Clean Energy Associations state that,
because of this oversight, an interconnection customer may, through no
fault of its own, have as little as one day to respond to a deficiency
notice. Clean Energy Associations argue that revised pro forma LGIP
section 3.4.4 includes significant consequences for interconnection
customers that fail to meet the 10 business-day deadline, but no
consequences for transmission providers that fail to meet the five-
business day deficiency notice deadline. Clean Energy Associations
argue that the Commission acted arbitrarily and capriciously and failed
to engage in reasoned decision-making by failing to account for
potential delay on the part of the transmission provider.
---------------------------------------------------------------------------

\220\ Clean Energy Associations Rehearing Request at 25-26.
---------------------------------------------------------------------------

122. Clean Energy Associations and [Oslash]rsted argue that the
Commission acted arbitrarily and capriciously and failed to engage in
reasoned decision-making when it declined to require transmission
owners to attend scoping meetings.\221\ Clean Energy Associations and
[Oslash]rsted state that requiring transmission owners to attend may
help RTOs/ISOs address potential challenges sooner, avoiding penalties
caused by transmission owner delays. Clean Energy Associations and
[Oslash]rsted assert that the purpose of the customer engagement window
is to provide interconnection customers with information to help them
determine the viability of their proposed generating facilities earlier
in the process, and without transmission owners in these meetings,
interconnection customers are deprived of critical information
necessary to determine the costs and commercial viability of their
projects.\222\ [Oslash]rsted additionally states that transmission
owners are fully responsible for design of network upgrades, including
both substation and system network upgrades, as well as play an
important role in informing point of interconnection decisions by
providing information about the existing grid conditions and
capabilities as well as information related to interconnection
requirements.\223\ [Oslash]rsted therefore argues that the transmission
owner is in the best position to give interconnection customers a sense
of the work required to expand the transmission facilities to
accommodate new interconnection customers, and that a failure to
include transmission owners in these meetings deprives interconnection
customers of critical information necessary to determine the costs and
commercial viability of their projects. [Oslash]rsted asserts that not
requiring transmission owners to attend the scoping meeting creates an
additional burden on both the interconnection customer and the
transmission owner because customer will need to schedule separate
meetings with the transmission owners to get additional information.
---------------------------------------------------------------------------

\221\ Id. at 26; [Oslash]rsted Rehearing Request at 3.
\222\ Clean Energy Associations Rehearing Request at 27-28;
[Oslash]rsted Rehearing Request at 3-4.
\223\ [Oslash]rsted Rehearing Request at 4-5.
---------------------------------------------------------------------------

123. EEI, NYISO, and NYTOs seek rehearing of Order No. 2023's
elimination of the feasibility study.\224\ EEI argues that carrying out
physical feasibility studies, which determine whether the project is
``physically constructable'' to the point of interconnection, early in
the interconnection process will allow for the early disqualification
of infeasible interconnection requests, which will save resources.\225\
NYTOs contend that analyzing feasibility is especially needed in highly
congested areas like New York City and Long Island, where geographic
and environmental limitations often restrict the ability to
interconnect new generation at certain locations, which cannot be
reflected in a heatmap.\226\ NYISO and NYTOs note that, because
physical feasibility issues are particularly important in New York,
NYISO needs to address early in the interconnection study process which
proposed projects will be eligible to make use of those limited points
of interconnection.\227\ NYISO and NYTOs assert that the Commission's
determination to eliminate the feasibility study and replace it with a
heatmap to provide project developers with a rough indication of
interconnection capacity before they submit their interconnection
requests will not address critical physical feasibility issues.
---------------------------------------------------------------------------

\224\ EEI Rehearing Request at 13-14; NYISO Rehearing Request at
11; NYTOs Rehearing Request at 6; see also WIRES Rehearing Request
at 12 (asking the Commission to clarify that feasibility studies can
continue to be performed under the ``Independent Entity Regional
Variation Standard'').
\225\ EEI Rehearing Request at 13-14.
\226\ NYTOs Rehearing Request at 8.
\227\ Id. at 7; NYISO Rehearing Request at 11.
---------------------------------------------------------------------------

124. EEI asks the Commission to clarify that provisional
interconnection service requests will continue to be processed as
received and outside the cluster study process.\228\ EEI states that
the Commission may have inadvertently failed to include provisional
service in its response to PacifiCorp's comments regarding processing
interconnection requests (including provisional service requests) in
Order No. 2023.
---------------------------------------------------------------------------

\228\ EEI Rehearing Request at 14-15.
---------------------------------------------------------------------------

