[Federal Register Volume 88, Number 171 (Wednesday, September 6, 2023)]
[Rules and Regulations]
[Pages 61014-61349]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-16628]
[[Page 61013]]
Vol. 88
Wednesday,
No. 171
September 6, 2023
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;
Final Rule
Federal Register / Vol. 88, No. 171 / Wednesday, September 6, 2023 /
Rules and Regulations
[[Page 61014]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM22-14-000; Order No. 2023]
Improvements to Generator Interconnection Procedures and
Agreements
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission (Commission or FERC)
is adopting reforms to its pro forma Large Generator Interconnection
Procedures, pro forma Small Generator Interconnection Procedures, pro
forma Large Generator Interconnection Agreement, and pro forma Small
Generator Interconnection Agreement to address interconnection queue
backlogs, improve certainty, and prevent undue discrimination for new
technologies. The reforms are intended to ensure that the generator
interconnection process is just, reasonable, and not unduly
discriminatory or preferential.
DATES: This final rule is effective November 6, 2023.
FOR FURTHER INFORMATION CONTACT: Tristan Kessler (Technical
Information), Office of Energy Policy and Innovation, 888 First Street
NE, Washington, DC 20426, (202) 502-6608, [email protected].
Franklin Jackson (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-6464,
[email protected].
Sarah Greenberg (Legal Information), Office of the General Counsel,
888 First Street NE, Washington, DC 20426, (202) 502-6230,
[email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph Numbers
I. Introduction 1
A. Historical Framework: Order Nos. 2003, 2006, and 845 11.
B. Regional Transmission Planning and Cost Allocation and
Generator Interconnection Advance Notice of Proposed Rulemaking 18
C. Notice of Proposed Rulemaking 20
D. Joint Federal-State Task Force on Electric Transmission 25
II. Overall Need for Reform 27
A. NOPR 27
B. Comments 30
C. Commission Determination 37
III. Reforms 61
A. Reforms To Implement a First-Ready, First-Served Cluster
Study Process 61
1. Interconnection Information Access 61
2. Cluster Study Process 165
3. Allocation of Cluster Study Costs 405
4. Allocation of Cluster Network Upgrade Costs 422
5. Shared Network Upgrades 468
6. Increased Financial Commitments and Readiness Requirements
490
7. Transition Process 814
B. Reforms To Increase the Speed of Interconnection Queue
Processing 872
1. Elimination of the Reasonable Efforts Standard 872
2. Affected Systems 1026
3. Optional Resource Solicitation Study 1294
C. Reforms To Incorporate Technological Advancements Into the
Interconnection Process 1324
1. Increasing Flexibility in the Generator Interconnection
Process 1324
2. Incorporating the Enumerated Alternative Transmission
Technologies Into the Generator Interconnection Process 1534
3. Modeling and Ride-Through Requirements for Non-Synchronous
Generating Facilities 1621
D. Issues Beyond the Scope of this Rulemaking 1736
1. Comments 1736
2. Commission Determination 1743
IV. Compliance Procedures 1744
A. NOPR Proposal 1744
B. Comments 1747
1. Compliance Filing Deadline 1747
2. Regional Flexibility 1750
3. Reciprocity Tariffs 1759
4. Effective Date 1760
5. Miscellaneous 1761
C. Commission Determination 1762
V. Information Collection Statement 1772
VI. Environmental Analysis 1779
VII. Regulatory Flexibility Act 1780
VIII. Document Availability 1783
IX. Effective Date and Congressional Notification 1785
I. Introduction
1. This final rule requires all public utility transmission
providers to adopt revised pro forma Large Generator Interconnection
Procedures (LGIP), pro forma Small Generator Interconnection Procedures
(SGIP), pro forma Large Generator Interconnection Agreements (LGIA),
and pro forma Small Generator Interconnection Agreements (SGIA).\1\
These revisions will ensure that interconnection customers are able to
interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner, and will prevent undue discrimination.
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\1\ Section 201(e) of the Federal Power Act (FPA) defines
``public utility'' to mean ``any person who owns or operates
facilities subject to the jurisdiction of the Commission under this
subchapter.'' 16 U.S.C. 824(e). A non-public utility that seeks
voluntary compliance with the reciprocity condition of a tariff may
satisfy that condition by filing a tariff, which includes the pro
forma LGIP, the pro forma SGIP, the pro forma LGIA, and the pro
forma SGIA. See Standardization of Generator Interconnection
Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003),
104 FERC ] 61,103, at PP 1, 616 (2003), order on reh'g, Order No.
2003-A, 69 FR 15932 (Mar. 5, 2004), 106 FERC ] 61,220, order on
reh'g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ]
61,287 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (July
18, 2005), 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of
Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007) (NARUC
v. FERC). As stated in the pro forma LGIP, pro forma LGIA, pro forma
SGIP, and pro forma SGIA, transmission provider ``shall mean the
public utility (or its designated agent) that owns, controls, or
operates transmission or distribution facilities used for the
transmission of electric energy in interstate commerce and provides
transmission service under the [Transmission Provider's Tariff]. The
term . . . should be read to include the Transmission Owner when the
Transmission Owner is separate from the Transmission Provider.'' Pro
forma LGIP section 1; pro forma LGIA art. 1; pro forma SGIP attach.
1; pro forma SGIA attach. 1.
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2. Twenty years ago the Commission issued Order No. 2003, in which
the Commission required all public utilities that own, control, or
operate facilities used for transmitting electric energy in interstate
commerce to have on file standard procedures and a standard agreement
for interconnecting generating facilities larger than 20 megawatts (MW)
(called the pro forma LGIP and the pro forma LGIA).\2\ The Commission
stated its expectation that the changes would prevent undue
discrimination, preserve reliability, increase energy supply, and lower
wholesale prices for customers by increasing the amount and variety of
new generation that would compete in the wholesale electricity
market.\3\ The Commission further stated that the standard procedures
would facilitate market entry for generation competitors by reducing
interconnection costs and time.\4\ In Order No. 2006, the Commission
adopted standard procedures and a standard agreement for
interconnecting generating facilities no larger than 20 MW (called the
pro forma SGIP and the pro forma SGIA), citing the same purposes
outlined in Order No. 2003.\5\
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\2\ Order No. 2003, 104 FERC ] 61,103 at P 2.
\3\ Id. P 1.
\4\ Id. P 12.
\5\ Standardization of Small Generator Interconnection
Agreements & Procs., Order No. 2006, 111 FERC ] 61,220, at PP 15,
35-36, order on reh'g, Order No. 2006-A, 70 FR 71760 (Dec. 30,
2005), 113 FERC ] 61,195 (2005), order granting clarification, Order
No. 2006-B, 71 FR 42587 (July 27, 2006), 116 FERC ] 61,046 (2006).
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3. The electricity sector has transformed significantly since the
issuance of Order Nos. 2003 and 2006. The growth of new resources
seeking to interconnect to the transmission system and the differing
characteristics of those resources have created new challenges for the
generator interconnection process. These new challenges are creating
large interconnection queue
[[Page 61015]]
backlogs and uncertainty regarding the cost and timing of
interconnecting to the transmission system, increasing costs for
consumers. Backlogs in the generator interconnection process, in turn,
can create reliability issues as needed new generating facilities are
unable to come online in an efficient and timely manner. While the
Commission recognized these issues and sought to address them in Order
No. 845,\6\ it is clear that further action is needed. Therefore, we
believe that it is necessary to reform the Commission's standard
interconnection procedures and agreements to ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner,
thereby ensuring that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly
discriminatory or preferential.
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\6\ See Reform of Generator Interconnection Procs. & Agreements,
Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ] 61,043, at P 24
(2018), order on reh'g, Order No. 845-A, 84 FR 8156 (Mar. 6, 2019)
166 FERC ] 61,137, order on reh'g, Order No. 845-B, 168 FERC ]
61,092 (2019).
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4. Accordingly, we adopt reforms to the Commission's pro forma LGIP
and pro forma LGIA. Specifically, as explained in detail in this final
rule, we adopt reforms to: (1) implement a first-ready, first-served
cluster study process; \7\ (2) increase the speed of interconnection
queue processing; and (3) incorporate technological advancements into
the interconnection process.
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\7\ A first-ready, first-served cluster study process improves
efficiency in the interconnection study process by including the
following elements: increased access to information prior to
entering the queue; a mechanism to study interconnection requests in
groups where all interconnection requests in the group are equally
queued and of equal study priority; and increased financial
commitments and readiness requirements to enter and proceed through
the queue. In contrast, the existing first-come, first-served serial
study process in the pro forma LGIA and LGIP provides limited
information to interconnection customers prior to entering the
queue, assigns interconnection requests an individual queue position
based solely on the date of entry into the queue, and contains
limited financial and readiness requirements.
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5. First, in order to implement a first-ready, first-served cluster
study process, this final rule requires: (1) transmission providers to
publicly post available information pertaining to generator
interconnection; (2) transmission providers to use cluster studies as
the interconnection study method; (3) transmission providers to
allocate cluster study costs on a pro rata and per capita basis; (4)
transmission providers to allocate network upgrade costs based on a
proportional impact method; (5) interconnection customers to pay study
and commercial readiness deposits as part of the cluster study process;
(6) interconnection customers to demonstrate site control at the time
of submission of the interconnection request; and (7) transmission
providers to impose withdrawal penalties on interconnection customers
for withdrawing from the interconnection queue, with certain
exceptions. We also require transmission providers to adopt a
transition process to move from the existing serial interconnection
process to the new cluster study process.
6. Second, in order to increase the speed of interconnection queue
processing, this final rule: (1) eliminates the reasonable efforts
standard for conducting interconnection studies and imposes a financial
penalty on transmission providers that fail to meet interconnection
study deadlines; and (2) establishes an affected system study process
and associated pro forma affected system agreements.
7. Third, in order to incorporate technological advancements into
the interconnection process, this final rule requires transmission
providers to: (1) allow more than one generating facility to co-locate
on a shared site behind a single point of interconnection and share a
single interconnection request; (2) evaluate the proposed addition of a
generating facility at the same point of interconnection prior to
deeming such an addition a material modification if the addition does
not change the originally requested interconnection service level; (3)
allow interconnection customers to access the surplus interconnection
service process once the original interconnection customer has an
executed LGIA or requests the filing of an unexecuted LGIA; (4) use
operating assumptions in interconnection studies that reflect the
proposed charging behavior of an electric storage resource; and (5)
evaluate the list of alternative transmission technologies enumerated
in this final rule during the generator interconnection study process.
This final rule also requires interconnection customers requesting to
interconnect a non-synchronous generating facility to: (1) provide the
transmission provider with the models needed for accurate
interconnection studies; and (2) have the ability to maintain power
production at pre-disturbance levels and provide dynamic reactive power
to maintain system voltage during transmission system disturbances and
within physical limits. Finally, this final rule requires that all
newly interconnecting large generating facilities provide ride through
capability consistent with any standards and guidelines that are
applied to other generating facilities in the balancing authority area
on a comparable basis.
8. We also adopt reforms to the pro forma SGIP and pro forma SGIA.
Specifically, as explained in detail in this final rule, for small
generating facilities we propose reforms to incorporate the enumerated
alternative transmission technologies into the interconnection process,
and to provide modeling and ride through requirements for non-
synchronous generating facilities.
9. Many of the reforms adopted in this final rule track the notice
of proposed rulemaking's \8\ (NOPR) proposed reforms closely. However,
as discussed more fully below, we have revised aspects of the reforms
pertaining to the cluster study process, allocation of cluster study
and network upgrade costs, increased financial commitments and
readiness requirements, financial penalties for delayed interconnection
studies, the affected system study process, pro forma affected system
agreements, the material modification process, operating assumptions
for interconnection studies, incorporating the enumerated alternative
transmission technologies, and ride through requirements. Additionally,
as discussed more fully below, we decline to adopt the NOPR proposals
pertaining to informational interconnection studies, shared network
upgrades, the optional resource solicitation study, and the alternative
transmission technologies annual report.
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\8\ Improvements to Generator Interconnection Procs. &
Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ] 61,194 (2022)
(NOPR).
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10. We recognize that transmission providers have undertaken
efforts to address interconnection queue management issues. This final
rule is not intended to divert or slow the potential progress
represented by those efforts, and we encourage transmission providers
to continue to innovate to remedy their identified interconnection
queue management issues. We note that the compliance obligations that
result from this final rule will be evaluated in light of the
independent entity variation standard for regional transmission
organizations (RTO) and independent system operators (ISO) and the
consistent with or superior to standard for non-RTO/ISO transmission
providers.\9\
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\9\ Order No. 2003, 104 FERC ] 61,103 at P 26; see infra section
IV.
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A. Historical Framework: Order Nos. 2003, 2006, and 845
11. In Order No. 2003, the Commission recognized a need for a
[[Page 61016]]
standard set of interconnection procedures for transmission providers
and a single, uniformly applicable interconnection agreement for large
generating facilities.\10\ The Commission noted that generator
interconnection is a ``critical component of open access transmission
service and thus is subject to the requirement that utilities offer
comparable service under the [pro forma open access transmission tariff
(tariff)].'' \11\ The Commission found that it was appropriate to
establish a standard set of generator interconnection procedures to
``minimize opportunities for undue discrimination and expedite the
development of new generation, while protecting reliability and
ensuring that rates are just and reasonable.'' \12\ To this end, the
Commission adopted the pro forma LGIP and pro forma LGIA and amended
its regulations to require all transmission providers to incorporate
these standard procedures and agreement into their tariffs.\13\
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\10\ Order No. 2003, 104 FERC ] 61,103 at P 11. Large generating
facilities are defined to mean ``a Generating Facility having a
Generating Facility Capacity of more than 20 MW.'' Pro forma LGIP
section 1.
\11\ Order No. 2003, 104 FERC ] 61,103 at P 9 (citing Tenn.
Power Co., 90 FERC ] 61,238 (2000)).
\12\ Id. P 11.
\13\ 18 CFR 35.28(f)(1) (2022).
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12. To initiate the generator interconnection process set forth in
the Commission's pro forma LGIP,\14\ the interconnection customer
submits an interconnection request for its proposed generating facility
that includes preliminary documentation of the site of the proposed
generating facility, certain technical information about the proposed
generating facility, and the expected commercial operation date of the
proposed generating facility, along with a refundable deposit of
$10,000.\15\ After the transmission provider determines that the
interconnection request is complete, the interconnection request enters
the transmission provider's interconnection queue with other pending
interconnection requests and is assigned a queue position based on the
time and date of its receipt.\16\ The queue position determines the
order in which the transmission provider studies the interconnection
requests in its interconnection queue.\17\
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\14\ While we provide a broad description of the process in the
Commission's pro forma LGIP as background here, we recognize that
many transmission providers have adopted (and the Commission has
accepted) variations to many of the terms in the Commission's pro
forma LGIP and pro forma LGIA. Consequently, some or many of the
details of a particular transmission provider's generator
interconnection procedures may vary considerably from the broad
description provided here.
\15\ Order No. 2003, 104 FERC ] 61,103 at P 35; pro forma LGIP
sections 3.1, 3.4.
\16\ Pro forma LGIP section 4.1.
\17\ Id.
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13. Transmission providers must schedule a scoping meeting with the
interconnection customer to discuss possible points of interconnection
for the proposed generating facility and exchange technical
information, which is followed by a series of interconnection studies
to evaluate the proposed interconnection in detail.\18\ Transmission
providers study interconnection requests in three phases: (1) the
interconnection feasibility study (feasibility study); \19\ (2) the
interconnection system impact study (system impact study); \20\ and (3)
the interconnection facilities study (facilities study).\21\ These
studies contain the power flow, short circuit, and stability analyses
necessary to: (1) identify any adverse impacts on the transmission
providers' transmission system or any affected systems; \22\ (2)
determine the interconnection facilities and network upgrades \23\
needed to reliably interconnect the generating facility; and (3)
estimate the interconnection customer's cost responsibility for these
facilities.\24\ The pro forma LGIP requires that transmission providers
use reasonable efforts to complete: (1) feasibility studies within 45
calendar days; (2) system impact studies within 90 calendar days; and
(3) facilities studies within 90 or 180 calendar days, depending on the
interconnection customer's requested accuracy margin.\25\
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\18\ Order No. 2003, 104 FERC ] 61,103 at P 36; pro forma LGIP
sections 3.4.4, 6-8.
\19\ The pro forma LGIP defines a feasibility study as ``a
preliminary evaluation of the system impact and cost of
interconnecting the Generating Facility to the Transmission
Provider's Transmission System.'' The scope of a feasibility study
is described in section 6 of the pro forma LGIP. Pro forma LGIP
sections 1, 6.
\20\ The pro forma LGIP defines a system impact study as ``an
engineering study that evaluates the impact of the proposed
interconnection on the safety and reliability of Transmission
Provider's Transmission System and, if applicable, an Affected
System.'' In particular, a system impact study identifies and
details ``the system impacts that would result if the Generating
Facility were interconnected without project modifications or system
modifications, focusing on the Adverse System Impacts identified in
the [feasibility study], or to study potential impacts, including
but not limited to those identified in the Scoping Meeting.'' Id.
section 1.
\21\ The pro forma LGIP defines a facilities study as ``a study
conducted by the Transmission Provider or a third-party consultant
for the Interconnection Customer to determine a list of facilities
(including Transmission Provider's Interconnection Facilities and
Network Upgrades as identified in the [system impact study]), the
cost of those facilities, and the time required to interconnect the
Generating Facility with the Transmission Provider's Transmission
System.'' The scope of a facilities study is described in section 8
of the pro forma LGIP. Id. sections 1, 8.
\22\ The pro forma LGIP defines an affected system as an
electric system other than the transmission provider's transmission
system that may be affected by the proposed interconnection. Id.
section 1; pro forma LGIA art. 1.
\23\ For purposes of this final rule, unless otherwise noted,
``network upgrades'' refer to interconnection-related network
upgrades. More specifically, the pro forma LGIP and pro forma LGIA
provide that, ``Network Upgrades shall mean the additions,
modifications, and upgrades to the Transmission Provider's
Transmission System required at or beyond the point at which the
Interconnection Facilities connect to the Transmission Provider's
Transmission System to accommodate the interconnection of the Large
Generating Facility to the Transmission Provider's Transmission
System.'' Pro forma LGIP section 1; pro forma LGIA art. 1.
\24\ Order No. 2003, 104 FERC ] 61,103 at PP 35-37; pro forma
LGIP sections 6-8. The interconnection customer is responsible for
the actual costs of interconnection studies and any necessary
restudies. Pro forma LGIP section 13.3.
\25\ Pro forma LGIP sections 6.3, 7.4, 8.3.
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14. At the completion of the facilities study, the pro forma LGIP
requires the transmission provider to issue a report on the best
estimate of the costs to effectuate the requested interconnection and
provide a draft generator interconnection agreement to the
interconnection customer.\26\ If the interconnection customer wishes to
proceed, after negotiations, the interconnection customer enters into a
generator interconnection agreement with the transmission provider or,
in specific circumstances, requests that the transmission provider file
the agreement with the Commission unexecuted.\27\ The transmission
provider is responsible for the construction of all network upgrades,
but, as further discussed below, the interconnection customer has the
option to build these facilities in certain circumstances.\28\
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\26\ Order No. 2003, 104 FERC ] 61,103 at P 38. Section 11.1 of
the pro forma LGIP requires the transmission provider to tender a
draft LGIA to the interconnection customer ``in the form of
Transmission Provider's FERC-approved standard form LGIA.''
\27\ If the transmission provider and interconnection customer
execute an LGIA that conforms to the transmission provider's
Commission-approved standard form LGIA, the agreement does not need
to be filed with the Commission (if the transmission provider has
such a standard form LGIA on file and submits an Electronic
Quarterly Report). Alternatively, the transmission provider must
file an LGIA with the Commission for review and approval if: (1) the
interconnection customer determines that negotiations with the
transmission provider over the terms of an LGIA are at an impasse
and requests submission of the unexecuted LGIA with the Commission;
or (2) the LGIA does not conform to the transmission provider's
Commission-approved standard form LGIA. See Order No. 2003-A, 106
FERC ] 61,220 at P 201; pro forma LGIP sections 11.2-11.3.
\28\ Order No. 2003, 104 FERC ] 61,103 at PP 351-354; pro forma
LGIA art. 5.1.3.
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15. Similar to Order No. 2003, in Order No. 2006, the Commission
recognized the need for standardized
[[Page 61017]]
interconnection procedures and agreements for small generating
facilities with a capacity of 20 MW or less.\29\ In addition to
establishing a pro forma interconnection study process for small
generating facilities similar to the process for large generating
facilities established in Order No. 2003, the Commission included: (1)
a ``fast track process'' \30\ that uses technical screens to evaluate a
certified small generating facility no larger than 2 MW; and (2) a ``10
[kilowatt (kW)] inverter process'' \31\ that uses the same technical
screens to evaluate a certified inverter-based small generating
facility no larger than 10 kW.\32\ The Commission later issued Order
No. 792,\33\ in which the Commission revised the pro forma SGIP and pro
forma SGIA to provide for interconnection customers to receive point of
interconnection information in advance of submitting an interconnection
request, increase the threshold for participation in the fast track
process to five MW, and to specifically include electric storage
devices.\34\
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\29\ Order No. 2006, 111 FERC ] 61,220 at P 36.
\30\ Pro forma SGIP section 2.1.
\31\ Id. attach. 5.
\32\ Order No. 2006, 111 FERC ] 61,220 at PP 36, 38-39.
\33\ Small Generator Interconnection Agreements & Procs., Order
No. 792, 78 FR 73240 (Dec. 5, 2013), 145 FERC ] 61,159 (2013),
clarifying, Order No. 792-A, 146 FERC ] 61,214 (2014).
\34\ See Order No. 792, 145 FERC ] 61,159 at P 1.
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16. In response to concerns voiced to the Commission about
interconnection queue management, in 2007, the Commission held a
technical conference,\35\ and later issued an order \36\ addressing
interconnection queue issues in RTOs/ISOs. In the order, the Commission
noted that some transmission providers were not processing their
interconnection queues within the timelines established in the pro
forma LGIP, and in certain cases, were greatly exceeding them.\37\ The
Commission stated that, although it ``may need to [impose solutions] if
the RTOs and ISOs do not act themselves,'' each RTO/ISO would have an
opportunity to work with its stakeholders to develop its own
solutions.\38\ As further discussed below, following the order,
multiple RTOs/ISOs submitted queue reform proposals to the Commission,
some of which moved away from a so-called ``first-come, first-served''
approach (whereby interconnection requests are processed in the order
they are received) to a so-called ``first-ready, first-served''
approach (whereby interconnection requests are processed based on when
interconnection customers meet certain project development
milestones).\39\ The reason for this move was to allow interconnection
customers with interconnection requests for generating facilities more
likely to achieve commercial operation to move faster instead of being
delayed by interconnection requests that were higher in the
interconnection queue but making limited or no progress towards
commercial operation and creating unreasonable queue delays.
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\35\ Interconnection Queuing Practices, Notice of Technical
Conference, Docket No. AD08-2-000 (issued Nov. 2, 2007).
\36\ Interconnection Queuing Pracs., 122 FERC ] 61,252 (2008)
(2008 Technical Conference Order).
\37\ Id. P 3.
\38\ Id. P 8.
\39\ See, e.g., Sw. Power Pool, Inc., 128 FERC ] 61,114 (2009);
Midwest Indep. Transmission Sys. Operator, Inc., 124 FERC ] 61,183
(2008); Cal. Indep. Sys. Operator Corp., 124 FERC ] 61,292 (2008).
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17. In 2018, the Commission issued Order No. 845, in which the
Commission made the most comprehensive revisions to the pro forma LGIP
and pro forma LGIA since their adoption in Order No. 2003. In Order No.
845, the Commission concluded that reforms to the pro forma LGIP and
pro forma LGIA were needed to mitigate concerns regarding systemic
inefficiencies, remedy discriminatory practices, and address recent
developments, including changes in the resource mix and emergence of
new technologies.\40\ The Commission therefore adopted reforms designed
to improve certainty for interconnection customers, promote more
informed interconnection decisions, and enhance the generator
interconnection process.\41\
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\40\ Order No. 845, 163 FERC ] 61,043 at P 7.
\41\ Id. P 2.
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B. Regional Transmission Planning and Cost Allocation and Generator
Interconnection Advance Notice of Proposed Rulemaking
18. On July 15, 2021, the Commission issued an advance notice of
proposed rulemaking (ANOPR) in Docket No. RM21-17-000, presenting
potential reforms to the Commission's requirements governing the
regional transmission planning and cost allocation and generator
interconnection processes.\42\ Specific to the generator
interconnection process, the Commission sought comment on whether and
which reforms may be necessary to ensure a more purposeful integration
of the generator interconnection process with the regional transmission
planning and cost allocation processes, establish a faster and more
efficient interconnection queueing process, and promote a more
efficient and cost-effective allocation of network upgrade costs.\43\
For instance, the Commission noted that the cost of network upgrades
can depend largely on both the timing of when the interconnection
customer enters the interconnection queue and where the interconnection
customer proposes to interconnect its generating facility. Therefore,
the Commission noted, interconnection customers may submit multiple
interconnection requests in an effort to determine the most favorable
point of interconnection \44\ that minimizes their network upgrade
costs.\45\ The Commission stated that this practice, in turn, may lead
to late-stage withdrawals of the excess interconnection requests, which
can then impede the transmission provider's ability to process its
interconnection queue in an efficient manner. As a result, the
Commission stated that it may be time to consider reforms to the
generator interconnection process that would make it more efficient and
ensure that generating facilities that are more ``ready'' than others
are not unduly delayed in the interconnection queue.
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\42\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, 86 FR 40266
(July 15, 2021), 176 FERC ] 61,024 (2021) (ANOPR).
\43\ Id. P 5.
\44\ The pro forma LGIP defines point of interconnection as
``the point, as set forth in Appendix A to the Standard Large
Generator Interconnection Agreement, where the Interconnection
Facilities connect to the Transmission Provider's Transmission
System.'' Pro forma LGIP section 1.
\45\ ANOPR, 176 FERC ] 61,024 at P 41.
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19. On April 21, 2022, the Commission issued a notice of proposed
rulemaking (Transmission Planning and Cost Allocation NOPR) proposing
reforms to its existing regional transmission planning and cost
allocation requirements in the same proceeding as it issued the
ANOPR.\46\ While the Transmission Planning and Cost Allocation NOPR did
not address many of the concerns raised by the Commission in the ANOPR
with respect to the generator interconnection queue process, the
Commission noted in the Transmission Planning and Cost Allocation NOPR
that it would continue to review the record and that it expected to
address possible inadequacies through subsequent proceedings that
propose reforms, as warranted, related to that topic.\47\ The
Commission took that next step with the reforms proposed
[[Page 61018]]
in the NOPR in this proceeding, many of which we adopt in this final
rule.
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\46\ Bldg. for the Future Through Elec. Reg'l Transmission Plan.
& Cost Allocation & Generator Interconnection, 87 FR 26504 (May 4,
2022), 179 FERC ] 61,028 (2022).
\47\ Id. P 10.
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C. Notice of Proposed Rulemaking
20. On June 16, 2022, the Commission issued the NOPR, proposing
reforms focused on improving aspects of the pro forma LGIP, pro forma
LGIA, pro forma SGIP, and pro forma SGIA. The Commission also sought
comment on, but did not propose, tariff revisions on other issues.
21. First, the Commission proposed reforms focused on improving
interconnection processes to ensure interconnection customers can
proceed in an efficient and timely manner.\48\ Among those, the
Commission proposed to: (1) require transmission providers to offer an
optional informational interconnection study to serve as additional
information for prospective interconnection customers in deciding
whether to submit an interconnection request and set minimum
requirements for transmission providers to publicly post available
information pertaining to generator interconnection; \49\ (2) require
transmission providers to implement a first-ready, first-served cluster
study process that allocates costs associated with cluster studies and
identified network upgrades consistent with the discussion below; \50\
and (3) impose more stringent financial commitments and readiness
requirements on interconnection customers, including increased study
deposits, more stringent site control requirements, a commercial
readiness framework, and higher withdrawal penalties.\51\ To implement
these reforms, the Commission also proposed to require transmission
providers to establish a transition process.\52\
---------------------------------------------------------------------------
\48\ NOPR, 179 FERC ] 61,194 at P 4.
\49\ Id. PP 42-52.
\50\ Id. PP 56-101.
\51\ Id. PP 104-148.
\52\ Id. PP 150-160.
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22. Second, the Commission proposed three reforms to increase the
speed of interconnection queue processing, including: (1) revisions to
eliminate the reasonable efforts standard for interconnection study
processing; \53\ (2) revisions to establish an affected system study
process, along with necessary pro forma affected system agreements;
\54\ and (3) revisions to establish an optional resource solicitation
study.\55\
---------------------------------------------------------------------------
\53\ Id. PP 168-173.
\54\ Id. PP 182-215.
\55\ Id. PP 223-237.
---------------------------------------------------------------------------
23. Finally, the Commission proposed three reforms to incorporate
technological advancements into the interconnection study process. With
these reforms, the Commission proposed to require transmission
providers to: (1) increase flexibility in the generator interconnection
process by allowing generating facilities to co-locate, allow the
interconnection customer to request the addition of a generating
facility to an existing interconnection request, increase the
availability of surplus interconnection service, and allow
interconnection customers to propose operating assumptions for their
generating facilities; \56\ (2) incorporate the enumerated alternative
transmission technologies into the interconnection study process at the
request of the interconnection customer; \57\ and (3) list required
modeling standards for inclusion in all interconnection requests that
include inverter-based resources (IBRs), as well as require certain
performance standards from IBRs during system disturbances.\58\
---------------------------------------------------------------------------
\56\ Id. PP 242-288.
\57\ Id. PP 297-302.
\58\ Id. PP 328-341.
---------------------------------------------------------------------------
24. In response to the NOPR, 189 comments were filed.\59\ These
comments have informed our determinations in this final rule.
---------------------------------------------------------------------------
\59\ Appendix A lists the entities that submitted comments on
the NOPR and the shortened names used through this final rule to
describe those entities.
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D. Joint Federal-State Task Force on Electric Transmission
25. On June 17, 2021, the Commission established a Joint Federal-
State Task Force on Electric Transmission (Task Force) to formally
explore broad categories of transmission-related topics.\60\ The
Commission explained that the development of new transmission
infrastructure implicated a host of different issues, including
generator interconnection. The Task Force is comprised of all FERC
Commissioners as well as representatives from 10 state commissions
nominated by the National Association of Regulatory Utility
Commissioners (NARUC), with two originating from each NARUC region.\61\
The Task Force convenes for multiple formal meetings annually, which
are open to the public. Since its creation and as of the date of
issuance of this final rule, the Task Force has met seven times.
---------------------------------------------------------------------------
\60\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC
] 61,224, at PP 1, 6 (2021).
\61\ An up-to-date list of Task Force members, as well as
additional information on the Task Force, is available on the
Commission's website at: https://www.ferc.gov/TFSOET. Public
materials related to the Task Force, including transcripts from
public meetings, are available in the Commission's eLibrary in
Docket No. AD21-15-000.
---------------------------------------------------------------------------
26. The discussion at the May 2022 meeting focused on
interconnection issues, including generator interconnection queue
processes and backlogs. The Task Force members discussed: the primary
challenges preventing more efficient processing of interconnection
queues; specific improvements to interconnection processes (such as
tighter applicant requirements to enter and remain in the queue,
clustering, fast tracking, tighter deadlines on transmission providers
completing studies, and minimizing reiterative studies); and how to
balance near-term improvements to the interconnection procedures with
longer-term regional transmission planning and development.\62\
---------------------------------------------------------------------------
\62\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022).
---------------------------------------------------------------------------
II. Overall Need for Reform
A. NOPR
27. In the NOPR, the Commission noted that the serial first-come,
first-served study process was adopted at a time when most
interconnection requests were for large traditional generating
facilities that would use readily available transmission capacity.\63\
The Commission stated that the continued use of this process in the
face of dramatic changes to the electric power industry, principally
the surge in interconnection requests, the rapidly changing resource
mix, evolving market forces, and the emergence of new technologies, has
led to a growing backlog of interconnection requests and study delays
for many transmission providers.\64\ The Commission also stated that
these interconnection queue backlogs and study delays create
uncertainty and inhibit project developers' ability to interconnect
generating facilities to the transmission system.\65\ The Commission
preliminarily found that the existing pro forma LGIP, pro forma LGIA,
pro forma SGIP, and pro forma SGIA may be insufficient to ensure that
new generating facilities are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner and to
thereby ensure that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly
[[Page 61019]]
discriminatory or preferential.\66\ Further, because the
interconnection queue backlogs and study delays afflicting generator
interconnection service nationwide hinder the timely development of new
generation and thereby stifle competition in the wholesale electric
markets, the Commission also preliminarily found that the Commission's
pro forma LGIP, pro forma LGIA, pro forma SGIP, and pro forma SGIA
result in rates, terms, and conditions in the wholesale electric
markets that are unjust, unreasonable, and unduly discriminatory or
preferential.
---------------------------------------------------------------------------
\63\ NOPR, 179 FERC ] 61,194 at P 18.
\64\ Id. PP 18-20.
\65\ Id. P 19 (citing Joint Fed.-State Task Force on Elec.
Transmission, Technical Conference, Docket No. AD21-15-000, Tr.
15:21-16:1 (Ted Thomas) (May 6, 2022) (May Joint Task Force Tr.)
(``Houston, we have a problem. As stated in the NARUC ANOPR
comments, existing methods for interconnecting new resources to the
transmission grid are inadequate and inefficient because of the time
necessary to interconnect new resources and the corresponding
network upgrade costs.'')).
\66\ Id. P 22 (citing May Joint Task Force Tr. 23:6-11 (Riley
Allen) (``Ultimately, this system is not working efficiently now and
those inefficiencies translate into costs. It's not just cost on the
developers, but I find from my decades of experience that, if there
are inefficiencies in the system, they ultimately have to be borne
by the loads and ratepayer interests.'')).
---------------------------------------------------------------------------
28. The Commission stated that its preliminary findings were based
on several features of the Commission's existing generator
interconnection procedures and agreements that are of concern,
specifically: (1) the information (or lack thereof) available to
prospective interconnection customers and the commitments required of
them to enter and progress through the interconnection queue; (2) the
reliance on a serial first-come, first-served study process and the
standard to which transmission providers are held for meeting
interconnection study deadlines; (3) the protocols for affected systems
studies; (4) the provisions for studying new or hybrid generation
technologies and considering alternative transmission technologies; and
(5) the performance requirements for non-synchronous generating
facilities, including wind, solar, and electric storage facilities.\67\
---------------------------------------------------------------------------
\67\ Id. PP 23-36 (citing May Joint Task Force Tr. 70:20-71:6
(Matthew Nelson) (analogizing reiterative studies to going to the
supermarket to buy ingredients for a recipe without knowing how much
the ingredients cost, finding out at the register that they cost too
much for your budget, and having to ``go home, get a new recipe, and
start it all over again'')).
---------------------------------------------------------------------------
29. The Commission found that some of the same issues persist in
the small generating facility context and, therefore, proposed limited
reforms to the pro forma SGIP and pro forma SGIA to incorporate
alternative transmission technologies into the interconnection process
and to provide modeling and performance requirements for non-
synchronous generating facilities.\68\
---------------------------------------------------------------------------
\68\ Id. P 5.
---------------------------------------------------------------------------
B. Comments
30. The vast majority of commenters overwhelmingly agree with the
Commission's preliminary conclusion that there is a need to reform the
Commission's pro forma interconnection procedures and agreements to
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner, thereby ensuring that rates, terms, and conditions for
Commission-jurisdictional services are just, reasonable, and not unduly
discriminatory or preferential.\69\ These commenters generally agree
that the unprecedented volume of generation in the interconnection
queue, which is almost equal to the current U.S. generation fleet, has
resulted in severe backlogs in interconnection processes across the
country.\70\ For example, the Ohio Commission Consumer Advocate states
that ``there is an urgent need to clear the current generator
interconnection queue backlog and to facilitate timely and economic
interconnection of new resources in a way that responds to current and
future market conditions.'' \71\ EEI recognizes that, despite many
efforts underway across the country to fix individual transmission
provider interconnection queue processes, there is still a need for the
Commission to address backlogs and improve certainty in the
interconnection queue process.\72\ Several commenters assert that these
interconnection backlogs have resulted in commercial uncertainty
regarding both the magnitude of identified upgrade costs and the
timeline for completion of interconnection studies, delayed project
development, increased costs for consumers due to the prevention of new
supply from reaching the market, and impaired reliability.\73\ Senators
Hickenlooper and King note that, in the past decade, 23% of proposed
generating facilities reached commercial operation, while 72% were
withdrawn.\74\ ELCON and APPA-LPPC both argue that uncertainty, on the
part of both transmission provider and generator project developer,
inevitably leads to an increase in costs to consumers.\75\ U.S. DOE
submits a recent report published by the Lawrence Berkeley National
Laboratory, which finds that interconnection costs in MISO have
escalated as the number of interconnection requests has increased.\76\
Specifically, the report finds that interconnection costs in MISO
doubled for projects completed between 2019-2021 compared to projects
completed prior to 2018, and cost estimates tripled for projects still
active in the queue between the same time periods. Some commenters
agree that the existing interconnection rules in the pro forma LGIP and
pro forma LGIA create an incentive for interconnection customers to
submit interconnection requests even if they are not prepared to
[[Page 61020]]
move forward with their projects, in order to secure a favorable
position in the interconnection queue or in an attempt to obtain
locations with available transmission capacity.\77\ They assert that
the withdrawal of each speculative interconnection request triggers
reassessments and possible restudies by the transmission provider that
can increase the timing and interconnection cost for lower-queued
interconnection requests. Several commenters point to ambitious climate
goals (such as the United States' commitment to reducing net greenhouse
gas emissions by 50-52% by 2030 under the Paris Climate Agreement) and
argue that: (1) these changes will likely spur greater investment in
new generation and exacerbate the delays in processing interconnection
requests; and/or (2) without an efficient and transparent
interconnection process, none of the clean energy generating facilities
intended to meet these goals can be effectively deployed.\78\ Consumers
Energy argues that delays in processing interconnection requests will
exacerbate resource adequacy challenges.\79\
---------------------------------------------------------------------------
\69\ ACE-NY Initial Comments at 2; ACE-NY Reply Comments at 5;
AEE Initial Comments at 3, 5; AEE Reply Comments at 5; AES Initial
Comments at 2; Affected Interconnection Customers Initial Comments
at 2; Ameren Initial Comments at 2; APPA-LPPC Reply Comments at 2;
Avangrid Initial Comments at 6, 8; Bonneville Initial Comments at 3;
CESA Initial Comments at 3; CESA Reply Comments at 1; Clean Energy
Associations Initial Comments at 8; Clean Energy Buyers Initial
Comments at 3; Clean Energy States Initial Comments at 2-3; Colorado
Commission Initial Comments at 1; Consumers Energy Initial Comments
at 2; Cypress Creek Initial Comments at 1; Dominion Initial Comments
at 4; EEI Initial Comments at 2; EEI Reply Comments at 3; EDF
Renewables Initial Comments at 1-2; Enel Initial Comments at 2;
Energy Keepers Initial Comments at 2; Evergreen Action Initial
Comments at 1; Eversource Initial Comments at 2; Fervo Energy
Initial Comments at 2; Google Initial Comments at 2; Guzman Energy
Initial Comments at 2; Hannon Armstrong Initial Comments at 1;
Hydropower Commenters Initial Comments at 5; Illinois Commission
Initial Comments at 2-3, 5; Interwest Initial Comments at 3;
Interwest Reply Comments at 2; ISO-NE Initial Comments at 2-3; MISO
TOs Initial Comments at 2, 6; NARUC Initial Comments at 3; New
Jersey Commission Initial Comments at 4-9; NY Commission and NYSERDA
Initial Comments at 3; NV Energy Initial Comments at 3; Ohio
Commission Consumer Advocate Initial Comments at 3-4; OMS Initial
Comments at 2; [Oslash]rsted Initial Comments at 5; Pine Gate
Initial Comments at 8; PJM Initial Comments at 1, 4; PJM Coalition
Initial Comments at 1; RWE Renewables Initial Comments at 1;
Senators Hickenlooper and King Initial Comments at 1-2; Shell
Initial Comments at 5-6; State Agencies Initial Comments at 1-2;
TAPS Initial Comments at 1; Union of Concerned Scientists Reply
Comments at 1; UMPA Initial Comments at 1; WATT Coalition Initial
Comments at 1; Xcel Initial Comments at 8.
\70\ AEE Initial Comments at 3; Apple Initial Comments at 1;
Bonneville Initial Comments at 3; Clean Energy Buyers Initial
Comments at 3; Colorado Commission Initial Comments at 2, 8-11; EDF
Renewables Initial Comments at 2; Evergreen Action Initial Comments
at 1; Eversource Initial Comments at 2; Interwest Initial Comments
at 1-2; NV Energy Initial Comments at 2-3; Ohio Commission Consumer
Advocate Initial Comments at 3-4; [Oslash]rsted Initial Comments at
2; Senators Hickenlooper and King Initial Comments at 1-2; U.S.
Chamber of Commerce Initial Comments at 5; UMPA Initial Comments at
1.
\71\ Ohio Commission Consumer Advocate Initial Comments at 3-4.
\72\ EEI Reply Comments at 3.
\73\ ACE-NY Initial Comments at 2; AEE Initial Comments at 4;
EDF Renewables Initial Comments at 2; ELCON Initial Comments at 2;
Fervo Energy Initial Comments at 2; PJM Coalition Initial Comments
at 2; Xcel Reply Comments at 1.
\74\ Senators Hickenlooper and King Initial Comments at 1
(citing Joseph Rand et al., Lawrence Berkeley Nat'l Lab., Queued Up:
Characteristics of Power Plants Seeking Transmission Interconnection
(Apr. 2022) (Queued Up 2022), https://emp.lbl.gov/sites/default/files/queued_up_2021_04-13-2022.pdf)).
\75\ ELCON Initial Comments at 2; APPA-LPPC Initial Comments at
2.
\76\ U.S. DOE Initial Comments at 1 (citing Joachim Seel et al.,
Lawrence Berkeley Nat'l Lab., Interconnection Cost Analysis in the
MISO Territory at 1 (Oct. 2022)).
\77\ Clean Energy Buyers Initial Comments at 3; Dominion Initial
Comments at 4-5; PJM Initial Comments at 12; U.S. Chamber of
Commerce Initial Comments at 4-5.
\78\ AEP Initial Comments at 2; Affected Interconnection
Customers Initial Comments at 2; Allen Meyer Initial Comments at 1;
Apple Initial Comments at 1; Bretton C Little Initial Comments at 1;
Colorado Commission Initial Comments at 13-14; EDF Renewables
Initial Comments at 2-3 (referencing Inflation Reduction Act, Pub.
L. 117-169 (2022)); ELCON Initial Comments at 2; Evergreen Action
Initial Comments at 2; GSCE Initial Comments at 5-6; Individual
Signatories Initial Comments at 1-2; Interwest Comments at 1-2;
National Grid Initial Comments at 2; Payton Alaama Reply Comments at
1; Pine Gate Reply Comments at 3-4; Rick K Lathrop Reply Comments at
1; Shell Initial Comments at 6; State Agencies Initial Comments at
8-9 (citing Int'l Energy Agency, Net Zero by 2050: A Roadmap for the
Global Energy Sector (2021) https://www.iea.org/reports/net-zero-by-2050; The United States' Nationally Determined Contribution (2021),
https://www4.unfccc.int/sites/ndcstaging/PublishedDocuments/United%20States%20of%20America%20First/United%20States%20NDC%20April%2021%202021%20Final.pdf; White House,
FACT SHEET: Biden Administration Jumpstarts Offshore Wind Energy
Projects to Create Jobs (Mar. 29, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/03/29/fact-sheet-biden-administration-jumpstarts-offshore-wind-energy-projects-to-create-jobs/); Sue Hilton Initial Comments at 1; Union of Concerned
Scientists Reply Comments at 6; Vistra Initial Comments at 4.
\79\ Consumers Energy Initial Comments at 7.
---------------------------------------------------------------------------
31. A small subset of commenters, while supporting an overall need
for reform, disagree with some of the Commission's preliminary
conclusions about the need for reform.\80\ A few other commenters claim
that there is no basis for the Commission's preliminary conclusion that
speculative projects that enter the interconnection queue and later
withdraw, causing cascading restudies, are responsible for
interconnection queue backlogs.\81\ A few commenters assert that the
Commission did not take into account pertinent factors affecting
interconnection queue sizes, such as an increase in the development of
smaller, more diverse generating facilities.\82\
---------------------------------------------------------------------------
\80\ For instance, Affected Interconnection Customers disagree
with the Commission's reference to a nationwide shortage of
qualified engineers and contend that the Commission fails to support
this conclusion with any evidence beyond statements made by CAISO
and MISO. Affected Interconnection Customers Initial Comments at 14
(citing NOPR, 179 FERC ] 61,194 at P 20 n.67).
\81\ CREA and NewSun Initial Comments at 35-37 (countering that
interconnection requests do not reach commercial operation due to
other reasons such as permitting or financing difficulties); NextEra
Initial Comments at 4; Public Interest Organizations Initial
Comments at 1-7 (arguing that the rate of queue withdrawal has been
consistent over the last decade); SEIA Reply Comments at 1.
\82\ AEE Initial Comments at 6-7; Pine Gate Reply Comments at 4;
SEIA Reply Comments at 1.
---------------------------------------------------------------------------
32. Three comments note that various transmission providers use
vastly different interconnection procedures from the pro forma
procedures established in Order No. 2003 and argue that there is an
insufficient legal foundation under FPA section 206 to demonstrate that
all of these approved interconnection procedures are unjust,
unreasonable, and unduly discriminatory or preferential.\83\ Southern
disagrees entirely with the Commission's preliminary conclusion that
there is a need for reform.\84\ Southern argues that the Commission
based its proposed actions in the NOPR on conjecture and thus failed to
provide substantial evidence or engage in reasoned decision-making to
demonstrate that the current interconnection processes are unjust and
unreasonable.\85\ In addition, Southern contends that the Commission's
proposals are arbitrary and capricious because they impose a broadly
applicable remedy to a problem that does not exist uniformly.\86\
---------------------------------------------------------------------------
\83\ Early Adopters Coalition Initial Comments at 1-2;
PacifiCorp Initial Comments at 9; Southern Initial Comments at 10-
11.
\84\ Southern Initial Comments at 10-12; Southern Reply Comments
at 1, 4.
\85\ Southern Initial Comments at 10 (citing Emera Me. v. FERC,
854 F.3d 9, 24 (D.C. Cir. 2017)); Southern Reply Comments at 1, 4.
\86\ Southern Initial Comments at 11-12.
---------------------------------------------------------------------------
33. Southern further asserts that the Commission failed to provide
any actual evidence that its proposals will reduce interconnection
queue backlogs or increase certainty for interconnection customers.\87\
---------------------------------------------------------------------------
\87\ Id. at 10; Southern Reply Comments at 5.
---------------------------------------------------------------------------
34. Some commenters argue that the sum of the NOPR may actually
slow study processes, increase backlogs, and may unintentionally
increase costs to ratepayers.\88\ For example, CAISO asserts that
shortening study timelines results in rushed, unreliable studies which
would ultimately require more iteration and longer interconnection
queue processing times.\89\ Additionally, NextEra argues that the NOPR
provides few, if any, solutions relevant to those regions that have
already implemented cluster studies yet continue to experience
significant study delays.\90\ Further, some commenters oppose any
generic one-size-fits-all reform, arguing that queue reform is best
left to the regional level.\91\
---------------------------------------------------------------------------
\88\ CAISO Initial Comments at 3; Dominion Initial Comments at
7; New York State Department Initial Comments at 2; NextEra Reply
Comments at 2; NRECA Initial Comments at 7.
\89\ CAISO Initial Comments at 3.
\90\ NextEra Reply Comments at 7.
\91\ Avangrid Initial Comments at 36-37; Southern Initial
Comments at 14-15.