125. EEI requests that the Commission clarify how the 150-day study
deadline applies to cascading restudies.\229\ EEI states that a
withdrawal has the potential to trigger the restudy of every subsequent
cluster, which will have to be conducted in turn. EEI specifically asks
the Commission to clarify that transmission providers have 150 days to
complete the restudy from the initiation of the restudy, rather than
from when the interconnection customers are informed that the restudy
is needed. EEI argues that this clarification is necessary so that
transmission providers have the full 150-day period for each restudy.
---------------------------------------------------------------------------

\229\ Id. at 15-16.
---------------------------------------------------------------------------

126. MISO asks the Commission to clarify that Order No. 2023's
statements that decline to allow transmission providers the flexibility
to set their own study deadlines were intended to respond to requests
to allow transmission providers to establish deadlines for specific
study clusters other than through deadlines fixed in

[[Page 27027]]

their tariffs, and were not intended to preempt transmission providers
from proposing to maintain existing tariff-defined study deadlines that
may differ from the pro forma LGIP's 150 day schedule.\230\ MISO
explains that it uses a three-phase process that has a different length
than the one phase process in the pro forma, and MISO's tariff includes
fixed study deadlines for each phase that are not subject to
discretionary adjustment.
---------------------------------------------------------------------------

\230\ MISO Rehearing Request at 26.
---------------------------------------------------------------------------

127. NYISO asserts that the one-size-fits-all, 150-calendar day
cluster study timeframe is arbitrary and capricious, does not reflect
reasoned decision-making, and is not based on substantial
evidence.\231\ NYISO states that the timeframes for the cluster restudy
and facilities studies are also arbitrary and capricious and deficient.
NYISO asserts that the Commission did not establish a basis for the
150-day timeframe, but rather stated that the timeframe for performing
the stability analyses, power flow analyses, and short circuit analyses
was based on the record without providing detail as to what in the
record supports that conclusion. NYISO also claims the Commission cites
to a limited number of parties, none of which it claims performs such
studies, in support of the 150-day timeframe.
---------------------------------------------------------------------------

\231\ NYISO Rehearing Request at 4-5.
---------------------------------------------------------------------------

128. NYISO contends that the Commission has not considered the
impact to the study timeline of any evaluations required to address
applicable reliability requirements.\232\ NYISO explains that in New
York, for example, the system impact study encompasses numerous steps
critical to evaluating reliability impacts of proposed generating
facilities, which must be performed to fully evaluate a proposed
interconnection under all Applicable Reliability Requirements. NYISO
notes that in New York, Applicable Reliability Requirements include
Northeast Power Coordinating Council rules and New York State
Reliability Council rules, which are often more stringent than NERC
rules because of New York's unique transmission system complexities,
including congestion around New York City and Long Island, and an
influx of offshore wind generation.
---------------------------------------------------------------------------

\232\ Id. at 6-7.
---------------------------------------------------------------------------