---------------------------------------------------------------------------
35. Several commenters generally support the suite of proposed
reforms in their entirety.\92\ As discussed in detail in each section
below discussing individual reforms, most commenters either support
specific proposals or suggest that the Commission prioritize certain
proposed reforms. For instance, Consumers Energy supports reforms that
increase the speed of interconnection queue processing because it
claims that the reforms provide clarity for resource planners and
interconnection customers as well as improve the reliability of the
bulk electric system and the clean energy resource transformation.\93\
Google urges the Commission to prioritize reforms that provide a level
playing field for both utility-backed resources and independent power
producer-developed resources.\94\ Google also expresses concern that
the layering of increased study deposits, more stringent site control
requirements, the proposed commercial readiness requirements, and
withdrawal penalties may place undue burden on interconnection
customers if the Commission does not also adopt proposals for more
publicly available interconnection information, firm study deadlines,
and penalties for missed study deadlines.\95\
---------------------------------------------------------------------------
\92\ APPA-LPPC Initial Comments at 2-3; APPA-LPPC Reply Comments
at 2; Apple Initial Comments at 1; ACORE Initial Comments at 2;
Amazon Initial Comments at 2; Evergreen Action Initial Comments at
1-4; Individual Signatories Initial Comments at 1; PJM Coalition
Initial Comments at 2.
\93\ Consumers Energy Initial Comments at 10-11.
\94\ Google Initial Comments at 3.
\95\ Id. at 16.
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36. Some commenters support adopting most or all of the limited
[[Page 61021]]
reforms to the pro forma SGIP and pro forma SGIA proposed in the
NOPR.\96\ For instance, Microgrid Resources asserts that including the
proposed reforms in the pro forma SGIP is necessary to reflect the
operating assumptions of, and to provide equitable treatment for,
microgrids and other behind-the-meter resources.\97\ Microgrid
Resources asserts that, if the Commission succeeds in expediting
interconnections for large generating facilities, while small
generating facility interconnections languish, it will bias the system
against smaller local generating facilities that are the backbone of
community resilience.
---------------------------------------------------------------------------
\96\ Bonneville Initial Comments at 24 (supporting applying some
of the Commission's proposed reforms to the pro forma SGIP and pro
forma SGIA (e.g., commercial readiness requirements), but asking
that transmission providers be granted flexibility to determine
which reforms should be applicable to small generator procedures and
agreements); IREC Initial Comments at 3 (stating that the pro forma
SGIP lacks the necessary provisions to safely and reliably
interconnect storage to the electric grid while enabling its unique
operating characteristics); Microgrid Resources Initial Comments at
8-9; Xcel Initial Comments at 19 (supporting applying reforms to
small generating facilities requesting energy only interconnection
service).
\97\ Microgrid Resources Initial Comments at 8-9.
---------------------------------------------------------------------------
C. Commission Determination
37. Based on the record, including comments submitted in response
to the NOPR, as discussed below, we find that there is substantial
evidence to support the conclusion that the existing pro forma
generator interconnection procedures and agreements are unjust,
unreasonable, and unduly discriminatory or preferential.\98\ We
therefore adopt the preliminary findings in the NOPR concerning the
need for reform \99\ and, pursuant to FPA section 206, conclude that
certain revisions to the pro forma open access transmission tariff and
the Commission's regulations are necessary to ensure rates that are
just, reasonable, and not unduly discriminatory or preferential.
Specifically, we find that the existing pro forma generator
interconnection procedures and agreements are insufficient to ensure
that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner, thereby ensuring that rates, terms, and conditions for
Commission-jurisdictional services are just, reasonable, and not unduly
discriminatory or preferential. Absent reform, the current
interconnection process will continue to cause interconnection queue
backlogs, longer development timelines, and increased uncertainty
regarding the cost \100\ and timing of interconnecting to the
transmission system. These backlogs and delays, and the resulting
timing and cost uncertainty,\101\ hinder the timely development of new
generation and thereby stifle competition in the wholesale electric
markets resulting in rates, terms, and conditions that are unjust,
unreasonable, and unduly discriminatory or preferential.
---------------------------------------------------------------------------
\98\ 16 U.S.C. 824e(a); 18 CFR 385.206 (2022).
\99\ NOPR, 179 FERC ] 61,194 at PP 18-36.
\100\ See May Joint Task Force Tr. 74:9-21 (Andrew French)
(stating that generator developers complain principally about cost
certainty and cost sharing and that ``cost certainty is the much
bigger issue'' given that ``an essential element of being able to
sell a product is to know what your inputs are so you can market
it'').
\101\ See May Joint Task Force Tr. 23:18-25 (Jason Stanek)
(expressing frustration with the status quo and agreement that it is
``no longer tenable'' considering the inability of generators to
interconnect in a timely manner, e.g., there are ``2,500 projects
under study [in the MACRUC region] and about a half of them have
been in the queue since at least 2001'').
---------------------------------------------------------------------------
38. Indeed, recent data support the Commission's preliminary
findings in the NOPR that the dramatic increase in the number of
interconnection requests and limited transmission capacity are
increasing interconnection queue backlogs across all regions of the
country.\102\ As of the end of 2022, there were over 10,000 active
interconnection requests in interconnection queues throughout the
United States, representing over 2,000 gigawatts (GW) of potential
generation and storage capacity.\103\ This potential generation is the
largest interconnection queue size on record, more than four times the
total volume (in GW) of the interconnection queues in 2010, and a 40%
increase over the interconnection queue size from just the year
prior.\104\ These trends are not exclusive to any one region of the
country. Instead, every single region has faced an increase in both
interconnection queue size and the length of time interconnection
customers are spending in the interconnection queue prior to commercial
operation in recent years.\105\ This is true for RTO/ISO and non-RTO/
ISO regions alike. The non-RTO/ISO west and southeast regions both have
faced queue size increases ranging from tripling to a 12-fold increase
while also seeing longer timelines between interconnection requests and
commercial operation dates.\106\ Furthermore, the uncertainty and
delays in the interconnection queues have resulted in fewer than 25% of
interconnection requests, by capacity, reaching commercial operation
between 2000 and 2017 in any region of the country--with some regions
as low as 8%.\107\
---------------------------------------------------------------------------
\102\ Joseph Rand et al., Lawrence Berkeley Nat'l Lab., Queued
Up: Characteristics of Power Plants Seeking Transmission
Interconnection, at 7-8 (Apr. 2023) (Queued Up 2023), https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf; see
also Order No. 845, 163 FERC ] 61,043 at P 305 (requiring
transmission providers to post interconnection study metrics). See
appendix B to this final rule, which provides an overview of recent
data based on reporting by transmission providers in compliance with
Order No. 845.
\103\ Queued Up 2023 at 7-8.
\104\ Id. at 10.
\105\ Id. at 9, 32.
\106\ Id. at 9, 32.
\107\ Id. at 3, 21.
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39. Additionally, recent data continue to show that interconnection
customers are waiting longer in the interconnection queue before
withdrawing their interconnection requests,\108\ even as overall
interconnection study timelines are increasing in many regions.\109\
For example, AEE states that, as of February 2022, all 2,274 projects
waiting for an interconnection agreement in the PJM interconnection
queue had been waiting for a year or more; 33% (758 projects) had been
waiting more than 500 days, 22% (497 projects) have been stuck for more
than two years, and 7% (166 projects) have been waiting more than three
years.\110\ NV Energy explains that several western utilities that are
not currently part of an RTO/ISO are experiencing an unprecedented high
volume of requests in excess of the utility's peak load.\111\ AEE notes
that wait times for generating facilities in interconnection queues
nationwide have increased from 2.1 years for generating facilities
built in 2000-2010 to 3.7 years for those built in 2011-2021.\112\ And
despite efforts to address
[[Page 61022]]
these challenges,\113\ interconnection queue backlogs and delays have
persisted and worsened. For generating facilities built in 2022, wait
times in the interconnection queue saw a marked increase to now roughly
five years.\114\
---------------------------------------------------------------------------
\108\ Id. at 25 (reporting that, although the median withdrawal
duration has been relatively consistent over time, the mean
withdrawal duration and distributions have edged higher in recent
years).
\109\ Id. at 27.
\110\ AEE Initial Comments at 4 (citing Advanced Energy Economy,
``In PJM, Renewable Energy Projects Are Getting Stuck'' (February
2022), https://blog.aee.net/in-pjm-renewable-energy-projects-are-getting-stuck).
\111\ NV Energy Initial Comments at 2-3. NV Energy explains that
it has a peak load of 9,400 MW with an interconnection queue backlog
for projects totaling more than 27,000 MW; Idaho Power has a peak
load of 3,751 MW with an interconnection queue backlog of over
18,000 MW; PacifiCorp has a peak load of 13,000 MW with an
interconnection queue backlog of over 45,000 MW; and APS has a peak
load of 7,600 MW with an interconnection queue backlog of over
50,000 MW.
\112\ AEE Initial Comments at 4 (citing Queued Up 2022); see
also ACE-NY Initial Comments at 2 (arguing that the ability of New
York to meet its clean energy goals is threatened by an
interconnection process that is too slow); Affected System
Interconnection Customers Initial Comments at 2 (stating that
Affected System Interconnection Customers have navigated the
generator interconnection queues of various transmission providers
around the country and experienced firsthand the inefficiencies and
delays, which represent the greatest obstacle to achieving
commercial operation of a new energy project); GSCE Initial Comments
at 5-6 (contending that an average of 6,000 MW of new solar, wind,
and batteries must be added each year until 2045 to reach
California's electric sector carbon-neutrality requirement, but that
over the past decade California has only succeeded with adding an
average of 1,000 MW of utility-scale solar and 300 MW of wind to the
transmission system each year).
\113\ Order No. 845, 163 FERC ] 61,043 at P 24.
\114\ Queued Up 2023 at 31; see also Shell Initial Comments at 6
(describing multiple instances of five to six years until execution
of an interconnection agreement, four years waiting for an initial
``kick-off'' call, two years waiting for a feasibility study, three
years waiting for a system impact study, and over two years waiting
for a facilities study).
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40. Delays in the interconnection study process are an important
contributor to interconnection queue backlogs nationwide. For instance,
based on the recent interconnection study metrics transmission
providers posted in compliance with Order No. 845, of the 2,179
interconnection studies completed in 2022, 68% were issued late.\115\
Furthermore, at the end of 2022, an additional 2,544 studies were
delayed (i.e., ongoing and past their deadline).\116\ All of the RTOs/
ISOs except CAISO and 14 non-RTO/ISO transmission providers reported
delayed studies at the end of 2022.\117\
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\115\ This is based on data provided by transmission providers
in compliance with Order No. 845. See appendix B to this final rule
for the underlying data. Note that data from SPP is omitted here and
in follow-on references to Order No. 845 data in this determination.
This is because during 2022, SPP was transitioning to a new
interconnection study process, and thus its data is not comparable
to the other transmission providers.
\116\ Id. Note that the vast majority of these studies (2,211)
were in PJM.
\117\ Id. CAISO revised the interconnection study deadlines of
their queue cluster 14 to account for the unprecedented increase in
interconnection requests. Cal. Indep. Sys. Operator Corp., 176 FERC
] 61,207 (2021).
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41. Consistent with the NOPR, we find that numerous factors have
contributed to the increasing volume of interconnection requests,
including a rapidly changing resource mix, market forces, and emerging
technologies. For example, the interconnection queues in all parts of
the country are now predominantly made up of comparatively new
technologies that have operating characteristics and generally shorter
construction cycles that were not taken into account when the
Commission issued Order No. 2003, such as solar, battery storage, and
hybrid resources, as older, larger generating facilities retire.\118\
The Colorado Commission notes that solar projects account for roughly
half of the cumulative requests in the five RTO/ISO queues and likely
an even greater percentage of the most recent requests.\119\ In
addition to the drastic increase in the number of interconnection
requests in all regions of the country, evidence shows that
interconnection studies have increased in complexity since the
Commission issued Order No. 2003, potentially straining transmission
provider resources.\120\ At the same time, we find that available
transmission capacity has been largely or fully utilized in many
regions, creating situations where interconnection customers face
significant network upgrade cost assignments to interconnect their
proposed generating facilities.\121\ For example, as referenced by the
U.S. DOE, a recent report finds that interconnection costs in MISO
doubled for generating facilities for which the interconnection studies
were completed between 2019 and 2021 as compared to those completed
prior to 2019, and cost estimates tripled for proposed generating
facilities still active in the interconnection queue between the same
time periods.\122\ These cost increases are similar to those being
faced in NYISO and PJM, where interconnection costs, per kW, have
doubled (or more) for recently completed generating facilities.\123\ As
a result, we find that this combination of increased volume of diverse
interconnection requests and insufficient transmission capacity leading
to higher costs to interconnect, which can result in interconnection
request withdrawals, has resulted in longer interconnection queue
processing times and larger, more delayed interconnection queues.
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\118\ Queued Up 2023 at 9; see also Colorado Commission Comments
at 9 (stating that the growth of solar project interconnection
requests is a significant cause of the overall supply and demand
imbalance across all RTOs/ISOs as well as other regions).
\119\ Colorado Commission Initial Comments at 9.
\120\ See, e.g., NYISO Initial Comments at 6-7 (stating that
``[s]tudies are only becoming more complex with the expanding scope
of ISO/RTOs' interconnection responsibilities''); Xcel Initial
Comments at 7 (stating that ``in many cases study models with large
clusters are difficult to solve . . . Ensuring new transmission
lines are realistic and even validating substation designs and
locations takes significant work to be done properly'').
\121\ See, e.g., ACORE Initial Comments at 2 (noting that
``upgrades based on generation interconnection may be a sub-optimal,
expensive, and ultimately ineffective way to accomplish transmission
expansion''); AEE Initial Comments at 3 (asserting that
``inefficient and impeded interconnection processes lead to
unacceptable delays and artificially high interconnection costs'');
EDF Renewables Initial Comments at 3.
\122\ Joachim Seel et al., Generator Interconnection Cost
Analysis in the Midcontinent Independent System Operator (MISO)
Territory, at 1, 4-5 (2022), https://emp.lbl.gov/interconnection_costs.
\123\ Julia Mulvaney Kemp et al., Interconnection Cost Analysis
in the NYISO Territory (2023), https://emp.lbl.gov/publications/interconnection-cost-analysis-nyiso (showing that costs have doubled
for generating facilities studied since 2017, relative to costs for
generating facilities studied from 2006 to 2016); Joachim Seel et
al., Interconnection Cost Analysis in the PJM Territory (2023),
https://emp.lbl.gov/publications/interconnection-cost-analysis-pjm
(showing that costs for recent ``complete'' generating facilities
have doubled on average relative to costs from 2000-2019).
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42. In response to comments asserting that the Commission did not
take into account other factors affecting interconnection queue sizes,
such as the development of smaller, more diverse generating facilities,
in its preliminary findings on the need for reform in the NOPR,\124\ we
find that the record shows that interconnection queue sizes are
increasing in both number of interconnection requests and in total MW
capacity in all regions of the country and such increases are not due
to an influx of any particular size of proposed generating facility.
Moreover, data show that the median duration for all generating
facilities that enter the interconnection queue hovers around 30
months, independent of the size of the interconnection request.\125\
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\124\ See, e.g., Pine Gate Reply Comments at 4 (stating that
``the days of . . . large, conventional resources are waning as the
majority of interconnection requests are now comprised of smaller,
more diverse resource'' and that ``[l]arger interconnection queues
are, to a certain extent, a natural byproduct of this change'');
SEIA Reply Comments at 1 (contending that interconnection requests
have increased in number ``because newer projects are smaller and
have less capacity'' and ``[m]ore interconnection requests are
needed to integrate the same amount of generation capacity into the
grid'').
\125\ Queued Up 2023 at 29.
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43. Interconnection queue backlogs and delays have created
uncertainty for interconnection customers regarding the timing and cost
of ultimately interconnecting to the transmission system. We agree with
commenters that such uncertainty, on the part of both transmission
provider and interconnection customer, may lead to an increase in costs
to consumers.\126\ First, delayed interconnection study results or
unexpected cost increases can disrupt numerous aspects of generating
facility development.\127\ Cost
[[Page 61023]]
uncertainty poses an especially significant obstacle because
interconnection customers may not be able to finance substantial
increases in unexpected interconnection costs. Second, transmission
providers may face uncertainty regarding the size and makeup of the
interconnection queue and the commercial viability of the project in
the interconnection queue, creating inefficiencies in the study
process, increasing interconnection study costs, and delayed study
results. Such uncertainty, either on the part of transmission providers
or interconnection customers, are ultimately passed through to
consumers through higher transmission or energy rates.\128\ Increases
in energy rates may result from wholesale customers having limited
access to new and more competitive supplies of generation. Conversely,
efficient interconnection queues and well-functioning wholesale markets
deliver benefits to consumers by driving down wholesale electricity
costs.
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\126\ See, e.g., Ameren Initial Comments at 2; ELCON Initial
Comments at 2; ELCON Initial Comments at 2; Xcel Initial Comments at
8.
\127\ See, e.g., Interwest Initial Comments at 8 (contending
that ``[t]he harm to interconnection customers associated with
interconnection study delays can be significant and costly,
including liquidated damages if compliance with a commercial
operation deadline is at risk'').
\128\ Ameren Initial Comments at 2.
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44. As the interconnection queue backlogs and study delays continue
and even increase, we find that the Commission's existing rules
contained in the pro forma LGIP, pro forma LGIA, pro forma SGIP, and
pro forma SGIA result in rates, terms, and conditions for Commission-
jurisdictional services that are unjust, unreasonable, and unduly
discriminatory or preferential. Not only do the problems described
above lead to an inability of interconnection customers to interconnect
to the transmission system in a reliable, efficient, transparent, and
timely manner, they also hinder the timely development of new
generation, thereby stifling competition in the wholesale electric
markets. We, therefore, find that reform to the Commission's existing
pro forma generator interconnection procedures and agreements is
necessary.
45. Our findings that the existing pro forma LGIP, pro forma LGIA,
pro forma SGIP, and pro forma SGIA must be reformed are based on the
following features of these existing rules: (1) the information (or
lack thereof) available to prospective interconnection customers and
the commitments required of them to enter and progress through the
interconnection queue; (2) the reliance on a serial first-come, first-
served study process and the ``reasonable efforts'' standard that
transmission providers are held to for meeting interconnection study
deadlines; (3) the protocols (or lack thereof) for affected system
studies; (4) the provisions for studying new generating facility
technologies and evaluating the list of alternative transmission
technologies enumerated in this final rule; and (5) the modeling or
performance requirements (or lack thereof) for non-synchronous
generating facilities, including wind, solar, and electric storage
facilities. We discuss each of these five features below.
46. First, we find that existing pro forma generator
interconnection procedures and agreements fail to contain a process by
which an interconnection customer can obtain information about
potential interconnection costs at a specific location or point of
interconnection prior to submitting an interconnection request. Without
this information, it is difficult for interconnection customers to
assess the commercial viability of a specific proposed generating
facility prior to entering the interconnection queue.\129\ Furthermore,
we find that for interconnection customers, the pro forma
interconnection procedures and agreements fail to include meaningful
financial commitment requirements to enter and stay in the
interconnection queue and lack of stringent requirements to establish
the commercial viability of proposed generating facilities.\130\ As a
result, interconnection customers often submit multiple interconnection
requests for proposed generating facilities at various points of
interconnection, knowing that not all of the proposed generating
facilities will reach commercial operation, as an exploratory mechanism
to obtain information to allow the interconnection customer to choose
to proceed with the interconnection request representing the most
favorable site in terms of potential interconnection-related
costs.\131\ For instance, recent interconnection study metrics posted
by transmission providers continue to show that some interconnection
customers are withdrawing interconnection requests before any studies
are completed.\132\ While interconnection customers may withdraw at any
stage of the interconnection process, to do so before any study is
completed indicates that interconnection customers may lack information
prior to entering the interconnection queue and are entering to obtain
valuable information about the commercial viability of their proposed
projects vis-[agrave]-vis other interconnection customers in the queue
or cluster.
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\129\ See, e.g., Fervo Energy Initial Comments at 2-3 (stating
that ``the incidence of interconnection applications simply intended
to solicit information discovery from the transmission provider . .
. is a significant defect in today's queue process''); Google
Initial Comments at 4 (asserting that ``there is extreme information
asymmetry in the interconnection process,'' with transmission owners
and their affiliates having greater access than independent power
producers to information on the relative cost of interconnection at
different points).
\130\ See, e.g., Dominion Initial Comments at 4 (stating that
``owners of speculative projects remain in the queue process for as
long as they possibly can in the hopes that their project somehow
becomes viable''); U.S. Chamber of Commerce Initial Comments at 5
(concurring with the NOPR that there is a ``lack of stringent
financial commitments and readiness requirements on interconnection
customers'').
\131\ See, e.g., Clean Energy Associations Initial Comments at
11 (stating that ``[i]n most cases, customers must actually enter
the queue to ascertain what upgrade costs they will be responsible
for''); Clean Energy Buyers Initial Comments at 3 (stating that
inefficiencies in the serial study queue are ``compounded by
exploratory interconnection requests that are based on developers'
attempts to obtain locations with available transmission
capacity''); NY Commission and NYSERDA Initial Comments at 6-7
(stating that ``increased access to valuable information . . . could
deter developers from submitting multiple, speculative
[interconnection requests]'').
\132\ Based on data provided by transmission providers in
compliance with Order No. 845 (showing that 35% of withdrawals in
2022 took place before any studies had been completed). See appendix
B to this final rule for the underlying data.
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47. Second, the existing serial first-come, first-served study
process in the pro forma LGIP requires transmission providers to
process interconnection requests in the order in which the transmission
provider receives them. This approach creates incentives for
interconnection customers to submit exploratory or speculative
interconnection requests pursuant to which interconnection customers
seek to secure valuable queue positions as early as possible, even if
they are not prepared to move forward with the proposed generating
facility. Such generating facilities are often not commercially viable
and, thus, the interconnection customers ultimately withdraw from the
interconnection queue. We agree with commenters that the withdrawal of
speculative interconnection requests that trigger reassessments and
possible restudies by the transmission provider can delay the timing
and increase the cost to interconnect for lower-queued interconnection
requests.
48. In summary, we find that the lack of (1) access of information
about a specific location or point of interconnection prior to
submitting an interconnection request and (2) meaningful financial
commitments in the pro forma interconnection procedures and agreements
for interconnection customers to enter and stay in the interconnection
queue, as well as the existing serial first-come,
[[Page 61024]]
first-served study process, all incentivize interconnection customers
to submit speculative interconnection requests that contribute to
interconnection study backlogs, delays, and uncertainty, and, in turn,
unjust and unreasonable Commission-jurisdictional rates.
49. We disagree with commenters' assertions that there is no basis
to find that speculative interconnection requests are responsible for
interconnection queue backlog and delays. We highlight that more than
70% of interconnection requests were withdrawn from the interconnection
queue between 2000 and 2017.\133\ Although we recognize that there are
various reasons an interconnection customer may withdraw its request
from the interconnection queue, a withdrawal indicates an inability to
reach commercial operation. Because a withdrawal can trigger costly
restudies and create uncertainty in the interconnection process for
interconnection customers and transmission providers alike, withdrawals
of commercially non-viable interconnection requests from the
interconnection queue is a significant contributing factor to
interconnection queue backlogs and delays.\134\ Late-stage withdrawals
of interconnection requests are also increasing.\135\ Late-stage
withdrawals present a significant problem, as they can trigger
restudies for other interconnection customers that can result in
significant increases to the interconnection costs attributed to those
customers and the timeline for completion of interconnection studies,
which can result in further late-stage withdrawals, thus exacerbating
the interconnection queue backlogs and delays.\136\
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\133\ Queued Up 2023 at 18 (reporting that 72% of all
interconnection requests submitted from 2000-2017 were withdrawn).
\134\ See, e.g., Ohio Commission Consumer Advocate Initial
Comments at 8 (stating that ``[e]ach withdrawn project entails PJM
restudy on lower-queued projects, which delays the processing of new
service queues and may have the consequence of a cascade of
withdrawals'').
\135\ Queued Up 2023 at 22.
\136\ See, e.g., AEE Initial Comments at 4-5; Queued Up 2023 at
22.
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50. We also find that interconnection queue backlogs and delays,
and the accompanying uncertainty, are further compounded because
transmission providers have limited incentive to perform
interconnection studies in a timely manner. Under the pro forma LGIP,
transmission providers are held to a ``reasonable efforts'' standard in
completing interconnection studies consistent with their tariff-imposed
deadlines. However, this standard offers significant discretion to the
transmission providers in extending their own deadlines. The record
demonstrates that a majority of transmission providers across the
country regularly fail to meet interconnection study deadlines.\137\
Despite pervasive delays in completing interconnection studies by
transmission providers, we acknowledge that transmission providers have
faced few, if any, consequences for failing to meet their tariff-
imposed study deadlines under the reasonable efforts standard.\138\
This outcome stands in stark contrast to interconnection customers that
face financial and commercial consequences due to late interconnection
study results and may be considered withdrawn from the interconnection
queue for failing to meet their tariff-imposed deadlines.\139\ For
these reasons, we find that the existing pro forma LGIP requirement for
transmission providers to make a reasonable effort to meet
interconnection study deadlines contributes to the interconnection
study backlogs, delays, and uncertainty that erects barriers to new
generation.\140\ Therefore, we find that the use of a reasonable
efforts standard in the existing pro forma LGIP results in Commission-
jurisdictional rates that are unjust and unreasonable.
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\137\ For example, based on data submitted by transmission
providers in compliance with Order No. 845, 80% of transmission
providers had delayed studies in at least one of the past three
years (2020-2022) and 57% had delayed studies in at least two.b See
also NARUC Initial Comments at 13 (stating ``nearly all transmission
providers across the country, including many transmission providers
that have implemented queue reforms, regularly fail to meet
interconnection study deadlines'').
\138\ See, e.g., Clean Energy Associations Initial Comments at
43-44 (stating that ``[a]t present, there is no specific incentive
for delivering on-time and accurate studies, and late or inaccurate
studies bring few if any consequences'').
\139\ See, e.g., ACE-NY Initial Comments at 3 (``Project
developers have strict deadlines they must adhere to in the
interconnection process, with penalties that include the forced
withdrawal of the project from the queue.'').
\140\ See, e.g., NARUC Initial Comments at 13-14 (contending
that ``the tendency to miss deadlines introduces uncertainty in a
process that is important to bringing new generation online in a
timely and cost-effective manner'').
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51. Third, the pro forma LGIP includes no requirements regarding
how or when transmission providers should complete affected system
studies. Without requirements, affected system studies often lag behind
those completed by the transmission provider to whose transmission
system the interconnection customer proposes to interconnect (the so-
called host transmission provider) and are sometimes completed very
late in the interconnection process, causing an additional round of
delays and cost uncertainty for interconnection customers.\141\
Additionally, for transmission providers that have procedures for how
to complete affected system studies in their tariffs or other documents
(e.g., business practice manuals or joint operating agreements), the
procedures are not consistent, may be hard for interconnection
customers to locate, and may not represent the actual practices in use
by the transmission provider, thus still creating uncertainty for
interconnection customers. As a result, we find that the lack of
consistent requirements for affected system modeling and procedures
results in Commission-jurisdictional rates that are unjust,
unreasonable, and unduly discriminatory or preferential.
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\141\ See, e.g., MISO Initial Comments at 72 (stating that ``the
need to wait for affected systems studies is the cause of the
majority of delays in the MISO study process''); May Joint Task
Force Tr. 65:2-8 (Dan Scripps) (citing affected systems studies as
``a growing source of delay and cost uncertainty for interconnection
customers, both in terms of just the timelines involved and the
difficulty in pinning those down'').
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52. Fourth, we find that the Commission's pro forma LGIP fails to
accommodate the operating characteristics and technical capabilities of
electric storage resources when it comes to specific interconnection
procedures and modeling. As stated above, the interconnection queues
predominantly consist of new technologies which have operating
characteristics that differ from synchronous resources and were not
anticipated when the Commission established the pro forma generator
interconnection procedures and agreements in Order Nos. 2003 and 2006.
Specifically, electric storage resources can be charged and dispatched
on a flexible, as-available basis, and are less likely than synchronous
generating facilities to withdraw energy from the transmission system
during peak load conditions or discharge during light load
conditions.\142\ However, the existing pro forma generator
interconnection procedures and agreements do not contemplate these
operating characteristics or technical capabilities of electric storage
resources. As a result, we find that electric storage resources
[[Page 61025]]
(whether standalone, co-located generating facilities, or part of a
hybrid generating facility), may be studied under inappropriate
operating assumptions (e.g., charging at full capacity during peak load
conditions) that result in assigning unnecessary network upgrades and
increased costs to interconnection customers. Therefore, we find that
the Commission's pro forma LGIP's lack of ability to modify operating
assumptions for electric storage resources results in Commission-
jurisdictional rates that are unjust, unreasonable, and unduly
discriminatory or preferential.
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\142\ See, e.g., Bonneville Initial Comments at 22-23 (stating
that ``storage resources are less likely to charge during peak load
conditions or discharge during light load conditions, and . . .
those considerations can be factored into assumptions used in
interconnection studies''); NARUC Initial Comments at 37 (stating
that ``assuming that an energy storage device will withdraw energy
during peak demand . . . fails to recognize that those resources are
likely to be highly responsive to price signals from the
transmission provider and can improve reliability'').
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53. Additionally, the record supports a finding that the existing
pro forma interconnection procedures regarding material modifications
do not provide for consistent evaluation of technology additions to an
existing interconnection request.\143\ We find that the record
demonstrates that automatically deeming a request to add a generating
facility to an existing interconnection request to be a material
modification creates a significant barrier to access to the
transmission system.\144\ As a result, we find the existing pro forma
LGIP and pro forma LGIA results in Commission-jurisdictional rates that
are unjust and unreasonable.
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\143\ See, e.g., NARUC Initial Comments at 35 (stating that the
``loss of queue position as a result of adding a generating facility
that does not increase the requested service level or cause
reliability issues . . . is an inefficient and discriminatory
outcome'').
\144\ See, e.g., AEE Initial Comments at 40-41; Public Interest
Organizations Initial Comments at 45-47; SEIA Initial Comments at
38-39.
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54. Finally, the record supports a finding that the Commission's
pro forma LGIP and pro forma SGIP fail to require the consideration of
alternative transmission technologies that can be deployed more quickly
to be used as network upgrades in place of, and at a lower cost than,
traditional network upgrades.\145\ In addition, commenters contend that
some alternative transmission technologies could provide substantial
benefits by resolving thermal overloads and avoiding voltage collapse,
allowing for better use of the existing transmission system, improving
reliability, and reducing interconnection request withdrawals,
restudies, and overall interconnection delays.\146\ We find that
failing to require transmission providers to evaluate the list of
alternative transmission technologies enumerated in this final rule
results in interconnection customers paying more than is just and
reasonable to reliably interconnect new generating facilities,
resulting in Commission-jurisdictional rates that are unjust,
unreasonable, and unduly discriminatory or preferential. Because the
benefits of the enumerated alternative transmission technologies
identified above are present across all interconnection processes,
regardless of the size of the interconnection request, we find that the
failure to evaluate the enumerated alternative transmission
technologies results in both the pro forma LGIP and pro forma SGIP
being unjust, unreasonable, and unduly discriminatory or preferential.
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\145\ See, e.g., NARUC Initial Comments at 38 (stating that
``failing to consider alternative transmission technologies that can
be deployed both more quickly and at lower costs than network
upgrades may render Commission-jurisdictional rates unjust and
unreasonable''); OMS Initial Comments at 19 (agreeing that ``failing
to consider these alternative transmission technologies runs the
risk of implementing longer lead-time network upgrades at a higher
cost'').
\146\ See, e.g., AEE Initial Comments at 42 (stating that
alternative transmission technologies ``provide benefits beyond
potential costs savings, including maximizing limited rights-of-way
and potentially avooiding or minimizing environmental and property
impacts taht can bog down siting and permitting proceedings''); Ohio
Commission Consumer Advocate Initial Comments at 15 (stating that
``[t]hese grid-enhancing technologies (`GETs') can improve
opertations, enhance system reliability, contribute to capacity, and
more'' and ``[s]ome [grid-enhancing technologies] could provide
substantial benefits by resolving thermal overloads and avoiding
voltage collapse, among other things''); WATT Coalition Initial
Comments at 2 (referring to the report Unlocking the Queue with Grid
Enhancing Technologies that showed that application of the three
grid-enhancing technologies in the Kansas and Oklahoma transmission
systems would enable twice as much renewable energy to interconnect
out of the queues without any traditional transmission upgrades.).
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55. Fifth, we find that the Commission's existing pro forma LGIP
and pro forma SGIP do not include a modeling requirement for non-
synchronous generating facilities, which is necessary to enable the
transmission provider to assess and model the facility's ability to
respond appropriately to transmission system disturbances. These
modeling requirements include: (1) a validated, user-defined root mean
square (RMS) positive sequence dynamic model; (2) an appropriately
parameterized, generic library RMS positive sequence dynamic model; and
(3) a validated electromagnetic transient (EMT) model, if the
transmission provider performs an EMT study as part of the
interconnection study process. Additionally, we find that accurate and
validated models are necessary to address study delays and to ensure
that transmission providers identify the necessary interconnection
facilities and network upgrades to accommodate the interconnection
request and appropriate assignment of interconnection costs. As a
result, we find that the lack of a modeling requirement for non-
synchronous generating facilities in the pro forma LGIP and pro forma
SGIP results in rates that are unjust, unreasonable, and unduly
discriminatory or preferential.
56. Furthermore, the physical characteristics of synchronous
generating facilities allow them to continue to inject electric current
during transmission system disturbances, as required by the pro forma
LGIA and pro forma SGIA.\147\ However, non-synchronous generating
facilities do not face a comparable requirement and many cease
injecting current through ``momentary cessation,'' which creates
reliability issues on the transmission system.\148\ Moreover, without
requirements for non-synchronous generating facilities to remain
connected to and synchronized with the transmission system,
interconnection studies may not accurately model expected behavior and
identify the appropriate interconnection facilities and network
upgrades to accommodate the interconnection request, skewing the
assignment of interconnection costs. As a result, we find that the lack
of comparable requirements for non-synchronous generating facilities to
remain ``connected to and synchronized with the [t]ransmission
[s]ystem'' in the pro forma LGIA and pro forma SGIA results in rates
that are unjust, unreasonable, and unduly discriminatory or
preferential.
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\147\ Pro forma LGIA art. 9.7.3 and pro forma SGIA art. 1.5.7
require synchronous generating facilities to remain ``connected to
and synchronized with'' the transmission system during system
disturbances.
\148\ See, e.g., NERC Initial Comments at 9 (stating that
``improper planning and operation of [non-synchronous resources] can
pose a significant risk to . . . reliability'' and adding that
``risk mitigation measures . . . have been inconsistently adopted by
industry''); MISO TOs Initial Comments at 32-33 (concurring with the
Commission that ``with more and more non-synchronous generation
facilities entering the interconnection queue, the lack of a
requirement for such resources to respond to system disturbances
becomes `more consequential' '').
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57. In response to commenters that express broad opposition to the
need for reform, we disagree with assertions that the existence of
regional variation in interconnection procedures across the country
creates an insufficient legal foundation under FPA section 206 to
demonstrate that rates are unjust, unreasonable, and unduly
discriminatory or preferential. Similarly, we disagree with assertions
that reforms to the pro forma generator interconnection procedures and
agreements are arbitrary and capricious because the problems identified
herein do not exist uniformly. As an initial matter, the ``Commission
may rely on `generic' or `general' findings of a systemic problem to
support imposition
[[Page 61026]]
of an industry-wide solution.'' \149\ That some interconnection
processes may fare better in the face of industry-wide challenges would
be ``as unastonishing as it is irrelevant.'' \150\ The Commission may
reasonably rely on rulemaking to address the systemic drivers leading
to widespread interconnection queue backlogs and delays,
notwithstanding regional variation among interconnection procedures.
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\149\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 67 (D.C. Cir.
2014) (quoting Interstate Nat. Gas Ass'n of Am. v. FERC, 285 F.3d
18, 37 (2002)).
\150\ Id. (quoting Wis. Gas v. FERC, 770 F.2d 1144, 1157 (D.C.
Cir. 1985)).
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58. Moreover, as noted above, every region of the country is seeing
an increase in both interconnection queue size and the length of time
interconnection customers are spending in the interconnection queue
prior to commercial operation in recent years.\151\ Furthermore, the
uncertainty and delays in the interconnection queues have resulted in
fewer than 25% of interconnection requests, by capacity, reaching
commercial operation between 2000 and 2017 in any region of the
country--with some regions as low as 8%.\152\ For example, only 10% of
interconnection requests, by capacity, have reached commercial
operation in the non-RTO/ISO southeast region between 2000 and
2017.\153\ Additionally, the challenges being faced across the country
will be further compounded in the future given the recent spikes in
interconnection queue sizes. In the non-RTO/ISO southeast region, the
interconnection queue size has more than tripled between 2014 and 2022,
with the increase predominantly made up of solar, storage, and hybrid
generating facilities, adding potential complexity to future
interconnection queue study processes.\154\ To the extent existing pro
forma interconnection procedures, such as first-come, first-served
study processes, have worked in the past for smaller or less complex
queues, such experience is not indicative of what will be necessary in
the future to ensure that a growing number of interconnection requests
are processed in a reliable, efficient, transparent, and timely
manner.\155\ Finally, as recognized in Order No. 2003, interconnection
queue delays may ``provide[] an unfair advantage to utilities that own
both transmission and generation facilities,'' \156\ making it
exceedingly necessary that interconnection delays are addressed in all
regions of the country, especially those where transmission providers
continue to own both transmission and generation.\157\ As discussed
above, because interconnection queue backlogs and delays afflict
generator interconnection service nationwide, which hinders the timely
development of new generation and thereby stifles competition in the
wholesale electric markets, reforms are necessary to ensure Commission-
jurisdictional rates are just, reasonable, and not unduly
discriminatory or preferential.
---------------------------------------------------------------------------
\151\ Queued Up 2023 at 9, 32.
\152\ Id. at 3, 21.
\153\ Id. at 21.
\154\ Id. at 9.
\155\ See, e.g., Public Interest Organization Initial Comments
at 17; R Street Initial Comments at 3.
\156\ Order No. 2003, 104 FERC ] 61,103 at P 11.
\157\ See, e.g., Pine Gate Initial Comments at 15; AEE Reply
Comments at 22.
---------------------------------------------------------------------------
59. We are not persuaded by commenters' concerns that the reforms
proposed in the NOPR, many of which we adopt in this final rule, will
be counterproductive in addressing the need for reform. As discussed in
more detail throughout this final rule, we believe that the reforms
adopted herein, as a whole, will improve the efficiency of study
processes, reduce interconnection queue backlogs, and thereby ensure
just, reasonable, and not unduly discriminatory or preferential rates.
We believe that, on balance, the reforms will produce efficiencies by,
for example, reducing speculative interconnection requests and
interconnection request withdrawals, which in turn will reduce the time
and resources spent in interconnection studies and restudies thereby
decreasing interconnection queue backlogs and delays. Additionally, the
majority of the individual reforms that the Commission proposed in the
NOPR and we adopt in this final rule have already been implemented in
one or more regions in order to improve the interconnection process,
demonstrating incremental improvements. This final rule uses some of
these individual and incremental improvements as a basis for a broad
suite of reforms that, in their entirety, have not yet been adopted by
any region and we believe will ensure that interconnection customers
are able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner. In some cases, such as for
the commercial readiness reforms adopted in this final rule, we have
significantly modified the NOPR proposal based on comments received.
60. Having concluded that the existing pro forma generator
interconnection procedures and agreements are unjust, unreasonable, and
unduly discriminatory or preferential, we turn, as we are required to
do under FPA section 206,\158\ to determining the replacement rate,
described--at some length--below.
---------------------------------------------------------------------------
\158\ 16 U.S.C. 824e(a); see, e.g., FERC v. Electric Power
Supply Ass'n, 577 US 260, 277 (2016) (``If FERC sees a violation of
[the just and reasonable] standard, it must take remedial action.'')
---------------------------------------------------------------------------
III. Reforms
A. Reforms To Implement a First-Ready, First-Served Cluster Study
Process
1. Interconnection Information Access
a. Need for Reform
i. NOPR
61. The Commission noted its concern regarding the lack of
information available to prospective interconnection customers
regarding potential interconnection costs prior to submitting an
interconnection request.\159\ The Commission stated that, without this
information, it is difficult for interconnection customers to assess
the viability of a specific proposed generating facility. Subsequently,
interconnection customers submit multiple speculative interconnection
requests in an attempt to obtain information through the system impact
study process about the costs associated with various project
configurations. The Commission preliminarily found that the
Commission's pro forma LGIP and pro forma LGIA are unjust,
unreasonable, and unduly discriminatory or preferential and that
reforms are needed to allow interconnection customers to interconnect
in a reliable, efficient, transparent, and timely manner, thereby
ensuring that rates, terms, and conditions for Commission-
jurisdictional services are just, reasonable, and not unduly
discriminatory or preferential.\160\
---------------------------------------------------------------------------
\159\ NOPR, 179 FERC ] 61,194 at P 40.
\160\ Id. P 39.
---------------------------------------------------------------------------
ii. Comments
62. Several commenters contend that it is a rational response to a
lack of pre-interconnection queue information for interconnection
customers to submit multiple interconnection requests to gain
information on which interconnection sites are favorable and hedge
risks, which leads to withdrawals that exacerbate unmanageable
interconnection queue backlogs.\161\ ELCON and Environmental Defense
[[Page 61027]]
Fund argue that the lack of sufficient information and unexpected cost
escalation are the primary reasons interconnection requests are
withdrawn, leading to delays and inefficiencies.\162\
---------------------------------------------------------------------------
\161\ AES Initial Comments at 3; Affected Interconnection
Customers Initial Comments at 30; Clean Energy Buyers Initial
Comments at 5-6; CREA and NewSun Initial Comments at 45;
Environmental Defense Fund Initial Comments at 3; ELCON Initial
Comments at 3; Northwest and Intermountain Initial Comments at 5;
Public Interest Organizations Initial Comments at 18.
\162\ Environmental Defense Fund Initial Comments at 3; ELCON
Initial Comments at 4.
---------------------------------------------------------------------------
63. Many commenters agree with the goal of providing additional
information prior to entering the interconnection queue.\163\ Some
commenters state that additional information prior to entering the
interconnection queue is beneficial,\164\ in particular access to
information on potential network upgrades and the cost and time to
interconnect.\165\ Many commenters expect that potential
interconnection customers' access to additional information prior to
entering the interconnection queue will reduce speculative
interconnection requests, thus promoting reliability and cost savings
by encouraging more optimal interconnection requests that can be
processed more efficiently and at lower overall cost.\166\
---------------------------------------------------------------------------
\163\ ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP
Initial Comments at 12; AES Initial Comments at 3; Affected
Interconnection Customers Initial Comments at 30; APS Initial
Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers
Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON
Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial
Comments at 15; MISO Initial Comments at 20-21; NARUC Initial
Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and
NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs
Initial Comments at 8; Pacific Northwest Utilities Initial Comments
at 13; PJM Initial Comments at 45; Puget Sound Initial Comments at
5; WAPA Initial Comments at 5.
\164\ AEP Initial Comments at 12; APS Initial Comments at 4.
\165\ EEI Reply Comments at 7-8; New Jersey Commission Initial
Comments at 23; NV Energy Initial Comments at 13.
\166\ Affected Interconnection Customers Initial Comments at 30;
Clean Energy States Initial Comments at 3; Duke Southeast Utilities
Initial Comments at 6; Environmental Defense Fund Initial Comments
at 3; ELCON Initial Comments at 3-4; Fervo Energy Initial Comments
at 2-3; Google Initial Comments at 4-5; NARUC Initial Comments at 4-
5; NESCOE Reply Comments at 3; New Jersey Commission Initial
Comments at 20-22; New York State Department Initial Comments at 8;
Pacific Northwest Utilities Initial Comments at 13; Public Interest
Organizations Initial Comments at 18; Puget Sound Initial Comments
at 5; SDG&E Initial Comments at 3-4.
---------------------------------------------------------------------------
64. Several commenters note the importance of additional
interconnection information access in light of the other reforms
proposed in the NOPR. AES contends that it would be inequitable for the
Commission to increase security deposits to stay in the interconnection
queue under the NOPR proposal to increase study and LGIA deposits
without requiring transmission providers to provide sufficient
information to interconnection customers.\167\ Vistra asserts that the
proposals to provide additional information will complement the
exclusive site control proposals and provide an avenue for prospective
interconnection customers to select the most viable sites on which to
obtain rights and develop a location, which is a costly and time-
consuming process, before entering the interconnection queue.\168\
Northwest and Intermountain argue that, in order for the other proposed
reforms in the NOPR to be effective, potential interconnection
customers must have a solution to the problem of identifying optimal
interconnection locations and configurations that is timely, cost-
effective, and accurate.\169\
---------------------------------------------------------------------------
\167\ AES Initial Comments at 13.
\168\ Vistra Initial Comments at 4.
\169\ Northwest and Intermountain Initial Comments at 9.
---------------------------------------------------------------------------
65. Google contends that pre-queue information is necessary because
there is an extreme information asymmetry between independent power
producers and transmission owners and their generating affiliates,
which have greater access to planning information, including load
growth, relative cost of interconnecting at different points, points of
chronic congestion where upgrades might be needed, and planned local
upgrades.\170\ Google asserts that this information asymmetry is
particularly pronounced in the non-RTO/ISO regions, and allows
transmission owners and their affiliates to identify the best locations
for interconnection more quickly than independent power producers.
---------------------------------------------------------------------------
\170\ Google Initial Comments at 3-4.
---------------------------------------------------------------------------
66. On the other hand, Dominion argues that there is no evidence in
the record that a lack of information is slowing down the
interconnection queue process or that transmission providers are not
engaged in good faith reviews of interconnection requests.\171\
According to Dominion, the Commission should focus on making the
interconnection process more efficient and speedier, and the best way
to achieve these goals is through the first-ready, first-served cluster
study reform. While APPA-LPPC support transparency in the generator
interconnection process and share the Commission's view that the
availability of transmission system information should reduce the
incentive to submit speculative interconnection requests, they argue
that sufficient information is currently publicly available.\172\
---------------------------------------------------------------------------
\171\ Dominion Reply Comments at 8-9.
\172\ APPA-LPPC Initial Comments at 11.
---------------------------------------------------------------------------
iii. Commission Determination
67. We find that, absent reforms to require transmission providers
to provide additional interconnection information, which can be used by
interconnection customers prior to submitting an interconnection
request, speculative interconnection requests will likely remain at
current levels and continue to contribute to interconnection study
delays and add costs to the interconnection process. Although
submitting multiple interconnection requests to gain information may be
a rational response to a lack of pre-interconnection queue information,
this practice increases interconnection study delays.\173\ We also
agree with commenters that additional access to interconnection
information is a valuable goal \174\ as it can increase the likelihood
that an interconnection request is viable when submitted. We disagree
with commenters that current information requirements are
sufficient.\175\ While certain information is currently available
through the feasibility study process, as part of our reforms discussed
below, we eliminate the feasibility study. Therefore, we find it
necessary to provide a means for interconnection customers to obtain
additional information prior to entering the interconnection queue. We
concur with comments that additional access to interconnection
information prior to entering the interconnection queue is important
for interconnection customers to make informed decisions, particularly
given the increased requirements for interconnection customers adopted
in this final rule, such as increased study deposits and site control,
as discussed
[[Page 61028]]
below.\176\ We also agree that commenters raise a valid concern that an
information asymmetry exists between independent power producers and
transmission owner affiliates, in particular in non-RTO/ISO
regions.\177\
---------------------------------------------------------------------------
\173\ See AES Initial Comments at 3; Affected Interconnection
Customers Initial Comments at 30; Clean Energy Buyers Initial
Comments at 5-6; CREA and NewSun Initial Comments at 45;
Enviornmental Defense Fund Initial Comments at 3; ELCON Initial
Comments at 3; Northwest and Intermountain Initial Comments at 5;
Public Interest Organizations Initial Comments at 18.
\174\ ACORE Reply Comments at 3; AEE Initial Comments at 9; AEP
Initial Comments at 12; AES Initial Comments at 3; Affected
Interconnection Customers Initial Comments at 30; APS Initial
Comments at 4; Bonneville Initial Comments at 5; Clean Energy Buyers
Initial Comments at 7; CREA and NewSun Initial Comments at 44; ELCON
Initial Comments at 3-4; Enel Initial Comments at 9; Google Initial
Comments at 15; MISO Initial Comments at 20-21; NARUC Initial
Comments at 4; NESCOE Reply Comments at 2-3; NY Commission and
NYSERDA Initial Comments at 6-8; NYISO Initial Comments at 16; NYTOs
Initial Comments at 8; Pacific Northwest Utilities Initial
Comments at 13; PJM Initial Comments at 45; Puget Sound Initial
Comments at 5; WAPA Initial Comments at 5.
\175\ APPA-LPPC Initial Comments at 9.
\176\ AES Initial Comments at 13; Northwest and Intermountain
Initial Comments at 9; Vistra Initial Comments at 4.
\177\ Google Initial Comments at 3-5.
---------------------------------------------------------------------------
b. Informational Interconnection Study
i. NOPR Proposal
68. In the NOPR, the Commission proposed to revise the Commission's
pro forma LGIP to require transmission providers to offer an
informational interconnection study for prospective interconnection
customers.\178\ The Commission proposed that the informational
interconnection study would provide cost estimates for the transmission
provider's interconnection facilities and network upgrade costs
specific to the interconnection scenario detailed in the study
agreement. The Commission also proposed to include new definitions for
an informational interconnection study and informational
interconnection study agreement.
---------------------------------------------------------------------------
\178\ NOPR, 179 FERC ] 61,194 at P 42.
---------------------------------------------------------------------------
69. Under the Commission's proposal, prospective interconnection
customers could request up to five separate informational
interconnection studies at a time.\179\ The Commission explained that
each configuration of an interconnection request would require a
separate informational interconnection study. The Commission proposed
that the informational interconnection study would be at the
interconnection customer's expense, and each study would require a
$10,000 deposit, subject to a true-up based on actual study costs.
---------------------------------------------------------------------------
\179\ Id. P 43.
---------------------------------------------------------------------------
70. The Commission proposed that, within seven business days of the
receipt of a prospective interconnection customer's request for an
informational interconnection study, the transmission provider would
have to provide the prospective interconnection customer with an
informational interconnection study agreement.\180\ The Commission
explained that the informational interconnection study agreement would
specify the technical data that the prospective interconnection
customer must provide and an estimate of the expected costs of the
study, including, to the extent known by the transmission provider, an
estimate of the study costs expected to be incurred by any relevant
affected systems. Under the proposal, the prospective interconnection
customer would have 10 business days to execute the agreement and
deliver it to the transmission provider, along with the relevant
technical data and study deposit, after which the transmission provider
would have 45 calendar days to complete the study.
---------------------------------------------------------------------------
\180\ Id. P 44.
---------------------------------------------------------------------------
71. The Commission proposed that the informational interconnection
study would consist of a sensitivity analysis based on the assumptions
specified in the informational interconnection study agreement.\181\
Under the proposal, the informational interconnection study would
identify potential interconnection facilities and network upgrades that
may be required to interconnect the prospective interconnection
customer's proposed generating facility, including an approximation of
the costs of such interconnection facilities and network upgrades. The
Commission noted that the transmission provider would also coordinate
with affected systems that may be impacted by the prospective
interconnection customer's request to provide information on affected
systems-related issues.
---------------------------------------------------------------------------
\181\ Id. P 45.
---------------------------------------------------------------------------
72. The Commission proposed an informational interconnection study
agreement form, which explains that the informational interconnection
study is performed solely for informational purposes and is not binding
on either party.\182\ The proposed agreement also requires the study
report to provide specific information, including, at a minimum: (1)
preliminary identification of any circuit breaker short circuit
capability limits exceeded; (2) preliminary identification of any
thermal overload or voltage limit violations; and (3) estimated network
upgrade costs related to the identified overloads and violations.
---------------------------------------------------------------------------
\182\ Id. P 46.
---------------------------------------------------------------------------
73. The Commission sought comment on: (1) whether the informational
interconnection study, as proposed, would provide prospective
interconnection customers with sufficient and timely information to
inform decision-making prior to submitting an interconnection request;
(2) whether transmission providers should be required to establish a
request window of a limited number of days each year in which potential
interconnection customers can request an optional informational
interconnection study; and (3) the burdens on transmission providers of
conducting informational studies and whether other options, such as the
proposal discussed below for public interconnection information, might
strike a better balance of providing interconnection customers with
useful information while making efficient use of transmission provider
resources.\183\
---------------------------------------------------------------------------
\183\ Id. PP 47-48.
---------------------------------------------------------------------------
74. Additionally, the Commission proposed to add new section 3.1.2
to the pro forma LGIP, which provides that interconnection customers
evaluating different options (such as different sizes, sites, or
voltages) are encouraged but not required to use the new informational
interconnection study proposed in the NOPR before entering the cluster
study.\184\
---------------------------------------------------------------------------
\184\ Id. P 66.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
75. Several commenters support the NOPR proposal to require
transmission providers to offer an informational interconnection study
to prospective interconnection customers.\185\ Several commenters agree
that the informational interconnection study proposal could reduce the
number of speculative or other interconnection requests \186\ and
improve the efficiency of siting decisions.\187\ Some commenters expect
that these changes will have other benefits for the interconnection
process, including cost savings from fewer and more viable
interconnection requests,\188\ a reduced need for project withdrawals
and queue restudies,\189\ and reduced burden on transmission providers,
which will result in fewer interconnection study delays.\190\
---------------------------------------------------------------------------
\185\ Affected Interconnection Customers Initial Comments at 30;
Clean Energy States Initial Comments at 4; Consumers Energy Initial
Comments at 3; Duke Southeast Utilities Initial Comments at 6;
Evergreen Action Initial Comments at 3; Fervo Energy Initial
Comments at 2; Illinois Commission Initial Comments at 6; Interwest
Initial Comments at 4, 7; NESCOE Reply Comments at 2; Public
Interest Organizations Initial Comments at 18; Southern Initial
Comments at 28; Tesla Initial Comments at 4; Tri-State Initial
Comments at 5.
\186\ Fervo Energy Initial Comments at 2-3; Google Initial
Comments at 4; NRECA Initial Comments at 13; NY Commission and
NYSERDA Initial Comments at 6-8.
\187\ Duke Southeast Utilities Initial Comments at 6-7; ISO-NE
Initial Comments at 18; NARUC Initial Comments at 5; NRECA Initial
Comments at 13; Pine Gate Initial Comments at 13-14; Tesla Initial
Comments at 4.
\188\ Evergreen Action Initial Comments at 3; NARUC Initial
Comments at 5.
\189\ Evergreen Action Initial Comments at 3; NRECA Initial
Comments at 13.
\190\ Google Initial Comments at 4.
---------------------------------------------------------------------------
76. MISO and Fervo Energy state that it is helpful for a
prospective interconnection customer to compare how various MW sizes,
points of interconnection, or other scenarios could affect costs,
especially for prospective interconnection customers that cannot
perform such analysis in house, and that the NOPR's
[[Page 61029]]
informational interconnection study proposal would assist in these
goals.\191\ Pacific Northwest Organizations argue that, without upfront
interconnection cost information, independent power producers may be
discouraged from entering the interconnection queue if they are
subjected to higher withdrawal fees, which may result in preventing
them from being considered in request for proposals (RFPs) in the
Pacific Northwest.\192\
---------------------------------------------------------------------------
\191\ Fervo Energy Initial Comments at 2; MISO Initial Comments
at 22.
\192\ Pacific Northwest Organizations Initial Comments at 3-4.
---------------------------------------------------------------------------
77. Some commenters stress the importance of the informational
interconnection study in light of the other reforms proposed in the
NOPR. For instance, Northwest and Intermountain aver that the
informational study will be the primary resource for interconnection
customers to demonstrate the feasibility and cost effectiveness of
their interconnection plan and will serve as the foundation for
subsequent negotiations for the documents that will establish
commercial readiness of their project for the cluster study
process.\193\ Pacific Northwest Organizations assert that the NOPR's
proposed commercial readiness framework would be problematic in the
region without something like the informational interconnection study
to discover costs before entering the queue.\194\
---------------------------------------------------------------------------
\193\ Northwest and Intermountain Initial Comments at 6-7.
\194\ Pacific Northwest Organizations Initial Comments at 3.
---------------------------------------------------------------------------
78. Several commenters are generally supportive of the NOPR
proposal but either (1) offer qualifications to that support \195\ or
(2) request specific changes to the proposal.\196\
---------------------------------------------------------------------------
\195\ Idaho Power Initial Comments at 3 (stating that it only
supports the proposal if the informational interconnection study
requirements are less prescriptive and allow for more flexibility);
NRECA Initial Comments at 8 (stating that it does not oppose the
proposal as long as the final rule includes a larger package of
reforms to reduce speculative interconnection requests and speed up
interconnection queues as well as affords reasonable flexibility on
compliance); Ohio Commission Consumer Advocate Initial Comments at 6
(stating that informational studies should not interfere with other
interconnection studies).
\196\ ACE-NY Initial Comments at 10; Avangrid Initial Comments
at 21; Clean Energy Buyers Initial Comments at 7; ELCON Initial
Comments at 4-5; NY Commission and NYSERDA Initial Comments at 6-7;
Pattern Energy Initial Comments at 20; Pine Gate Initial Comments at
11-13; Southern Initial Comments at 28.
---------------------------------------------------------------------------
(b) Comments in Opposition
79. Many commenters oppose the NOPR proposal to require
transmission providers to offer an informational interconnection study
to prospective interconnection customers.\197\ Many commenters argue
that the informational interconnection study proposal could be a burden
or divert resources,\198\ which they contend would increase delays for
the interconnection queue and other studies.\199\ Dominion insists that
the decision as to whether to offer informational interconnection
studies should be the transmission provider's and must have
limits.\200\ Longroad Energy states that transmission-interconnected
generating facilities are typically complex facilities with unique
operating characteristics which would be poorly approximated in
simplified studies.\201\ Environmental Defense Fund states that, while
it supported the informational interconnection studies proposal in its
initial comments, after review of the other comments submitted, it
recommends that the Commission reconsider the proposal and ensure that
any informational interconnection study reform not delay other
interconnection processes.\202\
---------------------------------------------------------------------------
\197\ AECI Initial Comments at 3; AEP Initial Comments at 7; AEP
Reply Comments at 2; APPA-LPPC Initial Comments at 3; Avangrid
Initial Comments at 21; Bonneville Initial Comments at 3; CAISO
Initial Comments at 5; Clean Energy Associations Initial Comments at
13; Dominion Reply Comments at 5; EEI Initial Comments at 11; EEI
Reply Comments at 7-8; Enel Initial Comments at 9; ENGIE Initial
Comments at 2; Eversource Initial Comments at 5; Indicated PJM TOs
Initial Comments at 12; Indicated PJM TOs Reply Comments at 14;
Longroad Energy Reply Comments at 3; NextEra Initial Comments at 5;
NextEra Reply Comments at 8; North Dakota Commission Initial
Comments at 3-4; NV Energy Initial Comments at 14; OMS Initial
Comments at 5; [Oslash]rstead Initial Comments at 7; PG&E Initial
Comments at 9; PJM Initial Comments at 45; PPL Initial Comments at
4; SEIA Initial Comments at 3; SPP Initial Comments at 2, 3-4;
Vermont Electric and Vermont Transco Initial Comments at 3; WIRES
Initial Comments at 8.
\198\ AECI Initial Comments at 3; AEE Reply Comments at 5-6; AEP
Initial Comments at 7-8; AEP Reply Comments at 2; AES Initial
Comments at 4; Alliant Energy Initial Comments at 4; APPA-LPPC
Initial Comments at 9; APS Initial Comments at 5; Bonneville Initial
Comments at 3; CAISO Initial Comments at 6; Clean Energy Buyers
Initial Comments at 6; Clean Energy States Initial Comments at 4;
Dominion Reply Comments at 5-6; Environmental Defense Fund Reply
Comments at 5; EEI Initial Comments at 11-12; EEI Reply Comments at
8-9; ELCON Initial Comments at 4-5; Enel Initial Comments at 9;
ENGIE Initial Comments at 2; Eversource Initial Comments at 5;
Google Initial Comments at 5; Idaho Power Initial Comments at 3;
Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply
Comments at 14; Longroad Energy Reply Comments at 4-5; MISO Reply
Comments at 17; National Grid Initial Comments at 9; NESCOE Reply
Comments at 2; NextEra Reply Comments at 8-9, 11-12; New Jersey
Commission Initial Comments at 21; North Dakota Commission Initial
Comments at 3-4; NRECA Initial Comments at 14; NV Energy Initial
Comments at 14; NYISO Initial Comments at 16; OMS Initial Comments
at 5; Pine Gate Initial Comments at 12; PPL Initial Comments at 4-6;
SDG&E Initial Comments at 3-4; SEIA Initial Comments at 3; SEIA
Reply Comments at 4; SoCal Edison Initial Comments at 12; Tesla
Initial Comments at 4; Vermont Electric and Vermont Transco Initial
Comments at 3; WIRES Initial Comments at 8.
\199\ AECI Initial Comments at 3; AEP Initial Comments at 7-8;
AEP Reply Comments at 2-3; AES Initial Comments at 4; Alliant Energy
Initial Comments at 4; APS Initial Comments at 4; Bonneville Initial
Comments at 3; CAISO Initial Comments at 6; Dominion Initial
Comments at 9; Duke Southeast Utilities Initial Comments at 7-8;
Environmental Defense Fund Reply Comments at 5; EEI Initial Comments
at 11; ELCON Initial Comments at 4-5; Eversource Initial Comments at
5-6; Google Initial Comments at 5; Idaho Power Initial Comments at
3; Indicated PJM TOs Initial Comments at 13; MISO Reply Comments at
17; National Grid Initial Comments at 7, 10-11; NESCOE Reply
Comments at 2; NextEra Reply Comments at 8; New Jersey Commission
Initial Comments at 21; North Dakota Commission Initial Comments at
3-4; NRECA Initial Comments at 14; NYISO Initial Comments at 16-19;
OMS Initial Comments at 5; Pennsylvania Commission Initial Comments
at 11; PG&E Initial Comments at 9; PG&E Reply Comments at 5; Pine
Gate Initial Comments at 12; PJM Initial Comments at 45; PPL Initial
Comments at 4; SEIA Initial Comments at 4; SoCal Edison Initial
Comments at 12; Tesla Initial Comments at 4.
\200\ Dominion Reply Comments at 5.
\201\ Longroad Energy Reply Comments at 7.
\202\ Environmental Defense Fund Reply Comments at 5.
---------------------------------------------------------------------------
80. Several commenters contend that the informational
interconnection study proposal would not likely be valuable.\203\ Clean
Energy Associations assert that the proposed informational
interconnection study would provide no information related to
stability-driven network upgrades, rendering it near-useless in areas
where stability limits are most typically the driver of network
upgrades.\204\ APPA-LPPC warn that informational interconnection
studies could engender controversy because prospective interconnection
customers would, notwithstanding the informational nature of the
studies, likely rely upon the study results in
[[Page 61030]]
making investment decisions, even though the informational study
results would inevitably diverge from the actual interconnection study
results.\205\
---------------------------------------------------------------------------
\203\ AEE Initial Comments at 9-10; AEE Reply Comments at 5-6;
AEP Initial Comments at 7; AEP Reply Comments at 2; Alliant Energy
Initial Comments at 4; CAISO Initial Comments at 5-6; Clean Energy
Associations Initial Comments at 14; CREA and NewSun Initial
Comments at 42; Dominion Reply Comments at 5; EEI Initial Comments
at 12; EEI Reply Comments at 8; Enel Initial Comments at 9; ENGIE
Initial Comments at 2; Eversource Initial Comments at 5-6; Indicated
PJM TOs Initial Comments at 12; Indicated PJM TOs Reply Comments at
14; ISO-NE Initial Comments at 19; Longroad Energy Reply Comments at
3; MISO Initial Comments at 20-21; MISO Reply Comments at 17-18;
NextEra Initial Comments at 5, 10-11; NextEra Reply Comments at 9;
North Dakota Commission Initial Comments at 4; NRECA Initial
Comments at 14; NV Energy Initial Comments at 14; NYISO Initial
Comments at 17; OMS Initial Comments at 5; Pacific Northwest
Utilities Initial Comments at 8 n.13; PG&E Initial Comments at 9;
PG&E Reply Comments at 4; PJM Initial Comments at 45; SDG&E Initial
Comments at 3-4; SEIA Initial Comments at 3; SEIA Reply Comments at
3; SoCal Edison Initial Comments at 11-12; WIRES Initial Comments at
8.
\204\ Clean Energy Associations Initial Comments at 14.
\205\ APPA-LPPC Initial Comments at 12.
---------------------------------------------------------------------------
81. Several commenters argue that the proposal is not an
improvement over the status quo.\206\ National Grid and NextEra assert
that it is unclear how the proposal would save any time compared to the
status quo, and that the best way for an interconnection customer to
obtain the necessary information is by entering and proceeding through
the interconnection queue with transmission providers focusing on
actual studies.\207\ NextEra adds that the proposed informational
interconnection study is only informative in extreme cases, such as
very limited capacity available on a transmission line, which the
interconnection customer should be able to identify themselves.\208\
---------------------------------------------------------------------------
\206\ National Grid Initial Comments at 9; New Jersey Commission
Initial Comments at 21; Vermont Electric and Vermont Transco Initial
Comments at 3.
\207\ National Grid Initial Comments at 9; NextEra Initial
Comments at 12.
\208\ NextEra Initial Comments at 12.
---------------------------------------------------------------------------
82. CREA and NewSun express concern that the NOPR proposal places
too much reliance on the usefulness of the informational
interconnection study in order to justify the financial readiness and
commitment NOPR proposals.\209\ They assert that the informational
interconnection study is not a useful replacement for the feasibility
study, which takes into account the impact of other interconnection
customers in the interconnection queue cluster. Therefore, CREA and
NewSun ask the Commission to instead retain the feasibility study as
part of the cluster study process to allow interconnection customers to
obtain cluster-level information on likely costs and network upgrades
before proceeding further with major deposits and irretrievable
commitments.
---------------------------------------------------------------------------
\209\ CREA and NewSun Initial Comments at 46-47.
---------------------------------------------------------------------------
83. Several commenters point to the experience with similar studies
in SPP and MISO as evidence that the optional informational
interconnection study proposal will be little-used in practice.\210\
SPP reports that its interconnection customers explained that their
time could be more effectively spent working on the more definitive
system impact studies, that the feasibility and preliminary impact
studies did not provide results that could be relied on in making
business decisions, and that this same outcome would be true of the
proposed informational interconnection study.\211\
---------------------------------------------------------------------------
\210\ AEE Initial Comments at 10; AEP Initial Comments at 8,12;
Clean Energy Associations Initial Comments at 14; Enel Initial
Comments at 9-10; Longroad Energy Reply Comments at 3-4; MISO
Initial Comments at 21; NextEra Reply Comments at 8; Omaha Public
Power Initial Comments at 3; SEIA Reply Comments at 3; SPP Initial
Comments at 3. NextEra argues that transmission providers with large
numbers of interconnection requests have tried optional
interconnection studies and have not found them to be useful.
NextEra Reply Comments at 10.
\211\ SPP Initial Comments at 3.
---------------------------------------------------------------------------
84. Several commenters point to the inability of the informational
interconnection studies to provide reliable cost estimates \212\ and
believe that the information provided in these studies will be quickly
outdated.\213\ The New Jersey Commission is concerned that this
approach may not materially reduce the uncertainty interconnection
customers currently face.\214\ In particular, many commenters contend
that the informational interconnection study is not meaningful in the
context of a cluster interconnection
---------------------------------------------------------------------------
\212\ AEP Initial Comments at 8; Ameren Initial Comments at 5;
CAISO Initial Comments at 5; Clean Energy Associations Initial
Comments at 14; CREA and NewSun Initial Comments at 43; Cyprus Creek
Initial Comments at 13; Enel Initial Comments at 9; Interwest
Initial Comments at 7-8; NextEra Initial Comments at 5; NRECA
Initial Comments at 14; PJM Initial Comments at 45; SoCal Edison
Initial Comments at 11-12.
\213\ AEP Initial Comments at 8; Alliant Energy Initial Comments
at 4; Dominion Initial Comments at 10; Enel Initial Comments at 9;
Eversource Initial Comments at 9; Interwest Initial Comments at 7-8;
PJM Initial Comments at 45; PJM TOs Initial Comments at 13; SEIA
Reply Comments at 4.
\214\ New Jersey Commission Initial Comments at 21.
---------------------------------------------------------------------------
process.\215\ Commenters argue that, because the informational
interconnection study does not provide information on other
interconnection customers that would enter the interconnection queue at
the same time, there is no guarantee that the study results will even
approximate the actual network upgrade costs determined by the cluster
results.\216\
---------------------------------------------------------------------------
\215\ Id.; AEE Initial Comments at 9-10; Avangrid Initial
Comments at 23-24; Clean Energy Associations Initial Comments at 14;
CREA and NewSun Initial Comments at 43; Dominion Reply Comments at
6; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial
Comments at 9; Eversource Initial Comments at 9-10; ISO-NE Initial
Comments at 18-19; MISO Initial Comments at 21; NRECA Initial
Comments at 14; NV Energy Initial Comments at 14; PJM Initial
Comments at 45; PPL Initial Comments at 5; SEIA Initial Comments at
4-5; SEIA Reply Comments at 3-4; SoCal Edison Initial Comments at
12; SPP Initial Comments at 2-3.
\216\ AEE Initial Comments at 9-10; CAISO Initial Comments at 5-
6; CREA and NewSun Initial Comments at 44; Dominion Initial Comments
at 10; Duke Southeast Utilities Initial Comments at 7; EEI Reply
Comments at 8; Indicated PJM TOs Initial Comments at 13; ISO-NE
Initial Comments at 18-19; MISO Initial Comments at 22; NextEra
Initial Comments at 11-12; New Jersey Commission Initial Comments at
21; PG&E Reply Comments at 5; PPL Initial Comments at 5; SEIA Reply
Comments at 3-4; SoCal Edison Initial Comments at 12.
---------------------------------------------------------------------------
85. Some commenters expect the proposal will work against the
Commission's goal of faster interconnection queue processing.\217\ Some
commenters state that any reduction in speculative interconnection
requests will be offset by an increase in speculative informational
interconnection requests, which would require transmission providers to
shift their focus from the actual interconnection queue to this more
burdensome informational interconnection process, which is outside of
their interconnection study process.\218\ NRECA states that, if the
proposal is included in the final rule, the Commission should ensure
that it is limited and is not expanded into an elaborate serial study
process prior to the cluster study process.\219\ Avangrid notes that
some transmission providers have recently eliminated interconnection
studies to reduce interconnection queue processing time.\220\
Pennsylvania Commission asserts that the Commission should assess the
results of the NOPR's proposed reforms before requiring any new study
processes that may further slow the interconnection queue process.\221\
---------------------------------------------------------------------------
\217\ AEE Reply Comments at 6; AEP Initial Comments at 11;
Avangrid Initial Comments at 22-23; CAISO Initial Comments at 6;
Dominion Reply Comments at 6-7; National Grid Initial Comments at 7;
NESCOE Reply Comments at 2; NV Energy Initial Comments at 14;
Pennsylvania Commission Initial Comments at 11-12.
\218\ AECI Initial Comments at 4; AEP Initial Comments at 11;
APPA-LPPC Initial Comments at 11-12; Bonneville Initial Comments at
3 (citing NOPR, 179 FERC ] 61,194 at PP 20, 22, 166); Clean Energy
Buyers Initial Comments at 6; Dominion Reply Comments at 6; NextEra
Initial Comments at 12; NYISO Initial Comments at 17; Pennsylvania
Commission Initial Comments at 11 (explaining that because the
informational study is not binding on any party, the study does not
move projects through the interconnection queue).
\219\ NRECA Initial Comments at 14.
\220\ Avangrid Initial Comments at 23 (citing NOPR, 179 FERC ]
61,194 at P 56 n.111).
\221\ Pennsylvania Commission Initial Comments at 11-12.
---------------------------------------------------------------------------
86. Several commenters note the challenge of staffing to fulfill
the informational interconnection study requirements given the limited
number of qualified planners and engineers.\222\
---------------------------------------------------------------------------
\222\ Id. at 11; AEP Initial Comments at 10-11; APPA-LPPC
Initial Comments at 12; Avangrid Initial Comments at 22-23;
Bonneville Initial Comments at 5; Eversource Initial Comments at 5-
6; Indicated PJM TOs Initial Comments at 12; Indicated PJM TOs Reply
Comments at 14; LADWP Initial Comments at 2; OMS Initial Comments at
5.
---------------------------------------------------------------------------
87. Several commenters urge the Commission to weigh the benefits
against the burdens to determine whether to adopt the informational
interconnection study proposal.\223\
[[Page 61031]]
WAPA states that, while it agrees that it is important to provide
prospective interconnection customers with additional information, it
has concerns about the proposed timelines and penalties, the potential
amount of informational interconnection study requests it could
receive, and its ability to process up to five simultaneous
informational interconnection study requests per interconnection
customer.\224\ According to Vermont Electric and Vermont Transco, even
if the informational interconnection studies envisioned by the NOPR
provide interconnection customer benefits, the burdens of providing
informational interconnection studies with cost estimates under the
NOPR's short proposed time frames and low deposit amounts would be
considerable especially for smaller companies such as Vermont Electric
and Vermont Transco.\225\ Other commenters contend that the
informational interconnection study proposal has insufficient
benefits.\226\
---------------------------------------------------------------------------
\223\ Ameren Initial Comments at 5; R Street Initial Comments at
9; Xcel Initial Comments at 20.
\224\ WAPA Initial Comments at 4-5.
\225\ Vermont Electric and Vermont Transco Initial Comments at
3.
\226\ Id.; AEP Initial Comments at 7; AES Initial Comments at 4;
EEI Initial Comments at 11; ENGIE Initial Comments at 2; NextEra
Initial Comments at 10-11; [Oslash]rstead Initial Comments at 7; PJM
Initial Comments at 45; SEIA Initial Comments at 3.
---------------------------------------------------------------------------
88. Given PJM's opposition to the informational interconnect study,
it recommends modifying the proposed new section 3.1.2 to the pro forma
LGIP to encourage, but not require, interconnection customers
evaluating different project characteristics to use a prescreening
tool, such as the queue scope tool PJM is developing, prior to
submitting an interconnection request.\227\
---------------------------------------------------------------------------
\227\ PJM Initial Comments at 19 (explaining that the queue
scope is an interactive prescreening tool that will allow
interconnection customers to screen potential points of
interconnection and assess grid capacity (head room) based on a
given amount of MW injection or withdrawal at a given point of
interconnection and that the tool will be available at no charge).
PJM's proposed section 3.1.2 of the pro forma LGIP would read:
``Interconnection Customers evaluating different options . . . to
use the prescreening tool (Section 6.1 of this LGIP) before entering
the Cluster Study.''
---------------------------------------------------------------------------
iii. Commission Determination
89. We decline to adopt the NOPR proposal to modify the pro forma
LGIP to require transmission providers to offer an informational
interconnection study for prospective interconnection customers. We are
persuaded by commenters' concerns that requiring an informational
interconnection study could divert the transmission provider's
resources away from the cluster studies we require in this final rule
and undermine the benefits of those reforms that seek to reduce
interconnection study delays, costs, and burden on constrained
engineering labor. Moreover, we agree with commenters that highlight
the various limitations of an informational interconnection study.
Notably, an informational interconnection study, as proposed in the
NOPR, would have provided a serial, snapshot-in-time analysis on the
impact of a single interconnection request, but, in the context of the
subsequent cluster study, the actual impact of an interconnection
request within a larger cluster would reflect different assumptions and
differ from the informational interconnection study, providing minimal
or no value to interconnection customers. The cost estimates that
result from such an informational interconnection study would bear
little correspondence to costs determined during a cluster study
process and thus provide minimal value to interconnection customers.
90. We also find persuasive comments that the informational
interconnection study requirement proposed in the NOPR is not the most
effective way to provide interconnection customers with the needed pre-
interconnection queue information. At the same time, we continue to
believe that there is a lack of information available to prospective
interconnection customers prior to entering the interconnection queue,
especially given other interconnection customer-related reforms adopted
in this final rule.\228\ Therefore, as discussed below, we adopt the
NOPR proposal to set minimum requirements for transmission providers to
publicly post available information pertaining to generator
interconnection.\229\ We find that the posting of this information
provides a better balance between the benefits of additional
information for prospective interconnection customers and the burdens
on transmission providers.
---------------------------------------------------------------------------
\228\ See Northwest and Intermountain Initial Comments at 6-7.
\229\ See infra section III.A.1.c.iii.
---------------------------------------------------------------------------
91. In response to commenters that support the informational
interconnection study NOPR proposal, below we explain how several of
the NOPR proposals that we adopt in this final rule address their
specific concerns. To address commenters' concerns with the number of
speculative interconnection requests,\230\ we adopt more stringent site
control requirements and increased commercial readiness deposit
requirements,\231\ which we believe will better address these concerns
than the informational interconnection study proposal. Additionally, we
find that the minimum requirements for transmission providers to
publicly post available information pertaining to generator
interconnection \232\ and the existing requirements in section 2.3 of
the pro forma LGIP for transmission providers to post up-to-date base
case study models on their Open Access Same-time Information System
(OASIS) or other password-protected websites will improve the
efficiency of siting decisions \233\ and will provide interconnection
customers with information about the feasibility of their
interconnection plans.\234\
---------------------------------------------------------------------------
\230\ Fervo Energy Initial Comments at 2-3; Google Initial
Comments at 4; NRECA Initial Comments at 13; NY Commission and
NYSERDA Initial Comments at 6-8.
\231\ See infra sections III.A.6.b.iii, III.A.6.c.iii.
\232\ See infra section III.A.1.c.iii.
\233\ Duke Southeast Utilities Initial Comments at 6-7; ISO-NE
Initial Comments at 18; NARUC Initial Comments at 5; NRECA Initial
Comments at 13; Pine Gate Initial Comments at 13-14; Tesla Initial
Comments at 4.
\234\ Northwest and Intermountain Initial Comments at 6-7;
Pacific Northwest Organizations Initial Comments at 3.
---------------------------------------------------------------------------
92. We are not persuaded that the informational interconnection
study proposal would benefit the interconnection process through: (1)
cost savings from fewer, more feasible interconnection requests; \235\
(2) a reduced need for interconnection request withdrawals and
restudies; \236\ and (3) accurate upfront interconnection cost
information.\237\ On the contrary, the Commission's adoption of the
cluster study reforms in this final rule \238\ means that the serial
nature of the informational interconnection study would fail to reflect
the outcome of the cluster study, and thus would provide minimal, if
any, benefits to interconnection customers.\239\ We also no longer
believe that adopting the informational interconnection study
[[Page 61032]]
proposal would reduce burdens on transmission providers.\240\ This is
because the record overwhelmingly demonstrates that the proposal would
result in additional burdens on transmission providers and would likely
cause transmission providers to divert resources from their cluster
study process to conduct informational interconnection studies,\241\
thus increasing study delays and costs. Similarly, we decline CREA and
NewSun's request that the Commission retain the feasibility study
instead of the informational interconnection study. As we discuss
below, the feasibility study was required for the serial study process
but is no longer relevant for the cluster study process.\242\ We
believe that our requirement for transmission providers to publicly
post certain interconnection information will provide interconnection
customers with the information they need prior to entering the
interconnection queue, and therefore decline to adopt CREA and NewSun's
request to maintain the feasibility study.
---------------------------------------------------------------------------
\235\ Evergreen Action Initial Comments at 3; NARUC Initial
Comments at 5.
\236\ Evergreen Action Initial Comments at 3; NRECA Initial
Comments at 13.
\237\ Fervo Energy Initial Comments at 2; MISO Initial Comments
at 22; Pacific Northwest Organizations Initial Comments at 3-4.
\238\ See infra section III.A.2.
\239\ See AEE Initial Comments at 9-10; Avangrid Initial
Comments at 23-24; Clean Energy Associations Initial Comments at 14;
CREA and NewSun Initial Comments at 43; Dominion Reply Comments at
6; EEI Initial Comments at 12; EEI Reply Comments at 8; Enel Initial
Comments at 9; Eversource Initial Comments at 9-10; ISO-NE Initial
Comments at 18-19; MISO Initial Comments at 21; New Jersey
Commission Initial Comments at 21; NRECA Initial Comments at 14; NV
Energy Initial Comments at 14; PJM Initial Comments at 45; PPL
Initial Comments at 5; SEIA Initial Comments at 4-5; SEIA Reply
Comments at 3-4; SoCal Edison Initial Comments at 12; SPP Initial
Comments at 2-3.
\240\ See Google Initial Comments at 5 (arguing that the
informational interconnection study requirement alone would likely
increase the burden on transmission providers in a way that would
lengthen delays).
\241\ Id.; AECI Initial Comments at 3; AEE Reply Comments at 5-
6; AEP Initial Comments at 7-8; AEP Reply Comments at 2; AES Initial
Comments at 4; Alliant Energy Initial Comments at 4; APPA-LPPC
Initial Comments at 9; APS Initial Comments at 5; Bonneville Initial
Comments at 3; CAISO Initial Comments at 6; Clean Energy Buyers
Initial Comments at 6; Clean Energy States Initial Comments at 4;
Dominion Reply Comments at 5-6; Environmental Defense Fund Reply
Comments at 5; EEI Initial Comments at 11-12; EEI Reply Comments at
8-9; ELCON Initial Comments at 4-5; Enel Initial Comments at 9;
ENGIE Initial Comments at 2; Eversource Initial Comments at 5; Idaho
Power Initial Comments at 3; Indicated PJM TOs Initial Comments at
12; Indicated PJM TOs Reply Comments at 14; Longroad Energy Reply
Comments at 4-5; MISO Reply Comments at 17; National Grid Initial
Comments at 9; NESCOE Reply Comments at 2; New Jersey Commission
Initial Comments at 21; NextEra Reply Comments at 8-9, 11-12; North
Dakota Commission Initial Comments at 3-4; NRECA Initial Comments at
14; NV Energy Initial Comments at 14; NYISO Initial Comments at 16;
OMS Initial Comments at 5; Pine Gate Initial Comments at 12; PPL
Initial Comments at 4-6; SDG&E Initial Comments at 3-4; SEIA Initial
Comments at 3; SEIA Reply Comments at 4; SoCal Edison Initial
Comments at 12; Tesla Initial Comments at 4; Vermont Electric and
Vermont Transco Initial Comments at 3; WIRES Initial Comments at 8.
\242\ See infra section III.A.2.f.iii.
---------------------------------------------------------------------------
93. Because we do not adopt the NOPR proposal to require
transmission providers to offer an informational interconnection study,
we decline to adopt the proposal to add new section 3.1.2 to the pro
forma LGIP to encourage interconnection customers to use the
informational interconnection study.
c. Public Interconnection Information
i. NOPR Proposal
94. In the NOPR, the Commission proposed to require transmission
providers to maintain and make publicly available an interactive visual
representation of available interconnection capacity (commonly known as
a ``heatmap'') as well as a table of relevant interconnection metrics
that allow prospective interconnection customers to see certain
estimates of a potential generating facility's effect on the
transmission provider's transmission system.\243\ Specifically, the
Commission proposed to revise section 6.4 of the pro forma LGIP to
require transmission providers to post on their public website a
heatmap of estimated incremental injection capacity (in MW) available
at each bus in the transmission provider's footprint under N-1
conditions, as well as provide a table of results showing the estimated
impact of the addition of a proposed project (based on the user-
specified MW amount, voltage level, and point of interconnection) for
each monitored facility impacted by the proposed project on: (1) the
distribution factor; (2) the MW impact (based on the proposed project
size and the distribution factor); (3) the percentage impact on the
monitored facility (based on the MW values of the proposed project and
the monitored facility rating); (4) the percentage of power flow on the
monitored facility before the proposed project; and (5) the percentage
power flow on the monitored facility after the injection of the
proposed project. The Commission explained that these metrics would be
calculated based on the power flow model of the cluster study or
restudy with the transfer simulated from each bus to the whole
transmission provider's footprint (to approximate Network Resource
Interconnection Service (NRIS)), and with the incremental capacity at
each bus decremented by the existing and queued generation in the
cluster (based on the existing or requested interconnection service
limit of the generation). The Commission proposed to require
transmission providers to update this information within 30 days after
the completion of each cluster study and restudy.
---------------------------------------------------------------------------
\243\ NOPR, 179 FERC ] 61,194 at P 51.
---------------------------------------------------------------------------
95. The Commission sought comment on whether: (1) there are any
security concerns with this proposed requirement; and (2) the
assumptions specified for the analysis are the right set of
assumptions.\244\
---------------------------------------------------------------------------
\244\ Id. P 52.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
96. Many commenters express support for the NOPR's proposal to
require transmission providers to provide public interconnection
information.\245\ Several commenters agree that the NOPR proposal will
provide valuable information to interconnection customers before they
enter the interconnection queue.\246\ Several commenters aver that the
proposal could reduce the number of interconnection requests withdrawn
\247\ and therefore could reduce costs for all parties.\248\ Alliant
Energy and Clean Energy Associations also see value in the standardized
format of the proposed
[[Page 61033]]
public interconnection information.\249\ R Street states that a
properly done visual representation of interconnection capacity can be
a ``powerful decentralized self-screening tool.'' \250\ R Street states
that better information and simpler deliverability requirements shift
congestion performance risk to generating facilities while reducing
barriers to entry.\251\ The Ohio Commission Consumer Advocate states
that the visual map of available interconnection capacity would be
useful both to transmission providers and interconnection customers and
would encourage information sharing on transmission system congestion
during the interconnection process.\252\ Google argues that making
these data publicly available to consumers would allow buyers to make
informed choices regarding power procurement.\253\ Additionally, Google
asserts that there needs to be a standard of reasonable care applied to
ensure that the publicly available information is reasonably current
and useful to avoid exploratory interconnection requests.\254\ SEIA
argues that greater transparency will increase competition between
merchant and utility developed generating facilities, benefiting
consumers.\255\ Illinois Commission contends that, if properly
implemented, the NOPR proposal will increase the pace at which new
generating facilities can connect to the transmission system,
furthering state policy objectives.\256\
---------------------------------------------------------------------------
\245\ ACE-NY Initial Comments at 11; AES Initial Comments at 3;
Affected Interconnection Customers Initial Comments at 30; APPA-LPPC
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial
Comments at 7; Clean Energy Associations Initial Comments at 12;
Clean Energy Buyers Initial Comments at 6-7; Colorado Commission
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA
and NewSun Initial Comments at 44-45; Duke Southeast Utilities
Initial Comments at 6; Environmental Defense Fund Initial Comments
at 3; Environmental Defense Fund Reply Comments at 2-3; ELCON
Initial Comments at 4; ENGIE Initial Comments at 2; Evergreen Action
Initial Comments at 3; Fervo Energy Initial Comments at 2; Google
Initial Comments at 14; Google Reply Comments at 6; Illinois
Commission Initial Comments at 6; Interwest Initial Comments at 7;
New Jersey Commission Initial Comments at 11-12; Northwest and
Intermountain Initial Comments at 9-10; NY Commission and NYSERDA
Initial Comments at 8; [Oslash]rsted Initial Comments at 7; Pattern
Energy Initial Comments at 23; Pine Gate Initial Comments at 13;
Public Interest Organizations Initial Comments at 18-19; R Street
Initial Comments at 8, 10; Southern Initial Comments at 28; Tesla
Initial Comments at 6-7; Vistra Initial Comments at 1, 4.
\246\ Alliant Energy Initial Comments at 5; Clean Energy
Associations Initial Comments at 12; CREA and NewSun Initial
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6;
EEI Initial Comments at 12-13; ELCON Initial Comments at 6; ENGIE
Initial Comments at 2; Evergreen Action Initial Comments at 3; Fervo
Energy Initial Comments at 2-3; Illinois Commission Initial Comments
at 6; Indicated PJM TOs Initial Comments at 14; Indicated PJM TOs
Reply Comments 6; ISO-NE Initial Comments at 26-27; New Jersey
Commission Initial Comments at 12; NY Commission and NYSERDA Initial
Comments at 8; Ohio Commission Consumer Advocate Initial Comments at
7; Pacific Northwest Utilities Initial Comments at 13; SEIA Initial
Comments at 5.
\247\ CESA Initial Comments at 9; CESA Reply Comments at 3;
Consumers Energy Initial Comments at 3; CREA and NewSun Initial
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6;
Environmental Defense Fund Initial Comments at 3; EEI Initial
Comments at 12-13; ELCON Initial Comments at 6; Evergreen Action
Initial Comments at 3; Google Initial Comments at 14; Illinois
Commission Initial Comments at 6-7; New Jersey Commission Initial
Comments at 12; NY Commission and NYSERDA Initial Comments at 8;
Pacific Northwest Utilities Initial Comments at 13; SEIA Initial
Comments at 5.
\248\ Evergreen Action Initial Comments at 3; New Jersey
Commission Initial Comments at 12.
\249\ Alliant Energy Initial Comments at 5; Clean Energy
Associations Initial Comments at 12.
\250\ R Street Initial Comments at 10.
\251\ R Street Reply Comments at 2.
\252\ Ohio Commission Consumer Advocate Initial Comments at 7.
\253\ Google Initial Comments at 4.
\254\ Google Reply Comments at 7.
\255\ SEIA Reply Comments at 5.
\256\ Illinois Commission Initial Comments at 6.
---------------------------------------------------------------------------
97. Some commenters contend that the proposal to provide public
interconnection information is not overly burdensome.\257\ APPA-LPPC
members report that the information posting and interactive capability
described in the NOPR could be feasibly implemented with available
industry system simulation tools.\258\ Clean Energy Associations state
that heatmaps should be as automated as possible, without significant
commitments of staff or resources.\259\
---------------------------------------------------------------------------
\257\ APPA-LPPC Initial Comments at 16; Clean Energy
Associations Initial Comments at 12-13; Google Initial Comments at
14; New York State Department Initial Comments at 8; Pennsylvania
Commission Initial Comments at 13; SEIA Initial Comments at 6.
\258\ APPA-LPPC Initial Comments at 16.
\259\ Clean Energy Associations Initial Comments at 13.
---------------------------------------------------------------------------
98. Several commenters point to the fact that some transmission
providers are already developing such tools as evidence that these
tools are unlikely to cause further delays to stressed interconnection
queues or additional burden on transmission providers.\260\ For
instance, some commenters note that MISO already offers a heatmap that
represents geographically advantageous siting locations.\261\ Several
commenters also note that PJM is developing such a tool.\262\ PJM
states that in 2023 its queue scope tool will provide a congestion map
with colors or symbols indicating the worst flowgate loading at each
point of interconnection.\263\ SPP states that it is also developing a
tool to be implemented by 2025 that would provide much of the
functionality described in the Commission's public information proposal
to new interconnections.\264\
---------------------------------------------------------------------------
\260\ Id. at 12; Environmental Defense Fund Reply Comments at 3;
ENGIE Initial Comments at 2-3; Pennsylvania Commission Initial
Comments at 13.
\261\ CESA Reply Comments at 5; Fervo Energy Reply Comments at
3; OMS Initial Comments at 3, 6; R Street Initial Comments at 10;
SEIA Initial Comments at 6.
\262\ CESA Reply Comments at 4; Fervo Energy Reply Comments at
3; Indicated PJM TOs Initial Comments at 14; Ohio Commission
Consumer Advocate Initial Comments at 7; Pennsylvania Commission
Initial Comments at 13; PJM Initial Comments at 48; PPL Initial
Comments at 9; R Street Initial Comments at 10; SEIA Initial
Comments at 6.
\263\ PJM Initial Comments at 46-47.
\264\ SPP Initial Comments at 4.
---------------------------------------------------------------------------
99. Several commenters contend that the public information proposal
is a more reasonable balance of costs and benefits relative to the
informational interconnection study proposal.\265\ Pennsylvania
Commission states that, once a public information tool is established,
it may require fewer ongoing resources, continuing to inform
interconnection customers while freeing those resources for additional
interconnection studies as compared to the proposed informational
interconnection study.\266\
---------------------------------------------------------------------------
\265\ Ameren Initial Comments at 5; APPA-LPPC Initial Comments
at 16; APS Initial Comments at 5; Bonneville Initial Comments at 5;
Pennsylvania Commission Initial Comments at 13; PJM Initial Comments
at 45-48; R Street Initial Comments at 10.
\266\ Pennsylvania Commission Initial Comments at 13.
---------------------------------------------------------------------------
(b) Comments in Opposition
100. A few commenters oppose the NOPR proposal to require
transmission providers to provide public interconnection
information.\267\ A larger number of commenters express reservations
about the proposal,\268\ in particular regarding its usefulness \269\
or the burden it creates.\270\ Other commenters request that the
Commission make public interconnection information posting
optional.\271\
---------------------------------------------------------------------------
\267\ Avangrid Reply Comments at 4; El Paso Electric Initial
Comments at 8; PG&E Initial Comments at 9.
\268\ AEP Initial Comments at 13; Idaho Power Initial Comments
at 3; NextEra Initial Comments at 12-13; Omaha Public Power Initial
Comments at 4; PacifiCorp Initial Comments at 13-14; SPP Initial
Comments at 4; Tri-State Initial Comments at 4; WAPA Initial
Comments at 7-8.
\269\ AEP Initial Comments at 13; Idaho Power Initial Comments
at 3; ISO-NE Initial Comments at 17; Longroad Energy Reply Comments
at 7; Omaha Public Power Initial Comments at 4; PacifiCorp Initial
Comments at 13-14; SPP Initial Comments at 4; WAPA Initial Comments
at 7-8.
\270\ AECI Initial Comments at 5; Dominion Initial Comments at
12; National Grid Initial Comments at 7; NextEra Initial Comments at
12-13; Omaha Public Power Initial Comments at 4; PacifiCorp Initial
Comments at 13-14; SPP Initial Comments at 4.
\271\ AEP Initial Comments at 13; Avangrid Initial Comments at
21-22; SPP Initial Comments at 4.
---------------------------------------------------------------------------
101. Several commenters argue that the proposal to require
transmission providers to provide public interconnection information is
not useful,\272\ particularly because it might not provide sufficient
detail \273\ or commercially actionable information for interconnection
customers.\274\ Commenters explain that heatmaps are specific to a
moment in time and thus not representative of actual available
injection across the transmission system, which is ever-changing.\275\
NextEra observes that heatmaps do not contain actionable information
for interconnection and instead focus on energy prices and
congestion.\276\ ISO-NE, MISO, and Omaha Public Power note that a
visual representation of interconnection capacity cannot account for
all of the conditions identified in a system impact study, including
different system stresses, operability issues (e.g., N-1-1), stability
and voltage issues, and weak transmission system issues.\277\
[[Page 61034]]
Longroad Energy asserts that generator interconnection heatmaps or
hosting capacity maps can be of some use for interconnections to the
distribution system but are unlikely to be beneficial for projects
interconnecting at transmission voltages.\278\
---------------------------------------------------------------------------
\272\ Dominion Initial Comments at 13; Idaho Power Initial
Comments at 3; ISO-NE Initial Comments at 17; NextEra Initial
Comments at 12; New York State Department Initial Comments at 8;
NYISO Initial Comments at 17; Omaha Public Power Initial Comments at
4; PacifiCorp Initial Comments at 14.
\273\ AECI Initial Comments at 5; Dominion Initial Comments at
13; Longroad Energy Reply Comments at 7; National Grid Initial
Comments at 8; New York State Department Initial Comments at 8;
Omaha Public Power Initial Comments at 4.
\274\ AEE Initial Comments at 9; Cypress Creek Initial Comments
at 13; NextEra Initial Comments at 12.
\275\ AECI Initial Comments at 5; AEP Initial Comments at 13;
New York State Department Initial Comments at 8; NYISO Initial
Comments at 17.
\276\ NextEra Initial Comments at 12.
\277\ ISO-NE Initial Comments at 17; MISO Initial Comments at 26
(citing NOPR, 179 FERC ] 61,194 at P 50 & n.105); Omaha Public Power
Initial Comments at 4.
\278\ Longroad Energy Reply Comments at 7.
---------------------------------------------------------------------------
102. Some commenters do not believe that the heatmap proposal will
appreciably reduce speculative interconnection requests.\279\ MISO
explains that, in its experience, few interconnection customers use its
interconnection heatmap tool and instead tend to use their own
tools.\280\ Puget Sound states that, even with a heatmap, if an
interconnection customer has a request that would require energy
transfer across balancing authorities, it would have to submit an
interconnection request to get information on the scope of necessary
network upgrades.\281\ NV Energy asserts that a heatmap of its
transmission system would be of little value, appearing as though there
is no available transfer capacity, because the generation in its
interconnection queue is more than five times the level of NV Energy
load.\282\ Meanwhile, Puget Sound states that a heatmap of its
territory would only account for generation and interconnection
capacity in its balancing authority footprint even though its
transmission goes beyond this footprint.\283\
---------------------------------------------------------------------------
\279\ Idaho Power Initial Comments at 3; PPL Initial Comments at
9.