129. NYISO contends that the Commission has also failed to consider
how the size or complexity of the cluster could affect the study
timeframe.\233\ NYISO explains that the system impact study timeframe
is driven by the study scope (e.g., whether the study addresses
physical feasibility), the number of impacted parties, the complexity
of the project, and unique challenges at the project's point of
interconnection. NYISO further explains that, for a system impact study
to effectively evaluate a proposed interconnection, the transmission
provider requires accurate modeling data from an interconnection
customer, study cases built for the proposed project, and precise
thermal, voltage, steady state, and short circuit analyses. NYISO
explains that accomplishing this requires a potential several-month
collaboration with transmission owners to: (1) build applicable study
base cases and the associated auxiliary study files; (2) complete any
short circuit base cases necessary to determine point of
interconnection requirements; (3) build pre-and post-project steady-
state base cases that represent various system conditions (e.g., summer
peak load, winter peak load, and spring light load conditions).\234\
NYISO further explains that it: (1) collaborates with applicable
transmission owners and/or interconnection customers to determine
upgrade solutions that constitute the least cost solution to mitigate
reliability violations consistent with good utility practice and all
applicable reliability requirements; (2) must sometimes iteratively
redo the reliability analyses to ensure network upgrades can be
reliably interconnected; and (3) must conduct stability analysis,
transfer analysis, deliverability analysis, short circuit analysis,
NPCC/NYSRC bulk power system transmission facility testing analysis,
sub-synchronous torsional interaction screening analysis, and
additional analyses. NYISO states that the study results must be
summarized and shared with impacted parties and stakeholders and
reviewed by the appropriate NYISO committees and subcommittees. NYISO
avers that, if it had to comply with the 150-day timeline, it may
likely be forced to eliminate this review and approval process.\235\
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\233\ Id. at 8.
\234\ Id. at 9-10.
\235\ Id. at 11.
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130. Additionally, NYISO asserts that cluster studies are unlikely
to create the time savings expected by the Commission.\236\ NYISO
disagrees with the Commission's statement that the transmission
provider ``will be conducting only one interconnection study, or at
most a small number of interconnection studies, at a time, allowing
them to devote more resources to completing the studies in a timely
manner'' because, NYISO argues, this statement does not accurately
reflect the type and amount of work required for the cluster study that
it proposes and the resources that will need to be committed to such
study.\237\ NYISO explains that a large portion of cluster study work
is spent identifying network upgrades at or near points of
interconnection for individual projects or subsets of projects within
the cluster which, as NYISO asserts, effectively requires transmission
providers to perform individual studies within the broader cluster
study and requiring resources similar to that of a serial study.\238\
NYISO contends that only a small portion of cluster study work involves
assessing the impacts on the system of the cluster as a whole. NYISO
adds that each additional project in the cluster adds to the total
amount of work required because each project must be modeled.
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\236\ Id. at 12.
\237\ Id. (citing Order No. 2023, 184 FERC ] 61,054 at P 326).
\238\ Id. at 13.
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131. Further, NYISO argues that efficiencies gained by
transitioning to a cluster study may be offset by increased
participation and resultant large clusters.\239\ NYISO contends that
the more stringent study deposit, commercial readiness, and site
control rules adopted in Order No. 2023 will not materially reduce the
number of projects entering interconnection queues. NYISO notes that it
and other RTOs/ISOs haves adopted similar rules without seeing a
corresponding decrease in projects entering and progressing through
their queues.\240\ NYISO states that, if the Commission does establish
a firm deadline for cluster study completion, it should define a
maximum number of projects in a cluster or allow for extending the 150-
day timeframe according to cluster size.
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\239\ Id. at 14.
\240\ Id. (citing, for example, Midcontinent Independent System
Operator Presentation, Generator Interconnection Queue Improvements,
Planning Advisory Committee (July 19, 2023) (proposing increasing
initial milestone payment from $4000/MW to $10,000/MW), at: <a href="https://cdn.misoenergy.org/20230719%20PAC%20Item%2006%20GI%20Queue%20Improvements%20Proposal629634.pdf">https://cdn.misoenergy.org/20230719%20PAC%20Item%2006%20GI%20Queue%20Improvements%20Proposal629634.pdf</a>).
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132. NYISO requests that the Commission allow RTOs/ISOs to propose
alternative study deadlines as independent entity variations.\241\
NYISO argues that requiring a single, firm study timeframe for all
transmission providers does not recognize that interconnection study
process requirements, challenges, reliability criteria, and queue size
will be different in each region. In the alternative, NYISO requests
that the Commission grant clarification that

[[Page 27028]]

Order No. 2023 was not intended to prevent RTOs/ISOs from proposing
region-specific study deadlines for some or all future studies in their
individual Order No. 2023 compliance filings.
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\241\ Id. at 15-16.
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133. NYISO also asks the Commission to confirm that, during the 45-
day cluster request window, the interconnection customer is limited to
one 10-business day opportunity (or shorter at the end of the request
window) to cure a deficiency in its application.\242\ Further, NYISO
asks the Commission to confirm that it did not intend to require the
transmission provider to issue a second deficiency notice even if time
allowed for such notice in the cluster request window and that, if the
interconnection customer fails to fully cure its application within its
single cure period, its application will be withdrawn. NYISO notes that
section 3.4.4 of the pro forma LGIP provides that: ``At any time, if
Transmission Provider finds that the technical data provided by
Interconnection Customer is incomplete or contains errors,
Interconnection Customer and Transmission Provider shall work
expeditiously and in good faith to remedy such issues.'' NYISO argues
that the Commission should clarify that this language is not intended
to extend the time period by which an interconnection customer must
address deficiencies for the transmission provider's acceptance of a
valid, complete interconnection request, but instead is simply intended
to permit the transmission provider and interconnection customer to
address any minor issues that may be discovered later in the
interconnection process, subject to applicable deadlines. NYISO
proposes revisions to section 3.4.4 of the pro forma LGIP which it
states would accomplish this clarification.
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\242\ Id. at 44-45.
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134. NYISO asks the Commission to confirm that the transmission
provider may complete its determination that an interconnection request
is valid into the customer engagement window, including assessing any
updated information provided by the interconnection customer, within
its permitted deficiency cure period in the cluster request
window.\243\ NYISO also requests confirmation that the transmission
provider is not required to permit interconnection customers to address
any further deficiencies identified in the customer engagement window.
Further, NYISO states the Commission should confirm that, if the
transmission provider determines in the customer engagement window that
an interconnection customer's updated interconnection request remains
deficient and is not valid, the transmission provider may withdraw the
project upon such determination. In particular, NYISO notes that
Paragraph 234 of Order No. 2023 appears to reject withdrawals for
interconnection requests that are not deemed valid until the close of
the customer engagement window. NYISO argues that this statement is
inconsistent with the Commission's requirements to not permit
interconnection customers to cure deficiencies during the customer
engagement window and to limit participation in the Scoping Meeting
during that window to only customers ``whose valid Interconnection
Requests were received in the Cluster Request Window.'' \244\
---------------------------------------------------------------------------