\280\ MISO Initial Comments at 25-26.
\281\ Puget Sound Initial Comments at 6.
\282\ NV Energy Initial Comments at 10.
\283\ Puget Sound Initial Comments at 6.
---------------------------------------------------------------------------
103. Several commenters contend that a heatmap tool as proposed
would be less useful in a cluster study than it is in a serial process
because it cannot include similarly queued generation.\284\ Ohio
Commission Consumer Advocate questions whether it will capture the
``dynamic elements'' of cluster studies and restudies.\285\ PacifiCorp
and AEP state that the mere fact that an area is not shown as congested
on a heatmap does not mean that it will be a suitable interconnection
location, particularly if multiple interconnection customers seek to
interconnect there.\286\
---------------------------------------------------------------------------
\284\ CAISO Initial Comments at 8; CREA and NewSun Initial
Comments at 48; Duke Southeast Utilities Initial Comments at 6-7;
MISO Initial Comments at 26; Ohio Commission Consumer Advocate
Initial Comments at 7; PacifiCorp Initial Comments at 15.
\285\ Ohio Commission Consumer Advocate Initial Comments at 7.
\286\ AEP Initial Comments at 13; PacifiCorp Initial Comments at
15.
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104. Longroad Energy and PacifiCorp express concern that the
heatmap tools would not be restricted to prospective interconnection
customers and could instead be used by third-party consultants for
their own business interests; for instance, real estate speculators
could use the information to secure exclusive site control for
locations that show significant generator interconnection
capacity.\287\ According to Longroad Energy, such risk is particularly
harmful to wind and solar generation interconnection customers' needs
for large tracts of land to accommodate their generation
equipment.\288\
---------------------------------------------------------------------------
\287\ Longroad Energy Reply Comments at 7; PacifiCorp Initial
Comments at 15.
\288\ Longroad Energy Reply Comments at 7.
---------------------------------------------------------------------------
105. Some commenters assert that maintaining the heatmap and
posting required information on available interconnection capacity
would be burdensome for transmission providers, especially in non-RTO/
ISO regions.\289\ Similarly, NV Energy states that it participates in
the CAISO energy imbalance market and its energy management system does
not currently have the technical functionality to build an interactive
map that shows information like the available interconnection
capacity.\290\ Some commenters argue that the heatmaps may provide
insufficient benefit to justify cost, resources, and time it would take
to produce them.\291\ Omaha Public Power further asserts that
interconnection customers will likely find it more valuable for a
transmission provider invest in more reliable and consequential
studies.\292\ Pacific Northwest Utilities assert that the Commission
should present additional data regarding the benefits of requiring a
heatmap before mandating their use.\293\ Clean Energy Associations
recommend that the Commission consider other means of increasing
information to prospective interconnection customers, such as public
scoping meetings prior to the prospective interconnection customers
entering the interconnection queue.\294\
---------------------------------------------------------------------------
\289\ National Grid Initial Comments at 7-8; PacifiCorp Initial
Comments at 13; Tri-State Initial Comments at 7.
\290\ NV Energy Initial Comments at 10.
\291\ Dominion Initial Comments at 13; National Grid Initial
Comments at 8; NextEra Initial Comments at 12; New York State
Department Initial Comments at 8; Omaha Public Power Initial
Comments at 4; Pacific Northwest Utilities Initial Comments at 14;
PPL Initial Comments at 9; Tri-State Initial Comments at 4; WAPA
Initial Comments at 7.
\292\ Omaha Public Power Initial Comments at 4.
\293\ Pacific Northwest Utilities Initial Comments at 14.
\294\ Clean Energy Associations Initial Comments at 14.
---------------------------------------------------------------------------
106. Some commenters express concern that the public information
proposal will impose new costs on ratepayers and market
participants.\295\ WAPA states that, given its defined appropriations
and budgets, it is difficult to create new programs, unlike for larger
investor-owned utilities or RTOs/ISOs.\296\ Dominion estimates that
implementation would require a large up-front financial commitment,
potentially for third-party software and personnel hours, and longer-
term financial commitment to maintain such a site.\297\ NV Energy
contends that creating such a heatmap showing interconnection
capabilities would require finding an eligible software, an ongoing
expense.\298\
---------------------------------------------------------------------------
\295\ New York State Department Initial Comments at 8; SoCal
Edison Initial Comments at 13.
\296\ WAPA Initial Comments at 7.
\297\ Dominion Initial Comments at 12.
\298\ NV Energy Initial Comments at 10.
---------------------------------------------------------------------------
107. Several commenters speak to the burden of additional staffing
needs to provide public interconnection information. National Grid
states that the interactive visual representation tool, even if
contracted from a third party, would require significant time
commitments from numerous personnel with relevant and advanced
expertise in transmission and interconnection engineering.\299\ Tri-
State notes that the Commission has recognized the lack of available
engineers and that imposing a heatmap requirement would exacerbate the
problem.\300\ Dominion and Duke Southeast Utilities state that any
additional process would require additional financial and personnel
resources, and also burden the same personnel that are already engaged
in managing the interconnection queue.\301\ El Paso Electric argues
that transmission providers should not be required to allocate human
resources from interconnection studies to monthly transmission line
capacity estimates because the staff reallocation could cause
interconnection study backlogs.\302\ PacifiCorp states that this burden
will be particularly onerous to transmission providers outside RTO/ISO
regions, which have comparatively few transmission staff
available.\303\
---------------------------------------------------------------------------
\299\ National Grid Initial Comments at 7-8.
\300\ Tri-State Initial Comments at 8.
\301\ Dominion Initial Comments at 13; Duke Southeast Utilities
Initial Comments at 7.
\302\ El Paso Electric Initial Comments at 7.
\303\ PacifiCorp Initial Comments at 13.
---------------------------------------------------------------------------
108. Several commenters suggest that interconnection customers, on
their own or with consultants, can perform studies with the available
information that would provide estimates on available capacity similar
to that produced under
[[Page 61035]]
the NOPR proposal.\304\ PPL states that interconnection customers can
make their own such maps using transmission planning models the
Commission makes available following a Freedom of Information Act
request.\305\ APPA-LPPC argue that the Commission fails to establish
that the information already available to prospective interconnection
customers under the existing pro forma LGIP, along with the substantial
supplement implemented with Order No. 845, is inadequate.\306\ SoCal
Edison states that the information included in the NOPR proposal and
more is already available if interconnection customers request it from
the Commission for their own studies or use studies developed by
transmission providers.\307\ The Ohio Commission Consumer Advocate
states that the determination of a suitable site depends largely on the
location and geography of the resources, which is publicly available
from national labs and the U.S. Energy Information Administration.\308\
---------------------------------------------------------------------------
\304\ Id. at 15; AEP Initial Comments at 8; APPA-LPPC Initial
Comments at 9; El Paso Electric Initial Comments at 7; PPL Initial
Comments at 9; SoCal Edison Initial Comments at 14.
\305\ PPL Initial Comments at 9.
\306\ APPA-LPPC Initial Comments at 9.
\307\ SoCal Edison Initial Comments at 14.
\308\ Ohio Commission Consumer Advocate Initial Comments at 6-7.
---------------------------------------------------------------------------
109. Several commenters state that sufficient data are already
required to be posted on OASIS.\309\ According to Idaho Power, Order
No. 2003-A required interconnection study reports to be publicly
available and provide locational and cost information for previously
studied interconnections, but this has not reduced the amount of
interconnection requests at congested locations.\310\ SoCal Edison and
NYISO state that this information is already available in FERC Form
715, where it is protected with a non-disclosure agreement as critical
energy infrastructure information (CEII) and has the benefit of being
available in one centralized location.\311\ On the other hand, ACE-NY
disagrees with the assertion that FERC Form 715 provides sufficient
information for interconnection customers to do their own analysis,
asserting that the FERC Form 715 database base cases do not contain
sufficient data about the generation interconnection queue and study
assumptions and are therefore inadequate.\312\ Rather, ACE-NY argues
that more detailed base cases such as those currently being made
available by MISO and PJM, should be required.
---------------------------------------------------------------------------
\309\ Duke Southeast Utilities Initial Comments at 6-7; Idaho
Power Initial Comments at 3; NV Energy Initial Comments at 10;
PacifiCorp Initial Comments at 14-15.
\310\ Idaho Power Initial Comments at 3.
\311\ NYISO Initial Comments at 17; SoCal Edison Initial
Comments at 14.
\312\ ACE-NY Reply Comments at 3-4.
---------------------------------------------------------------------------
110. Several commenters state that the usefulness of public
interconnection information proposal will depend on the implementation
details.\313\ For example, Illinois Commission and CESA recognize that
the accuracy of the heatmaps is an important part of how useful they
will be.\314\ Puget Sound states that it has considered creating such a
heatmap but has concerns about its effectiveness given implementation
challenges.\315\ SPP states that technology, information, and tools are
quickly evolving and that a standardization tool might be obsolete
before it is implemented.\316\ CESA explains that currently CAISO
provides static, snapshot-in-time transmission capability estimates
that are helpful but do not capture locational granularity or other
projects already in the interconnection queue, making it difficult to
make an informed project siting decision and at times requiring data
requests of CAISO.\317\ For this reason, CESA stresses that the
heatmaps and associated data must be made available in a user-friendly
format. CREA and NewSun argue that the Commission should be careful not
to overestimate the ability to forecast interconnection costs and
project viability that will ultimately result from a cluster
study.\318\ Several commenters stress that any potential increase in
transparency and interconnection process performance resulting from
this proposal must outweigh the additional burden imposed on
transmission providers.\319\
---------------------------------------------------------------------------
\313\ CESA Initial Comments at 8-9; Illinois Commission Initial
Comments at 6; Puget Sound Initial Comments at 6; SPP Initial
Comments at 4.
\314\ CESA Initial Comments at 9; Illinois Commission Initial
Comments at 6.
\315\ Puget Sound Initial Comments at 6.
\316\ SPP Initial Comments at 4.
\317\ CESA Initial Comments at 8.
\318\ CREA and NewSun Initial Comments at 48.
\319\ Cypress Creek Initial Comments at 14; EEI Initial Comments
at 12-13; Eversource Initial Comments at 11; New Jersey Commission
Initial Comments at 22-23; New York State Department Initial
Comments at 8-9.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
(1) Metrics
111. While some commenters agree with the Commission's proposed
table of metrics,\320\ multiple commenters suggest additional metrics
that should be posted.\321\ For instance, Public Interest Organizations
request information on the available interconnection capacity
(including, at a minimum, a snapshot of existing available
interconnection capacity and associated transmission during high load
conditions for each substation) including projects already in the
interconnection queue, and the capacity those projects are
requesting,\322\ as well as metrics on whether power flows from a point
of interconnection are likely to serve low income and people of color
communities (which would be consistent with Executive Order
13985).\323\ Other commenters suggest that the posted metrics should
also include: circuit strength and the harmonics of transmission system
elements; \324\ limiting elements at a substation or associated
transmission infrastructure; \325\ the level of congestion and resource
curtailment by location (historic, current, and/or expected); \326\
overload conditions; \327\ contingencies that drive the impacts to the
monitored facility; \328\ for a given transmission line, information on
the circuit (e.g., single or double), the conductor type, pole types,
the ratings of the equipment, and the age of the equipment; \329\
flowgate data, such as disconnect switches, breakers, transformers,
conductors, series reactors, and ground clearances of lines; \330\
change file models of network upgrades for deliverability in advance of
providing study results; \331\ base case models paired with
contingencies including local contingencies (below
[[Page 61036]]
200 kV); \332\ incremental injection capacity available at each bus in
the transmission provider's footprint under N-1 conditions with a five-
year outlook; \333\ the rating of the monitored facility; \334\
estimated costs of interconnection or transmission service, including
where interconnection is likely to be costly and not costly; \335\
proposed upgrades in the region that could affect interconnection
requests; \336\ lists of potential upgrades that would be needed to
export power to other regions or that would allow the transmission
provider to increase injection capacity at each substation; \337\ more
granular load growth data, defined by region, which could be combined
with existing and planned generation and congestion to view anticipated
system changes; \338\ and the share that all generating facilities
contribute to a network upgrade along with their share of allocated
costs.\339\ Tesla requests information that would particularly
developers of non-synchronous generating facilities to decide what
project controls might be best suited for a given point of
interconnection, including: the number of generating facilities and
power control devices (including series compensation systems, static
synchronous compensator devices and other power control devices) that
are two busses away from the given point of interconnection; the
circuit breaker short circuit ratings of the nearest substation; and
the maximum and minimum fault current in megavolt amperes (MVA) at the
given point of interconnection.\340\
---------------------------------------------------------------------------
\320\ NOPR, 179 FERC ] 61,194 at P 51.
\321\ Ameren Initial Comments at 5; Bonneville Initial Comments
at 7; Clean Energy Buyers Initial Comments at 7-8; MISO Initial
Comments at 25 (agreeing that the five data points are sufficient
but adding that, if the first is provided, then prospective
interconnection customers can calculate the other four).
\322\ Public Interest Organizations Initial Comments at 19-20.
\323\ Public Interest Organizations Reply Comments at 11-12
(citing 16 U.S.C. 824(a); Nat'l Ass'n for Advancement of Colored
People v. FPC, 425 U.S. 662, 669-670 (1976); Executive Order 13985,
``Executive Order on Advancing Racial Equity and Support for
Underserved Communities Through the Federal Government'' (Jan. 20,
2021)); see also Navajo Utility Initial Comments at 9.
\324\ SEIA Initial Comments at 6.
\325\ AES Initial Comments at 5-7; Hannon Armstrong Initial
Comments at 2; Pattern Energy Initial Comments at 23; Public
Interest Organizations Initial Comments at 19.
\326\ AEP Initial Comments at 13; Clean Energy Associations
Initial Comments at 12; Pine Gate Initial Comments at 14.
\327\ Ameren Initial Comments at 6; R Street Initial Comments at
10.
\328\ Pattern Energy Initial Comments at 23.
\329\ NextEra Initial Comments at 11.
\330\ AES Initial Comments at 6; Pattern Energy Initial Comments
at 23; Pine Gate Initial Comments at 14; SEIA Reply Comments at 4.
\331\ AES Initial Comments at 5; Pine Gate Initial Comments at
14; SEIA Reply Comments at 5.
\332\ AES Initial Comments at 5; SEIA Reply Comments at 5.
\333\ AES Initial Comments at 5; SEIA Reply Comments at 5.
\334\ Pattern Energy Group Initial Comments at 23; SEIA Reply
Comments at 5.
\335\ Bonneville Initial Comments at 5; Eversource Initial
Comments at 11.
\336\ [Oslash]rsted Initial Comments at 7; Pattern Energy
Initial Comments at 23; Public Interest Organizations Initial
Comments at 19; SEIA Reply Comments at 5.
\337\ Clean Energy Associations Initial Comments at 13; Public
Interest Organizations Initial Comments at 20-21.
\338\ Google Initial Comments at 6, 14.
\339\ AES Initial Comments at 5-7, 13-14.
\340\ Tesla Initial Comments at 7.
---------------------------------------------------------------------------
112. Several commenters highlight that additional information
regarding transmission system conditions, such as previous cluster
studies and models, posted in a secure way subject to CEII processes,
would allow interconnection customers to conduct their own initial
analyses of system conditions and desirable points of
interconnection.\341\ SoCal Edison states that, alternatively, the
transmission providers could identify areas where new generation is
desired, guided by state processes identifying the locations that can
accommodate additional generation currently or locations intended for
types of generation sought state policy.\342\
---------------------------------------------------------------------------
\341\ ACE-NY Initial Comments at 11; AES Initial Comments at 5;
Clean Energy States Alliance Initial Comments at 4; CREA and NewSun
Initial Comments at 47; ENGIE Initial Comments at 3; NextEra Reply
Comments at 9; PJM Initial Comments at 7; PPL Initial Comments at 9;
SEIA Reply Comments at 4.
\342\ SoCal Edison Initial Comments at 14-15.
---------------------------------------------------------------------------
113. Some commenters oppose these requests for additional metrics.
Dominion notes that tracking and providing the information requested by
Public Interest Organizations, including documenting the study process,
providing enhanced interconnection queue tracking, and metrics on
constraints that cause bottlenecks, would be burdensome, taking
engineers' time, slowing down the cluster study process, and diverting
resources.\343\ EEI and WIRES contend that certain information on
transmission line design, such as circuit type, conductor type, and
pole type, would be overly burdensome and offer little benefit, adding
that this information could invite potential disputes or be used to
threaten to the reliability of the transmission system or for
commercial gain if the information is not subject to confidentiality
protections.\344\ EEI also asserts that any additional information
beyond that proposed in the NOPR would complicate the interconnection
process by adding another potential area of dispute and risks potential
``backseat driving'' by the interconnection customer, while the
transmission provider is responsible for performing and standing by its
study results.\345\
---------------------------------------------------------------------------
\343\ Dominion Reply Comments at 8.
\344\ EEI Reply Comments at 9-10; WIRES Reply Comments at 5-6.
\345\ EEI Reply Comments at 9-10.
---------------------------------------------------------------------------
114. Some commenters disagree as to the appropriate level of
granularity of the required metrics. SEIA and ENGIE support the NOPR
proposal to require transmission providers to post bus-level
interconnection capacity constraints.\346\ Dominion disagrees, arguing
that requiring capacity constraint information to be provided at the
bus-level is outside the scope of the NOPR and would not necessarily be
useful in a networked system where injection at one bus will affect the
capability at other buses and significant additional power flow
analysis would be required to determine these values at each bus.\347\
According to Dominion, information about bus-level interconnection
capacity constraints makes more sense where the system is radial in
nature and injection capability at one bus is not dependent on
contingencies or injections at another bus. Eversource adds that bus
level information will not provide significant benefits because it may
be too simplistic if it is not based on N-1 conditions or if it fails
to incorporate stability considerations.\348\ Public Interest
Organizations state that many utilities provide hosting capacity
information on their websites at the distribution level in heatmaps or
tables, in particular to help distributed solar interconnection
customers, and this information is required by states and updated
regularly.\349\ Public Interest Organizations ask the Commission to
require analogous hosting capacity information to be provided by
transmission providers for all potential generation locations with
exemptions for urban substations where there is limited potential for
generation development. PJM requests that, rather than requiring that
all buses be made available in a large RTO/ISO, a transmission provider
should be allowed to screen and only present the majority of the
feasible points of interconnection.\350\ As an alternative to providing
information at every bus, Tri-State states that a transmission provider
could post the most recent cluster study to provide information for the
buses that were studied as opposed to studying all buses on the system,
while also making clear that the heatmap does not reflect
interconnection requests in neighboring systems.\351\ Similarly,
Bonneville argues that cluster studies would not provide the
incremental injection capacity at each bus on the transmission
provider's system, which would warrant a separate study, and therefore,
transmission providers should be afforded flexibility to provide this
capacity information as it becomes available.\352\
---------------------------------------------------------------------------
\346\ ENGIE Initial Comments at 2-3; SEIA Initial Comments at 5.
\347\ Dominion Reply Comments at 8-9.
\348\ Eversource Initial Comments at 11.
\349\ Public Interest Organizations Initial Comments at 20
(citing National Renewable Energy Laboratory, Advanced Hosting
Capacity Analysis, https://www.nrel.gov/solar/market-research-analysis/advanced-hosting-capacity-analysis.html).
\350\ PJM Initial Comments at 48-49.
\351\ Tri-State Initial Comments at 8.
\352\ Bonneville Initial Comments at 6-7.
---------------------------------------------------------------------------
115. Some commenters argue that the proposed heatmap is not an
ideal way to present public interconnection information. For instance,
Illinois Commission states that it is not immediately evident what
information maps posted to an RTO/ISO website would reflect.\353\ For
example, Illinois Commission questions whether
[[Page 61037]]
congestion maps would reflect present congestion or congestion that
might arise after generating facilities interconnect. Fervo Energy
states that additional research might be needed to determine the most
useful informational suite.\354\ Clean Energy Associations proposes,
and SEIA supports, that two maps, one for Energy Resource
Interconnection Service (ERIS) and one for capacity or NRIS, should be
made available where appropriate, and notes that in ISO-NE overlapping
impact analysis is used to determine eligibility for capacity
NRIS.\355\ Finally, Clean Energy Associations and ISO-NE recommend that
the Commission consider allowing information to be qualitative, such
that, rather than a ``hosting map,'' transmission providers could post
a map and accompanying report regarding system conditions at various
points on the transmission system.\356\
---------------------------------------------------------------------------
\353\ Illinois Commission Initial Comments at 6.
\354\ Fervo Energy Reply Comments at 3.
\355\ Clean Energy Associations Initial Comments at 12; SEIA
Reply Comments at 5.
\356\ Clean Energy Associations Reply Comments at 3; ISO-NE
Initial Comments at 17.
---------------------------------------------------------------------------
(2) Security of Critical Information
116. Several commenters express concern that the NOPR's proposed
heatmap and/or metrics may create a security risk \357\ by, among other
things, indicating areas where transmission is heavily loaded and more
vulnerable to interference.\358\ In particular, LADWP and Bonneville
express concerns over sharing distribution factor and MW impact, which
they believe could identify highly stressed transmission lines, as well
as concerns with identifying the line locations, which are not
currently provided publicly.\359\ LADWP further expresses concern with
CEII issues that may arise from publicly releasing a table of metrics
regarding the estimated impact of a potential generating facility.\360\
---------------------------------------------------------------------------
\357\ EEI Reply Comments at 9-10; Indicated PJM TOs Initial
Comments at 15; LADWP Initial Comments at 3; NRECA Initial Comments
at 16-17; PacifiCorp Initial Comments at 16; PPL Initial Comments at
8; SoCal Edison Initial Comments at 13-14; WIRES Reply Comments at
5-6.
\358\ LADWP Initial Comments at 3; PacifiCorp Initial Comments
at 16; PPL Initial Comments at 8.
\359\ Bonneville Initial Comments at 6; LADWP Initial Comments
at 3.
\360\ LADWP Initial Comments at 3.
---------------------------------------------------------------------------
117. Other commenters counter that the security risks associated
with the NOPR proposal are reasonable or non-existent. For example,
Pacific Northwest Utilities and Puget Sound states that the purpose of
the heatmap is to provide an overview of interconnection capacity,
which is unlikely to implicate CEII, and thus the risk of unrestricted
critical infrastructure information should be low.\361\ Indicated PJM
TOs and PPL state that a visual map with limited information, excluding
reliability constraints or other particular information that could be
used to identify vulnerabilities, could be made public without security
concerns and highlight PJM as a good example of this.\362\ Xcel states
that it does not have security concerns about posting estimated
injection capacity but that some of the more detailed information
should be limited.\363\ MISO states that it is currently unaware of any
security concerns associated with the proposal.\364\
---------------------------------------------------------------------------
\361\ Pacific Northwest Utilities Initial Comments at 15; Puget
Sound Initial Comments at 6-7.
\362\ Indicated PJM TOs Initial Comments at 14-15; PPL Initial
Comments at 8-9.
\363\ Xcel Initial Comments at 22.
\364\ MISO Initial Comments at 27.
---------------------------------------------------------------------------
118. While SoCal Edison and Southern assert that there should be no
requirement on transmission providers to make public or display any
CEII or confidential information,\365\ other commenters contend that
the CEII label should not be used to unreasonably impede
interconnection customers' access to interconnection information
necessary to understand the cost and other impacts of locating their
projects in different areas of the transmission system.\366\ Some
commenters recommend that the Commission require transmission providers
to make CEII data available only to interconnection customers who meet
restricted access requirements, such as through a secure portal or
subject to a confidentiality agreement.\367\ Pattern Energy asks that
this information be made available through a cost-free process that
takes no longer than two weeks,\368\ and Pine Gate adds that the
retrieval of this information should not require background checks, as
required by certain transmission providers.\369\ EEI suggests that
transmission providers should have the discretion to identify sensitive
information that should be withheld.\370\ Clean Energy States add that
the Commission may want to limit access to permitted users, controlling
the copying and dissemination of data, or take other security
measures.\371\
---------------------------------------------------------------------------
\365\ SoCal Edison Initial Comments at 14; Southern Initial
Comments 28.
\366\ CESA Reply Comments at 4; Google Reply Comments at 7;
Pattern Energy Initial Comments at 24.
\367\ Google Reply Comments at 7; Indicated PJM TOs Initial
Comments at 15; ISO-NE Initial Comments at 17; NRECA Initial
Comments at 16; Pattern Energy Initial Comments at 24; SEIA Initial
Comments at 6; SEIA Reply Comments at 5.
\368\ Pattern Energy Initial Comments at 24.
\369\ Pine Gate Initial Comments at 14.
\370\ EEI Initial Comments at 13.
\371\ Clean Energy States Initial Comments at 5.
---------------------------------------------------------------------------
(3) Miscellaneous
119. SEIA requests that the Commission require transmission
providers to use the most recent available study models as well as the
most recently completed system impact study in creating their data
results.\372\
---------------------------------------------------------------------------
\372\ SEIA Initial Comments at 6.
---------------------------------------------------------------------------
120. A few commenters express concern with the proposal to require
updated information 30 days after the completion of each cluster study
and restudy and instead request that the Commission allow for regional
flexibility on the timing of updates.\373\ MISO states that, as
written, the NOPR proposal would require it to update the tool
available to help interconnection customers pre-screen for potential
points of interconnection each time a regional system impact study is
issued, which would be numerous times during a calendar year due to the
configuration of MISO's transmission system.\374\ PJM states that it is
not feasible for an RTO/ISO as large as PJM to update an interactive
public interconnection information tool within 30 days after completing
a cluster restudy.\375\ PJM states that, once the tool includes light
load results, it will be uploading four to six datasets a year with
each dataset including millions of points of interconnection flowgate
records, which may eventually not be feasible to maintain from a
storage perspective. According to El Paso Electric, the interconnection
queue changes often as interconnection customers withdraw their
requests and therefore transmission providers should not be required to
update capacity line estimates monthly because the burden on staff
could increase interconnection study delays.\376\ Tri-State explains
that only a subset of buses and lines are studied in each cluster
study, so to require an estimate of the injection capacity at every bus
in each cluster study to be posted within 30 days would greatly
increase the scope and cost and would likely have a negative impact on
the time to complete the study and cause rates to increase.\377\
---------------------------------------------------------------------------
\373\ Bonneville Initial Comments at 8; El Paso Electric Initial
Comments at 7; MISO Initial Comments at 26; Pacific Northwest
Utilities Initial Comments at 14; PJM Initial Comments at 49; Tri-
State Initial Comments at 7.
\374\ MISO Initial Comments at 26-27.
\375\ PJM Initial Comments at 49.
\376\ El Paso Electric Initial Comments at 7.
\377\ Tri-State Initial Comments at 7.
---------------------------------------------------------------------------
121. On the other hand, [Oslash]rsted notes that any system
representation needs to
[[Page 61038]]
be frequently updated to be useful and avoid the risk of becoming out-
of-date,\378\ and Public Interest Organizations state that hosting
capacity data should be updated at least quarterly.\379\ Environmental
Defense Fund argues that the public interconnection information should
be updated immediately at the end of each cluster request window so
that interconnection customers using that information are informed of
generating facilities being studied that may impact transmission
capacity.\380\
---------------------------------------------------------------------------
\378\ [Oslash]rsted Initial Comments at 6.
\379\ Public Interest Organizations Initial Comments at 20.
\380\ Environmental Defense Fund Initial Comments at 3.
---------------------------------------------------------------------------
(4) Requests for Flexibility
122. Several commenters request flexibility from the Commission
with respect to the particular information included in a potential
heatmap.\381\ Dominion asserts that the proposal is overly prescriptive
and that the Commission should focus on the goal itself rather than
uniformity.\382\ Clean Energy Associations state that the heatmaps may
need to be tailored to the services offered by a particular
transmission provider, because their services are not uniform.\383\
Several commenters claim that flexibility will help ensure that the
information provided is useful and understandable, and will place a
reasonable level of burden on transmission providers.\384\ MISO states
that flexibility is reasonable given the burden on transmission
providers of maintaining a heatmap tool relative to the limited value
of frequent updates given that few interconnection customers use this
tool and its inability to include future queued projects that will be
relevant to the prospective interconnection customer.\385\ Bonneville
also argues that flexibility is needed to ensure consistency with
security requirements.\386\ On the other hand, Cypress Creek asserts
that, as a broad consideration, the particular types of information to
be made transparent that are valuable should be determined by the
Commission in consultation with market participants who are best
positioned to identify information relevant to financing and
constructing new projects.\387\
---------------------------------------------------------------------------
\381\ Avangrid Initial Comments at 21-22; Bonneville Initial
Comments at 6-8; Dominion Initial Comments at 14; MISO Initial
Comments at 27; NY Commission and NYSERDA Initial Comments at 8;
NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial
Comments at 14; PJM Initial Comments at 48; Puget Sound Initial
Comments at 6; SEIA Initial Comments at 6; Southern Initial Comments
at 28; SPP Initial Comments at 4; WAPA Initial Comments at 7-8.
\382\ Dominion Initial Comments at 13.
\383\ Clean Energy Associations Initial Comments at 12.
\384\ Avangrid Initial Comments at 21-22; Bonneville Initial
Comments at 6-8; Cypress Creek Initial Comments at 14; MISO Initial
Comments at 27; NY Commission and NYSERDA Initial Comments at 7-8;
NYTOs Initial Comments at 8; Pacific Northwest Utilities Initial
Comments at 14; WAPA Initial Comments at 8.
\385\ MISO Initial Comments at 26-27.
\386\ Bonneville Initial Comments at 6.
\387\ Cypress Creek Initial Comments at 14.
---------------------------------------------------------------------------
123. Several commenters ask for flexibility in the way information
is shared. SEIA states that whether the data are in a map or other
format is not as important as the product itself.\388\ NYTOs expect
that flexibility would allow regions to adopt some form of the virtual
tool as long as it is clear that the information is illustrative, non-
binding, and subject to change.\389\ NRECA states that smaller
generation and transmission cooperatives may be able to just post a
table with bus names and injection capability and present the same
useful information in a more economical way.\390\ NV Energy states
that, if it were to post to its OASIS the CAISO locational marginal
price map with a link to CAISO's OASIS to provide a list of interchange
limits and interchange schedules, this would be just as valuable as a
map for its own transmission system.\391\
---------------------------------------------------------------------------
\388\ SEIA Initial Comments at 6.
\389\ NYTOs Initial Comments at 9.
\390\ NRECA Initial Comments at 16.
\391\ NV Energy Initial Comments at 10.
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124. Some commenters argue that transmission providers that already
provide public interconnection information should have flexibility to
use their existing systems to comply.\392\ However, Environmental
Defense Fund avers that this flexibility should not extend to
transmission providers who, prior to the NOPR, were without a
substantial public interconnection information system, because they
have no sunk costs related to public interconnection information
systems.\393\
---------------------------------------------------------------------------
\392\ Environmental Defense Fund Reply Comments at 4; OMS
Initial Comments at 6.
\393\ Environmental Defense Fund Reply Comments at 4.
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125. Several commenters express concern that heatmaps would be
technically difficult to implement outside of RTOs/ISOs and ask the
Commission to provide non-RTO/ISO regions with flexibility in how they
comply with the mapping tool.\394\ Tri-State states that, in non-RTO/
ISO regions, it is common for multiple transmission providers to use a
single substation, making injection capacity dependent on
interconnection requests in neighboring interconnection queues and
their associated study assumptions.\395\ Tri-State, therefore,
encourages the Commission to permit variations among heatmaps, adding
that entities in non-RTOs/ISOs should not be required to study every
bus.\396\
---------------------------------------------------------------------------
\394\ Dominion Initial Comments at 12-14; NRECA Initial Comments
at 16; NV Energy Initial Comments at 10; PPL Initial Comments at 9;
Puget Sound Initial Comments at 5-6; Tri-State Initial Comments at
8.
\395\ Tri-State Initial Comments at 8.
\396\ Id.; see also Eversource Initial Comments at 11.
---------------------------------------------------------------------------
126. Xcel recommends that the Commission consider applying the
requirement only in RTO/ISO regions or granting non-RTO/ISO
transmission providers sufficient time, such as two years, to
comply.\397\ WAPA asks the Commission to first require data
visualization by larger utilities, wait approximately 18 months after
implementation, and then measure the benefits of interactive tools
produced by larger utilities, giving stakeholders a chance to comment
before extending the heatmap requirement.\398\
---------------------------------------------------------------------------
\397\ Xcel Initial Comments at 22.
\398\ WAPA Initial Comments at 8.
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127. On the other hand, some commenters expressly argue that
uniformity should be required inside and outside of RTO/ISO
regions.\399\ Google states that such publicly available information
would begin to address the critical information advantage that
transmission owners have over independent power producers, particularly
in non-RTO/ISO regions.\400\ R Street notes that non-RTO/ISO regions
may have additional challenges in implementing such a tool but states
that this should not eliminate their requirement to do so and those
regions could be granted extra implementation time.\401\
---------------------------------------------------------------------------
\399\ Environmental Defense Fund Reply Comments at 3; Fervo
Energy Reply Comments at 3; Google Initial Comments at 6; R Street
Initial Comments at 10.
\400\ Google Reply Comments at 6.
\401\ R Street Initial Comments at 10.
---------------------------------------------------------------------------
(d) Requests for Clarification or Technical Conference
128. Several commenters seek clarification on the information
transmission providers are required to present in the heatmap, use of
that information, who has the responsibility of presenting the
information, timing of updating that information and recovery of costs
for providing this information. PJM asks that the Commission clarify
that an interactive visual congestion map could comply, instead of
requiring its specific form.\402\
---------------------------------------------------------------------------
\402\ PJM Initial Comments at 48.
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129. APPA-LPPC ask the Commission to clarify that it is not
proposing that
[[Page 61039]]
transmission providers be required to conduct any individualized
analyses or take any action in response to particular prospective
interconnection customers' use of the interactive tools.\403\
---------------------------------------------------------------------------
\403\ APPA-LPPC Initial Comments at 13-14.
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130. Some commenters request that the Commission make clear that
the public information is published only as a guide and not as a
binding or definitive statement of available interconnection capacity
or costs.\404\ Xcel asks the Commission to clarify that transmission
providers have no liability associated with the posting of public
information.\405\ EEI urges the Commission to make clear that
interconnection customers that rely exclusively on this information,
including these maps, do so at their own risk.\406\
---------------------------------------------------------------------------
\404\ AECI Initial Comments at 5; AEE Initial Comments at 9; AEP
Initial Comments at 13; Ameren Initial Comment at 6; CAISO Initial
Comments at 8; Duke Southeast Utilities Initial Comments at 6-7; EEI
Initial Comments at 12-13; National Grid Initial Comments at 8-9;
New York State Department Initial Comments at 8; NYISO Initial
Comments at 17; NYTOs Initial Comments at 9.
\405\ Xcel Initial Comments at 22.
\406\ EEI Initial Comments at 13.
---------------------------------------------------------------------------
131. Eversource asks that the Commission clarify that ``no
information would be required to be made available before the
conclusion of the first cluster study.'' \407\
---------------------------------------------------------------------------
\407\ Eversource Initial Comments at 11.
---------------------------------------------------------------------------
132. Dominion seeks clarification that, in an RTO/ISO context, the
proposed requirements to maintain a visual representation would apply
to the RTO/ISO, and not additionally to individual transmission
owners.\408\
---------------------------------------------------------------------------
\408\ Dominion Initial Comments at 14.
---------------------------------------------------------------------------
133. Several commenters request clarification on how the public
information proposal will be funded.\409\ Some commenters assert that a
user-pays model is the only appropriate funding mechanism because not
all interconnection customers will use the public information tools,
and the transmission provider or their customers should not be required
to pay for work that only benefits some.\410\ Tri-State asserts that it
might increase the $5,000 application fee to cover the significant
heatmap costs.\411\
---------------------------------------------------------------------------
\409\ National Grid Initial Comments at 8; PacifiCorp Initial
Comments at 14; Tri-State Initial Comments at 7-8.
\410\ National Grid Initial Comments at 8; PacifiCorp Initial
Comments at 14.
\411\ Tri-State Initial Comments at 8.
---------------------------------------------------------------------------
134. AEP, Tesla, and ACORE ask the Commission to initiate a
proceeding and hold a technical conference to, among other things,
identify useful information tools that could be feasibly developed,
establish uniform and transparent study assumptions, share best
practices, and help less sophisticated interconnection customers learn
to use available tools and information to lessen their own risk before
entering an interconnection queue.\412\
---------------------------------------------------------------------------
\412\ ACORE Reply Comments at 3, AEP Initial Comments at 13, 15;
Tesla Initial Comments at 6.
---------------------------------------------------------------------------
iii. Commission Determination
135. We adopt, without modification, the NOPR proposal to revise
pro forma LGIP section 6.4, now section 6.1, to require transmission
providers to publicly post available information pertaining to
generator interconnection (i.e., public interconnection information or
a heatmap). We require transmission providers to update the heatmap
within 30 calendar days after the completion of each cluster study and
cluster restudy. Such heatmaps must be calculated under N-1 conditions
and studied based on the power flow model of the transmission system
with the transfer simulated from each point of interconnection to the
whole transmission provider's footprint (to approximate NRIS), and with
the incremental capacity at each point of interconnection decremented
by the existing and queued generation at that location (based on the
existing or requested interconnection service limit of such
generation). We require transmission providers to provide the following
information as outputs at each point of interconnection: (1) the
distribution factor; (2) the MW impact (based on the proposed project
size and the distribution factor); (3) the percentage impact on each
impacted transmission facility (based on the MW values of the proposed
project and the facility rating); (4) the percentage of power flow on
each impacted transmission facility before the proposed project; and
(5) the percentage power flow on each impacted transmission facility
after the injection of the proposed project.
136. We find that the benefit of providing further transparency to
interconnection customers about potential points of interconnection
outweighs the added administrative burden to transmission providers.
Commenters generally support supplementing the existing publicly
available interconnection information and note their broad support for
the NOPR proposal.\413\ Many commenters further assert that the heatmap
will provide valuable information to interconnection customers before
they enter the interconnection queue,\414\ and as SEIA explains,
interconnection customers currently lack substantial information prior
to entering the interconnection queue, which is valuable in determining
whether to proceed with a proposed generating facility.\415\ In
particular, the information that we require transmission providers to
provide to prospective interconnection customers will allow such
interconnection customers to learn about available interconnection
capacity as well as other metrics that reflect the impact of the
addition of a proposed generating facility to the transmission
provider's transmission system at a particular point of
interconnection. Such information may allow a prospective
interconnection customer to estimate expected congestion,\416\ and, in
turn, to assess likely network upgrades triggered by a proposed
generating facility or the possibility of curtailment of a proposed
generating facility.
---------------------------------------------------------------------------
\413\ ACE-NY Initial Comments at 11; AES Initial Comments at 3;
Affected Interconnection Customers Initial Comments at 30; APPA-LPPC
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial
Comments at 7; Clean Energy Associations Initial Comments at 12;
Clean Energy Buyers Initial Comments at 6-7; Colorado Commission
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA
and NewSun Initial Comments at 44-45; Duke Southeast Utilities
Initial Comments at 6; Environmental Defense Fund Initial Comments
at 3; Environmental Defense Fund Reply Comments at 2-3; ELCON
Initial Comments at 4; ENGIE Initial Comments at 2; Evergreen Action
Initial Comments at 3; Fervo Energy Initial Comments at 2; Google
Initial Comments at 14; Google Reply Comments at 6; Illinois
Commission Initial Comments at 6; Interwest Initial Comments at 7;
New Jersey Commission Initial Comments at 11-12; Northwest and
Intermountain Initial Comments at 9-10; NY Commission and NYSERDA
Initial Comments at 8; [Oslash]rsted Initial Comments at 7; Pattern
Energy Initial Comments at 23; Pine Gate Initial Comments at 13;
Public Interest Organizations Initial Comments at 18-19; R Street
Initial Comments at 8, 10; R Street Reply Comments at 2; Southern
Initial Comments at 28; Tesla Initial Comments at 6-7; Vistra
Initial Comments at 1, 4.
\414\ Alliant Energy Initial Comments at 5; Clean Energy
Associations Initial Comments at 12; CREA and NewSun Initial
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6;
EEI Initial Comments at 12-13; ELCON Initial Comments at 6; ENGIE
Initial Comments at 2; Evergreen Action Initial Comments at 3; Fervo
Energy Initial Comments at 2-3; Google Initial Comments at 4;
Illinois Commission Initial Comments at 6; Indicated PJM TOs Initial
Comments at 14; Indicated PJM TOs Reply Comments 6; ISO-NE Initial
Comments at 26-27; New Jersey Commission Initial Comments at 12; NY
Commission and NYSERDA Initial Comments at 8; Ohio Commission
Consumer Advocate Initial Comments at 7; Pacific Northwest Utilities
Initial Comments at 13; SEIA Initial Comments at 5.
\415\ SEIA Initial Comments at 6.
\416\ Google Initial Comments at 14.
---------------------------------------------------------------------------
137. With access to this type of information, a prospective
interconnection customer will be able to better assess the viability of
a proposed generating facility before it submits an interconnection
request and therefore may be able to submit fewer exploratory
[[Page 61040]]
and unviable interconnection requests. We believe that, by reducing the
number of speculative interconnection requests, this reform will reduce
the delays caused by restudies triggered by interconnection request
withdrawals and overcrowded interconnection queues.\417\ We believe
that this information is also beneficial in the cluster study context,
contrary to some commenters' concerns regarding the availability of
information about the composition of the cluster and the effect of the
other proposed generating facilities in the cluster. In fact,
interconnection customers will be able to evaluate the viability of
their proposed generating facility in the context of a cluster by using
the publicly posted information as a baseline and incorporating the
cluster information that transmission providers are required to post,
during the customer engagement window, per new pro forma LGIP section
3.4.5 (Customer Engagement Window). Further, the heatmap requirement
will standardize the information available to interconnection customers
across regions and such standardization will provide interconnection
customers with consistency as they assess the viability of proposed
generating facilities, including where to site them, across
regions.\418\ Despite MISO's assertion that interconnection customers
typically use their own tools to conduct analyses, as opposed to MISO's
heatmap, several commenters identify MISO's heatmap tool as an example
of a transmission provider posting generator interconnection
information that is useful for prospective interconnection
customers.\419\ Therefore, we continue to find that it is important to
make similar information available to prospective interconnection
customers across the country to ensure comparable access to information
and the above mentioned resultant benefits of such information for the
interconnection process.
---------------------------------------------------------------------------
\417\ See CESA Initial Comments at 9; CESA Reply Comments at 3;
Consumers Energy Initial Comments at 3; CREA and NewSun Initial
Comments at 44-45; Duke Southeast Utilities Initial Comments at 6;
Environmental Defense Fund Initial Comments at 3; EEI Initial
Comments at 12-13; ELCON Initial Comments at 6; Evergreen Action
Initial Comments at 3; Google Initial Comments at 14; Illinois
Commission Initial Comments at 6-7; New Jersey Commission Initial
Comments at 12; NY Commission and NYSERDA Initial Comments at 8;
Pacific Northwest Utilities Initial Comments at 13; SEIA Initial
Comments at 5.
\418\ See, e.g., Alliant Energy Initial Comments at 5; Clean
Energy Associations Initial Comments at 12.
\419\ ACE-NY Initial Comments at 11; AES Initial Comments at 3;
Affected Interconnection Customers Initial Comments at 30; APPA-LPPC
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial
Comments at 7; Clean Energy Associations Initial Comments at 12;
Clean Energy Buyers Initial Comments at 6-7; Colorado Commission
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA
and NewSun Initial Comments at 44-45; Duke Southeast Utilities
Initial Comments at 6; Environmental Defense Fund Initial Comments
at 3; ELCON Initial Comments at 4; ENGIE Initial Comments at 2;
Evergreen Action Initial Comments at 3; Fervo Energy Initial
Comments at 2; Google Initial Comments at 14; Google Reply Comments
at 6; Illinois Commission Initial Comments at 6; Interwest Initial
Comments at 7; New Jersey Commission Initial Comments at 11-12;
Northwest and Intermountain Initial Comments at 9-10; NY Commission
and NYSERDA Initial Comments at 8; [Oslash]rsted Initial Comments at
7; Pattern Energy Initial Comments at 23; Pine Gate Initial Comments
at 13; Public Interest Organizations Initial Comments at 18-19; R
Street Initial Comments at 8, 10; Southern Initial Comments at 28;
Tesla Initial Comments at 6-7; Vistra Initial Comments at 1, 4.
---------------------------------------------------------------------------
138. Some commenters assert that the NOPR proposal is not useful
\420\ in part because it does not provide sufficient detail and may not
correspond with future study conditions,\421\ its usefulness depends on
its implementation,\422\ and it is unlikely to address cost uncertainty
challenges.\423\ In response to such objections, we find that the
public interconnection information requirements we adopt in this final
rule will provide further transparency of interconnection conditions,
but, as we have acknowledged above, will remain non-binding and
therefore cannot provide cost certainty. We recognize that this
requirement does not provide real-time transmission system information,
but we find that this information is valuable to prospective
interconnection customers before they enter the interconnection queue.
---------------------------------------------------------------------------
\420\ Dominion Initial Comments at 13; Idaho Power Initial
Comments at 3; ISO-NE Initial Comments at 17; NextEra Initial
Comments at 12; New York State Department Initial Comments at 8;
NYISO Initial Comments at 17; Omaha Public Power Initial Comments at
4; PacifiCorp Initial Comments at 14.
\421\ Dominion Initial Comments at 13; New York State Department
Initial Comments at 8; Omaha Public Power Initial Comments at 4.
\422\ Indicated PJM TOs Initial Comments at 14; New York State
Department Initial Comments at 8; NYTOs Initial Comments at 9; SPP
Initial Comments at 4.
\423\ AEE Initial Comments at 9; Cypress Creek Initial Comments
at 13.
---------------------------------------------------------------------------
139. We disagree with commenters that assert that the NOPR proposal
is overly burdensome.\424\ By moving the pro forma LGIP from a serial
to a cluster study process, the reforms adopted in this final rule will
reduce the number of studies and restudies performed by transmission
providers, therefore reducing the burden on both transmission providers
and their staff. In addition, as commenters assert, and we agree, the
information posting and interactive capability we require in this final
rule could feasibly be implemented with available industry system
simulation tools.\425\ We also agree with Clean Energy Associations
that providing these data in a standardized format should be a
``relatively low-impact'' requirement for transmission providers.\426\
This appears to be consistent with comments from Dominion that suggests
that the majority of the burden associated with complying with this
reform will be through an up-front financial commitment in new
software, rather than ongoing costs.\427\ Having made such software
commitments, though, transmission providers should be able to automate
much of the heatmap development, without significant commitments of
staff or resources. In doing so, we expect the ongoing costs of
maintaining such a heatmap to be relatively low. Moreover, because
transmission providers must use the most recent cluster study or
cluster restudy to populate the heatmap, they will not face the burden
of individualized analyses, which addresses the concern raised by some
commenters.\428\
---------------------------------------------------------------------------
\424\ Dominion Initial Comments at 13; National Grid Initial
Comments at 8; New York State Department Initial Comments at 8;
NextEra Initial Comments at 12; Omaha Public Power Initial Comments
at 4; Pacific Northwest Utilities Initial Comments at 14; PPL
Initial Comments at 9; Tri-State Initial Comments at 4; WAPA Initial
Comments at 7.
\425\ APPA-LPPC Initial Comments at 13; Pennsylvania Commission
Initial Comments at 13, which explains that transmission providers
are already implementing these tools further illustrates the point:
heatmaps will not likely cause further delay in already-stressed
queues.
\426\ Clean Energy Associations Initial Comments at 23-13; see
also ACORE Reply Comments at 3 (stating that collaboration to
increase automation of interconnection studies is a best practice
that could be adopted elsewhere).
\427\ Dominion Initial Comments at 12.
\428\ See APPA-LPPC Initial Comments at 13-14.
---------------------------------------------------------------------------
140. We adopt the requirement for transmission providers to update
the heatmaps within 30 calendar days after the completion of each
cluster study and cluster restudy. We recognize the need to balance the
burden of a specific update frequency with the value of ensuring
uniform, up-to-date information that can inform prospective
interconnection customers evaluating whether to enter the next cluster.