\243\ Id. at 45.
\244\ Id. (citing pro forma LGIP section 3.4.5).
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135. NYISO requests rehearing of the requirement that transmission
providers post an anonymized list of the projects eligible to
participate in the cluster study during the customer engagement
window.\245\ NYISO argues that the requirement creates another
administrative burden on the transmission provider for which the
Commission has not provided a reasonable basis and could result in the
unequal public disclosure of certain information to only a subset of
developers. NYISO asserts that the Commission has not provided support
for this anonymity requirement, aside from a general assertion that
such requirement is appropriate ``to reduce opportunities for
developers to gain competitive advantage over others before
interconnection requests have been finalized and accepted by the
transmission provider.'' \246\ NYISO further states that the Commission
has not provided a description of any means by which publicly
identifying the developers of projects with valid interconnection
requests would provide the developer or other parties with a
competitive advantage. NYISO also explains that its OATT requires
transmission providers to publicly post queue information that includes
certain identifying information about valid interconnection requests.
NYISO argues that the proposed requirement would therefore require a
further administrative step for NYISO to have to conceal certain
information in its publicly posted queue, including the developer's
name and/or the status of the project, as well as take additional steps
to maintain the projects' anonymity, such as masking information in any
other public communications.\247\ Further, NYISO notes that the group
scoping meeting required during the customer engagement window will
reveal many of the cluster participants, and that even if developer
names are not provided during the meeting, many developers in a region
are aware of the employees of other developers in that region.
Therefore, NYISO argues that anonymity of developer names will not mask
the identity of the underlying developers from other cluster
participants but would simply give them an information advantage over
other developers. Finally, NYISO explains that in many cases, such
information would be public anyway, such as through a developer posting
its projects on its website or participating in public request for
proposals, permitting processes, Commission submissions, or other
federal, state, or local proceedings.
---------------------------------------------------------------------------

\245\ Id.
\246\ Id. at 46 (citing Order No. 2023, 184 FERC ] 61,054 at P
237).
\247\ Id. at 46-47.
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136. NewSun argues that the 30-day timeline permitted following
receipt of the cluster study report for interconnection customers to
execute the facilities study agreement and provide deposits is
arbitrary and capricious because it is commercially unreasonable,
counterproductive to the Commission's goals of reducing withdrawals and
restudies, fails to address record evidence, and inconsistent with the
rationale provided in Order No. 2023.\248\ NewSun argues that the 30-
day timeline does not leave time for the proper review and discussion
of the study information, especially where third party information is
involved, or where the interconnection customer's understanding of the
information (even assuming the study was without errors) is contingent
upon study results meetings. NewSun explains that it takes time to, for
example, read the report, formulate questions, set up meetings with
consultants, run financial models, and engage with outside bankers and
financiers.\249\ NewSun asserts that companies with ``near infinite
resources can just play chicken with their balance sheets, many of whom
can merely post a letter of credit (by paying points) to proceed, and/
or make the strategic decision to hold their noses and stay in, hope it
works out, and just treat withdrawal penalties as a cost of doing
business,'' while companies like NewSun have to arrange cash-backed

[[Page 27029]]

letter of credit facilities which takes longer than 30 days to
arrange.\250\ NewSun states that forcing all interconnection customers,
big and small, to make such huge decisions in short windows creates
biases towards ``nose-holding behavior, fearful exits, and inability to
thoughtfully consider outcomes--or changes--much less to collaborate
and/or adapt to avoid delay-causing or costly upgrades.\251\
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