While some commenters support the timeline proposed in the NOPR,\429\
others argue that it is overly burdensome or, given the division of
their footprint into regions that have different timelines, would
trigger frequent updates. We find that the requirements we adopt here
[[Page 61041]]
establish an appropriate period of time because, as discussed above,
once the necessary software is in place, updating the heatmap after the
completion of a study is expected to be largely automated without
significant commitments of staff or resources. As the record
demonstrates, such heatmaps can be implemented with available industry
system simulation tools \430\ and with a standardized format that
causes the burden to be a ``relatively low-impact'' requirement for
transmission providers,\431\ once transmission providers have invested
in new software.\432\
---------------------------------------------------------------------------
\429\ Environmental Defense Fund Initial Comments at 3;
[Oslash]rsted Initial Comments at 6; Public Interest Organizations
Initial Comments at 20.
\430\ APPA-LPPC Initial Comments at 13-14; Pennsylvania
Commission Initial Comments at 13.
\431\ Clean Energy Associations Initial Comments at 23-13; see
also ACORE Reply Comments at 3 (stating that collaboration to
increase automation of interconnection studies is a best practice
that could be adopted elsewhere).
\432\ Dominion Initial Comments at 12.
---------------------------------------------------------------------------
141. In response to Eversource, which asks the Commission to
clarify that the heatmap would not be required to be made available
before the first cluster study concludes,\433\ we agree and further
clarify that the heatmap would not be required to be made available
until after the transition period. In response to El Paso Electric's
comments regarding the burden of a monthly update,\434\ we clarify that
the heatmaps must be updated within 30 calendar days after the
completion of each cluster study and cluster restudy, not on a cycle of
every 30 calendar days.
---------------------------------------------------------------------------
\433\ Eversource Initial Comments at 11.
\434\ El Paso Electric Initial Comments at 7.
---------------------------------------------------------------------------
142. In response to comments from PJM, Bonneville, and Tri-State
requesting flexibility for the posting of information for points of
interconnection that have yet to be studied,\435\ we clarify that
transmission providers need to provide updates only for anything that
has changed in the most recent cluster study or restudy after the first
cluster study after the Commission-approved effective date of the
transmission provider's filing in compliance with this final rule.
Requiring transmission providers to study each potential point of
interconnection, rather than just those requested in each cluster,
would expand the scope of this requirement. In turn, requiring such
expanded studies would be inconsistent with ensuring that
interconnection customers are able to interconnect in a reliable,
efficient, transparent, and timely manner. In response to PJM, which
states that transmission providers should be allowed to use prescreened
datasets that capture a majority of the feasible points of
interconnection that remove existing generator buses on the low side of
the generator step-up unit, rather than using all buses to populate the
heatmap,\436\ we agree that the heatmap may not differ significantly
between the existing generating facility's point of interconnection on
the low voltage side of the generating facility's step-up unit and the
high voltage side of the step-up unit. If that is the case, this final
rule provides transmission providers with the flexibility to populate
the heatmap with only the high side of the step-up unit.
---------------------------------------------------------------------------
\435\ Bonneville Initial Comments at 6; PJM Initial Comments at
48-49; Tri-State Initial Comments at 8.
\436\ PJM Initial Comments at 48-49.
---------------------------------------------------------------------------
143. In response to comments arguing that the Commission has failed
to demonstrate that information already made available is
inadequate,\437\ we disagree. The heatmap requirement is distinct from
information that transmission providers are already required to
provide. The existing pro forma LGIP requires transmission providers to
post the interconnection models and assumptions on OASIS or a password-
protected website. But the information that we require to be posted in
compliance with this final rule is the output of such models and
assumptions. We believe that publicly posting such resulting output is
necessary to aid prospective interconnection customers in their
decision-making prior to entering the interconnection queue. While
interconnection customers, on their own or through the hiring of
consultants, may be capable of performing studies with information
already published by transmission providers to arrive at information
similar to that required as part of this final rule, we believe that
making high-level information more easily accessible to all prospective
interconnection customers is needed to remedy unjust and unreasonable
Commission-jurisdictional rates. While Order No. 845 and FERC Form 715
do require certain, more detailed information to be filed with the
Commission and/or posted on OASIS or a password-protected website,\438\
access to this information has not addressed the problem of speculative
interconnection requests that we aim to remedy with several reforms
adopted in this final rule.
---------------------------------------------------------------------------
\437\ APPA-LPPC Initial Comments at 9; Duke Southeast Utilities
Initial Comments at 6-7; Idaho Power Initial Comments at 3; New York
State Department Initial Comments at 8; NV Energy Initial Comments
at 10; NYISO Initial Comments at 17; Ohio Commission Consumer
Advocate Initial Comments at 6-7; PacifiCorp Initial Comments at 14-
15; PG&E Initial Comments at 9-10; SoCal Edison Initial Comments at
14.
\438\ Order No. 845, 163 FERC ] 61,043 at P 236.
---------------------------------------------------------------------------
144. We recognize the need to balance security concerns with the
benefits of additional transparency. While some commenters express
security-related concerns with the NOPR proposal,\439\ as discussed
below, we are not modifying the Commission's CEII procedures,\440\
which we believe are sufficient to address security concerns raised in
comments. Some commenters state that publicly posting information that
indicates areas of transmission congestion or constraints is a risk as
these areas are more vulnerable. We are not persuaded by these concerns
and note that location-specific congestion information is already
publicly available in RTO/ISO markets. Moreover, the Commission's
regulations already provide that, upon request, transmission providers
must make available all data used to calculate available transfer
capability, total transfer capability, capacity benefit margin, and
transmission reliability margin for any constrained posted paths
publicly available (including the limiting element(s) and the cause of
the limit (e.g., thermal, voltage, stability)).\441\ Additionally, we
find these concerns to be speculative, particularly in light of the
fact that MISO already provides similar information over a large area.
Rather, we agree with those commenters that do not believe that the
NOPR proposal introduces additional security concerns.\442\
---------------------------------------------------------------------------
\439\ Bonneville Initial Comments at 6; Indicated PJM TOs
Initial Comments at 15; LADWP Initial Comments at 3; NRECA Initial
Comments at 16-17; PacifiCorp Initial Comments at 16; PPL Initial
Comments at 8; SoCal Edison Initial Comments at 13-14.
\440\ 18 CFR 388.113 (2022), which govern ``the procedures for
submitting, designating, handling, sharing, and disseminating [CEII]
submitted to or generated by the Commission'' (emphasis added).
\441\ 18 CFR 37.6(b)(2) (2022).
\442\ MISO Initial Comments at 27.
---------------------------------------------------------------------------
145. In response to concerns from PPL and LADWP regarding the
distribution factor analysis being made public,\443\ we are not
persuaded and find these concerns to be speculative as well. MISO has
long made distribution factors publicly available and states it is
currently unaware of any security concerns associated with the
proposal.\444\ As such, there is no evidence in the record to suggest
this posting has raised any concerns in the past. Moreover, we observe
that the distribution factor analyses informing the heatmaps are the
result of multi-year forward projections that inevitably
[[Page 61042]]
diverge from actual, real-time conditions, mitigating any potential
concerns with publicly posting this information.
---------------------------------------------------------------------------
\443\ LADWP Initial Comments at 3; PPL Initial Comments at 8-9.
\444\ MISO Initial Comments at 27.
---------------------------------------------------------------------------
146. We are similarly unpersuaded by potential data confidentiality
concerns.\445\ As with distribution factors, we find such concerns to
be speculative and contrary to the experience of MISO, which, for the
last several years, has already provided this information
publicly,\446\ as well as contrary to the statements of commenters that
support the NOPR proposal and do not raise data confidentiality
concerns.\447\
---------------------------------------------------------------------------
\445\ Bonneville Initial Comments at 6; PPL Initial Comments at
9.
\446\ Rod Walton, MISO Introduces New Generation Interconnection
Online Tool, Power and Engineering (May 19, 2020), at https://www.power-eng.com/om/miso-introduces-new-generation-interconnection-online-tool/#gref.
\447\ Affected Interconnection Customers Initial Comments at 30;
AES Initial Comments at 3; ACE-NY Initial Comments at 11; APPA-LPPC
Initial Comments at 13; CAISO Initial Comments at 7; CESA Initial
Comments at 7; Clean Energy Associations Initial Comments at 12;
Clean Energy Buyers Initial Comments at 7-8; Colorado Commission
Initial Comments at 8; Consumers Energy Initial Comments at 3; CREA
and NewSun Initial Comments at 44-45; Duke Southeast Utilities
Initial Comments at 6; Environmental Defense Fund Initial Comments
at 3; ELCON Initial Comments at 4; ENGIE Initial Comments at 2;
Evergreen Action Initial Comments at 3; Fervo Energy Initial
Comments at 2; Google Initial Comments at 14; Google Reply Comments
at 6; Interwest Initial Comments at 7; Illinois Commission Initial
Comments at 6; New Jersey Commission Initial Comments at 11-12; NY
Commission and NYSERDA Initial Comments at 8; Northwest and
Intermountain Initial Comments at 9-10; [Oslash]rsted Initial
Comments at 7; Pine Gate Initial Comments at 13; Public Interest
Organizations Initial Comments at 18-19; R Street Initial Comments
at 8, 10; Southern Initial Comments at 28; Tesla Initial Comments at
6-7; Vistra Initial Comments at 1,4.
---------------------------------------------------------------------------
147. We provide further clarification in response to comments
regarding the scope of analysis and assumptions which must provide the
basis for the heatmaps. In response to comments from Public Interest
Organizations,\448\ we decline to specifically require the heatmap to
be studied at high load conditions. Instead, we reiterate that such
heatmap should be based on the power flow model of the cluster study or
restudy. While such cluster studies are often simulated at high load
conditions, we understand that transmission providers typically conduct
interconnection studies by studying a variety of situations. As such,
we clarify that the information posted, for consistency and
actionability, must not only be based on the cluster studies, but also
must reflect the most limiting result of each of these situations
studied.
---------------------------------------------------------------------------
\448\ Public Interest Organizations Initial Comments at 20.
---------------------------------------------------------------------------
148. We find that it is necessary for the heatmaps to reflect N-1
conditions because transmission systems are operated to withstand N-1
contingencies. To the extent that such information was not calculated
under N-1 conditions, the results would not be useful or sufficiently
actionable to potential interconnection customers. As Eversource
asserts, point of interconnection level information would be too
simplistic if it is based only on N-0 conditions and would not provide
prospective interconnection customers with the information necessary to
select viable points of interconnection.\449\ Similarly, we find that
it is necessary for such posted information to approximate NRIS because
such level of interconnection service is generally subject to more
stringent requirements and therefore, reflecting this type of service
will cover both types of interconnection requests, whether they are
NRIS or ERIS.\450\ Similar to information calculated under only N-0
conditions, to the extent such a heatmap was not calculated to
approximate NRIS, the results would not be useful or sufficiently
actionable to a significant portion of interconnection customers.
---------------------------------------------------------------------------
\449\ Eversource Initial Comments at 11.
\450\ Specifically, the pro forma LGIP defines NRIS service as
``an Interconnection Service that allows the Interconnection
Customer to integrate its Large Generating Facility with the
Transmission Provider's Transmission System (1) in a manner
comparable to that in which the Transmission Provider integrates its
generating facilities to serve native load customers; or (2) in an
RTO or ISO with market-based congestion management, in the same
manner as Network Resources. Network Resource Interconnection
Service in and of itself does not convey transmission service.'' Pro
forma LGIP section 1. Whereas, the pro forma LGIP defines ERIS as
``an Interconnection Service that allows the Interconnection
Customer to connect its Generating Facility to the Transmission
Provider's Transmission System to be eligible to deliver the
Generating Facility's electric output using the existing firm or
nonfirm capacity of the Transmission Provider's Transmission System
on an as available basis. Energy Resource Interconnection Service in
and of itself does not convey transmission service.'' Id. (emphasis
added).
---------------------------------------------------------------------------
149. In response to comments from AES,\451\ we decline to require
the heatmaps to include a five-year outlook of available
interconnection capacity. The purpose of the heatmaps is to provide
potential interconnection customers an idea of the amount of
interconnection capacity available at the conclusion of each cluster
study or restudy. Because we are requiring transmission providers to
consider pending generating facilities when collating the information
to make public, interconnection customers will be aware of some of the
future conditions on the transmission system. Further, any requirement
to produce forecasts would place an additional burden on transmission
providers that we find would outweigh its usefulness to interconnection
customers.
---------------------------------------------------------------------------
\451\ AES Initial Comments at 5-7.
---------------------------------------------------------------------------
150. In response to comments from Alliant Energy and Clean Energy
Associations arguing that the assumptions used to produce the heatmap
should be made clear to users,\452\ we find that the assumptions used
to produce the heatmap should be consistent with those used in the
interconnection cluster studies. As those assumptions are already
required to be publicly posted, along with the models themselves,\453\
the assumptions used to produce the heatmap will be publicly posted via
these preexisting requirements.
---------------------------------------------------------------------------
\452\ Alliant Energy Initial Comments at 5; Clean Energy
Associations Initial Comments at 12-13.
\453\ Order No. 845, 163 FERC ] 61,043 at P 236; pro Forma LGIP
section 2.3.
---------------------------------------------------------------------------
151. Tri-State describes difficulties associated with multiple
transmission providers that inhabit a single substation. In such
situations, we clarify that transmission providers must populate the
required heatmaps using the results from their interconnection studies.
In response to the Illinois Commission, we clarify that the heatmaps
must represent potential congestion that might result after a
generating facility interconnects, not present congestion values. The
heatmap must reflect the base case assumptions from the most recent
cluster study or cluster restudy. Such studies are not intended to
analyze current operational conditions.
152. We next respond to specific objections raised regarding the
heatmaps' required level of granularity and scope, requested
flexibilities regarding alternatives to the adopted reform, and
clarifications regarding which transmission providers are required to
provide heatmaps, whether heatmaps are non-binding, and how costs
related to the heatmaps requirement are to be recovered. We decline to
alter the level of granularity of the heatmaps from that proposed in
the NOPR. As Ameren and MISO attest,\454\ the five data points proposed
in the NOPR are reasonable and sufficient to provide a high-level
comparison between several points of interconnection, and therefore to
satisfy the goals of this reform.
---------------------------------------------------------------------------
\454\ Ameren Initial Comments at 5; Bonneville Initial Comments
at 7; Clean Energy Buyers Initial Comments at 7-8; MISO Initial
Comments at 25.
---------------------------------------------------------------------------
[[Page 61043]]
153. Similarly, consistent with support from ENGIE and SEIA,\455\
we adopt the scope of the heatmap requirement proposed in the NOPR,
which is the amount of point of interconnection-level interconnection
capacity available to be injected at each point of interconnection. We
decline to expand the scope of the reporting. We believe that the scope
of information that we require transmission providers to publicly post
appropriately balances the burdens on transmission providers associated
with providing this information with the benefits that might be
realized by prospective interconnection customers of having ready
access to this information. In response to Dominion, which argues that
point of interconnection-level information may not necessarily be
useful because, in a networked system, injection at one point of
interconnection will affect the capability at other points of
interconnection,\456\ we agree that injections at one location affect
capabilities at other locations. Because the information provided by
the transmission provider accounts for full transmission system
conditions, interconnection customers should have the information they
need to approximate the impact of their potential generating facility
on the transmission system. For example, interconnection customers will
know if they are proposing to interconnect near constrained regions
even if those constraints are not necessarily at the proposed point of
interconnection.
---------------------------------------------------------------------------
\455\ ENGIE Initial Comments at 2-3; SEIA Initial Comments at 5.
\456\ Dominion Reply Comments at 8-9.
---------------------------------------------------------------------------
154. We decline to require transmission providers to provide
additional interconnection information metrics, as requested by some
commenters.\457\ While we are supportive of increased transparency, we
are not persuaded that the benefits of such information would outweigh
the burden of tabulating and posting such information.
---------------------------------------------------------------------------
\457\ AEP Initial Comments at 13; AES Initial Comments at 5-7;
Bonneville Initial Comments at 5; Clean Energy Associations Initial
Comments at 12-13; CREA and NewSun Initial Comments at 43-44; ENGIE
Initial Comments at 3; Eversource Initial Comments at 11; Google
Initial Comments at 6, 14; Hannon Armstrong Initial Comments at 2;
Pattern Energy Initial Comments at 23; Pine Gate Initial Comments at
14; Public Interest Organizations Reply Comments at 11-12; SEIA
Initial Comments at 6; SoCal Edison Initial Comments at 14-15; Tesla
Initial Comments at 7.
---------------------------------------------------------------------------
155. In response to ISO-NE, we decline to require that the heatmap
be qualitative only.\458\ We find that providing information only
qualitatively would not provide interconnection customers information
they could use to adequately mitigate risks such as obtaining site
control and providing significant deposits to the transmission provider
in order to enter the interconnection queue. Thus, providing only
qualitative information would be insufficient to address the lack of
information available to interconnection customers prior to entering
the interconnection queue, which leads to speculative interconnection
requests and the problems identified in the need for reform section
above.
---------------------------------------------------------------------------
\458\ Eversource Initial Comments at 11.
---------------------------------------------------------------------------
156. In response to requests for flexibility for transmission
providers to identify and post alternative heatmaps,\459\ we decline to
grant such additional flexibility. In this final rule, we establish a
set of required information that transmission providers must publicly
provide. We believe that this level of information is what is needed to
address the lack of information available to interconnection customers
prior to entering the interconnection queue, and therefore remedy the
unjust and unreasonable Commission-jurisdictional rates discussed in
section II of this final rule. We therefore disagree that the proposal
is overly prescriptive,\460\ as we believe that the required
information is necessary to adequately inform prospective
interconnection customers. While we establish a set of required
information, in response to comments from Clean Energy Associations
that the heatmap may need to be tailored to the services offered by a
particular transmission provider,\461\ and comments from Bonneville
that flexibility would allow transmission providers to determine
whether a different methodology would more clearly identify
interconnection capability for interconnection customers,\462\ we note
that if transmission providers find value in providing additional or
different information, they may propose such variations on compliance.
---------------------------------------------------------------------------
\459\ Avangrid Initial Comments at 21-22; Bonneville Initial
Comments at 6-8; Clean Energy Associations Initial Comments at 12;
Dominion Initial Comments at 14; MISO Initial Comments at 27; NY
Commission and NYSERDA Initial Comments at 8; NYTOs Initial Comments
at 8; Pacific Northwest Utilities Initial Comments at 14; PJM
Initial Comments at 48; Puget Sound Initial Comments at 6; SEIA
Initial Comments at 6; Southern Initial Comments at 28; WAPA Initial
Comments at 7-8.
\460\ Dominion Initial Comments at 13.
\461\ Clean Energy Associations Initial Comments at 12.
\462\ Bonneville Initial Comments at 7-8.
---------------------------------------------------------------------------
157. While we acknowledge that, as a result of the relative
interconnection queue sizes and load levels, many transmission
providers may have heatmaps that indicate negative interconnection
capacity and thereby would simply be ``red,'' \463\ we agree with R
Street that providing a visual representation of available
interconnection capacity is a best practice and should be required
nationwide.\464\ Moreover, we find that there is value in providing an
all ``red'' heatmap, as such information will demonstrate to
prospective interconnection customers the potential and likely network
upgrade-related consequences associated with interconnecting. In other
words, an all ``red'' heatmap sends a valuable signal to
interconnection customers regarding where proposed generating
facilities may be more or less economic to interconnect prior to
entering the interconnection queue.
---------------------------------------------------------------------------
\463\ See PacifiCorp Initial Comments at 15.
\464\ See R Street Initial Comments at 10.
---------------------------------------------------------------------------
158. Not only is there value in requiring this information from all
transmission providers, we are not persuaded that the burden is so
great as to outweigh the benefits for non-RTO/ISO transmission
providers and for smaller transmission providers.\465\ We acknowledge
that RTOs/ISOs are operationally different from their non-RTO/ISO
counterparts and that RTOs/ISOs are often more technologically
advanced, but the requirement is to reproduce interconnection studies
and publish the results in a heatmap. No commenter attests that
existing interconnection studies in non-RTO/ISO regions fail to
evaluate point of interconnection-level interconnection injection
capability. Moreover, we find that by publicly reproducing the results
of existing interconnection studies, the heatmaps will address the need
for additional interconnection information that exists in both RTOs/
ISOs and non-RTOs/ISOs. In other words, we find that there are unjust
and unreasonable Commission-jurisdictional rates stemming from the lack
of this information for prospective interconnection customers both
within and outside of RTOs/ISOs and that this problem must be remedied.
Additionally, as Environmental Defense Fund comments, at least one
other relatively small transmission owner posts an interactive capacity
heatmap for its distribution system comparable to
[[Page 61044]]
that required by this final rule.\466\ Thus, contrary to comments from
PPL,\467\ we find that smaller transmission providers are able to
provide this information to prospective interconnection customers and
that the benefits outweigh the burdens.
---------------------------------------------------------------------------
\465\ Dominion Initial Comments at 12; NRECA Initial Comments at
16; NV Energy Initial Comments at 10; PPL Initial Comments at 9;
Puget Sound Initial Comments at 5-6; Tri-State Initial Comments at
7-8.
\466\ Environmental Defense Fund Reply Comments at 3-4 (citing
Central Hudson Gas & Electric Corp., Solar PV Hosting Capacity Map,
https://www.cenhud.com/en/my-energy/distributed-generation/solar-pv-hc-map/).
\467\ PPL Initial Comments at 9.
---------------------------------------------------------------------------
159. In response to comments from the NY Commission and NYSERDA
asking for flexibility to ensure that the information is accessible and
understandable,\468\ we do not think that such flexibility is needed--
we specifically require the information to be contained within an
interactive map and posted on transmission providers' websites for this
purpose. Contrary to comments from NV Energy,\469\ we find that the
interactive map is necessary to ensure accessibility and
understandability. Absent the map, potential interconnection customers
would need to separately map injection points of interconnection to
specific locations.
---------------------------------------------------------------------------
\468\ NY Commission and NYSERDA Initial Comments at 7.
\469\ NV Energy Initial Comments at 10.
---------------------------------------------------------------------------
160. In response to comments from PJM and NV Energy requesting
flexibility for transmission providers, in lieu of the heatmap, to post
congestion information and a link to OASIS with interchange limits and
schedules, we decline to grant such flexibility. We find that there are
meaningful differences between the results of planning studies, such as
those used in the interconnection process, and operational data, like
congestion and interchange schedules. Interconnection studies are
generally conducted at a specific high-stress point in time for
injection at a specific point of interconnection to determine flows
across the whole transmission system, while operational data are simply
the accumulation of real-time and/or day-ahead results. Thus, posting
such operational data would only introduce timing differences and could
not substitute for the deliverability analyses conducted in the
interconnection processes.
161. In response to NYTOs, we clarify that the information
displayed in the heatmap will be illustrative, non-binding, and subject
to change.\470\ We agree with Tri-State's statement that transmission
providers must also caveat that the results do not account for affected
system impacts. As we have acknowledged, one primary driver of the
available interconnection capacity is the composition of the
interconnection customer's cluster, and the heatmap cannot reflect
those additional interconnection requests prior to the end of the
customer request window.
---------------------------------------------------------------------------
\470\ NYTOs Initial Comments at 9.
---------------------------------------------------------------------------
162. In response to requests to clarify the funding mechanism
associated with the heatmap requirement,\471\ we clarify that
transmission providers, not interconnection customers, are responsible
for paying for costs associated with posting the relevant heatmaps
required in pro forma LGIP section 6.1. However, we note that, to the
extent such costs are properly recoverable in transmission rates
consistent with existing Commission accounting and ratemaking policy,
such rate treatment is appropriate, and this final rule does not
preclude such treatment. We find that this reform will improve overall
interconnection queue efficiency to the benefit of transmission
customers, consistent with Commission policy.\472\
---------------------------------------------------------------------------
\471\ National Grid Initial Comments at 8; PacifiCorp Initial
Comments at 14; Tri-State Initial Comments at 7-8.
\472\ Order No. 845, 163 FERC ] 61,043 at P 37.
---------------------------------------------------------------------------
163. In response to Dominion, which requests clarification in the
RTO/ISO context,\473\ we clarify that within an RTO/ISO, the heatmap
requirement applies to the RTO/ISO, rather than to an individual
transmission owner in an RTO/ISO. Thus, transmission owners in RTOs/
ISOs are not required to separately post their own visual
representations and results.
---------------------------------------------------------------------------
\473\ Dominion Initial Comments at 14.
---------------------------------------------------------------------------
164. Finally, in response to concerns from WAPA about Federal power
marketing agencies having defined budgets and appropriations,\474\ we
note that transmission providers may explain specific circumstances on
compliance and justify why any deviations are either ``consistent with
or superior to'' the pro forma LGIP or merit an independent entity
variation in the context of RTOs/ISOs.
---------------------------------------------------------------------------
\474\ WAPA Initial Comments at 7-8.
---------------------------------------------------------------------------
2. Cluster Study Process
a. Need for Reform and Interconnection Study Procedures
i. NOPR Proposal
165. To remedy what may now be an unjust and unreasonable
interconnection process, the Commission proposed to eliminate the
serial first-come, first-served study process in the pro forma LGIP and
instead require transmission providers to use a first-ready, first-
served cluster study process.\475\ The Commission explained that under
a first-ready, first-served cluster study process, transmission
providers would perform larger interconnection studies encompassing
numerous proposed generating facilities, rather than separate studies
for each individual interconnection request. Under the NOPR proposal,
transmission providers would perform a single cluster study and cluster
restudy each year, the particulars of which are further discussed
below.
---------------------------------------------------------------------------
\475\ NOPR, 179 FERC ] 61,194 at P 64.
---------------------------------------------------------------------------
ii. Comments
166. Many commenters support the elimination of the serial study
process and the use of the proposed cluster study process.\476\ Several
commenters assert that the proposed cluster study process will increase
efficiency in the interconnection process by diminishing delays and
backlogs in processing
[[Page 61045]]
interconnection queues.\477\ Several commenters also believe that the
proposed cluster study process will result in fewer interconnection
request withdrawals \478\ and will discourage speculative
interconnection requests.\479\ Some commenters assert that, from the
interconnection customer's perspective, the proposed cluster study
process provides more certainty on timing and cost.\480\ Several
commenters state that they have already implemented some of the
proposed cluster study process reforms.\481\
---------------------------------------------------------------------------
\476\ ACE-NY Initial Comments at 2; ACORE Initial Comments at 4;
AEE Initial Comments at 10; AEE Reply Comments at 8; AEP Reply
Comments at 3-4; AES Initial Comments at 9; Amazon Initial Comments
at 2-3; Ameren Initial Comments at 6; APPA-LPPC Initial Comments at
14; Apple Initial Comments at 1; APS Initial Comments at 6; Avangrid
Initial Comments at 10, 11; Avangrid Reply Comments at 4; Bonneville
Initial Comments at 3; CAISO Initial Comments at 8; Clean Energy
Associations Initial Comments at 19; Clean Energy Buyers Initial
Comments at 8; Clean Energy States Initial Comments at 5; Colorado
Commission Initial Comments at 8; Cypress Creek Initial Comments at
12; Dominion Initial Comments at 14; Duke Southeast Utilities
Initial Comments at 1; Environmental Defense Fund Reply Comments at
6; EEI Initial Comments at 2, 5; EEI Reply Comments at 4-5; El Paso
Electric Initial Comments at 4; NERC Initial Comments at 26; Enel
Initial Comments at 11; EPSA Initial Comments at 5-6; Evergreen
Action Initial Comments at 3; Eversource Initial Comments at 12;
Fervo Energy Initial Comments at 3; Fervo Energy Reply Comments at
3; Idaho Power Initial Comments at 1, 4; Illinois Commission Initial
Comments at 7; Indicated PJM TOs Initial Comments at 10; Iowa
Commission Initial Comments at 3; ISO-NE Initial Comments at 19;
MISO Initial Comments at 28; NARUC Initial Comments at 6; National
Grid Initial Comments at 3-4; Navajo Utility Initial Comments at 12;
NESCOE Initial Comments at 9; NextEra Initial Comments at 13;
Northwest and Intermountain Initial Comments at 2; NV Energy Initial
Comments at 4; NY Commission and NYSERDA Initial Comments at 5;
NYISO Initial Comments at 10-11; NYTOs Initial Comments at 7; Ohio
Commission Consumer Advocate Initial Comments at 7; Omaha Public
Power Initial Comments at 4; OMS Initial Comments at 7; OPSI Initial
Comments at 3-4; [Oslash]rsted Initial Comments at 7; OSPA Reply
Comments at 15; Pacific Northwest Utilities Initial Comments at 1;
Pennsylvania Commission Initial Comments at 5-6; Pine Gate Initial
Comments at 14; PJM Initial Comments at 16; Public Interest
Organizations Initial Comments at 25; Puget Sound Initial Comments
at 4, 5; R Street Initial Comments at 8; SDG&E Initial Comments at
2; SEIA Initial Comments at 7; SoCal Edison Initial Comments at 3;
State Agencies Initial Comments at 2, 12; Tesla Initial Comments at
1; Tri-State Initial Comments at 3; U.S. Chamber of Commerce Initial
Comments at 6; UMPA Initial Comments at 2; WAPA Initial Comments at
8; WIRES Initial Comments at 5.
\477\ AEP Initial Comments at 16; Amazon Initial Comments at 2-
3; Apple Initial Comments at 1; Consumers Energy Initial Comments at
4; Environmental Defense Fund Initial Comments at 5; EEI Initial
Comments at 2, 5; ELCON Initial Comments at 2, 8; EPSA Initial
Comments at 10; NV Energy Initial Comments at 4; Ohio Commission
Consumer Advocate Initial Comments at 8; Pennsylvania Commission
Initial Comments at 5-6; Pine Gate Initial Comments at 14; Public
Interest Organizations Initial Comments at 25; SEIA Initial Comments
at 7; WIRES Initial Comments at 6.
\478\ AEP Initial Comments at 16; Dominion Initial Comments at
14; ELCON Initial Comments at 9; EPSA Initial Comments at 7; Ohio
Commission Consumer Advocate Initial Comments at 8; SEIA Initial
Comments at 7.
\479\ Clean Energy States Initial Comments at 5; Colorado
Commission Initial Comments at 8; ELCON Initial Comments at 9; EPSA
Initial Comments at 6; SoCal Edison Initial Comments at 3-4.
\480\ Avangrid Initial Comments at 11; Dominion Initial Comments
at 14.
\481\ APS Initial Comments at 6; Duke Southeast Utilities
Initial Comments at 2; MISO Initial Comments at 28; PacifiCorp
Initial Comments at 16; SPP Initial Comments at 5.
---------------------------------------------------------------------------
167. Dominion states that another benefit of moving to the proposed
cluster study process is that, if a proposed generating facility is not
ready for its cluster study, it can join the next cluster rather than
losing its interconnection queue position as occurs in a serial study
process.\482\ Dominion asserts that, as a result, the proposed cluster
study process removes the incentive for an interconnection customer to
``reserve a spot in line'' for a proposed generating facility is not
yet viable. Ohio Commission Consumer Advocate believes that larger
interconnection studies encompassing numerous proposed generating
facilities would be especially beneficial for interconnection customers
with multiple proposed generating facilities in close geographical
proximity.\483\ Avangrid believes that applying this concept to more
regions will lead to a more guided and proactive build-out of new
generation and required transmission upgrades.\484\
---------------------------------------------------------------------------
\482\ Dominion Initial Comments at 15.
\483\ Ohio Commission Consumer Advocate Initial Comments at 8.
\484\ Avangrid Initial Comments at 11.
---------------------------------------------------------------------------
168. Several commenters argue that the proposed cluster study
process will foster renewable resource development and aid in meeting
national and/or state clean energy and carbon emissions reduction
goals.\485\ Puget Sound states that over the past year, it has seen
unprecedented numbers of interconnection requests in response to the
resource solicitation process and a demand for new renewable energy
sources.\486\ Puget Sound adds that it has experienced a backlogged
interconnection queue, entry of speculative interconnection requests,
and uncertainty for interconnection customers relying on higher-queued
interconnection requests to complete the interconnection process for
their proposed generating facilities to be feasible. Clean Energy
States assert that, because wind and solar projects can be relatively
small, clustering should help smaller projects share the cost of
interconnection studies and upgrades, thereby providing them a viable
path through the interconnection process.\487\
---------------------------------------------------------------------------
\485\ Apple Initial Comments at 1; Navajo Utility Initial
Comments at 12; SoCal Edison Initial Comments at 4; State Agencies
Initial Comments at 12.
\486\ Puget Sound Initial Comments at 4-5.
\487\ Clean Energy States Initial Comments at 5.
---------------------------------------------------------------------------
169. Some commenters support the use of the proposed cluster study
process, so long as it is coupled with additional requirements, some of
which the Commission proposed in the NOPR.\488\ AEE recommends that the
Commission consider further reforms to harmonize study assumptions and
more closely link generator interconnection and long-term regional
transmission planning processes.\489\ R Street states that the
Commission should consider an interconnection study approach that uses
transparent, realistic study assumptions.\490\ Clean Energy
Associations argue that certain conservative assumptions--such as NERC
standard TPL-001's extreme contingency cases--can lead to the
identification of unreasonably large and costly upgrades.\491\ Clean
Energy Associations also assert that the Commission should make clear
in its final rule whether moving from a serial study process to a
cluster study process should or should not be accompanied by any change
in the interconnection standards and assumptions used in those
studies.\492\ Ameren generally supports the proposal to move to a
first-ready, first-served cluster study process, but argues that this
move without other reforms is unlikely to clear the interconnection
queue backlog.\493\ NERC states that its support for cluster studies is
predicated on parallel enhancements for model validation with actual
installed equipment and a true-up prior to interconnection.\494\
---------------------------------------------------------------------------
\488\ AEP Initial Comments at 6, 16; Ameren Initial Comments at
6; Cypress Creek Initial Comments at 12; CREA and NewSun Initial
Comments at 10, attach. A; CREA and NewSun Reply Comments at 8; Enel
Initial Comments at 11; Eversource Initial Comments at 13; Invenergy
Initial Comments at ii; NRECA Initial Comments at 8, 18; PPL Initial
Comments at 10; SoCal Edison Initial Comments at 4.
\489\ AEE Initial Comments at 10.
\490\ R Street Reply Comments at 2.
\491\ Clean Energy Associations Initial Comments at 28.
\492\ Id. at 21.
\493\ Ameren Initial Comments at 6.
\494\ NERC Initial Comments at 26.
---------------------------------------------------------------------------
170. Other commenters express some concern with the move to the
proposed cluster study process. For example, Enel states that cluster
studies increase interdependence between interconnection requests, with
a greater likelihood that multiple interconnection customers are
responsible for a single network upgrade, which creates a paradigm
where one interconnection customer's actions, such as withdrawing from
the interconnection queue, can have drastic impacts on many other
interconnection customers.\495\ Enel also asserts that, while the
proposed cluster study process has some benefits, recent cluster
studies are resulting in significant regional transmission constraints
with very high associated network upgrade costs and long construction
schedules. Enel contends that the proposed cluster study process can
still reduce interdependency and succeed if there are much smaller,
more local, regional groupings of interconnection requests in cluster
studies and lower minimum impact thresholds for determining network
upgrades. Enel says the Commission should adopt these two practices if
it adopts the proposed cluster study process.
---------------------------------------------------------------------------
\495\ Enel Initial Comments at 12-13.
---------------------------------------------------------------------------
171. Some commenters note that, where the demand for generator
interconnection significantly exceeds the available supply of
interconnection access, the NOPR's proposed cluster study process and
interconnection queue management reforms alone may be insufficient to
address the backlog of interconnection requests.\496\ Other commenters
assert that under these circumstances, some form of interconnection
request prioritization may be needed to effectively allocate scarce
interconnection access to the lowest-cost or highest-value proposed
generating facilities.\497\
---------------------------------------------------------------------------
\496\ AEE Reply Comments at 8; Cypress Creek Initial Comments at
12.
\497\ NARUC Initial Comments at 11-12; Western Regulators
Initial Comments at 1.
---------------------------------------------------------------------------
[[Page 61046]]
172. Several commenters state that, while they support the use of
the proposed cluster study process, the Commission should allow
variation among transmission providers in the makeup of the study
process.\498\ Some commenters argue that regional variations should be
permitted, especially where transmission providers have already
implemented a first-ready, first-served cluster study process.\499\
Environmental Defense Fund, on the other hand, argues that the
Commission should provide limited flexibility for transmission
providers to demonstrate in their compliance filing that a preexisting
cluster study process is substantially similar to the process
established in the Commission's final rule.\500\
---------------------------------------------------------------------------
\498\ AEP Initial Comments at 16; APPA-LPPC Initial Comments at
14; Avangrid Initial Comments at 10; Dominion Initial Comments at
14; EEI Initial Comments at 5; Eversource Initial Comments at 13;
NARUC Initial Comments at 6-7; NEPOOL Initial Comments at 14; NRECA
Initial Comments at 18-19; Omaha Public Power Initial Comments at 4;
OMS Initial Comments at 8.
\499\ AEP Initial Comments at 16; APPA-LPPC Initial Comments at
14; Idaho Power Initial Comments at 4; Indicated PJM TOs Initial
Comments at 10-11, 16; MISO Initial Comments at 31-32; NextEra Reply
Comments at 7; NYISO Initial Comments at 10-11; Pacific Northwest
Utilities Initial Comments at 2; SoCal Edison Initial Comments at 4;
U.S. Chamber of Commerce Initial Comments at 6-7; WIRES Initial
Comments at 6-7.
\500\ Environmental Defense Fund Reply Comments at 7.
---------------------------------------------------------------------------
173. Pacific Northwest Utilities and CREA and NewSun urge the
Commission to allow flexibility for transmission providers to design
the cluster study process to implement either a single-phase or two-
phase cluster study process.\501\ Pacific Northwest Utilities contend
that requiring full commercial readiness in a single-phase study
process, as proposed in the NOPR, significantly restricts an
interconnection customer's ability to enter the interconnection
queue.\502\ Pacific Northwest Utilities argue that a two-phase approach
provides greater accessibility to some interconnection customers by not
requiring commercial readiness for entry into the first phase.
According to Pacific Northwest Utilities, this is because all
interconnection customers who have attained site control will have
information about the network upgrades needed to meet the
interconnection requirements of the cluster and the expected cost
responsibility for each interconnection customer in the cluster.
Pacific Northwest Utilities aver that this information reduces the
potential for interconnection customers to withdraw from phase two and,
therefore, should reduce the need for additional restudies that might
slow or stall the interconnection process.
---------------------------------------------------------------------------
\501\ CREA and NewSun Reply Comments at 12-13; Pacific Northwest
Utilities Initial Comments at 6, 8-9.
\502\ Pacific Northwest Utilities Initial Comments at 7-8.
---------------------------------------------------------------------------
174. Some commenters argue that it may not be appropriate to
mandate the proposed cluster study process for every transmission
provider as cluster studies can be complex, expensive, and not the most
efficient or necessary approach for all proposed generating facilities
or circumstances.\503\ Some commenters generally support the use of
cluster studies if transmission providers retain discretion to use the
existing serial study process.\504\ Vermont Electric and Vermont
Transco notes that not all interconnection requests need to be studied
in a cluster format, and that this has frequently been the situation in
New England, where interconnection queue bottlenecks have historically
been locational and driven by state clean energy procurement
efforts.\505\ ISO-NE requests that the Commission consider a more
targeted approach for clusters triggered by geographic or electric
proximity among interconnection requests, rather than a blanket
clustering process for all interconnection requests.\506\ Instead of
mandating a clustering in all regions, ISO-NE contends that the
Commission consider the expanded use of clustering in areas with larger
concentrations of proposed generating facilities, while allowing use of
serial studies for customers seeking to interconnect in areas with low
activity, where serial studies could proceed relatively quickly.
---------------------------------------------------------------------------
\503\ SPP Initial Comments at 5.
\504\ AECI Initial Comments at 5; AEP Reply Comments at 4;
Avangrid Reply Comments at 4-5; CREA and NewSun Initial Comments at
44; ELCON Initial Comments at 9; NextEra Initial Comments at 15;
Southern Initial Comments at 6; Vermont Electric and Vermont Transco
Initial Comments at 2-3.
\505\ Vermont Electric and Vermont Transco Initial Comments at
2.
\506\ ISO-NE Initial Comments at 24.
---------------------------------------------------------------------------
175. National Grid asks for clarification as to whether the
proposed cluster study process encompasses energy or capacity
interconnection service requests, or both.\507\
---------------------------------------------------------------------------
\507\ National Grid Initial Comments at 16.
---------------------------------------------------------------------------
176. Some commenters contend that the Commission should encourage
relevant state entities to consider the efficient coordination of their
state-jurisdictional interconnection process with Commission-
jurisdictional interconnection processes.\508\ Avangrid argues that
sizable distributed energy resources should be aggregated and included
in the broader cluster study of large and small Commission-
jurisdictional generating facilities. Pine Gate suggests the Commission
require transmission providers, on compliance, to ``document how they
will ensure that any serial processes for state-jurisdictional
interconnection agreements will interact with the required cluster
study process'' and explain how the interconnection queue position of
qualifying facilities (QFs) will not be prejudiced by the transition to
a cluster study process.\509\
---------------------------------------------------------------------------
\508\ Avangrid Initial Comments at 12.
\509\ Pine Gate Initial Comments at 15.
---------------------------------------------------------------------------
iii. Commission Determination
177. We adopt the NOPR proposal to revise the pro forma LGIP and
pro forma LGIA to make cluster studies the required interconnection
study method. We find that the move from the serial study process in
the pro forma LGIP to the proposed cluster study process, alongside the
other reforms adopted in the final rule, will remedy the unjust and
unreasonable rates discussed in section II of this final rule.
Specifically, we believe that this reform will help remedy the problems
of the existing interconnection process for large generating facilities
in several ways. First, the cluster study process will increase
efficiency because transmission providers can perform larger
interconnection studies encompassing many proposed generating
facilities, rather than separate studies for each individual
interconnection customer.\510\ The cluster study process will provide
greater certainty to interconnection customers, regarding both the
timing of studies and the magnitude of network upgrade costs. Coupled
with the increased financial commitments and requirements to enter the
interconnection queue, such as a demonstration of site control, as
discussed further below, the cluster study process will also
disincentivize interconnection customers from submitting
interconnection requests for speculative generating facilities and
ensure that ready, more viable proposed
[[Page 61047]]
generating facilities can proceed through the study process.\511\ We
also expect that the cluster study process will result in fewer
withdrawals because conducting a single cluster study and cluster
restudy will minimize delays that arise from proposed generating
facility interdependencies under the existing serial study process, in
which lower-queued interconnection customers can strategically and
monetarily benefit from network upgrades and associated costs borne
earlier in the interconnection process by higher-queued interconnection
customers. We further expect that the cluster study process will
minimize the risk of cascading restudies when an interconnection
customer withdraws.\512\
---------------------------------------------------------------------------
\510\ NOPR, 179 FERC ] 61,194 at P64; May Joint Task Force Tr.
46:15-19 (Clifford Rechtschaffen) (stating that CAISO's cluster
process has been helpful and important for improving interconnection
queue processing and that clustering ``is a best practice and should
be promoted''); EEI Initial Comments at 2,5; ELCON Initial Comments
at 2,8; EPSA Initial Comments at 6; Idaho Power Initial Comments at
4; Indicated PJM TOs Initial Comments at 10; Pennsylvania Commission
Initial Comments at 5-6; see also May Joint Task Force Tr. 43:25-
44:4 (Riley Allen) (``Clustering helps the system to the benefit
ultimately of ratepayers. New England has been relying on
(explaining that clustering has two goals: minimizing the study time
and minimizing the first mover disadvantage by sharing costs among
those resources that need the same upgrades).
\511\ ELCON Initial Comments at 9; EPSA Initial Comments at 6;
NYTOs Initial Comments at 7; Ohio Commission Consumer Advocate
Initial Comments at 8; SoCal Edison Initial Comments at 4; State
Agencies Initial Comments at 12.
\512\ Cypress Creek Initial Comments at 12; Dominion Initial
Comments at 14; SEIA Initial Comments at 7.
---------------------------------------------------------------------------
178. We are not persuaded by Enel's request that the Commission
adopt smaller, more local regional groupings of proposed generating
facilities in interconnection studies and lower minimum impact
thresholds for determining upgrades.\513\ We find the record
insufficient to support these additional requirements. We also decline
requests to allow transmission providers to either continue to use a
serial study process or to create a parallel serial study process \514\
because, as discussed further below, we find that establishing in the
pro forma LGIP a separate interconnection process outside the cluster
study process could detract from transmission providers' efforts to
efficiently process cluster studies, and would be insufficient to
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner.
---------------------------------------------------------------------------
\513\ Enel Initial Comments at 13.
\514\ AECI Initial Comments at 5; AEP Reply Comments at 4;
Avangrid Reply Comments at 4-5; CREA and NewSun Initial Comments at
44; ELCON Initial Comments at 9; SPP Initial Comments at 5; Vermont
Electric and Vermont Transco Initial Comments at 2-3.
---------------------------------------------------------------------------
179. In response to requests to allow variation in how clusters are
formed,\515\ we emphasize that the reforms to the pro forma LGIP
adopted in this final rule do not prescribe how transmission providers
should form clusters.
---------------------------------------------------------------------------
\515\ Clean Energy States Initial Comments at 10; CREA and
NewSun Reply Comments at 12-13; Pacific Northwest Utilities Initial
Comments at 6-9; R Street Initial Comments at 11.
---------------------------------------------------------------------------
180. In response to National Grid,\516\ we decline to clarify
whether the proposed cluster study process encompasses energy or
capacity interconnection service requests. ``Energy interconnection
requests'' and ``capacity interconnection requests'' are not defined
terms in the pro forma LGIP, and we decline to define them here. We do
not believe that such detail is needed for transmission providers to
implement the reforms adopted herein.
---------------------------------------------------------------------------
\516\ National Grid Initial Comments at 16.
---------------------------------------------------------------------------
181. In response to Avangrid,\517\ we encourage relevant state
entities to consider the efficient coordination of their state-
jurisdictional interconnection processes with Commission-jurisdictional
interconnection processes.
---------------------------------------------------------------------------
\517\ Avangrid Initial Comments at 12.
---------------------------------------------------------------------------
182. In response to requests to create some form of generating
facility prioritization,\518\ we are neither persuaded that such
prioritization is needed, nor do we have an adequate record to dictate
how generating facility prioritization should be implemented in a just,
reasonable, and not unduly discriminatory or preferential manner.
---------------------------------------------------------------------------
\518\ AEE Reply Comments at 8; Cypress Creek Initial Comments at
12; NARUC Initial Comments at 11-12; Western Regulators Initial
Comments at 1.
---------------------------------------------------------------------------
183. Finally, we decline to adopt the following proposals advocated
by some commenters because they are outside the scope of this
proceeding: (1) AEE's request that the Commission consider further
reforms to more closely link generator interconnection and long-term
regional transmission planning process; \519\ (2) Cypress Creek's
request to require transmission providers to allow interconnection
customers to seek energy-only injection as a default and provide a
subsequent process (needed to address capacity-market constructs) by
which an interconnection customer can add firm rights; \520\ (3) Pine
Gate's suggestion for the Commission to require transmission providers
to document on compliance how they will ensure that any serial study
processes for state-jurisdictional interconnection agreements will
interact with the required cluster study process and explain how the
interconnection queue position of QFs will not be prejudiced by the
transition to a cluster study process; \521\ and (4) AEE's and Clean
Energy Associations' request that the Commission also harmonize study
standards and assumptions.\522\ We find that these proposals are
outside the scope of this proceeding as the Commission did not propose
specific reforms on these issues, and we find an inadequate record to
fully consider or adopt these requested changes.
---------------------------------------------------------------------------
\519\ AEE Initial Comments at 10.
\520\ Cypress Creek Initial Comments at 8-9.
\521\ Pine Gate Initial Comments at 15.
\522\ AEE Initial Comments at 10; Clean Energy Associations
Initial Comments at 21, 28.
---------------------------------------------------------------------------
b. Defined Terms in the Pro Forma LGIP and Pro Forma LGIA
i. NOPR Proposal
184. In the NOPR, the Commission proposed to add several new
defined terms (such as cluster, cluster study process, and cluster
request window) and to revise several defined terms (such as stand
alone network upgrade and material modification) in section 1 of the
pro forma LGIP and article 1 of the pro forma LGIA.\523\
---------------------------------------------------------------------------
\523\ NOPR, 179 FERC ] 61,194 at P 65.
---------------------------------------------------------------------------
ii. Comments
185. Starting with the proposed definition of stand alone network
upgrade, a few commenters support the Commission's proposal.\524\ Tri-
State suggests adding to the definition of stand alone network upgrade
that a transmission provider's interconnection facilities may be shared
by more than one generating facility in a given cluster study,
including a co-located resource.\525\
---------------------------------------------------------------------------
\524\ Ameren Initial Comments at 9; MISO Initial Comments at 32.
\525\ Tri-State Initial Comments at 25.
---------------------------------------------------------------------------
186. Other commenters oppose the proposed revisions to the
definition of stand alone network upgrade. Clean Energy Associations
argue that the proposal to modify the definition of stand alone network
upgrade to restrict it to those needed only for a single
interconnection customer is problematic and counterproductive.\526\
Clean Energy Associations contend that allowing interconnection
customers the right to self-build interconnection facilities and stand
alone network upgrades since Order No. 845 has served as a welcome
relief valve to transmission providers' lengthy construction timelines,
giving customers increased control of both the time and cost for
building these upgrades. As an alternative, Clean Energy Associations
suggest an approach similar to ISO-NE's for network upgrades that are
needed for multiple interconnections where an independently developed
elective network upgrade, if selected by all of the interconnection
customers in the cluster that require the network upgrade, can take the
place of the incumbent-built cluster enabling network upgrade.
---------------------------------------------------------------------------
\526\ Clean Energy Associations Initial Comments at 22-23.
---------------------------------------------------------------------------
187. Pine Gate states that in its experience, after Order No. 845,
[[Page 61048]]
transmission providers have taken a very narrow view of the facilities
that constitute stand alone network upgrades, and thus the potential
for interconnection customers to exercise the option to build has not
been fully realized.\527\ Pine Gate asserts that the proposed change
would further restrict the opportunity for interconnection customers to
exercise the option to build, exacerbate construction delays, and
result in a lack of competition to construct stand alone network
upgrades, ultimately harming consumers. Pine Gate therefore recommends
that the Commission not modify the definition of stand alone network
upgrade as proposed and instead grant the interconnection customer with
the largest projected impact on a potential stand alone network upgrade
facility the ability to elect the option to build with priority falling
to each interconnection customer based on the next largest impact on
the stand alone network upgrades.
---------------------------------------------------------------------------
\527\ Pine Gate Initial Comments at 63-64 (citing Comments of
Pine Gate, Docket No. RM21-17-000, at 9-10 (filed Oct. 12, 2021);
Order No. 2003, 104 FERC ] 61,103 at PP 85, 353).
---------------------------------------------------------------------------
188. Enel argues that the Commission should not adopt the proposed
substantive revisions to the definition of stand alone network upgrades
and should instead expand the definition of stand alone network
upgrades to include upgrades to an existing transmission facility which
involves a transmission line or substation being entirely rebuilt.\528\
Enel offers suggestions for implementing a third-party option that
would give interconnection customers more control over the cost and
schedule of larger network upgrades, resolving a frequent barrier to
bringing needed generating facilities online. To that end, Enel states
that pro forma LGIA article 5.1 could be modified to specify that the
option to build is only eligible for stand alone network upgrades
funded by a single interconnection customer, while the proposed third-
party option could be used for all stand alone network upgrades,
including line and substation rebuilds.
---------------------------------------------------------------------------
\528\ Enel Initial Comments at 55-56.
---------------------------------------------------------------------------
189. Moving to the proposed definition of material modification,
some commenters support the Commission's proposal.\529\ [Oslash]rsted
urges the Commission to ensure that under the newly proposed definition
of material modification, any changes to a proposed generating facility
that occur on the generating facility side of the point of
interconnection that do not result in changes to the electrical output
at the point of interconnection or the electrical characteristics of
the generating facility's interconnection: (1) will not be deemed to be
a material modification; and (2) will not result in the termination of
the interconnection customer's queue position.\530\
---------------------------------------------------------------------------
\529\ Ameren Initial Comments at 9; MISO Initial Comments at 32.
\530\ [Oslash]rsted Initial Comments at 8.
---------------------------------------------------------------------------
190. Ameren suggests that the Commission consider clarifying the
proposed definition of material modification, so that cost and timing
are factors to be considered in addition to when the transmission
provider determines changes to the point of interconnection are
otherwise material (e.g., from an electrical standpoint).\531\ Ameren
states that the Commission may want to consider whether the change
should only be triggered by a change to the point of interconnection or
whether a change to the inverters or other pieces of equipment in the
interconnecting generating facility, which could require other
upgrades, should also result in the determination of a material
modification.
---------------------------------------------------------------------------
\531\ Ameren Initial Comments at 9.
---------------------------------------------------------------------------
191. EPSA asks the Commission to be clearer in determining a
standard definition of a material modification.\532\ EPSA argues that,
at minimum, the Commission should direct each RTO/ISO or each NERC
region to establish clear criteria for the evaluation of material
modifications.
---------------------------------------------------------------------------
\532\ EPSA Initial Comments at 13.
---------------------------------------------------------------------------
iii. Commission Determination
192. We adopt the proposed revisions to section 1 of the pro forma
LGIP and article 1 of the pro forma LGIA to revise and add several
defined terms. Specifically, we adopt the proposed revisions to the
definition of stand alone network upgrade to clarify that, for a
network upgrade to be eligible for treatment as a stand alone network
upgrade, the network upgrade must be required for only one
interconnection customer and must meet the other existing requirements
in the definition of stand alone network upgrade. We address further
modifications to the definition of stand alone network upgrade below
where discussing network upgrade cost allocation (section III.A.4.c of
this final rule). We also adopt the proposed revisions to the
definition of material modification, which account for the equal
interconnection queue position of proposed generating facilities that
are part of the same cluster. We also modify the NOPR proposal to
define interconnection facilities study report.
193. With respect to the definition of stand alone network upgrade,
in response to Clean Energy Associations' concerns, we note that we do
not remove the right to self-build interconnection facilities and stand
alone network upgrades established in Order No. 845. Rather, we are
explicitly maintaining the status quo, which is to say that, under the
existing pro forma LGIP, there is no potential for a stand alone
network upgrade to be shared by more than one interconnection customer.
With the revision proposed in the NOPR and adopted here, we are
ensuring that within the structure of a cluster study process adopted
in this final rule, stand alone network upgrades continue to be defined
as only those required for a single interconnection customer, and
therefore the option to build is only available for a single
interconnection customer. Were we to not adopt this revision, multiple
interconnection customers could potentially attempt to construct the
same stand alone network upgrades, leading to confusion and potentially
lengthy negotiations and/or disputes regarding which interconnection
customer had the right to construct the stand alone network upgrade.
Additionally, with regard to Clean Energy Associations' request that
the Commission consider an approach similar to ISO-NE's for certain
upgrades that are needed for multiple interconnections, we decline to
adopt this approach because it is outside the scope of this proceeding.
We are not proposing in this proceeding to modify the pro forma LGIP to
address the cost responsibility and division of work between
interconnection customers that may share cost allocation for stand
alone network upgrades.
194. Similarly, Tri-State, Pine Gate, and Enel argue that the
Commission should expand the definition of stand alone network upgrade,
thereby expanding the right of interconnection customers to build
certain network upgrades. These requests are outside the scope of this
proceeding, which is not proposing to modify the scope of
interconnection customers' option to build certain stand alone network
upgrades but rather is only revising definitions insofar as is
necessary to implement reforms adopted elsewhere in this final rule.
For the same reason, we decline to expand the definition of material
modification, as [Oslash]rsted, Ameren, and EPSA request.\533\
---------------------------------------------------------------------------
\533\ See Ameren Initial Comments at 9; EPSA Initial Comments at
13; [Oslash]rsted Initial Comments at 8.
---------------------------------------------------------------------------
[[Page 61049]]
c. Definitive Point of Interconnection
i. NOPR Proposal
195. In the NOPR, the Commission proposed to add new section 3.1.2
to the pro forma LGIP and therein to require interconnection customers
to select a definitive point of interconnection to be studied no later
than the execution of the cluster study agreement. The Commission also
proposed that, upon mutual agreement, the transmission provider may
make reasonable changes to the requested point of interconnection to
facilitate efficient generator interconnection of clustered
interconnection requests at common points of interconnection.\534\
---------------------------------------------------------------------------
\534\ NOPR, 179 FERC ] 61,194 at P 66.
---------------------------------------------------------------------------
ii. Comments
196. MISO supports the Commission requiring the selection of a
definitive point of interconnection when executing the cluster study
agreement; however, MISO encourages the Commission to require the
selection of a definitive point of interconnection even earlier, as
part of the interconnection request.\535\ MISO notes that requiring an
earlier selection of the definitive point of interconnection will
assist in interconnection queue processing, as a transmission provider
would not be able to begin modeling work if the interconnection
customer is permitted to wait until a later point in time to select its
definitive point of interconnection. MISO further argues that the
definitive point of interconnection (even if subject to change) should
be selected prior to any scoping meeting. MISO also supports the
proposed language that limits the ability of the interconnection
customer to change its point of interconnection after the submission of
interconnection request.
---------------------------------------------------------------------------
\535\ MISO Initial Comments at 33-34.
---------------------------------------------------------------------------
197. Other commenters do not support the Commission's proposal to
require a definitive point of interconnection when executing the
cluster study agreement.\536\ ACE-NY supports making the demonstration
of a feasible point of interconnection a requirement for a generating
facility to move into the facilities study phase of the generator
interconnection process.\537\
---------------------------------------------------------------------------
\536\ ACE-NY Initial Comments at 3; CREA and NewSun Initial
Comments at 47; Pine Gate Initial Comments at 15.
\537\ ACE-NY Initial Comments at 3-4.
---------------------------------------------------------------------------
198. Pine Gate and CREA and NewSun assert that the Commission
should modify its proposal to permit interconnection customers to
request alternative points of interconnection.\538\ Pine Gate argues
that the Commission should permit interconnection customers to request
a study of a primary and secondary point of interconnection within one
or two electrical buses, then select a point of interconnection restudy
after receiving initial cluster study results.\539\ Similarly, CREA and
NewSun assert that the Commission should permit alternative points of
interconnection, and collective points of interconnection for proposed
generating facilities in a cluster (e.g., those that could connect to a
single substation), to be proposed and studied, at least through the
system impact study in order to obtain more complete cost
information.\540\
---------------------------------------------------------------------------
\538\ CREA and NewSun Initial Comments at 47-48; Pine Gate
Initial Comments at 15-16.
\539\ Pine Gate Initial Comments at 15-16.
\540\ CREA and NewSun Initial Comments at 47-48.
---------------------------------------------------------------------------
199. Enel suggests that, in the second paragraph of proposed
section 3.1.2 of the pro forma LGIP, the Commission should change the
word ``make'' to ``propose'' in the following quoted language: ``For
purposes of clustering Interconnection Requests, Transmission Provider
may make reasonable changes to the requested Point of
Interconnection.'' \541\ Enel explains that this would clarify that any
such changes can only be made with the consent of the interconnection
customer, as specified in the proposed new final sentence to that
paragraph.
---------------------------------------------------------------------------
\541\ Enel Initial Comments at 82.
---------------------------------------------------------------------------
iii. Commission Determination
200. We adopt the proposed section 3.1.2 of the pro forma LGIP
insofar as it requires an interconnection customer to select a
definitive point of interconnection to be studied when executing the
cluster study agreement, with one modification discussed below.
201. Requiring interconnection customers to select a definitive
point of interconnection when executing the cluster study agreement
allows the interconnection customer to submit its interconnection
request with a proposed point of interconnection, participate in the
scoping meeting during the customer engagement window, and receive
feedback on its proposed point of interconnection. We believe that this
strikes the right balance between allowing for flexibility and
potential adjustments to the point of interconnection, based on
discussion with the transmission provider and the transmission
provider's detailed knowledge of its transmission system, and providing
transmission providers with the information necessary to conduct the
cluster study, thus reducing the potential for restudies that would be
required if interconnection customers could change their points of
interconnection later in the process.
202. We decline to: (1) require that the definitive point of
interconnection be selected earlier (e.g., as part of the
interconnection request); \542\ (2) only require that the definitive
point of interconnection be selected later (e.g., at the facilities
study phase); \543\ or (3) permit interconnection customers to submit
multiple alternative points of interconnection for study in a single
interconnection request.\544\ We believe that requiring the selection
of a definitive point of interconnection earlier in the cluster study
process, as suggested by MISO, would deprive interconnection customers
of information that could aid in their selection. Similarly, we believe
that requiring the selection of a definitive point of interconnection
after the cluster study, as suggested by ACE-NY, or allowing multiple
points of interconnection to be studied before the interconnection
customer is required to select the definitive point of interconnection,
as suggested by Pine Gate and CREA and NewSun, fails to take into
account the fact that, if an interconnection customer changes the
definitive point of interconnection after the cluster study, it will
likely impact the study results of the other interconnection customers
in the cluster and could lead to restudies and delays. We do not
believe that the alternatives suggested by commenters would remedy the
unjust and unreasonable status quo described in section II of this
final rule.
---------------------------------------------------------------------------
\542\ See MISO Initial Comments at 33.
\543\ See ACE-NY Initial Comments at 3-4.
\544\ See CREA and NewSun Initial Comments at 47-48; Pine Gate
Initial Comments at 15-16.
---------------------------------------------------------------------------
203. Finally, we agree with Enel's suggestion to change the word
``make'' to ``propose'' in pro forma LGIP section 3.1.2. We modify that
section to state: ``For purposes of clustering Interconnection
Requests, Transmission Provider may propose reasonable changes to the
requested Point of Interconnection.'' \545\ We agree that this
clarifies that any such changes can only be made with the consent of
the interconnection customer.
---------------------------------------------------------------------------
\545\ Enel Initial Comments at 82.
---------------------------------------------------------------------------
d. Cluster Request Window and Customer Engagement Window
i. NOPR Proposal
204. In the NOPR, the Commission proposed to add new section 3.4.1
(Cluster Request Window) to the pro forma LGIP to require
interconnection
[[Page 61050]]
customers to submit an interconnection request during the cluster
request window--a 45-calendar day period with the start date to be
determined by each transmission provider (with the annual start date
for the transmission provider's cluster request window included in its
LGIP).\546\ The transmission provider would consider all
interconnection requests accepted during this period to have equal
queue priority for purposes of the cluster study. The Commission also
proposed to add in pro forma LGIP section 3.1.1 (Initial Study Deposit)
a non-refundable application fee of $5,000 to be submitted with the
interconnection request. The Commission further proposed that
interconnection customers must cure deficient interconnection requests
within 10 business days after receipt of notice from the transmission
provider, but no later than the close of the cluster request window.
---------------------------------------------------------------------------
\546\ NOPR, 179 FERC ] 61,194 at P 67.
---------------------------------------------------------------------------
205. The Commission also proposed to add new pro forma LGIP section
3.4.5 (Customer Engagement Window), which provides that, following the
close of the cluster request window, the transmission provider begins a
30-calendar day customer engagement window.\547\ New pro forma LGIP
section 3.4.5 also requires the transmission provider to post within
the first 10 business days following the close of the cluster request
window a list of interconnection requests for that cluster.
---------------------------------------------------------------------------
\547\ Id.
---------------------------------------------------------------------------
ii. Comments
206. Clean Energy Associations support the proposal to require
interconnection customers to submit interconnection requests during the
cluster request window.\548\ MISO supports the Commission requiring a
definitive application deadline as part of the implementation of
cluster studies, and equal interconnection queue priority for all
interconnection requests submitted prior to that deadline, but does not
see an intrinsic value in a defined application start time.\549\ MISO
supports granting interconnection customers flexibility to submit an
interconnection request earlier than the beginning of a cluster request
window. Noting that, under proposed pro forma LGIP section 3.4.5,
interconnection requests that are deemed valid during the customer
engagement window are placed into the cluster study, Southern proposes
that if an interconnection request is not deemed valid, the
interconnection request should be withdrawn from the interconnection
queue.\550\
---------------------------------------------------------------------------
\548\ Clean Energy Associations Initial Comments at 19.
\549\ MISO Initial Comments at 35 (noting that, under the MISO
tariff, all interconnection requests received after the application
deadline ``shall be applied towards the following Definitive
Planning Phase cycle'') (citing MISO, FERC Electric Tariff, attach.
X, section 3.3.1 (158.0.0)).
\550\ Southern Initial Comments at 37.
---------------------------------------------------------------------------
207. MISO expresses concern that the timelines listed in the
customer engagement window for posting information are
impractical.\551\ MISO asserts that the Commission should not require a
posting so near to the close of the cluster request window because the
transmission provider must devote its resources to reviewing the
interconnection requests for deficiencies.\552\ MISO contends that this
information would only be useful at this time to interconnection
customers with speculative interconnection requests that may be trying
to determine if their proposed generating facility is economically
viable and that may be trying to identify a point of interconnection
change to increase the viability of their interconnection requests.
---------------------------------------------------------------------------
\551\ MISO Initial Comments at 36.
\552\ Id. (stating that a majority of its interconnection
requests are submitted on the last day of the application window, or
two days prior at most).
---------------------------------------------------------------------------
208. MISO argues that the Commission should not require any
informational posting pertaining to an interconnection request prior to
the interconnection customer's finalization of the interconnection
request because a definitive point of interconnection has not yet been
selected.\553\ MISO highlights that the proposed pro forma LGIP section
3.4.5 requires the transmission provider's OASIS posting to include
``(3) the station or transmission line where the interconnection will
be made.'' \554\ However, MISO notes that an interconnection customer
is not required to select a definitive point of interconnection until
the end of the customer engagement window. As such, MISO contends that
the posting requirement is impossible if the transmission provider is
required to post the point of interconnection. MISO argues that the
Commission should not require any posting until a reasonable period
after the interconnection customer is required to select its definitive
point of interconnection and the information is complete, such as when
the customer engagement window is completed and cluster studies are
about to begin.
---------------------------------------------------------------------------
\553\ Id. at 36-37.
\554\ Id. at 37.
---------------------------------------------------------------------------
209. Regarding the makeup of the cluster, Clean Energy States
assert that the cluster study process should allow for changes in the
makeup of the cluster, and that the study process may identify ways to
improve a cluster to provide better performance for the transmission
system, such as by adding or subtracting certain interconnection
requests from the cluster.\555\ Clean Energy States assert that a
transmission provider should be able to modify the cluster in response
to interconnection customer changes or study findings without
threatening the interconnection customer's queue priority or paying
penalties.
---------------------------------------------------------------------------
\555\ Clean Energy States Initial Comments at 8-9.
---------------------------------------------------------------------------
210. EPSA argues that the final rule should specify that
transmission providers are required to work with interconnection
customers during the customer engagement window and study agreement
negotiation in a manner that is fair and equitable regarding the study
models to be used, data verification, and stakeholder engagement--
regardless of the planning or procurement method used by the
prospective interconnection customer.\556\
---------------------------------------------------------------------------
\556\ EPSA Initial Comments at 7.
---------------------------------------------------------------------------
211. Enel recommends that the Commission consolidate the
interconnection request and cluster and facilities study agreements
into a single study agreement to be submitted at the time of
application.\557\ Enel also recommends that the Commission include
language in the pro forma LGIP that provides that transmission
providers will not post information about interconnection requests
proceeding through or withdrawing from the interconnection queue until
all interconnection requests submitted within a cluster request window
successfully meet their milestone requirements to proceed, withdraw, or
fail to cure their breach within the specific cure period.\558\
---------------------------------------------------------------------------
\557\ Enel Initial Comments at 13.
\558\ Id. at 48.
---------------------------------------------------------------------------
212. Regarding the length of the cluster request window, some
commenters support the proposed 45-calendar day time frame for the
cluster request window.\559\ Although it supports the 45-calendar day
time frame, Eversource suggests the Commission add more structure to
this element of its proposal by establishing rules that enable
potential interconnection customers to be informed of when the request
windows
[[Page 61051]]
will be open and how to prepare to apply.\560\
---------------------------------------------------------------------------
\559\ Eversource Initial Comments at 13; Clean Energy
Associations Initial Comments at 19.
\560\ Eversource Initial Comments at 13.
---------------------------------------------------------------------------
213. Other commenters argue that the proposed 45-calendar day time
frame for the cluster request window is too short and should be
increased to 60 calendar days.\561\ ISO-NE states that, based on its
experience implementing its forward capacity market process, each of
the cluster study windows proposed in the NOPR should be extended to
help ensure an efficient cluster study process.\562\ Pine Gate also
argues that a longer cluster request window would reduce the burden on
transmission providers by providing more time to administer their
deficiency notice processes.\563\ Pine Gate explains that, for larger
interconnection customers that may be developing numerous
interconnection requests for multiple transmission providers,
overlapping cluster request windows are likely. Additionally, Pine Gate
contends that, as contemplated by the NOPR, it is likely that increased
requirements and additional information for interconnection customers
will be due at the time of interconnection queue entry (e.g., the
complex modeling required to be submitted) and burdensome to
accommodate in the proposed time frame.
---------------------------------------------------------------------------
\561\ ISO-NE Initial Comments at 22-23; Pine Gate Initial
Comments at 16; PJM Initial Comments at 19-20.
\562\ ISO-NE Initial Comments at 22. ISO-NE requests that the
Commission consider the following windows for the cluster study
process: (i) cluster request window--60 calendar days; (ii) customer
engagement window--90 calendar days; (iii) cluster study--270 to 365
calendar days (depending on the size of a given cluster); (iv)
cluster restudy--150 calendar days; and (v) facilities study--90 to
180 calendar days. Id. at 23.
\563\ Pine Gate Initial Comments at 16.
---------------------------------------------------------------------------
214. On the other hand, some commenters argue that a shorter
cluster request window is appropriate. CAISO argues that longer cluster
request windows result in low quality requests because interconnection
customers have more time within the window to fix their
submissions.\564\ CAISO contends that its use of a shorter 15-day
interconnection request completeness window followed by a longer
validation and scoping meeting window have significantly improved
interconnection request quality and the speed with which CAISO
processes requests.\565\ Similarly, Tri-State recommends that the
cluster request window be shortened because, based on its experience,
most interconnection requests submitted in the cluster request window
are received the last two days of the request window.\566\
---------------------------------------------------------------------------
\564\ CAISO Initial Comments at 9.
\565\ Id. (citing CAISO, CAISO Tariff, app. DD, sections 3.5.1,
3.5.2.2 (16.0.0); id. section 6.1.2 (21.0.0)).
\566\ Tri-State states that during its 2022 definitive
interconnection system impact study request window, 75% of the
interconnection requests were received during the last two days of
the request window, and 50% of the interconnection requests were
received in the last two days of the 2021 definitive interconnection
system impact study request window. Id. at 10.
---------------------------------------------------------------------------
215. Regarding the requirement for correcting deficiencies in the
proposed pro forma LGIP section 3.4.4 (Deficiencies in Interconnection
Request), Tri-State argues that requiring interconnection customers to
provide any requested information within 10 business days after
receiving notice of deficiencies in the interconnection request, but no
later than the close of the cluster request window, does not take into
account that most requests are not submitted until the last day of the
cluster request window.\567\
---------------------------------------------------------------------------
\567\ Tri-State Initial Comments at 27.
---------------------------------------------------------------------------
216. Regarding the number of cluster request windows opened each
year, a couple of commenters argue that there should be more than one
cluster request window per year.\568\ Clean Energy States assert that,
because presumably there will be fewer generator interconnection
studies to be done, transmission providers should provide opportunities
more frequently (e.g., quarterly) for interconnection customers to
submit interconnection requests.\569\ Environmental Defense Fund argues
that the Commission should require that the cluster request windows
occur bi-annually, rather than once a year, to reduce the delay caused
by missing a cluster request window while still covering a large enough
time period that a number of interconnection requests will be included
in each cluster.\570\
---------------------------------------------------------------------------
\568\ Clean Energy States Initial Comments at 9; Environmental
Defense Fund Initial Comments at 4.
\569\ Clean Energy States Initial Comments at 9.
\570\ Environmental Defense Fund Initial Comments at 4.
---------------------------------------------------------------------------
217. Southern generally agrees with the Commission that a cluster
study process, including the individual facilities study, should be
completed within a year, but recommends eliminating unnecessary delays,
such as multiple, overlapping clusters, by only permitting one cluster
study at a time (i.e., that a new cluster should not commence until the
previous cluster has been completed).\571\ According to Southern, under
this format, an annual cluster study can be performed because the
previous cluster study process has been completed. Southern asserts
that overlapping cluster study processes will not help end
interconnection queue backlogs and uncertainty, but rather add to them.
---------------------------------------------------------------------------
\571\ Southern Initial Comments at 23-24.
---------------------------------------------------------------------------
218. Regarding the length of the customer engagement window, Clean
Energy Associations support the proposed 30-calendar day time frame for
the customer engagement window as a baseline.\572\ A number of
commenters argue that the proposed 30-calendar day customer engagement
window is too short and recommend a longer window.\573\ Duke Southeast
Utilities argue that, based on experience with Duke Carolinas
Utilities' cluster study process, which includes a 60-calendar day
customer engagement window, the proposed 30-calendar day customer
engagement window may not provide sufficient time to facilitate robust
engagement.\574\ Duke Southeast Utilities therefore urge the Commission
to adopt a 60-calendar day customer engagement window. Xcel describes
PSCo's recent interconnection queue reform, which extended the customer
engagement window to 95 calendar days to allow interconnection
customers additional time to reevaluate their readiness in a way that
includes other customers.\575\
---------------------------------------------------------------------------
\572\ Clean Energy Associations Initial Comments at 19.
\573\ APS Initial Comments at 10-11; CAISO Initial Comments at
8, 10-11; Duke Southeast Utilities Comments at 8; ISO-NE Initial
Comments at 23; Tri-State Initial Comments at 9-10; PJM Initial
Comments at 20.
\574\ Duke Southeast Utilities Initial Comments at 8.
\575\ Xcel Initial Comments at 21 (citing Pub. Serv. Co. of
Colo., Docket No. ER22-2087-000 (Aug. 9, 2022) (delegated order)).
---------------------------------------------------------------------------
219. ISO-NE suggests a 90-calendar day customer engagement
window.\576\ In addition, ISO-NE suggests that the Commission clarify
that transmission providers may withdraw interconnection requests for
which the models and data do not meet the requirements following the
customer engagement window in order to improve efficiency. ISO-NE
further asks that the Commission recognize the role of the
participating transmission owners in performance of interconnection
studies and build time into the cluster study time frames that accounts
for this coordination.
---------------------------------------------------------------------------
\576\ ISO-NE Initial Comments at 23.
---------------------------------------------------------------------------
220. Indicated PJM TOs argue that there should be a 30-calendar day
window after the date that the cluster request window closes, and
between the time the transmission provider posts the interconnection
cases for the cluster study and the cluster study commences, during
which interconnection customers qualified to receive CEII information
have the opportunity to conduct their own studies with the transmission
provider's base case and
[[Page 61052]]
the new interconnection service requests. Indicated PJM TOs assert that
during this time, interconnection customers should be able to withdraw
their interconnection request with minimal financial impact.\577\
---------------------------------------------------------------------------
\577\ Indicated PJM TOs Reply Comments at 6-7.
---------------------------------------------------------------------------
221. APS states that multiple customers requesting individual
scoping meetings could place a significant burden on the transmission
provider to schedule several meetings under a condensed time frame if
the customer engagement window remains 30 calendar days.\578\ For
example, APS states that, assuming all notifications of valid
interconnection requests are made by the time the customer engagement
window starts, the interconnection customer has 15 business days to
request an individual meeting and, if an interconnection customer uses
all 15 business days, that is a minimum 21 calendar days out of the
total 30 calendar days of the overall customer engagement window. APS
contends that this leaves nine calendar days at most (i.e., no more
than seven business days) to schedule an individual customer meeting,
which could be less if there are holidays occurring within the customer
engagement window.
---------------------------------------------------------------------------
\578\ APS Initial Comments at 10.
---------------------------------------------------------------------------
222. Similarly, Tri-State argues that the proposed 30-day customer
engagement window is not sufficient to meet the purpose of the customer
engagement window and recommends it be extended to allow adequate time
to cure deficiencies and hold individual scoping meetings.\579\ Tri-
State argues that a 75-day customer engagement window would give
interconnection customers an opportunity to: (1) assess the viability
of their proposed generating facilities before committing to the
interconnection process and subjecting themselves to a withdrawal
penalty; and (2) cure deficiencies in their interconnection
requests.\580\
---------------------------------------------------------------------------
\579\ Tri-State Initial Comments at 9, 10.
\580\ Id. at 9.
---------------------------------------------------------------------------
iii. Commission Determination
223. We adopt the proposed new pro forma LGIP section 3.4.1
(Cluster Request Window), which provides that interconnection customers
must submit an interconnection request during a specified period--the
cluster request window--a 45-calendar day period with the start date to
be determined by each transmission provider. We also adopt the non-
refundable $5,000 application fee required to be submitted with the
interconnection request.\581\ We also adopt the requirement that
interconnection customers provide requested information within 10
business days of receiving an interconnection request deficiency notice
but no later than the close of the cluster request window, as proposed
and adopted in new pro forma LGIP section 3.4.4 (Deficiencies in
Interconnection Request), but we modify that section to clarify the
timeline for curing deficiencies. We modify the proposed new pro forma
LGIP section 3.4.5 (Customer Engagement Window) and extend the customer
engagement window from 30 days to 60 calendar days.
---------------------------------------------------------------------------
\581\ We note that the application fee is separate from the
initial study deposit, commercial readiness deposit, and deposit in
lieu of site control.
---------------------------------------------------------------------------
224. To ensure clarity for both interconnection customers and
transmission providers, based on the record, we believe that 45
calendar days is a sufficient window to adequately notify prospective
interconnection customers of the formation of a new cluster but not so
long as to delay the processing of the interconnection queue.
225. Contrary to commenters' assertions, we are not persuaded to
extend the cluster request window. We do not believe that more time is
needed for transmission providers to work with interconnection
customers that submitted invalid interconnection requests to cure
deficiencies, particularly given the limit we adopt on the time for
such additional information to be submitted by interconnection
customers, and because the start date of the cluster request window
will be included in the transmission provider's LGIP for prospective
interconnection customers. We similarly do not believe that shortening
the cluster request window would result in fewer ``low quality''
interconnection requests, as CAISO argues. Given the package of reforms
adopted in this final rule, we expect fewer speculative interconnection
requests and that interconnection customers will be more likely as a
result of this final rule to submit interconnection requests for
proposed generating facilities that they believe are viable and ready
to move forward in the interconnection process.
226. As for Tri-State's concern about the requirement for
correcting deficiencies in new pro forma LGIP section 3.4.4
(Deficiencies in Interconnection Request),\582\ we clarify that the 10-
business day window is the maximum time allowed to submit a response.
This means that an interconnection customer that submits its
interconnection request more than 10 business days before the close of
the cluster request window will have a full 10 business days to submit
a response, whereas an interconnection customer that does not submit
its interconnection request until less than 10 business days before the
close of the cluster request window will have however many days remain
in the cluster request window to respond to any deficiencies.
Accordingly, we modify pro forma LGIP section 3.4.4 to provide that if
the interconnection customer does not respond before the deadline: (1)
the interconnection request is immediately deemed withdrawn (without
the cure period provided under pro forma LGIP section 3.7); (2) the
application fee is forfeited to the transmission provider; and (3)
because the cluster study has not commenced, the study deposit and
commercial readiness deposit are returned to the interconnection
customer.
---------------------------------------------------------------------------
\582\ Tri-State Initial Comments at 27.
---------------------------------------------------------------------------
227. We decline to adopt revisions to the pro forma LGIP to require
biannual or quarterly cluster study windows, as suggested by Clean
Energy States and Environmental Defense Fund. Based on the record, we
are not convinced that mandating multiple cluster request windows per
year will result in a more efficient cluster study process, especially
considering the various sizes of transmission provider footprints and
interconnection queues. As we adopt an annual cluster study process, an
annual cluster request window will allow transmission providers to
dedicate resources to the cluster request window only once per year,
dedicating their resources to the remainder of the cluster study
process for the rest of the year. We also are not convinced by
Environmental Defense Fund's concern with interconnection customers
missing a cluster request window, as the date of the start of the
cluster request window will be in each transmission provider's LGIP,
providing sufficient notice for prospective interconnection customers
to prepare required application materials accordingly. We do not
believe that additional rules are needed to govern how transmission
providers will inform interconnection customers about the cluster
request window.
228. We disagree with Southern's suggestion that the cluster study
process should only permit transmission providers to conduct one
cluster study at a time (i.e., eliminating the possibility of
conducting multiple cluster studies at any time). Prohibiting the
transmission provider from conducting overlapping cluster studies, in
the instance where it is necessary to process cluster subgroups or to
process delayed studies, would delay the interconnection process for
interconnection customers. We therefore find that this suggestion
[[Page 61053]]
would contribute to more backlogs and uncertainty, as delays to any
cluster study would significantly delay cluster studies for all
remaining interconnection requests in an interconnection queue and
would be insufficient to ensure that interconnection customers are able
to interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner. Transmission providers with the
capacity to conduct multiple cluster studies at a given time should be
permitted to do so to facilitate more effective and efficient
interconnection processes.
229. In response to MISO's concern about posting requirements close
to the conclusion of the cluster request window, we reiterate that we
are extending the length of the customer engagement window from the
proposed 30 calendar days to 60 calendar days, which will allow
transmission providers a total of 60 calendar days from the close of
the cluster request window to post the list of interconnection requests
for that cluster.
230. MISO argues that the Commission should not require any OASIS
posting prior to the interconnection customer's finalization of the
interconnection request because a definitive point of interconnection
would have not yet been selected.\583\ While we recognize MISO's
concern about transmission providers posting interconnection request
information on OASIS that may later change, we find that providing as
much information as possible to interconnection customers early in the
customer engagement window provides important transparency to improve
interconnection queue processing. Providing information about other
interconnection requests that may be studied within the same cluster to
interconnection customers considering whether to execute a cluster
study agreement and to continue with the cluster, may help them
determine the viability of their proposed generating facilities, making
it less likely that interconnection customers will withdraw later in
the cluster study process, triggering delays and restudies and the
associated problems discussed in section II of this final rule.
---------------------------------------------------------------------------
\583\ MISO Initial Comments at 36-37.
---------------------------------------------------------------------------
231. We disagree with Clean Energy States' assertion that a cluster
should be able to be modified in response to interconnection customer
changes or study findings without threatening the interconnection
customer's relative queue priority or paying penalties.\584\ Any
interconnection customer that submits a valid interconnection request
during the customer request window will become part of the cluster, if
the interconnection customer chooses to execute a cluster study
agreement by the end of the customer engagement window. The
transmission provider may not modify the makeup of the cluster or pick
and choose which interconnection customers to keep in the cluster in
the way Clean Energy States describes. We also note that
interconnection customers can request a modification assessment
pursuant to section 4.4 of the pro forma LGIP.
---------------------------------------------------------------------------
\584\ Clean Energy States Initial Comments at 9.
---------------------------------------------------------------------------
232. Regarding the customer engagement window, we adopt the NOPR
proposal to add a new section 3.4.5 (Customer Engagement Window) to the
pro forma LGIP, which provides that, following the close of the cluster
request window, the transmission provider begins a customer engagement
window. Additionally, we modify the proposal to extend the customer
engagement window from 30 calendar days, as proposed, to 60 calendar
days. Under this provision, the transmission provider must post new
cluster information on OASIS with details of each interconnection
request for that cluster, including information on the amount of
interconnection service and the location of the proposed generating
facility, within the first 10 business days of the customer engagement
window. While we extend the customer engagement window from 30 calendar
to 60 calendar days, we retain the proposed 10 business day deadline by
which the transmission provider must post new cluster information on
OASIS. We find that it is more beneficial for interconnection customers
to have this information as early as possible, such that they are able
to assess the composition of the cluster and make informed choices
moving forward with their interconnection requests earlier rather than
later in the customer engagement window. Further, during the customer
engagement window, an interconnection customer may withdraw its
interconnection request without penalty.
233. We extend the customer engagement window to 60 calendar days
in response to numerous commenters' arguments that 30 calendar days is
insufficient to adequately engage with interconnection customers in a
cluster, including based on experience implementing a similar cluster
study process to that we require as part of this final rule.\585\ By
extending the customer engagement window, we provide transmission
providers with additional time to conduct individual meetings with
interconnection customers that submitted interconnection requests
within the cluster request window, lessening the burden on transmission
providers, particularly larger transmission providers such as RTOs/
ISOs.\586\ At the same time, we provide interconnection customers with
more time to consider information collected during this period of
engagement with the transmission provider--including the makeup of the
cluster--and assess the continued viability of their proposed
generating facilities before withdrawal of the interconnection request
will incur a penalty. For example, the interconnection customer can
assess the expected costs of potential network upgrades and the impact
of those costs on the viability of its proposed generating facility in
the context of the size and location of other interconnection requests
in the cluster. Interconnection customers will have 46 calendar days to
consider the posted information (which must be posted within 10
business days after the start of the customer engagement window). Not
only will this longer time period for interconnection customers to
consider whether to withdraw their interconnection requests prior to
the start of the cluster study save interconnection customers'
resources by avoiding future penalties, but it will also result in more
efficient interconnection queue processing with fewer withdrawals later
in the cluster study process--withdrawals that can trigger restudies
and cause the problems discussed in section II of this final rule.
---------------------------------------------------------------------------
\585\ Duke Southeast Utilities Initial Comments at 8; PJM
Initial Comments at 20; Xcel Initial Comments at 21 (citing Pub.
Serv. Co. of Colo., Docket No. ER22-2087-000 (Aug. 9, 2022)
(delegated order)).
\586\ PJM Initial Comments at 20; ISO-NE Initial Comments at 23.
---------------------------------------------------------------------------
234. We reject Southern's suggestion that if an interconnection
request is not deemed valid,\587\ the interconnection request should be
withdrawn from the interconnection queue. Under new section 3.4.5 of
the pro forma LGIP, any interconnection requests not deemed valid at
the close of the customer engagement window will not be included in the
cluster. This provision is designed to ensure that interconnection
customers and transmission providers have sufficient time to conduct
scoping meetings and to discuss and comprehensively evaluate whether
interconnection requests are fully valid during the customer engagement
window. We find that
[[Page 61054]]
forced withdrawals prior to the close of the customer engagement window
could result in potentially valid interconnection requests being
rejected prior to allowing for interconnection customers and
transmission providers to discuss alternative interconnection options,
exchange information that could impact such options, and conduct due
diligence informed by information discussed during the customer
engagement window per the provisions set forth in new pro forma LGIP
section 3.4.6 detailing scoping meetings.
---------------------------------------------------------------------------
\587\ Southern Initial Comments at 37.
---------------------------------------------------------------------------
235. In response to EPSA,\588\ we note that transmission providers
and interconnection customers should always work in a manner that is
fair and nondiscriminatory, including during the customer engagement
window and study agreement negotiation.
---------------------------------------------------------------------------
\588\ EPSA Initial Comments at 7.
---------------------------------------------------------------------------
236. We decline to adopt MISO's suggestion that transmission
providers allow interconnection customers to submit an interconnection
request prior to the beginning of the cluster request window. We note
that the cluster request window is specifically designed to structure
when transmission providers should expect interconnection customers to
submit interconnection requests for assessment. We find that allowing
interconnection request submission prior to the cluster request window
may be burdensome to transmission providers, who would have to dedicate
staff and resources towards assessing the viability of interconnection
requests before the designated request window opening, instead of
concentrating their resources towards the prior stage of the
interconnection process.
237. We agree with Enel's recommendation that the Commission
include language in the pro forma LGIP that, in the cluster study
process, the transmission provider will not post detailed information
about interconnection requests proceeding or withdrawing until all
interconnection requests successfully meet their milestone requirements
to proceed, withdraw, or fail to cure their breach within the specific
cure period. We note that transmission providers are required to post
this information at the conclusion of the cluster request window, at
which point interconnection customers must provide significant
requirements to proceed. We find that maintaining confidentiality early
in the customer engagement window stage is appropriate to reduce
opportunities for developers to gain competitive advantage over others
before interconnection requests have been finalized and accepted by the
transmission provider. We therefore adopt the following modification to
section 3.4.5 of the pro forma LGIP (addition in italics): ``Within ten
(10) Business Days after the close of the Cluster Request Window,
Transmission Provider shall post on its OASIS site a list of
Interconnection Requests for that Cluster. The list shall identify, for
each anonymized Interconnection Request[s]: (1) the requested amount of
Interconnection Service; (2) the location by county and state; (3) the
station or transmission line or lines where the interconnection will be
made; (4) the projected In-Service Date; (5) the type of
Interconnection Service requested; and (6) the type of Generating
Facility or Facilities to be constructed, including fuel types, such as
wind, natural gas, coal, or solar. The transmission provider must
ensure that project information is anonymized and does not reveal the
identity or commercial information of interconnection customers with
submitted requests.'' Further, as discussed below, we modify section
3.4.6 of the pro forma LGIP to require that transmission providers
exercise the use of non-disclosure agreements to maintain
confidentiality of identifying or commercially sensitive information
for all other interconnection customers in a group scoping meeting.
e. Scoping Meeting
i. NOPR Proposal
238. In the NOPR, the Commission proposed to renumber and revise
section 3.4.4 of the pro forma LGIP as section 3.4.6 to provide that,
during the proposed customer engagement window, transmission providers
must hold a scoping meeting with all interconnection customers whose
valid interconnection requests were received in that cluster request
window.\589\ Revised section 3.4.6 of the pro forma LGIP would also
require transmission providers to hold individual customer-specific
scoping meetings, at the interconnection customer's request, which must
be requested by no later than 15 business days after the close of the
cluster request window.
---------------------------------------------------------------------------
\589\ NOPR, 179 FERC ] 61,194 at P 68.
---------------------------------------------------------------------------
ii. Comments
239. MISO supports the Commission requiring individual customer-
specific scoping meetings only when requested by interconnection
customers.\590\ APS agrees that a single scoping meeting with all
interconnection customers in the cluster during the customer engagement
window is beneficial to transmission providers and eases the burden of
scheduling individual meetings with all parties. However, APS has
concerns about security and confidentiality.\591\ APS notes that,
currently, each interconnection customer in the interconnection queue
is provided a queue number that becomes the only identifying
information posted publicly. APS requests that the Commission provide
clarity on whether the requirements to treat additional information as
confidential no longer apply or if there is a form of good utility
practice as it pertains to holding a single scoping meeting without
revealing the identities of the other interconnection customers
involved and some examples thereof.
---------------------------------------------------------------------------
\590\ MISO Initial Comments at 35-36.
\591\ APS Initial Comments at 10.
---------------------------------------------------------------------------
240. MISO expresses concern that the timelines listed in the
customer engagement window for posting information are impractical.
MISO asserts that the Commission should not require a posting so near
the close of the request window because the transmission provider must
devote its resources to reviewing the interconnection requests for
deficiencies.\592\
---------------------------------------------------------------------------
\592\ MISO Initial Comments at 36.
---------------------------------------------------------------------------
241. Enel and AEE argue that the Commission should also require
transmission providers and transmission owners to hold individual,
customer-specific scoping meetings at the request of the
interconnection customer before the customer commits to entering the
cluster.\593\ Enel states that an individual pre-interconnection queue
scoping meeting would be an opportunity for the interconnection
customer to ask basic questions that can help inform economically
significant decisions an interconnection customer faces in deciding to
enter the interconnection queue.\594\ As an alternative to requiring a
pre-interconnection queue meeting, Enel suggests that the Commission
could require transmission providers to maintain an electronic inbox
where prospective interconnection customers could submit
interconnection-related questions and be guaranteed a response in time
to inform decisions on entering the interconnection queue.
---------------------------------------------------------------------------
\593\ AEE Initial Comments at 10; Enel Initial Comments at 10.
\594\ Enel Initial Comments at 10.
---------------------------------------------------------------------------
242. PJM believes that ``grouping kick off meetings'' will reduce
the burden on transmission owners and providers of scheduling and
participating in hundreds of meetings, and the burden on
interconnection customers of waiting
[[Page 61055]]
for their meeting to be scheduled.\595\ PJM requests clarification that
a transmission provider may group requests for this customer engagement
window unless an interconnection customer requests otherwise.
---------------------------------------------------------------------------
\595\ PJM Initial Comments at 20-21.
---------------------------------------------------------------------------
243. Tri-State asks the Commission to consider providing only one
week to schedule the requested individual customer-specific scoping
meeting if the interconnection customer does not request a scoping
meeting until the fifteenth business day.\596\
---------------------------------------------------------------------------
\596\ Tri-State Initial Comments at 27.
---------------------------------------------------------------------------
244. Noting the difficulty of coordinating in-person scoping
meetings, SEIA requests that the Commission clarify that both
generating facility-specific and cluster scoping meetings must provide
the option for interconnection customers to attend via teleconference,
which is currently not available in all regions.\597\ Enel suggests
that, for all scoping meetings, the Commission should require
transmission owners, not just interconnection customers and
transmission providers, to attend; otherwise, Enel continues, there
could be crucial questions that the transmission provider may not be
able to answer.\598\
---------------------------------------------------------------------------
\597\ SEIA Initial Comments at 8.
\598\ Enel Initial Comments at 11.
---------------------------------------------------------------------------
iii. Commission Determination
245. We adopt, in part, the proposed revisions to section 3.4.6 of
the pro forma LGIP, and therefore require that, during the customer
engagement window, transmission providers hold a scoping meeting with
all interconnection customers whose interconnection requests were
received in that cluster request window. We decline to adopt the NOPR
proposal to require transmission providers to hold individual customer-
specific scoping meetings at the interconnection customer's request.
246. These revisions to the pro forma LGIP align the timing and
purpose of scoping meetings between transmission providers and
interconnection customers with the adoption of the cluster study
process in this final rule. We do not believe that providing the option
for interconnection customers to request an individual customer-
specific scoping meeting is necessary to ensure that interconnection
customer-specific questions are answered as interconnection customers
consider whether to remain in the interconnection queue for the cluster
study or to withdraw their interconnection request. We find that this
requirement would be comparatively inefficient and burdensome for
transmission providers, leading to potentially significant
interconnection delays. We thus find that this requirement would be
inconsistent with the goal to ensure that interconnection customers are
able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner. We find that the cluster-
wide scoping meeting is an appropriate forum in which all
interconnection customers can direct questions to transmission
providers in an efficient manner without delaying the cluster process
with unnecessarily time-consuming individual scoping meetings.
247. We agree with APS' concerns pertaining to good utility
practices \599\ for security and confidentiality regarding the
disclosure of potentially sensitive commercial information during the
cluster scoping meeting that will include numerous interconnection
customers in the cluster.\600\ We therefore modify section 3.4.6 of the
pro forma LGIP to require that transmission providers use non-
disclosure agreements to maintain confidentiality of identifying or
commercially sensitive information for all other interconnection
customers in a group scoping meeting until the close of the customer
engagement window.
---------------------------------------------------------------------------
\599\ Good utility practice means ``any of the practices,
methods and acts engaged in or approved by a significant portion of
the electric industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices,
reliability, safety and expedition. Good utility practice is not
intended to be limited to the optimum practice, method, or act to
the exclusion of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region.'' See pro forma
LGIP section 1 (Definitions).
\600\ APS Initial Comments at 10.
---------------------------------------------------------------------------
248. In response to Enel and AEE,\601\ we will not modify the pro
forma LGIP to require transmission providers to hold individual
interconnection customer-specific scoping meetings at the request of
the interconnection customer before the interconnection customer
commits to entering the cluster. As discussed above, we decline to
adopt a requirement that transmission providers conduct individual
interconnection customer scoping meetings. Additionally, as discussed
above,\602\ we adopt the heatmap requirement, which will assist
interconnection customers prior to entering the interconnection queue
in evaluating the viability of their proposed generating facilities,
and we are also permitting interconnection customers to withdraw from
the interconnection queue without penalty prior to the close of the
customer engagement window. With these reforms, we do not believe that
pre-interconnection queue scoping meetings should be required to ensure
just and reasonable rates.
---------------------------------------------------------------------------
\601\ AEE Initial Comments at 10; Enel Initial Comments at 10.
\602\ See supra section III.A.1.c.
---------------------------------------------------------------------------
249. In response to MISO's concern about posting requirements close
to the conclusion of the cluster request window,\603\ we find that
allowing transmission providers a total of 10 business days from the
close of the cluster request window to post the required list of
interconnection requests for that cluster is a reasonable amount of
time.
---------------------------------------------------------------------------
\603\ MISO Initial Comments at 36.
---------------------------------------------------------------------------
250. In response to SEIA,\604\ we decline to modify the pro forma
LGIP to require transmission providers to include an option for
interconnection customers to attend via teleconference for cluster-wide
scoping meetings. We do not believe that such level of logistical
specification governing how transmission providers choose to conduct
scoping meetings with interconnection customers is needed in the pro
forma LGIP.
---------------------------------------------------------------------------
\604\ SEIA Initial Comments at 8.
---------------------------------------------------------------------------
251. In response to Enel,\605\ we decline to modify the pro forma
LGIP to require transmission owners, not just interconnection customers
and transmission providers, to attend scoping meetings. The pro forma
LGIP contemplates that the transmission owner and transmission provider
may be the same entity, except in the case of an RTO/ISO, in which case
the transmission owner does not have operational control of the
facilities and does not perform cluster studies. In the case of an RTO/
ISO, only the entity that independently administers the cluster study
is required to attend the scoping meeting.
---------------------------------------------------------------------------
\605\ Enel Initial Comments at 11.
---------------------------------------------------------------------------
f. Posting of Metrics for Cluster Study Processing Time and Restudy
Processing Time
i. NOPR Proposal
252. In the NOPR, the Commission proposed to revise the
requirements included in section 3.5.2 of the pro forma LGIP to post
metrics for interconnection feasibility study processing time and
system impact study processing time, to instead require transmission
providers to post metrics for cluster study processing time and
[[Page 61056]]
cluster restudy processing time.\606\ The Commission also proposed to
require transmission providers to post the time from when the
transmission provider received a valid interconnection request to the
completion of the cluster study, cluster restudy, and facilities study.
---------------------------------------------------------------------------
\606\ NOPR, 179 FERC ] 61,194 at P 69.
---------------------------------------------------------------------------
253. Specifically, in section 3.5.2.1 of the pro forma LGIP, the
Commission proposed requiring that transmission providers must post the
number of interconnection requests that had cluster studies completed
within the transmission provider's coordinated region during the
reporting quarter that were completed more than 150 calendar days after
the close of the customer engagement window. Similarly, in section
3.5.2.2 of the pro forma LGIP, the Commission proposed requiring that
transmission providers must post the number of interconnection requests
that had cluster restudies completed within the transmission provider's
coordinated region during the reporting quarter that were completed
more than 150 calendar days after the transmission provider's receipt
of the interconnection customer's executed cluster restudy agreement.
254. In section 6.4 of the pro forma LGIP, the Commission proposed
that transmission providers publicly post new metrics requirements on
their websites pertaining to various technical specifications for, and
impacts of, potential generating facilities on the transmission
provider's transmission system, requiring that these metrics must be
updated on the transmission provider's website ``within 30 days after
the completion of each Cluster Study and Cluster Restudy period.''
\607\
---------------------------------------------------------------------------
\607\ Proposed pro forma LGIP section 6.4.
---------------------------------------------------------------------------
ii. Comments
255. Clean Energy Associations support the proposal to require the
posting of metrics for cluster study processing time and cluster
restudy processing time, starting from when the transmission provider
received a valid interconnection request.\608\ Clean Energy
Associations further argue that these reports should also identify the
level of accuracy of these studies relative to final costs.
---------------------------------------------------------------------------
\608\ Clean Energy Associations Initial Comments at 20-21.
---------------------------------------------------------------------------
256. While supportive of the use of metrics that reflect cluster
study and cluster restudy processing time, some commenters do not
support measuring these metrics from the date that the transmission
provider received the interconnection request.\609\ APS argues that
this seems contradictory to the NOPR proposal that the 150-day timeline
to process cluster study requests begins at the end of the customer
engagement window.\610\ MISO asserts that for study metrics to be a
useful measurement of whether a transmission provider is meeting its
tariff deadlines, the start date used in the metrics must reflect when
studies actually commence.\611\ MISO notes that an interconnection
customer may choose to submit its interconnection request weeks ahead
of the cluster request window deadline and that the time between that
deadline and study commencement is variable.\612\ MISO urges the
Commission to allow RTOs/ISOs flexibility to maintain metrics that
reflect their tariff deadlines, especially where the RTO/ISO already
has a Commission-approved cluster study process.
---------------------------------------------------------------------------
\609\ APS Initial Comments at 9; MISO Initial Comments at 37.
\610\ APS Initial Comments at 9.
\611\ MISO Initial Comments at 38.
\612\ Id. (submitting MISO's tariff as an example).
---------------------------------------------------------------------------
257. Ameren contends that if the Commission retains the proposal to
require the posting of the time from when the transmission provider
received a valid interconnection request to the completion of the
cluster study, cluster restudy, and facilities study, it should clarify
that in the context of an RTO/ISO, ``complete'' refers to the final
sign-off by the RTO/ISO.\613\ Ameren asserts that transmission owners
within an RTO/ISO may act on behalf of the RTO/ISO transmission
provider for purposes of certain studies; however, it is the RTO/ISO
and not the transmission owner that decides when a study is complete.
---------------------------------------------------------------------------
\613\ Ameren Initial Comments at 10-11.
---------------------------------------------------------------------------
258. In section 6.4 of the pro forma LGIP, regarding the proposed
requirement that ``[t]hese metrics must be updated within 30 days after
the completion of each Cluster Study and Cluster Re-study period[,]''
Enel recommends that the word ``period'' should be deleted. Enel argues
that the trigger should be the completion of the studies
themselves.\614\
---------------------------------------------------------------------------
\614\ Enel Initial Comments at 83.
---------------------------------------------------------------------------
iii. Commission Determination
259. We adopt the proposed revisions to section 3.5.2 of the pro
forma LGIP to require transmission providers to post metrics for
cluster study processing time and cluster restudy processing time,
including the number of cluster studies completed within 150 calendar
days of the close of the customer engagement window. We modify section
3.5.2.2 of the pro forma LGIP as proposed in the NOPR to be consistent
with the new requirement adopted in section 7.5 of the pro forma LGIP
that cluster restudies should be completed within 150 calendar days of
the transmission provider notifying interconnection customers in the
cluster and that a cluster restudy is required. The requirement to post
these metrics replaces the existing requirement to post metrics for
interconnection feasibility study processing time and system impact
study processing time, which were relevant for the serial study process
but are no longer relevant for the cluster study process required by
this final rule. We therefore believe that these revisions are
necessary to implement the change from a serial study process to the
cluster study process.
260. As for the point at which to begin measuring the metrics,
several commenters argue against using the date on which the
transmission provider received the interconnection requests. We clarify
that sections 3.5.2.1 and 3.5.2.2 of the pro forma LGIP adopted in this
final rule establish that these metrics must be measured from the close
of the customer engagement window for the cluster study processing time
metric and from when transmission provider notifies interconnection
customers in the cluster that a cluster restudy is needed for the
cluster restudy processing time metric. We find that these are
appropriate start dates from which to calculate the metrics because
they reflect when the respective studies are to actually commence.\615\
We decline to grant additional flexibility to maintain metrics and
associated timelines for those metrics, as urged by MISO.\616\
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\615\ APS Initial Comments at 9; MISO Initial Comments at 37-38.
\616\ MISO Initial Comments at 38.
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261. Regarding Clean Energy Associations' suggestion that the
metrics also identify the level of accuracy of studies relative to
final costs,\617\ we decline to adopt this suggestion. For one, it is
unclear to what final costs Clean Energy Associations is referring to.
Additionally, the metrics that we require transmission providers to
post as part of this final rule focus on the timing of interconnection
studies and not on the accuracy of cost estimates. The metrics are
intended, as described in Order No. 845, to provide needed transparency
``to allow interconnection customers to develop informed expectations
about how long the
[[Page 61057]]
interconnection study portion of the process actually takes.'' \618\
---------------------------------------------------------------------------
\617\ Clean Energy Associations Initial Comments at 21.
\618\ Order No. 845, 163 FERC ] 61,043 at P 307.
---------------------------------------------------------------------------
262. We decline to adopt Ameren's suggestion to base the 150-
calendar day cluster study deadline on the RTO/ISO's completion of the
cluster study rather than the transmission owner's completion because
the deadlines are applicable to the transmission provider and such a
clarification is unnecessary to be added to the pro forma LGIP.
263. We agree with Enel's suggestion to modify proposed pro forma
LGIP section 6.4--now pro forma LGIP section 6.1--by deleting
``period'' because, as Enel explains, this would more concisely convey
that the metrics should be updated following the completion of the
studies themselves.\619\
---------------------------------------------------------------------------
\619\ Enel Initial Comments at 83.
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g. Interconnection Request Evaluation Process
i. NOPR Proposal
264. In the NOPR, the Commission proposed several changes to pro
forma LGIP section 4, renamed ``interconnection request evaluation
process'' from ``queue position.'' First, the Commission proposed to
rename and revise section 4.1 of the pro forma LGIP as ``queue
position'' and added two new proposed sections: (1) section 4.1.1
(Assignment of Queue Position), which provides that queue position will
be based on the time and date that the transmission provider receives
all items required under section 3.4 (Valid Interconnection Request)
and that there is no queue priority for interconnection customers that
opted for informational interconnection studies; and (2) section 4.1.2
(Higher Queue Position), which provides that all interconnection
requests studied in a single cluster shall be considered to have equal
queue priority, but clusters initiated earlier in time shall be
considered to have a higher queue position than clusters initiated
later in time.\620\
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\620\ NOPR, 179 FERC ] 61,194 at P 70.
---------------------------------------------------------------------------
265. The Commission also proposed to remove from section 4.2 of the
pro forma LGIP the provisions allowing transmission providers to study
interconnection requests serially and the requirement for transmission
providers to provide 180 calendar days' advance notice before opening a
cluster window.\621\ The Commission also proposed to rename section 4.2
of the pro forma LGIP ``general study process,'' and revise it to
require transmission providers to perform interconnection studies
within the cluster study process.
---------------------------------------------------------------------------
\621\ Id. P 72.
---------------------------------------------------------------------------
266. In the NOPR, the Commission also proposed changes to the
material modification provisions in section 4.4 (Modification) of the
pro forma LGIP to provide that moving a point of interconnection shall
result in a loss of interconnection queue position if it is deemed a
material modification by the transmission provider. Additionally,
proposed additions to pro forma LGIP section 4.4 require that any
identified changes to a planned interconnection, proposed by an
interconnection customer or the transmission provider, must be
acceptable to any impacted interconnection customer in the same
cluster, and such acceptance is not to be unreasonably withheld.\622\
The Commission noted that the interconnection customer may decide to
forego the requested change that constitutes a material modification
and retain its existing queue position.\623\
---------------------------------------------------------------------------
\622\ Proposed pro forma LGIP section 4.4.
\623\ NOPR, 179 FERC ] 61,194 at P 71.
---------------------------------------------------------------------------
267. Further, the Commission proposed to revise section 4.4.1 of
the pro forma LGIP to make clear that: (1) the modifications previously
permitted prior to return of the executed system impact study agreement
are now permitted to be made prior to return of the executed cluster
study agreement; and (2) for generating plant increases, the
incremental increase will be studied with the next cluster study for
purposes of cost allocation and study analysis.\624\ Pro forma LGIP
section 4.4.1 also explicitly permits specific modifications prior to
the interconnection customer's return of the executed cluster study
agreement to the transmission provider, including: (a) a decrease of up
to 60 percent of electrical output (MW) of the proposed project,
through either a decrease in plant size or a decrease in
interconnection service level; (b) modifying the technical parameters
associated with the generating facility technology or step up
transformer; and (c) modifying the interconnection configuration.
---------------------------------------------------------------------------
\624\ Id. P 73.
---------------------------------------------------------------------------
ii. Comments
268. With regards to the proposed changes to section 4.1 (Queue
Position), Tri-State questions whether the proposed definition of queue
position includes surplus interconnection requests.\625\ Xcel argues,
and EEI agrees, that the Commission should modify the proposal to
clarify that queue position or queue priority is based on
interconnection request readiness and not on the date and time the
interconnection request is submitted.\626\
---------------------------------------------------------------------------
\625\ Tri-State Initial Comments at 25.
\626\ EEI Reply Comments at 5; Xcel Initial Comments at 9 n.12.
---------------------------------------------------------------------------
269. CAISO asserts that it is unclear what losing a queue position
means in a cluster-based study (e.g., being withdrawn from the
interconnection queue or moving to a lower interconnection queue
position), but also contends that no specification or reform is
necessary because interconnection customers will simply withdraw the
modification every time if it is found to be material.\627\ CAISO
argues that the Commission should either remove the ``option'' to lose
an interconnection queue position when a proposed modification is found
to be material, or clarify what replaces the interconnection queue
position when it is lost.
---------------------------------------------------------------------------
\627\ CAISO Initial Comments at 11-12.
---------------------------------------------------------------------------
270. Clean Energy States argue that, in addition to the ``signs of
commercial progress'' proposed by the Commission, clusters should be
prioritized for study based on a number of other transparent and
quantifiable factors, such as alignment with state policy (e.g.,
participation in procurement actions), and benefits to low-income,
environmentally impacted, and ``energy communities'' as defined under
the Inflation Reduction Act, state policies, and the Justice40
Initiative.\628\ Clean Energy States assert that clusters could further
be prioritized for development by how well the combined cluster meets
transmission system needs, with preference for interconnection
agreements given to those that result in the lowest cost upgrades, have
the most attractive operational profile, or deliver the best
reliability improvements.
---------------------------------------------------------------------------
\628\ Clean Energy States Initial Comments at 8.
---------------------------------------------------------------------------
271. Regarding the proposed changes to pro forma LGIP section 4.4
(Modifications), Enel argues that the Commission should remove the
proposed language requiring the acceptance of ``any impacted
Interconnection Customer in the same Cluster'' to modify an
interconnection request.\629\ Enel asserts that this requirement not
only will be challenging to facilitate (especially in large clusters)
but is also a redundant and unnecessary hurdle that could result in
anticompetitive behavior. If the Commission keeps this language, to
avoid uncertainty regarding the application of this provision, Enel
proposes to replace this language with ``any Interconnection Customer
in the same Cluster whose interconnection would be delayed or whose
[[Page 61058]]
interconnection-related costs would be increased as a result of the
identified changes.'' \630\
---------------------------------------------------------------------------
\629\ Enel Initial Comments at 19-20.
\630\ Id. at 83.
---------------------------------------------------------------------------
272. A few commenters argue that the Commission should consider
changes to the material modification process such that only certain
modifications trigger a restudy.\631\ Clean Energy Associations
recommend that the Commission modify the current material modification
definition to clearly state that certain changes are presumptively
immaterial, such as changing solar modules or turbines, adding storage
capacity, or making minor adjustments to inverter performance. Clean
Energy Associations argue that this presumption should be in place so
long as planned export and import capacity remains the same.\632\ Clean
Energy Associations also support the concept of expedited, limited
studies for project modifications, provided that: (1) an expedited
approach does not change the level of interconnection service; (2)
there is no impact on cost or timing of an interconnection request that
is lower- or equally queued; and (3) it does not cause any reliability
concern. Additionally, Pattern Energy asserts that, in its experience,
transmission providers apply widely disparate standards where even de
minimis impacts--timing or financial--can be determined to be material,
which Pattern Energy believes is unreasonable and unduly discriminatory
in light of the dynamic nature of the generator interconnection
processes.\633\ Pattern Energy argues that, absent severe delay, timing
delay should not be factored into materiality. Pattern Energy suggests
instead that materiality be tied to financial impact on a proposed
generating facility (or group of proposed generating facilities).
---------------------------------------------------------------------------
\631\ AEP Initial Comments at 18; Clean Energy Associations
Initial Comments at 42; Pattern Energy Initial Comments at 17; PPL
Initial Comments at 11.
\632\ Clean Energy Associations Initial Comments at 42.
\633\ Pattern Energy Initial Comments at 16-17.
---------------------------------------------------------------------------
273. With regard to modifications under proposed pro forma LGIP
section 4.4.1, MISO supports the proposed revisions to avoid proposed
project service level increasing \634\ and other changes disrupting
cluster studies that are in progress or delaying the negotiation and
execution timelines for the LGIA.\635\
---------------------------------------------------------------------------
\634\ We understand MISO to be referring to the NOPR proposal
that clarified that for plant increases, the incremental increase
will be studied with the next cluster study for purposes of cost
allocation and study analysis.
\635\ MISO Initial Comments at 39.
---------------------------------------------------------------------------
274. Enel recommends that the Commission modify the proposed pro
forma LGIP section 4.4.1 language to give interconnection customers
flexibility in the initial stages of interconnection studies,
otherwise, it argues that, interconnection customers are more likely to
work around the rules by submitting multiple smaller interconnection
requests to retain size flexibility after seeing their initial results,
which is more administratively burdensome for transmission providers
and leads to its own form of inefficiency as size reductions come in
the form of withdrawals at any point in the process rather than being
limited to partial reductions prior to entering the cluster
restudy.\636\
---------------------------------------------------------------------------
\636\ Enel Initial Comments at 16-17 (proposing the section be
revised to read: ``Prior to the deadline to return the milestones
listed in Section 7.5 of this LGIP to proceed into the initial
Cluster Re-study, modifications permitted. . . .'').
---------------------------------------------------------------------------
275. CREA and NewSun argue that the Commission should explicitly
permit interconnection customers to modify their interconnection
requests to reduce or eliminate the assignment of network upgrade or
stand alone network upgrade costs associated with a proposed generating
facility after receipt of the first cluster-level interconnection
study.\637\ CREA and NewSun argue that interconnection customers should
be permitted to modify their proposed generating facilities to avoid
impacts on the transmission system that trigger network upgrades by,
for example, reducing their capacity or installing devices that will
limit their output during critical periods.\638\ CREA and NewSun state
that the existing pro forma LGIP allows an interconnection customer to
downsize its interconnection capacity up to 60% upon receipt of the
first interconnection study (i.e., the feasibility study) and before
progressing to the second study (i.e., the system impact study).\639\
CREA and NewSun state that, in contrast, the NOPR proposes to only
allow downsizing to occur before receipt of the first cluster system
impact study and, as a result, the opportunity to downsize the
interconnection request to tailor the facility to the available
capacity identified in the first useful interconnection study would be
lost. Therefore, CREA and NewSun argue that the Commission should
revise the NOPR proposal to ensure that a reasonable amount of
downsizing (e.g., 60%) is permitted after receipt of the first cluster-
level interconnection study.\640\
---------------------------------------------------------------------------
\637\ CREA and NewSun Initial Comments at 45-47.
\638\ Id. at 46.
\639\ Id. (citing NOPR, 179 FERC ] 61,194 at app. B (proposed
pro forma LGIP section 4.4.1)).
\640\ Id. at 47.
---------------------------------------------------------------------------
iii. Commission Determination
276. We adopt the proposed revisions to pro forma LGIP section 4.1
(Queue Position), section 4.2 (General Study Process), and section
4.4.1, and we modify the proposed definition of queue position and the
proposed revisions to the material modification provisions in section
4.4 (Modification). These are discussed below.
277. First, we adopt the proposed revisions to section 4.1 of the
pro forma LGIP (Queue Position), which reflect the impact of the
adoption of the proposed cluster study process in this final rule on
queue position assignments. These revisions provide that transmission
providers must assign queue positions based on the date and time of
receipt of a valid interconnection request, but all interconnection
customers that submit interconnection requests within a cluster request
window must be considered equally queued. Clusters initiated earlier in
time must have a higher queue position than clusters initiated later in
time. Under the existing serial study process in the pro forma LGIP,
queue position had a greater effect on an interconnection customer, for
instance, in the allocation of network upgrade costs. By contrast,
network upgrade costs within a cluster will not be allocated by queue
position; rather, as discussed below, network upgrade costs within a
cluster must be allocated generally through a proportional impact
method among the interconnection customers in the cluster. Given the
nature of the cluster study process, including the nature of the cost
allocation for network upgrades, it is appropriate for all
interconnection customers in a cluster to be considered equally queued.
278. Second, we adopt the proposal to remove from section 4.2 of
the pro forma LGIP the provisions allowing transmission providers to
study interconnection requests serially and the requirement for
transmission providers to provide 180 days' advance notice before
opening a cluster window. We also adopt the proposal to rename section
4.2 of the pro forma LGIP ``General Study Process'' and revise it to
require transmission providers to perform interconnection studies
within the cluster study process. These revisions are necessary to
implement the cluster study process required by this final rule.
279. As requested by Tri-State, we clarify that the definition of
queue
[[Page 61059]]
position is not relevant to surplus interconnection requests, which are
processed outside of the normal interconnection queue, as further
discussed in section III.A.2.n below.
280. We also maintain the language in the pro forma LGIP that
moving a point of interconnection in a way that is deemed a material
modification will impact an interconnection customer's queue position,
but we clarify the meaning of this in the context of the cluster study
process. Specifically, if moving a point of interconnection is deemed
by the transmission provider to be a material modification to the
interconnection request, and the interconnection customer chooses to
proceed with the proposed modification, the interconnection request
will be deemed withdrawn and the interconnection customer must re-enter
the interconnection queue with a new interconnection request, if it
desires to proceed to interconnect. To avoid being deemed withdrawn,
the interconnection customer may choose not to move its point of
interconnection and to instead remain in the same cluster with the
original interconnection request, and, thus, in the same queue
position.
281. In response to CREA and NewSun, we do not opine on whether
moving a point of interconnection within a cluster will be a material
modification. Instead, we leave the determination as to whether it is
deemed a material modification to the transmission provider, as in the
existing process for determining whether a proposed modification is
material.
282. We decline to adopt Clean Energy States' suggestion that, in
addition to the ``signs of commercial progress'' proposed by the
Commission, clusters should be prioritized for study based on other
transparent and quantifiable factors.\641\ Clean Energy States neither
provides sufficient rationale or detail regarding such factors by which
clusters would be prioritized by transmission providers, nor explains
how such prioritization criteria would be determined. We note that the
Commission did not propose alternative factors for consideration.
Additionally, we note that the record lacks adequate discussion in
favor of such prioritization mechanisms or such ``factors'' for the
Commission to consider adopting in this final rule.
---------------------------------------------------------------------------
\641\ Clean Energy States Initial Comments at 8.
---------------------------------------------------------------------------
283. Third, we modify the proposed definition of queue position in
the pro forma LGIP and LGIA to provide that queue position is
established pursuant to section 4.1 of the pro forma LGIP. Fourth, we
modify the proposed revisions to the material modification provisions
in section 4.4 (Modification) of the pro forma LGIP. We adopt the
language that provides that moving a point of interconnection shall
result in a loss of queue position if it is deemed a material
modification by the transmission provider, for the reasons discussed
above. At the same time, we modify the proposed revisions to remove the
requirement to obtain the approval of ``any impacted Interconnection
Customer in the same Cluster.'' \642\ We are persuaded by Enel's
argument that this proposed language in pro forma LGIP section 4.4
should be struck for two reasons. First, we find this language
unnecessary because the point of interconnection could be changed only
if the transmission provider had deemed it to not be a material
modification to the interconnection request. Through this requirement,
the transmission provider's analysis ensures that the change will not
have a material impact on the cost or timing of another interconnection
request in the cluster. Second, although the proposal included the
language ``such acceptance not to be unreasonably withheld,'' we are
still concerned about the potential for anticompetitive behavior to the
extent that other interconnection customers in the cluster could refuse
to accept the point of interconnection change to limit competition. The
interconnection customers within a cluster will be competitors in the
wholesale markets in many, if not all, respects. To ensure competitive
market outcomes, they should not be provided an undue opportunity to
affect the advancement or the costs for a proposed generating facility
of one of their competitors.
---------------------------------------------------------------------------
\642\ Proposed pro forma LGIP section 4.4.
---------------------------------------------------------------------------
284. A number of commenters argue that the Commission should
consider changes to the material modification process such that only
certain modifications trigger a restudy.\643\ We decline to adopt any
of the suggested revisions to the material modification provisions and
restudy triggers in the pro forma LGIP. We did not propose changes
suggested by commenters and do not find the need to adopt such changes
to the material modification provisions to ensure just and reasonable
rates. We believe that the list of permitted modifications in section
4.4 of the pro forma LGIP is appropriate because they allow
interconnection customers a degree of flexibility with respect to
generating facility size, interconnection service level, and specific
generating facility technology that appropriately balances the high
burden to enter the interconnection queue and the lengthy duration of
the interconnection queue, during which external factors may change,
including the introduction of new technology that interconnection
customers may wish to incorporate into their generating facility
design.
---------------------------------------------------------------------------
\643\ AEP Initial Comments at 18; Clean Energy Associations
Initial Comments at 42; Pattern Energy Initial Comments at 17; PPL
Initial Comments at 11.
---------------------------------------------------------------------------
285. Finally, we adopt the proposed revisions to section 4.4.1 of
the pro forma LGIP to make clear that: (1) the modifications previously
permitted prior to the return of the executed system impact study
agreement are now permitted to be made prior to return of the executed
cluster study agreement; and (2) for plant increases, the incremental
increase will be studied with the next cluster study for purposes of
cost allocation and study analysis. We believe that these revisions are
needed to implement the cluster study process adopted to ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner.
Notably, we believe that prior to the return of the executed cluster
study agreement is the appropriate time to permit the modifications
previously permitted prior to the return of the executed system impact
study agreement because these represent approximately the same point of
the interconnection process in a serial study process versus a cluster
study process. For plant increases, we find that it is appropriate to
exclude increases to proposed generating facility size from the cluster
study that is ongoing as any increase to size may create the need for
restudies. By moving the increase to the subsequent cluster, the
interconnection customer can still pursue its requested addition,
albeit on a delayed schedule.
286. We decline to adopt Enel's alternative proposed language that
would allow the same modifications permitted to be made prior to the
executed cluster study agreement to also be permitted before a cluster
restudy. This would not only represent a significant change from the
existing modification language in pro forma LGIP section 4.4.1, but
allowing such modifications at the cluster restudy stage could
negatively affect the integrity of the cluster and cause further
restudies, which would not ensure that interconnection customers are
able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner.
[[Page 61060]]
287. We also decline to adopt the revisions suggested by CREA and
NewSun that would explicitly permit interconnection customers to modify
their interconnection requests to reduce or eliminate the assignment of
network upgrade or stand alone network upgrade costs associated with a
proposed generating facility after receipt of the first cluster-level
interconnection study. The ``loss'' of the opportunity for
interconnection customers to downsize the interconnection request to
tailor the facility to the available capacity identified in the first
useful interconnection study \644\ reflects the nature of moving from a
serial study process, with an initial, high-level feasibility study, to
a cluster study process, with the benefit of a customer engagement
window, potential for shared cost allocation, and lower likelihood of
cascading restudies. Moreover, providing interconnection customers an
opportunity to reduce the size of their proposed generating facilities
after the cluster study would undercut the increased certainty and
efficiency that are key benefits of the shift to a cluster study
process. With the adoption of clusters, a reduction in size that may
eliminate one interconnection customer's cost responsibility for a
network upgrade could affect other interconnection customers in the
cluster, either by increasing their costs or requiring a different
network upgrade. This type of uncertainty could lead to further
reductions, withdrawals, and restudies, and would be insufficient to
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner. We note, however, that interconnection customers may request a
material modification assessment under section 4.4 of the pro forma
LGIP for reductions and that if those reductions are found to not be
material, the interconnection customer may proceed with them without a
loss of queue position.
---------------------------------------------------------------------------
\644\ CREA and NewSun Initial Comments at 46.
---------------------------------------------------------------------------
h. Fewer Than Three Year Extension to Commercial Operation Date
i. NOPR Proposal
288. Currently, if an interconnection customer's generating
facility is delayed by fewer than three years, the pro forma LGIP
states that such extensions are not material and shall be handled
through construction sequencing. However, the pro forma LGIP does not
state the starting point for this fewer than three-year period. In the
NOPR, the Commission proposed to revise section 4.4.5 of the pro forma
LGIP, which currently allows an extension of less than three cumulative
years of the generating facility's commercial operation date, to
require that the commercial operation date reflected in the initial
interconnection request be used in calculating the permissible fewer
than three-year extension.\645\
---------------------------------------------------------------------------
\645\ NOPR, 179 FERC ] 61,194 at P 71.
---------------------------------------------------------------------------
ii. Comments
289. Several commenters contend that the commercial operation dates
set out in the executed LGIA, rather than the date in the initial
interconnection request, are generally more accurate \646\ and provide
more certainty when established at the end of the interconnection study
process as they would include the schedule estimates for network
upgrades,\647\ and the interconnection customer may have greater
control over pursuing its development timeline.\648\
---------------------------------------------------------------------------
\646\ Invenergy Initial Comments at 34; [Oslash]rsted Initial
Comments at 8; Pine Gate Initial Comments at 65.
\647\ [Oslash]rsted Initial Comments at 8.
\648\ Invenergy Initial Comments at 34.
---------------------------------------------------------------------------
290. Invenergy argues that, because assigned upgrades necessary for
interconnection can require more than three years for construction, it
would be reasonable to permit a greater extension right of five years
from the date set out in the LGIA.\649\ Enel also argues that the
Commission should grant a longer extension of time if the transmission
provider's studies are delayed or if more time is required to build
network upgrades because these circumstances are beyond the
interconnection customer's control.\650\ Enel also recommends requiring
the transmission provider to grant a day-for-day delay to the
originally requested commercial operation date for any delays in the
study process relative to the LGIP deadlines as well as due
consideration for network upgrades that require more than 18 months to
design, procure, and construct.
---------------------------------------------------------------------------
\649\ Id.
\650\ Enel Initial Comments at 18-19.
---------------------------------------------------------------------------
291. Ameren and PPL assert that continuing to provide a three-year
extension of the commercial operation date would allow projects to move
forward when they are not ready or viable.\651\ APS believes that
limiting the ability to suspend interconnection requests or extend the
commercial operation date to instances of force majeure, including
where a customer demonstrates specific timeline obstructions such as
permit issuance or supply chain delays, is more in line with the
proposals in the NOPR.\652\
---------------------------------------------------------------------------
\651\ Ameren Initial Comments at 10; PPL Initial Comments at 11.
\652\ APS Initial Comments at 7-8 (citing Midcontinent Indep.
Transmission Sys. Operator, Inc., 120 FERC ] 61,293, at PP 23, 27
(2007)).
---------------------------------------------------------------------------
292. NV Energy seeks clarification on how long an interconnection
customer may extend its commercial operation date because the pro forma
LGIP allows seven to 10 years from the initial interconnection request
to construct.\653\ NV Energy requests clarification on how the three-
year suspension clause in the pro forma LGIA plays into the timeline
for the commercial operation date. Pine Gate argues that any extension
period from the commercial operation date be subject to the overall
seven-year time period for achieving commercial operation.\654\
Invenergy argues that the Commission should also make clear that the
limits on the initial proposed in-service date that can be specified in
an interconnection request to no more than seven years beyond the
interconnection request date, does not limit the ability to take
advantage of commercial operation date extensions that are otherwise
provided under the pro forma LGIP or an LGIA.\655\ For example, some
transmission owners have taken the position that, when exercising a
suspension right, if the suspension would result in an in-service date
greater than seven years after the date specified in the
interconnection request, the interconnection customer cannot use its
full suspension period. Invenergy asserts that the Commission has
already clarified that the interconnection request limitation on
proposed in-service dates is applicable only for the purpose of
limiting the date requested at the application stage, and does not
limit in-service dates that extend beyond that period as a result of
other factors, which would include transmission owner delay, exercise
of suspension, and here, additional commercial operation date
extensions.\656\ Invenergy also states that the Commission should
clarify that its revisions to pro forma LGIP section
[[Page 61061]]
4.4.5 are in addition to, and do not limit, an interconnection
customer's suspension rights under its interconnection agreement.\657\
---------------------------------------------------------------------------
\653\ NV Energy Initial Comments at 5-6. NV Energy states that
it currently has several customers that requested to move well
beyond the three-year time frame and that most of its
interconnection customers use the full seven to 10-year window. Id.
at 6.
\654\ Pine Gate Initial Comments at 65. Pine Gate also
reiterates its comments on the ANOPR, stating that the Commission
should expand the interconnection customer's option to build. Id. at
63 (citing Comments of Pine Gate, Docket No. RM21-17-000, at 9-10
(filed Oct. 12, 2021) (citing Order No. 2003, 104 FERC ] 61,103 at
PP 85, 353)).
\655\ Invenergy Initial Comments at 35 (citing pro forma LGIP
section 3.4.1 and pro forma LGIA art. 5.16).
\656\ Id. (citing Midcontinent Indep. Sys. Operator, Inc., 150
FERC ] 61,180, at P 23 (2015)).
\657\ Id. at 34.
---------------------------------------------------------------------------
iii. Commission Determination
293. We adopt the proposed revisions to section 4.4.5 of the pro
forma LGIP that require that interconnection customers receive an
extension of fewer than three cumulative years of the generating
facility's commercial operation date without requiring them to request
such an extension from the transmission provider. In response to
commenters' concerns, however, we modify our proposal to clarify that
the commercial operation date reflected in the initial interconnection
request shall be used in calculating the permissible fewer than three-
year extension until the interconnection customer executes, or requests
the unexecuted filing of, an LGIA. Once the interconnection customer
has executed an LGIA or requested that the LGIA be filed unexecuted,
the commercial operation date established in the LGIA shall be the date
from which the up to three cumulative years is calculated.
294. At the time the pro forma LGIP was adopted, the
interconnection process was considerably shorter than it is now; the
delays and sizeable interconnection queues facing transmission
providers create a situation where many interconnection customers use
this up to three-year period to ensure that their proposed generating
facilities reach commercial operation. Furthermore, the length of the
interconnection queues is such that at the time an interconnection
customer enters the queue, it may have little idea of how long it will
spend in the interconnection queue before commencement of the
construction of its generating facility and required interconnection
facilities and network upgrades. Thus, we agree with Invenergy,
[Oslash]rsted, and Pine Gate, and we modify our proposal to require the
up to three-year period to commence from the commercial operation date
established in the interconnection customer's LGIA once the LGIA is
executed or the interconnection customer has requested that it be filed
unexecuted with the Commission.
295. We decline commenters' requests to revise the actual length of
the permissible extension of a proposed generating facility's
commercial operation date. The Commission did not propose to change the
length of the permissible extension in the NOPR, and we lack an
adequate record that the existing up to three-year extension is unjust
and unreasonable.
296. Commenters request clarification \658\ of how the changes to
pro forma LGIP section 4.4.5 adopted in this final rule affect other
provisions such as pro forma LGIP section 3.4.2 and pro forma LGIA
article 5.16, which provide for extensions of the in-service date or
suspension of construction.\659\ We reiterate that the revisions to
section 4.4.5 of the pro forma LGIP adopted in this final rule
establish only the starting point for the less than three-year
extension to the commercial operation date. The Commission did not
propose in the NOPR, and we do not adopt in this final rule, changes to
the extension of in-service date provisions in pro forma LGIP section
3.4.2, or to the suspension provision in pro forma LGIA article 5.16.
---------------------------------------------------------------------------
\658\ Invenergy Initial Comments at 35; NV Energy Initial
Comments at 5-6.
\659\ Specifically, pro forma LGIP section 3.4.2 (previously pro
forma LGIP section 3.4.1) provides that the expected in-service date
of the new generating facility or increase in capacity of the
existing generating facility shall not exceed seven years, but may
be extended up to 10 years upon mutual agreement of the transmission
provider and interconnection customer. Pro forma LGIA article 5.16
provides the interconnection customer the right to suspend work by
the transmission provider associated with the construction and
installation of transmission provider's interconnection facilities
and/or network upgrades for up to three years, at which time the
LGIA would be deemed terminated.
---------------------------------------------------------------------------
i. Cluster Study Provisions (Pro Forma LGIP Sections 6, 7)
i. NOPR Proposal
297. As part of the proposed revisions to the pro forma LGIP, the
NOPR proposed to replace section 6 (Interconnection Feasibility Study)
with the new requirements to publicly post interconnection information,
i.e., the ``heatmap'' as discussed above in section III.A.1.c, thereby
removing the entirety of the feasibility study from the pro forma
LGIP.\660\ Furthermore, in the NOPR, the Commission proposed to rename
pro forma LGIP section 7 from ``interconnection system impact study''
to ``cluster study.'' \661\ The Commission proposed revisions to pro
forma LGIP section 7.1 (Cluster Study Agreement) to state that the
transmission provider must tender to each interconnection customer that
submitted a valid interconnection request a cluster study agreement no
later than five business days after the close of the cluster request
window.\662\ The Commission proposed revisions to pro forma LGIP
section 7.2 (Execution of Cluster Study Agreement) to state that if the
interconnection customer does not provide technical data when it
delivers the cluster study agreement, the transmission provider must
notify the interconnection customer of the deficiency within five
business days, and the interconnection customer must cure the
deficiency within 10 business days of receipt of the notice.\663\ The
Commission proposed revisions to pro forma LGIP section 7.3 (Scope of
Cluster Study Agreement) to make clear that the stability analysis,
power flow analysis, and short circuit analysis previously conducted
under the feasibility and system impact studies would be conducted on a
clustered basis.\664\ The Commission also proposed changes to pro forma
LGIP section 7.3 to make clear that, for purposes of determining
necessary interconnection facilities and network upgrades, the cluster
study shall use the level of interconnection service requested by
interconnection customers in the cluster, except where the transmission
provider otherwise determines that it must study the full generating
facility capacity due to safety or reliability concerns. The Commission
proposed revisions to pro forma LGIP section 7.4 (Cluster Study
Procedures) to state that, within 10 business days of simultaneously
furnishing a cluster study report and a draft facilities study
agreement to each interconnection customer within the cluster and
posting such report on OASIS, the transmission provider shall convene
an open meeting to discuss the study results and shall, upon request,
make itself available to meet with individual interconnection customers
after the report is provided.\665\ Pro forma LGIP section 7.4 also
states that the transmission provider must complete the cluster study
within 150 calendar days. The Commission proposed revisions to pro
forma LGIP section 7.5 (Cluster Study Restudies) to state that the
interconnection customer must provide, within 20 calendar days after
the cluster study report meeting, a study deposit, demonstration of
site control, and a commercial readiness demonstration. Pro forma LGIP
section 7.5 also states that the transmission provider must complete
the cluster restudy within 150 calendar days and delineates the steps
the transmission provider must take when a restudy is required or not
required.\666\
---------------------------------------------------------------------------
\660\ Proposed pro forma LGIP section 6.
\661\ NOPR, 179 FERC ] 61,194 at P 74.
\662\ Proposed pro forma LGIP section 7.1.
\663\ Id. at section 7.2.
\664\ Id. at section 7.3.
\665\ Id. at section 7.4.
\666\ Id. at section 7.5.
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[[Page 61062]]
ii. Comments
298. MISO supports the deletion of section 6 of the pro forma LGIP
and the removal of the feasibility study from the pro forma LGIP.\667\
---------------------------------------------------------------------------
\667\ MISO Initial Comments at 40.
---------------------------------------------------------------------------
299. In reference to the proposed revisions to section 7.1 (Cluster
Study Agreement) of the pro forma LGIP, Tri-State stresses that five
business days is a tight time frame to tender a valid cluster study
agreement to each interconnection customer that submitted a valid
interconnection request and argues that this timeline is not feasible
for transmission providers with greater than 50 interconnection
requests submitted in a cluster request window.\668\
---------------------------------------------------------------------------
\668\ Tri-State Initial Comments at 31.
---------------------------------------------------------------------------
300. In reference to the proposed revisions to section 7.2 of the
pro forma LGIP, Tri-State asserts that the Commission needs to confirm
or reiterate that the interconnection request is considered withdrawn
if the interconnection customer does not cure a deficiency identified
by the transmission provider.\669\
---------------------------------------------------------------------------
\669\ Id.
---------------------------------------------------------------------------
301. In reference to the proposed revisions to section 7.3 (Scope
of Cluster Study) of the pro forma LGIP, Tri-State asks the Commission
to add language to address situations with studies pending completion
of higher-queued project cluster studies.\670\
---------------------------------------------------------------------------
\670\ Id.
---------------------------------------------------------------------------
302. Enel proposes an alternative method for performing the cluster
study and restudy to the NOPR proposal.\671\ Enel states that if the
Commission wants to retain the full scope of analyses in the cluster
study, the Commission could require draft power flow analyses to be
provided to interconnection customers part way through the cluster
study. Enel explains that interconnection customers could be granted
the right to reduce interconnection service amounts and make other
changes pursuant to pro forma LGIP section 4.4.1 following receipt of
these results. Enel states that the transmission provider would repeat
the power flow analyses until the queue stabilized, with the motivation
for interconnection customers to make changes in a timely way being
driven by knowledge that once the latter portion of the studies
started, the interconnection customer would lose this flexibility.
---------------------------------------------------------------------------
\671\ Enel Initial Comments at 17.
---------------------------------------------------------------------------
303. In the list of requirements to proceed to the cluster restudy
in proposed revisions to section 7.5 of the pro forma LGIP, Enel
proposes to add ``(d) election of project changes as permitted by LGIP
section 4.4.1.'' \672\
---------------------------------------------------------------------------
\672\ Id.
---------------------------------------------------------------------------
304. In the proposed revisions to section 7.5 of the pro forma
LGIP, Enel suggests removing item (2), which states that if there are
no changes to the composition of the cluster, a cluster restudy is not
required, because it claims that the cluster restudy would always be
required, at least in part, to add short circuit and stability
analyses.
305. With regard to the 150-day cluster study deadline, some
commenters generally support the proposed 150-day deadline to complete
the cluster study.\673\ Enel recommends a reduction in the scope and
schedule of the cluster study to only include power flow analysis and a
short circuit ratio test (to test grid strength and flag potential
inverter instability issues) and suggests that this initial cluster
study be completed in 90 days instead of 150 days.\674\ Enel contends
that, the availability of some information from this first study,
interconnection customers retain more flexibility up to the point of
committing to the initial cluster restudy, which allows interconnection
customers to optimize the characteristics of their proposed generating
facilities, most notably the amount of ERIS and NRIS interconnection
service requested, in response to the results of the study. Enel argues
that early flexibility for optimization of proposed generating
facilities is better than forcing interconnection customers to withdraw
and re-enter the interconnection queue, is less disruptive, and does
not add a year of delay to an interconnection customer completing the
interconnection process.
---------------------------------------------------------------------------
\673\ AEE Initial Comments at 33; Clean Energy Associations
Initial Comments at 20-21; Consumers Energy Initial Comments at 4.
\674\ Enel Initial Comments at 15-16.
---------------------------------------------------------------------------
306. A number of commenters argue that the proposed 150-day
deadline to complete the initial cluster study may be, or is, too short
and recommend a longer study window.\675\ A few commenters also argue
that the study timelines are too short, given the proposal to eliminate
the reasonable efforts standard and impose penalties on transmission
providers that miss those deadlines.\676\ National Grid asserts that
the proposed 150-day deadline may be ``unreasonably condensed'' and
could result in a decline in the quality of the studies, which could
lead to delays.\677\ Specifically, National Grid claims that rushing
the issuance of the cluster study could lead to later amendments or
corrections to certain engineering requirements or cost estimates, that
in turn may lead to later-stage interconnection request withdrawals.
---------------------------------------------------------------------------
\675\ APS Initial Comments at 8; AES Initial Comments at 9; ISO-
NE Initial Comments at 23; National Grid Initial Comments at 13-14;
Tri-State Initial Comments at 10.
\676\ Dominion Initial Comments at 18; Tri-State Initial
Comments at 4.
\677\ National Grid Initial Comments at 13-14.
---------------------------------------------------------------------------
307. Tri-State notes that it currently implements a 270-day system
impact study period, specifically 150 days for phase 1 (power flow,
short circuit, reactive capability) and 120 days for phase 2 (short
circuit, transient stability), and has yet to miss a study
deadline.\678\ Tri-State argues that this time frame allows for a
thorough study process, including coordination with neighboring systems
and the correction of errors found in interconnection customers'
modeling data.
---------------------------------------------------------------------------
\678\ Tri-State Initial Comments at 10.
---------------------------------------------------------------------------
308. AES contends that cluster study timelines should be tailored
to the types of studies being completed at each stage of the respective
cluster.\679\ For example, AES states that steady state analysis takes
less time to complete than dynamic analysis, meaning that a longer time
frame should be afforded for dynamic analysis in the cluster study
process. Accordingly, AES recommends that the Commission adopt a 150-
day general study timeline for cluster studies and restudies (system
impact study-steady state, and short-circuit analysis performed) and a
200-day timeline for facilities studies (dynamic analysis performed).
---------------------------------------------------------------------------
\679\ AES Initial Comments at 9.
---------------------------------------------------------------------------
309. APS requests that the Commission extend the initial study time
frame to 180 days to provide meaningful studies identifying feasible
proposed generating facilities, explaining that the APS transmission
system is situated in such a way that many interconnections are at
jointly owned facilities that require reviews and sign-off from
multiple owners, including non-jurisdictional entities.\680\ APS argues
that 180 days is more prudent for initial studies, with the exception
of specific criteria such as jointly owned facilities, Western
Electricity Coordinating Council (WECC) rated paths, and federally
owned and Tribal lands, for which studies take significantly longer
despite good faith efforts.
---------------------------------------------------------------------------
\680\ APS Initial Comments at 8-9.
---------------------------------------------------------------------------
310. NYTOs and National Grid argue that the proposal is not clear
on which specific steps would be included in the 150-day time frame for
the initial cluster study and argue that certain additional special
studies that a transmission
[[Page 61063]]
provider may need to perform should not be subject to a 150-day time
frame.\681\ NYTOs state that it is unclear when the clock starts for
the proposed 150-day cluster study deadline and how the scope of the
work can be reasonably limited to comply with the 150-day
deadline.\682\ NYTOs argue that transmission providers and transmission
owners should be afforded the flexibility to provide clarifications and
supporting details on compliance.
---------------------------------------------------------------------------
\681\ National Grid Initial Comments at 15; NYTOs Initial
Comments at 15.
\682\ NYTOs Initial Comments at 15.
---------------------------------------------------------------------------
311. Similarly, National Grid notes that certain RTO/ISO
interconnection processes require special supplemental studies in
addition to general system impact studies and that, while the NOPR
recognizes that these studies may be required to ensure reliable
interconnection of new generating facilities, it does not address
whether such studies must be conducted within the proposed 150-day
cluster study window or could be conducted outside of this window.\683\
National Grid argues that the time to complete such special studies
should not be included in the NOPR's proposed 150-day cluster study
window and that the final rule should allow regions to adjust their
overall interconnection timelines to accommodate such region-specific
studies and take into consideration the time required to develop system
models. Finally, National Grid states that the NOPR does not address
whether the 150-day cluster study window includes the time required to
develop system models and base case data for the cluster study.
---------------------------------------------------------------------------
\683\ National Grid Initial Comments at 15.
---------------------------------------------------------------------------
312. Several commenters recommend that the Commission provide
transmission providers with flexibility to specify study
timelines.\684\
---------------------------------------------------------------------------
\684\ AEP Initial Comments at 17-18; APPA-LPPC Initial Comments
at 21; Avangrid Initial Comments at 13; Bonneville Initial Comments
at 16; CAISO Initial Comments at 11; Dominion Initial Comments at
16-17; Indicated PJM TOs Reply Comments at 39; ISO-NE Initial
Comments at 35-37; NYISO Initial Comments at 29, 33; NY Commission
and NYSERDA Initial Comments at 5; NYTOs Initial Comments at 14;
SEIA Reply Comments at 6.
---------------------------------------------------------------------------
313. Regarding the 150-day cluster restudy deadline, several
commenters agree that the 150-day deadline is reasonable for a cluster
restudy.\685\ Other commenters oppose the 150-day deadline. Bonneville
argues that the proposed requirement to conduct a cluster restudy
within 150 days is unworkable because the complexity of the cluster
restudy would vary and directly impact the completion timeline.\686\
Therefore, Bonneville seeks a longer time frame.
---------------------------------------------------------------------------
\685\ AES Initial Comment at 11; APS Initial Comments at 8; ISO-
NE Initial Comments at 23.
\686\ Bonneville Initial Comments at 9.
---------------------------------------------------------------------------
314. On the other hand, several commenters argue that the deadline
to conduct a cluster restudy should be shorter.\687\ AES recommends
that the Commission instead require transmission providers to include
restudies and model rebuilds between cluster study phases, and to
require that the timeline for such model rebuilds and restudies cannot
be greater than 90 days.\688\ Enel similarly asserts that if the
Commission leaves the cluster study timeline at 150 days and does not
change the study scope, the timeline for cluster restudies should be 90
days.\689\
---------------------------------------------------------------------------
\687\ AEE Initial Comments at 33; Clean Energy Associations
Initial Comments at 42; Cypress Creek Initial Comments at 18.
\688\ AES Initial Comments at 11.
\689\ Enel Initial Comments at 83.
---------------------------------------------------------------------------
315. A few commenters argue that a 30-day window per restudy is
more reasonable because network models are already built, and therefore
substantially fewer staff resources should be required than for the
initial study.\690\ Cypress Creek adds that a shorter restudy window
will also help avoid potential delays in a cluster study process in
which multiple restudies are required.\691\ AEE also recommends that
the Commission limit interconnection restudy timelines to 30 days,
arguing that this will encourage transmission providers to treat
customers in interconnection restudy with the same urgency as customers
in the initial interconnection study, eliminating the possibility of
asymmetric treatment of interconnection customers and alleviating
interconnection queue congestion by moving those interconnection
customers that have been in the interconnection queue the longest to
study completion.\692\
---------------------------------------------------------------------------
\690\ AEE Reply Comments at 11-12; Clean Energy Associations
Initial Comments at 42; Cypress Creek Initial Comments at 18; SEIA
Initial Comments at 8.
\691\ Cypress Creek Initial Comments at 18.
\692\ AEE Initial Comments at 33.
---------------------------------------------------------------------------
iii. Commission Determination
316. We adopt the proposed deletion of the feasibility study as
effectuated by the replacement of the current section 6
(Interconnection Feasibility Study) of the pro forma LGIP with the new
heatmap requirements, as discussed in section III.A.1.c. The move from
a serial interconnection process to the new cluster study process,
coupled with the Commission's heatmap requirements, render the
feasibility study redundant at best and an unnecessary burden on
transmission provider resources. As discussed in section III.A.1.c,
above, we find that the publicly available information required by this
final rule will provide the appropriate level of pre-interconnection
queue information for interconnection customers to make informed
choices.
317. We also adopt, with one modification, the proposed revisions
to section 7 of the pro forma LGIP that rename it ``cluster study''
instead of ``interconnection system impact study,'' which set out the
requirements and scope of the cluster study agreement, as well as the
cluster study and restudy procedures. These revisions reflect the
adoption of the cluster study process set forth in this final rule by
making clear that the interconnection studies that transmission
providers previously performed as part of the serial system impact
studies (i.e., stability analysis, power flow analysis, and short
circuit analysis) must now be conducted on a clustered basis. As
discussed further in section III.A.6 of this final rule, pro forma LGIP
section 7.5 is modified to remove the requirement to provide an initial
study deposit that would have been applied towards the cost of the
cluster study process.
318. We are not persuaded by Tri-State's concern that five business
days after the close of the cluster request window is too short a time
frame for a transmission provider to tender a cluster study agreement
to each interconnection customer. Transmission providers may start to
prepare cluster study agreements before the close of the cluster
request window, as the overall terms and conditions of the cluster
study agreement are standardized so that a transmission provider need
not engage in rewriting each agreement before tendering a draft to the
interconnection customer.
319. In response to Tri-State's comments concerning section 7.2 of
the pro forma LGIP, we confirm that an interconnection request is
considered withdrawn if the interconnection customer does not cure
deficiencies identified by the transmission provider. We note that
under new section 3.4.4 of the pro forma LGIP, if a transmission
provider identifies that an interconnection customer's technical data
are incomplete or contain errors, both parties must ``work
expeditiously and in good faith to remedy such issues,'' but the
failure by the interconnection customer to provide the missing data or
correct data errors will be treated as a withdrawal and dealt with
under pro forma LGIP section 3.7 (Withdrawal).
320. In reference to Tri-State's comments on the proposed revisions
to
[[Page 61064]]
section 7.3 of the pro forma LGIP, we decline to add language to
address situations with studies pending completion of higher-queued
project cluster studies because Tri-State's comments are unclear as to
what additional language may be needed.
321. We decline to adopt the alternative methods to perform cluster
studies and restudies suggested by Enel. The current pro forma LGIP
does not prescribe particular study methods and instead provides
discretion to transmission providers to determine the particular
methods of study appropriate for their transmission systems. We do not,
based on the record in this proceeding, find a basis to determine that
existing study methods are unjust, unreasonable, and unduly
discriminatory or preferential. We also decline to add Enel's suggested
section (d) to section 7.5 of the pro forma LGIP. Pro forma LGIP
section 4.4.1 contains the modifications permitted to an
interconnection request prior to the return of an executed cluster
study agreement, which predates any potential cluster restudy. We
further note that the record does not support Enel's modification
request.
322. We decline to adopt the provision requiring transmission
providers to hold cluster study report meetings with individual
customers as proposed in section 7.4 of the pro forma LGIP. We find
that the individual meetings would be unnecessary, and that individual
customers should utilize the group cluster study report meeting as a
more efficient forum in which to address any questions or concerns
pertaining to the cluster study report. We also find that requiring
transmission providers to conduct individual meetings would impose
unnecessarily burdensome additional requirements on transmission
providers and would be insufficient to ensure that interconnection
customers are able to interconnect to the transmission system in a
reliable, efficient, transparent, and timely manner.
323. Also, we decline to remove proposed section 7.5(2) of the pro
forma LGIP, as suggested by Enel. Contrary to Enel's claim, pro forma
LGIP section 7.3 establishes that the cluster study will consist of
short circuit and stability analyses; therefore, we disagree with Enel
that a cluster restudy will be needed in all cases to perform the short
circuit and stability analyses. Section 7.5(2) states that if there are
no changes to the composition of the cluster, a cluster restudy is not
required. We find that this is appropriate as it prevents the
transmission provider from performing an unnecessary restudy if no
conditions have changed after the first cluster study. This will
increase efficiency, free up the transmission provider's resources to
perform other studies, and increase the speed of interconnection,
ensuring that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner.
324. Based on the record, we find that a 150-calendar day cluster
study deadline provides a sufficient time to allow transmission
providers to perform the stability analyses, power flow analyses, and
short circuit analyses required in the cluster study process for
complex clusters consisting of numerous interconnection requests. We
find that the 150-calendar day time frame balances providing
transmission providers with sufficient time to perform these technical
cluster studies while providing certainty about the timeline for the
interconnection process and ensuring that cluster studies progress in a
timely manner. We note that depending on the cluster size, cluster
studies may not always consume the entire 150 calendar days, and if a
cluster study is complete prior to this deadline, transmission
providers have flexibility to provide the cluster study report at that
time prior to the deadline indicated in its LGIP and commence any
necessary restudies or move to the facilities study phase. We also note
that if a transmission provider progresses to the next study phase
prior to the deadline indicated in its LGIP, the transmission provider
must post any changes on its website or OASIS.
325. We disagree with Enel's suggestion to reduce the scope and
schedule of the cluster study in the proposed pro forma LGIP. The
cluster study represents the first time the interconnection customer
will obtain information about its potential interconnection costs. At
this point, interconnection customers will have to make significant
financial decisions about whether to remain in the interconnection
queue. The information provided in the cluster study report will likely
dictate that decision, and we find that the scope of the study is
appropriate to allow interconnection customers to make these types of
decisions and evaluate whether they will face significant risk. Given
that we decline to reduce the scope of the study, we find Enel's
request to reduce the timeline overly restrictive. Enel's proposal
would create significant burden on transmission providers to perform
complex studies in an even shorter timeline, and we therefore decline
to adopt it.
326. We also disagree with commenters that argue that the 150-
calendar day time frame to complete the cluster study is too short. As
discussed above, numerous commenters agree with the Commission's
conclusion that the significant interconnection queue backlogs create
uncertainty and risk in bringing new generating facilities online,
rendering Commission-jurisdictional rates unjust and unreasonable.
While we have extended the timeline from that provided in the
individual serial study process, we believe that 150 calendar days is a
reasonable extension to account for the more complex study. We also
note that transmission providers will be conducting only one
interconnection study, or at most a small number of interconnection
studies, at a time, allowing them to devote more resources to
completing the studies in a timely manner. Thus, on balance, we believe
that 150 calendar days represents an appropriate and reasonable
timeline on which transmission providers must complete initial cluster
studies.
327. We disagree with NYTOs that it is not clear as to when the
clock starts for the proposed 150-calendar day cluster study deadline,
as proposed pro forma LGIP section 7.3 contains this information (150
calendar days from the close of the customer engagement window). We
also disagree with NYTOs' statement that it is not clear how the scope
of the work can be reasonably limited to comply with the 150-calendar
day deadline, as we are not proposing to limit the scope of work
necessary to effectively run a cluster study. As discussed above, we
find that the 150-calendar day cluster study deadline, combined with
the fewer necessary studies, provides a reasonable amount of time to
allow transmission providers to perform the required studies.
328. In response to National Grid's concern that some RTO/ISO
interconnection processes require supplemental studies and that these
studies should not be required to be conducted within the 150-calendar
day cluster study window, we decline to modify the pro forma LGIP to
provide for more time for such studies. We also clarify for National
Grid that the 150-calendar day deadline includes the time required to
develop system models and base case data for the cluster study.
329. Regarding the 150-calendar day cluster restudy deadline, we
agree with commenters that the proposed 150-calendar day deadline is
reasonable for a cluster restudy. We acknowledge that some commenters
argue that 150 calendar days is too short, while others argue that it
is too long. On balance, we
[[Page 61065]]
find that 150 calendar days is a just and reasonable time frame for
purposes of the pro forma LGIP that allows transmission providers to
conduct potentially complex restudies for instances in which larger
clusters experience multiple withdrawals and/or modifications.
330. In response to commenters' arguments that a 150-calendar day
restudy deadline is too long, we note that if transmission providers
complete the cluster restudy prior to the full 150-calendar day period
elapsing, transmission providers may move to the facilities study stage
at that time. As such, the adopted 150-calendar day cluster restudy
time frame accommodates more complex instances of cluster restudies
while still allowing flexibility for transmission providers to move
forward without waiting for the deadline to pass if the restudy does
not take the full 150 calendar days.
331. Additionally, we decline to adopt suggestions to allow
transmission providers flexibility to set their own study
deadlines,\693\ which would undermine the purpose of ensuring that
transmission providers complete interconnection studies by standard
deadlines prescribed by their tariffs and would thus be insufficient to
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner.
---------------------------------------------------------------------------
\693\ AEP Initial Comments at 17-18; APPA-LPPC Initial Comments
at 21; Avangrid Initial Comments at 13; Bonneville Initial Comments
at 16; CAISO Initial Comments at 11; Dominion Initial Comments at
16-17; Indicated PJM TOs Reply Comments at 39; ISO-NE Initial
Comments at 35-37; NYISO Initial Comments at 29, 33; NY Commission
and NYSERDA at 5; NYTOs Initial Comments at 14; SEIA Reply Comments
at 6.
---------------------------------------------------------------------------
j. Restudies Triggered by Higher- or Equally Queued Generating Facility
i. NOPR Proposal
332. In the NOPR, the Commission proposed to revise section 8.5
(Restudy) of the pro forma LGIP to make clear that restudies can be
triggered by a higher- or equally queued interconnection request
withdrawing from the interconnection queue or modification of a higher-
or equally queued interconnection request pursuant to section 4.4
(Modifications) of the pro forma LGIP.\694\
---------------------------------------------------------------------------
\694\ NOPR, 179 FERC ] 61,194 at P 75.
---------------------------------------------------------------------------
ii. Comments
333. Shell argues the withdrawal of an interconnection request
should not automatically trigger a cluster restudy, and instead the
Commission should consider a process and cost allocation method that
creates a ``secondary market'' to replace a proposed generating
facility that withdraws with another generating facility in the same
location or nearby.\695\ CREA and NewSun agree with Shell's suggestion
to allow interconnection customers to step in and assume the rights of
any interconnection customer that withdraws its interconnection
request.\696\ Similarly, R Street argues that the cluster study process
should not impede the transfer of interconnection request
``ownership,'' as, according to R Street, allowing parties to trade
will help ensure an efficient balance between generation additions and
transmission interconnection costs.\697\
---------------------------------------------------------------------------
\695\ Shell Initial Comments, app. A at i.
\696\ CREA and NewSun Reply Comments at 10.
\697\ R Street Initial Comments at 11.
---------------------------------------------------------------------------
334. MISO seeks clarification on the trigger for restudies. MISO
states that its understanding is that any modification during its study
process that is found to be material would not be allowed.\698\
Further, MISO contends that allowing a material modification to impact
an equally queued interconnection customer seems to be inconsistent
with the Commission's proposal to modify the definition of material
modification.\699\ Therefore, MISO argues that there should not be a
need for a restudy due to such modification. MISO asserts that the
Commission should not allow modifications during the study process that
materially impact other interconnection customers and may require
restudies.
---------------------------------------------------------------------------
\698\ MISO Initial Comments at 40.
\699\ Id. (referencing NOPR, 179 FERC ] 61,194 at P 65).
---------------------------------------------------------------------------
iii. Commission Determination
335. We adopt the proposed revisions to section 8.5 of the pro
forma LGIP to make clear that restudies can be triggered by a
withdrawal or modification by a higher- or equally queued
interconnection request. First, we clarify that the ``modification'' we
refer to in this section must be explicitly permitted under pro forma
LGIP section 4.4. Any other modification that triggered a restudy would
be found to be material and would not be allowed, as it would affect
the cost and/or timing of the other customers in the interconnection
queue by necessitating a restudy. Next, we find that restudies may be
triggered if there is either a withdrawal or a modification explicitly
permitted under pro forma LGIP section 4.4. Changes to the composition
of the cluster often require the transmission provider to restudy the
entire cluster to ensure that all network upgrades and the associated
costs are still needed. Finally, we find that stating that restudy may
be required due to the withdrawal or modification of a higher- or
equally queued interconnection request, rather than requiring that a
restudy must occur, provides the transmission provider with flexibility
to assess whether the restudy is necessary. If the transmission
provider is able to move forward without performing a full restudy,
that is a preferable outcome in terms of interconnection queue
efficiency, as the transmission provider can maintain the study
milestones already achieved and maintain progress towards completion
and operation for generating facilities in the cluster, as opposed to
dedicating significant additional time required to restart and conduct
the study process over again when it may not be necessary or beneficial
to do so.
336. In response to Shell, CREA and NewSun, and R Street, we
decline to consider modifications to the pro forma LGIP to create a
``secondary market'' process that would allow one generating facility
to replace a similarly situated one that withdraws from the
interconnection queue, where that withdrawal would otherwise trigger a
restudy. The Commission did not propose such a process in the NOPR, and
we do not have a sufficient record to consider adopting such a process
in this final rule.
337. In response to MISO, we clarify that material modifications
are defined in section 1 of the pro forma LGIP as modifications that
have a material impact on the cost or timing of any interconnection
request with an equal or later queue position. Under section 4.4.3 of
the pro forma LGIP, if an interconnection customer chooses to move
forward with the modification that has been deemed material by the
transmission provider, the interconnection customer will lose its queue
position and must proceed with a new interconnection request if
desired. However, we note that certain modifications as listed in pro
forma LGIP sections 4.4.1, 4.4.2, and 4.4.5 are permitted regardless of
their impact on other interconnection customers.
k. Timing of LGIA Tender, Execution, and Filing
i. NOPR Proposal
338. In the NOPR, the Commission proposed to revise sections 11.1
(Tender) and 11.3 (Execution and Filing) of the pro forma LGIP, which
include provisions related to the tender, execution, and filing of the
LGIA, to incorporate a 60 calendar-day
[[Page 61066]]
negotiation period and to incorporate the site control demonstrations
and LGIA deposit provisions included in proposed section 3 of the pro
forma LGIP.\700\
---------------------------------------------------------------------------
\700\ NOPR, 179 FERC ] 61,194 at P 76.
---------------------------------------------------------------------------
ii. Comments
339. Enel states that many transmission providers and
interconnection customers are confused as to how to interpret pro forma
LGIP sections 11.1 and 11.2 in relation to each other, and Enel thus
recommends that the Commission revise and simplify sections 11.1 and
11.2 of the pro forma LGIP to provide more clarity.\701\ Enel argues
that additional changes are needed to address common delays in
completion of the final facilities study report; delays in a
transmission provider issuing the draft LGIA; and delays in the
transmission provider executing the LGIA after receiving the
interconnection customer's signature and milestones, and subsequently
proposes targeted revisions to pro forma LGIP sections 11.1 and 11.2 to
provide additional time for interconnection customers to review and
negotiate LGIAs.\702\
---------------------------------------------------------------------------
\701\ Enel Initial Comments at 13-14.
\702\ Id. at 14-15.
---------------------------------------------------------------------------
340. Tri-State notes that section 11.3 of the pro forma LGIP is
unclear when it states that the ``Transmission Provider must not
suspend the LGIA'' until the interconnection customer meets the tariff
requirements because it is the interconnection customer that has the
ability to suspend a proposed generating facility.\703\
---------------------------------------------------------------------------
\703\ Tri-State Initial Comments at 32.
---------------------------------------------------------------------------
341. APS requests that the Commission be more prescriptive on what
is considered reasonable evidence of achieving development milestones
when executing an LGIA in the same manner that the Commission defines
commercial readiness milestones in order to avoid subjectivity and
potential disagreements regarding what is considered ``reasonable.''
\704\ APS also asserts that the reference to simultaneous submission of
the interconnection customer-executed LGIA and the continued
demonstration of site control is duplicative and unnecessary if an
interconnection customer demonstrates site control at the time an
interconnection request is made.
---------------------------------------------------------------------------
\704\ ASP Initial Comments at 7.
---------------------------------------------------------------------------
342. Hydropower Commenters contend that the Commission should
provide additional time for payment of interconnection costs after the
interconnection process is complete.\705\ Hydropower Commenters assert
that once a transmission provider delivers the interconnection
agreement and construction agreement to the interconnection customer,
the interconnection customer has only 60 days to execute the agreements
and 15 business days after receipt of the signed agreements to
demonstrate site control or post a non-refundable additional security
deposit to cover the interconnection costs. Hydropower Commenters argue
that, because the end of the study process may occur long before a
proposed generating facility is fully funded, and the interconnection
customer risks losing its queue position if it does not execute the
agreements, the Commission should extend this period to at least one
year so the interconnection customer has time to secure funding and
avoids having to restart the interconnection process.
---------------------------------------------------------------------------
\705\ Hydropower Commenters Initial Comments at 18.
---------------------------------------------------------------------------
343. NV Energy similarly suggests changes to the NOPR proposal to
allow interconnection customers that request a transmission provider to
file an unexecuted LGIA to satisfy these requirements within 15 days of
the Commission issuing an order. NV Energy states that the proposed
extra time between receiving a draft LGIA and having to satisfy these
requirements creates an undue preferential advantage for those
interconnection customers that request unexecuted LGIAs to be filed at
the Commission and could delay the interconnection process for
others.\706\ To address this issue, NV Energy suggests that
interconnection customers who choose to have their unexecuted LGIAs
filed with the Commission should be required to submit their data to
the transmission provider by the day after the filing of the LGIA.
---------------------------------------------------------------------------
\706\ NV Energy Initial Comments at 20.
---------------------------------------------------------------------------
iii. Commission Determination
344. We adopt, in part, and modify, in part, the proposal to revise
sections 11.1 and 11.3 of the pro forma LGIP, regarding the tendering,
execution, and filing of the LGIA, to incorporate a 60-calendar day
negotiation period and to incorporate the site control demonstrations
and LGIA deposit provisions included in proposed section 3 of the pro
forma LGIP. We find that the revisions to section 11.1 of the pro forma
LGIP that we adopt herein clarify the process of tendering an LGIA and
the revisions to section 11.3 of the pro forma LGIP that we adopt
herein incorporate the site control and LGIA deposit provisions adopted
elsewhere in this final rule.
345. We do not adopt the proposed revisions to pro forma LGIP
section 11.3 that reference the commercial readiness demonstration
provisions of proposed section 8.1 of the pro forma LGIP because we are
not adopting those provisions, as discussed below in section III.A.6.
346. We modify the proposed revisions to pro forma LGIP section
11.3, as requested by Tri-State, because we agree that the proposal was
unclear when it stated that ``Transmission Provider must not suspend
the LGIA under LGIA article 5.16'' until the interconnection customer
meets certain tariff requirements. We modify pro forma LGIP section
11.3 to instead state: ``Interconnection Customer may not request to
suspend its LGIA under LGIA Article 5.16 until Interconnection
Customer'' meets certain tariff requirements. This reflects the fact
that it is the interconnection customer, not the transmission provider,
that has the right to suspend the LGIA.
347. We also modify proposed section 11.3 of the pro forma LGIP in
response to NV Energy's concerns about favoring interconnection
customers that request a transmission provider to file an unexecuted
LGIA. We agree that the proposal has the potential to encourage more
filings of unexecuted LGIAs simply to delay the due date for submission
of deposits, evidence of site control, and milestone progress data. We
therefore modify the proposal such that interconnection customers that
request a transmission provider to file an unexecuted LGIA must satisfy
these submission requirements within 10 business days after the date of
the filing of the unexecuted LGIA with the Commission.
348. We decline to make further modifications to the proposal
beyond those discussed above. Enel has neither explained why pro forma
LGIP sections 11.1, as revised by this final rule, and 11.2, cause an
unjust and unreasonable result for interconnection customers, nor has
it explained why changes to the negotiation process between
transmission providers and interconnection customers are needed at this
time.
349. Similarly, we decline APS' request that the Commission be
``more prescriptive'' on what is considered reasonable evidence of
achieving development milestones when executing an LGIA. We believe
that the requirement that interconnection customers provide reasonable
evidence is sufficient to ensure just and reasonable rates without
imposing detailed requirements surrounding the meaning of
``reasonable.'' There is inadequate record to demonstrate a more
prescriptive approach is needed.
[[Page 61067]]
For example, development milestones generally involve the execution of
contracts or applications for permits.
350. We also decline to adopt Hydropower Commenters' request to
modify the pro forma LGIP to provide additional time for payment of
interconnection costs after the conclusion of the interconnection study
process. The pro forma LGIP, as modified by this final rule, requires
transmission providers to give interconnection customers ample notice
of costs and the timing that costs are due as part of the
interconnection process so that interconnection customers can secure
funding for a proposed generating facility. We are unpersuaded that
interconnection customers should have additional time beyond that
already provided, especially given the number of generating facilities
that have been developed using the existing process and the added
transparency that we adopt in this final rule that will only serve to
improve the ability of interconnection customers to secure financing.
l. Cluster Subgroups
i. NOPR Proposal
351. In the NOPR, the Commission sought comment on whether to
require transmission providers to conduct cluster studies on subgroups
of interconnection customers based on areas of geographic and electric
relevance, and, if so, whether to adopt provisions governing how
cluster areas should be formed to ensure that cluster areas are formed
in a transparent and not unduly discriminatory manner.\707\
---------------------------------------------------------------------------
\707\ NOPR, 179 FERC ] 61,194 at P 77.
---------------------------------------------------------------------------
ii. Comments
352. A number of commenters support permitting transmission
providers to study clusters in subgroups based on geographic or
electrical relevance,\708\ but some argue that clustering projects in
subgroups should not be required.\709\
---------------------------------------------------------------------------
\708\ APS Initial Comments at 9; ClearPath Initial Comments at
7; NARUC Initial Comments at 6; NextEra Initial Comments at 14-15;
[Oslash]rsted Initial Comments at 8; PacifiCorp Initial Comments at
17; Pennsylvania Commission Initial Comments at 8.
\709\ APS Initial Comments at 9; Indicated PJM TOs Initial
Comments at 18; NextEra Initial Comments at 15; PJM Initial Comments
at 22.
---------------------------------------------------------------------------
353. Several entities argue that clustering around subgroups of
geographic or electrical relevance is a reasonable approach,
particularly for transmission providers with a large or fragmented
footprint.\710\ Some commenters argue that creating sub-clusters may
not make sense for transmission providers with small footprints.\711\
Several commenters argue that transmission providers should have
flexibility in deciding whether to form subgroups of interconnection
customers because geographic and electric relevance will vary with each
cluster study.\712\ Similarly, some commenters contend that the
Commission should not mandate studying subgroups based on geographic
and electric relevance, and that the efficacy of this approach should
instead first be evaluated through experience.\713\
---------------------------------------------------------------------------
\710\ Illinois Commission Initial Comments at 5; NextEra Initial
Comments at 14-15; PacifiCorp Initial Comments at 18; Pennsylvania
Commission Initial Comments at 8.
\711\ NRECA Initial Comments at 19; Tri-State Initial Comments
at 11.
\712\ Bonneville Initial Comments at 8-9; ClearPath Initial
Comments at 8; ENGIE Reply Comments at 2; Fervo Energy Reply Comment
at 4; Indicated PJM TOs Initial Comments at 18; SEIA Reply Comments
at 6.
\713\ AES Initial Comments at 10; PJM Initial Comments at 22.
---------------------------------------------------------------------------
354. PacifiCorp notes that using cluster study areas allows it to
assess and more efficiently allocate the costs of network upgrades to
requesters triggering the improvements and protect interconnection
customers in different clusters from bearing the cost of network
upgrades triggered by interconnection customers in different parts of
PacifiCorp's system, thereby facilitating more expedient processing of
all the cluster studies.\714\ PacifiCorp asserts that its ability to
create cluster areas where appropriate is a critical feature of its
cluster study process, adding that cluster areas can facilitate
expedient processing of interconnection requests that might otherwise
be delayed due to restudies or other study complications.\715\
---------------------------------------------------------------------------
\714\ PacifiCorp Initial Comments at 18-19.
\715\ Id. at 17.
---------------------------------------------------------------------------
355. On the other hand, Pattern Energy asserts that designating
subregions may result in separate geographic regions bearing a
disproportionate share of network upgrade costs that provide regional
benefits and should be subject to regional cost allocations.\716\
Pattern Energy notes that it is also important for the transmission
provider to review subregional cluster study results and determine
whether inter-cluster network upgrades would better serve the needs of
the subregional clusters during each planning cycle. Illinois
Commission asserts that interconnection requests that are near one
another might have a greater impact on each other, and subgroups could
ease the study process, but any subgroup process should not compromise
cost or timing efficiency gains that the clustering process is meant to
address.\717\ OPSI argues that to reduce the ``first mover
disadvantage'' most effectively, the Commission should continue to
analyze and further explain in any final rule whether a region-wide,
annual cluster in a large region like PJM could benefit from better
defined subclusters.\718\ OPSI asserts that the Commission should
further evaluate methods to ensure that clusters facilitate
identification of shared network upgrades by grouping generating
facilities based on areas of geographic and electrical relevance.
---------------------------------------------------------------------------
\716\ Pattern Energy Initial Comments at 16.
\717\ Illinois Commission Initial Comments at 5.
\718\ OPSI Initial Comments at 4.
---------------------------------------------------------------------------
356. Avangrid contends that the open call cluster request window
should have geographic distinctions, but that if the open call results
in only one interconnection request in a particular area of the system
electrically, this interconnection should be able to undergo a process
reminiscent of current serial study processes in a parallel track if it
will influence, or be influenced by, the broader cluster study
process.\719\
---------------------------------------------------------------------------
\719\ Avangrid Initial Comments at 12.
---------------------------------------------------------------------------
357. Some commenters argue that the Commission should set forth
specific mandates to transmission providers on how cluster areas should
be formed.\720\ CREA and NewSun argue that clear mandates would prevent
transmission providers from subgrouping as a means to engage in anti-
competitive conduct (e.g., assigning the utility's own generation to
subgroups with lower congestion or network upgrade costs).\721\
Similarly, Fervo Energy contends that the Commission should adopt
provisions governing how cluster areas should be formed to ensure that
clusters are formed in a transparent and not unduly discriminatory
manner.\722\
---------------------------------------------------------------------------
\720\ CREA and NewSun Initial Comments at 48-49; Environmental
Defense Fund Reply Comments at 7-8; Fervo Energy Initial Comments at
3.
\721\ CREA and NewSun Initial Comments at 48-49.
\722\ Fervo Energy Initial Comments at 3.
---------------------------------------------------------------------------
358. Other commenters argue that the Commission should provide
flexibility by creating a general framework for defining cluster study
subgroups appropriate for their own regions, rather than a specific set
of requirements.\723\
[[Page 61068]]
Some commenters further contend that transmission providers have
extensive knowledge of their own transmission systems,\724\ and the
particular interconnection requests that should and should not be
included within a cluster based on their system's geography, electric
configuration, or other relevant factors.\725\
---------------------------------------------------------------------------
\723\ APS Initial Comments at 9; Clean Energy Associations
Initial Comments at 20; ClearPath Initial Comments at 8; EEI Initial
Comments at 5; Eversource Initial Comments at 13-14; LADWP Initial
Comments at 3; Longroad Energy Initial Comments at 10; MISO Initial
Comments at 41-42; New York State Department Initial Comments at 5-
6; Pattern Energy Initial Comments at 15; PacifiCorp Initial
Comments at 18; PPL Initial Comments at 10; R Street Initial
Comments at 11; Tri-State Initial Comments at 11; U.S. Chamber of
Commerce Initial Comments at 7; Xcel Initial Comments at 23.
\724\ Shell Initial Comments, app. A at i; Tri-State Initial
Comments at 11.
\725\ U.S. Chamber of Commerce Initial Comments at 7.
---------------------------------------------------------------------------
A number of commenters suggest that transmission providers develop
subgroup criteria with stakeholder input.\726\
---------------------------------------------------------------------------
\726\ Interwest Initial Comments at 14; MISO Initial Comments at
42; Northwest and Intermountain Initial Comments at 7; Pattern
Energy Initial Comments at 15-16; PacifiCorp Initial Comments at 18
(citing PacifiCorp, Transmission OATT and Service Agmts, Part
IV.42.4(a) (5.0.0)); Shell Initial Comments, app. A at i.
---------------------------------------------------------------------------
359. Other commenters argue that the Commission should allow
variation in how transmission providers form clusters. For example, R
Street argues that the Commission should refrain from being too
prescriptive regarding how cluster areas are defined, and instead
require that transmission providers publish their cluster definitions
well in advance of the request window for interconnection
requests.\727\ Clean Energy States believe that allowing
interconnection customers to create their own clusters would result in
an internal vetting of proposed generating facilities in the cluster
and negotiation about how costs and penalties will be managed.\728\
Regarding how clusters should be defined, several commenters provide
suggestions for subgroup criteria beyond geographic proximity or
electrical relevance.\729\ PPL suggests cluster formation be based on
geographic or electrical proximity only and that interconnection
customers should not be separated based on fuel type.\730\ Energy
Keepers asserts that, when utilities are considering cluster studies on
subgroups of interconnection customers, those clusters should be based
on location.\731\ Clean Energy Associations, Vistra, and ENGIE assert
that cluster studies should evaluate subgroups of projects based on
electric proximity to one another.\732\ Further, ENGIE agrees that
distribution factors should not be the sole indicator of electrical
proximity as there are other factors around which subgroups might
appropriately be grouped.\733\
---------------------------------------------------------------------------
\727\ R Street Initial Comments at 11.
\728\ Clean Energy States Initial Comments at 10.
\729\ Id. at 5; Fervo Energy Initial Comments at 3; Interwest
Initial Comments at 13-14; Longroad Energy Initial Comments at 10;
Pattern Energy Initial Comments at 15-16; Pennsylvania Commission
Initial Comments at 6.
\730\ PPL Initial Comments at 10.
\731\ Energy Keepers Initial Comments at 4.
\732\ Clean Energy Associations Initial Comments at 20; ENGIE
Reply Comments at 2; Vistra Initial Comments at 2.
\733\ ENGIE Reply Comments at 2.
---------------------------------------------------------------------------
360. Xcel argues that it is not necessary to create ``separate''
clusters for electrically distinct regions, noting that PSCo separates
interconnection requests into ``study pockets'' based on geographic/
electrical separation but studies all the interconnection requests in a
single cluster.\734\
---------------------------------------------------------------------------
\734\ Xcel Initial Comments at 23.
---------------------------------------------------------------------------
361. Clean Energy Associations assert that the Commission should
make clear whether a cluster study must identify the upgrades required
in order to interconnect every interconnection request in whole, or
whether it might identify upgrades that would be sufficient for only a
subset of the interconnection requests; if the latter, Clean Energy
Associations continue, the Commission should establish a pro forma
process for determining which requests might proceed with those initial
upgrades.\735\ Clean Energy Associations claim that transmission
development is a ``lumpy'' process, and in some cases there can be
``breakpoints'' where adding one more generating facility can result in
a significant per-unit cost increase compared to the interconnection
costs that could have been achieved for a subset of the interconnection
requests up to that point. Clean Energy Associations state that, in the
current ISO-NE cluster study process, ISO-NE attempts to identify such
breakpoints and fills each cluster up to that level, with remaining
requests able to either withdraw or proceed into the next cluster
study. Some commenters contend that studies should include or consider
including breakpoints, which can provide helpful information to inform
interconnection customers' next steps.\736\
---------------------------------------------------------------------------
\735\ Clean Energy Associations Initial Comments at 26.
\736\ Id. at 26-27; SEIA Reply Comments at 6.
---------------------------------------------------------------------------
362. Finally, several commenters encourage transparency and request
that any subgrouping criteria be publicly posted or filed by
transmission providers or RTOs/ISOs.\737\
---------------------------------------------------------------------------
\737\ ENGIE Reply Comments at 2; Fervo Energy Initial Comments
at 3; Fervo Energy Reply Comments at 4; [Oslash]rsted Initial
Comments at 8; R Street Initial Comments at 11; Tri-State Initial
Comments at 11.
---------------------------------------------------------------------------
iii. Commission Determination
363. We will neither require transmission providers to conduct
cluster studies on subgroups of interconnection customers based on
areas of geographic and electric relevance, nor adopt provisions
governing how cluster subgroup areas should be formed. However, we
adopt revisions to section 7.4 of the pro forma LGIP to permit
transmission providers to use subgroups in their cluster study process
if they so choose. To the extent a transmission provider chooses to use
subgroups, it must include provisions in its pro forma LGIP in its
tariff that state that it will use subgroups. We further modify section
7.4 of the pro forma LGIP to require that the criteria used to define
subgroups be publicly posted on a publicly accessible website. We
believe that publicly sharing these criteria is important to ensure
adequate transparency and to safeguard against the potential for undue
discrimination in the design and implementation of cluster subgroups.
364. We agree with commenters that support permitting transmission
providers to study clusters in subgroups based on geographic or
electrical relevance but argue that clustering projects in subgroups
should not be required. We believe that there may be benefits to
studying clusters in subgroups in certain circumstances, and therefore
we do not want to preclude transmission providers from proposing such a
process on compliance. At the same time, based on the record, we do not
believe that requiring subgroups for all transmission providers is
appropriate. In some instances, the administrative burden of defining
and separately studying subgroups may not outweigh the benefits.
365. Consistent with our decision to not require transmission
providers to conduct cluster studies on subgroups of interconnection
customers, we decline to adopt provisions governing how clusters should
be formed. Rather, we believe it more appropriate to allow transmission
providers to determine how to define subclusters appropriate for their
regions, taking into consideration their system geography, electrical
configuration, and other relevant factors.\738\
---------------------------------------------------------------------------
\738\ Clean Energy Associations Initial Comments at 20;
ClearPath Initial Comments at 8; EEI Initial Comments at 5;
Eversource Initial Comments at 13-14; LADWP Initial Comments at 3;
Longroad Energy Initial Comments at 10; MISO Initial Comments at 41-
42; New York State Department Initial Comments at 5-6; PacifiCorp
Initial Comments at 18; Pattern Energy Initial Comments at 15; PPL
Initial Comments at 10; Shell Initial Comments, app. A at i; Tri-
State Initial Comments at 11; U.S. Chamber of Commerce Initial
Comments at 7.
---------------------------------------------------------------------------
[[Page 61069]]
366. Regarding concerns raised by Pattern Energy and others about
the use of subgroups resulting in a disproportionate allocation of
network upgrade costs, we note that if a transmission provider opts to
study in subgroups, it cannot change how it allocates network upgrade
costs. That is, it must follow the requirement adopted in this final
rule to use a proportional impact method to allocate system network
upgrade costs among all interconnection customers in the cluster
regardless of subgroup, as discussed further below. Because
transmission providers will be using a proportional impact method to
allocate system network upgrade costs, regardless of whether
interconnection customers are studied in subgroups, we believe
subgroups would not change an interconnection customer's potential cost
allocation. An interconnection customer with an impact on a network
upgrade would be allocated its portion of the cost of that network
upgrade regardless of whether its request was studied in a subgroup
with another interconnection customer allocated a different portion of
that network upgrade.
m. Restudy
i. NOPR Proposal
367. In the NOPR, the Commission sought comment on whether to
specify in the pro forma LGIP how cluster studies must be rerun after
restudy is triggered or whether there are provisions the Commission
could adopt to improve the efficacy of the restudy process, such as
preventing excessive restudy by limiting the transmission provider to
two restudies per month within the 150-calendar day cluster restudy
period.\739\
---------------------------------------------------------------------------
\739\ NOPR, 179 FERC ] 61,194 at P 78.
---------------------------------------------------------------------------
ii. Comments
368. Eversource recommends that the Commission adopt detailed
restudy rules.\740\ Pine Gate suggests that the Commission provide
guidance on when the need for a restudy is triggered, as even minimal
changes can trigger long and costly restudies.\741\ Pine Gate
recommends that the Commission: (1) furnish criteria to be used by
transmission providers in determining whether a restudy is required;
(2) require transmission providers to limit the scope of restudies if
only a local impact is anticipated; (3) require transmission providers
to publish restudy criteria, determinations, and scoping as resources
for interconnection customers; (4) permit interconnection customers to
send engineering analyses applying the transmission provider's
published criteria, which could be used by the transmission provider to
help decide whether to conduct a restudy, thereby reducing the
transmission providers' burden; and (5) not require every cluster
participant to submit additional study deposits until the transmission
provider determines the need for and scope of any restudy and affected
cluster participants are notified. Pattern Energy believes that
transmission providers should be required to develop expedited modeling
processes to evaluate whether the withdrawal of an interconnection
request or other allowed modification may cause a full restudy.\742\
Pattern Energy argues that such a requirement would allow
interconnection customers to make better informed decisions about
withdrawing or modifying interconnection requests.
---------------------------------------------------------------------------
\740\ Eversource Initial Comments at 14.
\741\ Pine Gate Initial Comments at 62-63.
\742\ Pattern Energy Initial Comments at 17.
---------------------------------------------------------------------------
369. Conversely, a number of commenters recommend that the
Commission provide flexibility to transmission providers and not adopt
overly prescriptive requirements specifying how cluster studies must be
rerun after a restudy is triggered.\743\ MISO encourages the Commission
to grant maximum flexibility to transmission providers regarding the
necessity of restudies and the scope of restudies as the situations
that give rise to restudies are varied and unique.\744\ PJM states that
it finds acceptable the NOPR's proposal requiring transmission
providers to specify in their tariffs how cluster studies must be
rerun, but suggests the Commission avoid being overly prescriptive
regarding restudies.\745\ Xcel recommends that the Commission not
propose additional prescriptive requirements on how restudies must be
performed, but suggests that if there are multiple clusters impacted,
where each cluster only has ``ready'' projects, the transmission
provider may combine the clusters into a single cluster for a single
restudy instead of restudying multiple clusters.\746\
---------------------------------------------------------------------------
\743\ Bonneville Initial Comments at 9; EEI Initial Comments at
5; Idaho Power Initial Comments at 4; MISO Initial Comments at 43;
NYISO Initial Comments at 12; PacifiCorp Initial Comments at 19; PJM
Initial Comments at 22-23; Xcel Initial Comments at 24.
\744\ MISO Initial Comments at 43.
\745\ PJM Initial Comments at 22-23.
\746\ Xcel Initial Comments at 24.
---------------------------------------------------------------------------
370. Some commenters support limiting the number of restudies a
transmission provider may perform within a restudy period.\747\ Ameren
states that limiting the number of restudies to two within the 150-day
cluster restudy period seems reasonable, given the size of the many
interconnection queues and the reported uncertainty of interconnection
customers in the queue.\748\ Ohio Commission Consumer Advocate concurs
that conducting a single cluster study and cluster restudy annually may
reduce the risk of cascading restudies occurring if an interconnection
customer withdraws from the interconnection queue.\749\
---------------------------------------------------------------------------
\747\ Ameren Initial Comments at 8; Clean Energy Associations
Initial Comments at 42; Cypress Creek Initial Comments at 18; Ohio
Commission Consumer Advocate Initial Comments at 8; Southern Initial
Comments at 24.
\748\ Ameren Initial Comments at 8.
\749\ Ohio Commission Consumer Advocate Initial Comments at 8.
---------------------------------------------------------------------------
371. A few commenters argue that the Commission should address the
lack of any limit on restudy requests, stating that this issue is a
known shortcoming that results in essentially unlimited time and
resource obligations for interconnection customers.\750\ Southern
expresses concern that the proposed pro forma LGIP language allows for
multiple restudies, which would interfere with a one-year timeline
maximum.\751\
---------------------------------------------------------------------------
\750\ Clean Energy Associations Initial Comments at 42; Cypress
Creek Initial Comments at 18 (citing PJM Manual 14A at 26).
\751\ Southern Initial Comments at 24.
---------------------------------------------------------------------------
372. A number of commenters do not support a set limit on the
number of restudies a transmission provider may perform.\752\
Bonneville asserts that efforts to prevent excessive restudies (e.g.,
limit of two per month) could be overly prescriptive.\753\ Bonneville
argues that transmission providers should be afforded the flexibility
to determine and publish the timing of any restudy, and limits thereto,
on their OASIS sites to help to facilitate transparency and ensure
timelines are attainable. NextEra states that experience has shown that
having a defined and limited number of restudies, such as in MISO's
three-phase process, can help limit the duration of the study
process.\754\ However, NextEra contends that it would be too
restrictive for the Commission to dictate exactly how transmission
providers should limit the number of restudies, and argues that the
final rule should instead require that each transmission provider
[[Page 61070]]
propose to the Commission on compliance what rules or processes it will
use to ensure there is not an undefined and unpredictable number of
restudies, e.g., whether it will have a fixed number of scheduled
restudies or some other method to limit the number of restudies and
associated potential delays. PacifiCorp notes that, because restudies
are typically triggered through a withdrawal or modification of an
interconnection request, the transmission provider is responding to
changes, typically outside of its control, that warrant a restudy and
undertaking efforts to complete the restudy as efficiently as
possible.\755\
---------------------------------------------------------------------------
\752\ Bonneville Initial Comments at 9; MISO Initial Comments at
42, 43; NextEra Initial Comments at 15; PacifiCorp Initial Comments
at 20; PJM Initial Comments at 23; Tri-State Initial Comments at 11.
\753\ Bonneville Initial Comments at 9.
\754\ NextEra Initial Comments at 15.
\755\ PacifiCorp Initial Comments at 19.
---------------------------------------------------------------------------
373. Idaho Power requests clarification surrounding the single
cluster and cluster restudy process and the suggested limitation of
allowing only two restudies per month within the 150-day cluster
restudy period.\756\ Idaho Power states, for example, an entity may
have three cluster areas requiring three cluster studies, and
withdrawals from those studies may require more than two simultaneous
cluster restudies in the same month to prevent delay of any one cluster
restudy.
---------------------------------------------------------------------------
\756\ Idaho Power Initial Comments at 4.
---------------------------------------------------------------------------
iii. Commission Determination
374. We decline to modify the pro forma LGIP to specify how a
transmission provider conducts cluster restudies and when it must
conduct a cluster restudy. We find persuasive the arguments of several
commenters that the Commission allow transmission providers flexibility
on how and whether to conduct a restudy and the scope and frequency of
any restudies. The transmission provider is best positioned to
determine when and how to conduct a restudy, including the scope and
frequency of restudies, because it determines the need for the
restudies to maintain the reliability of the transmission system.\757\
We agree with commenters like MISO and Xcel that different events can
trigger restudies, and transmission providers are in the best position
to determine whether an event warrants a restudy, and if so, what the
scope of that restudy should be (for example, whether a new study is
required, or whether only a modification as to certain model data and a
reanalysis is required).\758\
---------------------------------------------------------------------------
\757\ National Glossary of Terms Used in NERC Reliability
Standards, https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\758\ MISO Initial Comments at 43; Xcel Initial Comments at 24.
---------------------------------------------------------------------------
375. As to frequency of restudies, we also agree with PacifiCorp
that because restudies are typically triggered through a withdrawal of
an interconnection request, the transmission provider is responding to
changes, typically outside of its control, that warrant a restudy, and
thus limiting the number of restudies could hinder the ability of a
transmission provider to undertake efforts to complete a restudy as
efficiently as possible.\759\ Because we are not modifying the pro
forma LGIP to specify how cluster studies must be rerun after restudy
is triggered, we will also not limit the transmission provider to two
restudies per month within the 150-calendar day cluster restudy period.
We agree with commenters like Bonneville, NextEra, and PacifiCorp that
it would be too restrictive for the Commission to dictate exactly how
transmission providers should limit the number of restudies.\760\
---------------------------------------------------------------------------
\759\ PacifiCorp Initial Comments at 19.
\760\ Id.; Bonneville Initial Comments at 9; NextEra Initial
Comments at 15.
---------------------------------------------------------------------------
376. Regarding Idaho Power's request for clarification on the
suggested limitation of allowing only two restudies per month within
the 150-calendar day cluster restudy period,\761\ because we are not
adopting a limit of two restudies per month within the restudy period,
Idaho Power's clarification request is moot.
---------------------------------------------------------------------------
\761\ Idaho Power Initial Comments at 4.
---------------------------------------------------------------------------
n. Exceptions to the Cluster Study Process
i. NOPR Proposal
377. In the NOPR, the Commission sought comment on whether there
should be an option in the pro forma LGIP for transmission providers to
process some interconnection requests outside of the annual cluster
study process, and if so, in what circumstances and on what time frame
(for completion of the study), and on what priority compared to any
active clusters.\762\
---------------------------------------------------------------------------
\762\ NOPR, 179 FERC ] 61,194 at P 79.
---------------------------------------------------------------------------
ii. Comments
378. Several parties generally support an option in the pro forma
LGIP for some interconnection requests to be processed outside of the
annual cluster study process,\763\ with some commenters supporting such
an option only under specific circumstances.\764\ For example,
[Oslash]rsted argues that such an option could be beneficial in the
case of a stand alone network upgrade built to serve a single
interconnection customer that will not impact the cluster.\765\ Some
commenters suggest establishing a separate process outside of the
cluster study process to expedite certain interconnection
requests.\766\ Several commenters contend that an option to study
interconnection requests outside of clusters would be particularly
beneficial as more renewable generating facilities are added to the
resource mix.\767\ Two commenters support exceptions for replacement
resources specifically.\768\ A few commenters argue that the Commission
should allow transmission providers to separately or individually study
certain interconnection requests that are not geographically or
electrically relevant to other interconnection requests in the
interconnection queue.\769\
---------------------------------------------------------------------------
\763\ AES Initial Comments at 10; Fervo Energy Initial Comments
at 3; [Oslash]rsted Initial Comments at 9; Tri-State Initial
Comments at 11.
\764\ AEP Initial Comments at 19, 42; APPA-LPPC Initial Comments
at 15; Clean Energy Associations Initial Comments at 21; CREA and
NewSun Initial Comments at 49; Energy Keepers Initial Comments at 4-
5; Eversource Initial Comments at 14; Iowa Commission Initial
Comments at 3; Northwest and Intermountain Initial Comments at 7;
UMPA Initial Comments at 3-4; Xcel Initial Comments at 24.
\765\ [Oslash]rsted Initial Comments at 9.
\766\ Clean Energy Associations Initial Comments at 21; Iowa
Commission Initial Comments at 4; Navajo Utility Initial Comments at
13; UMPA Initial Comments at 4.
\767\ AEP Initial Comments at 19-20; Clean Energy Associations
Initial Comments at 21; ENGIE Reply Comments at 2; Iowa Commission
Initial Comments at 4.
\768\ AEP Initial Comments at 19; Clean Energy Associations
Initial Comments at 21.
\769\ Energy Keepers Initial Comments at 4-5; Eversource Initial
Comments at 14.
---------------------------------------------------------------------------
379. Additionally, APPA-LPPC request that the Commission recognize
that there are transmission providers, principally in rural communities
or where the transmission system provides limited opportunities for
advantageous interconnections, where there are too few interconnection
requests to justify a cluster study approach.\770\ In these cases,
APPA-LPPC recommend that the Commission provide for a self-executing
``opt out,'' permitting the transmission providers to continue to study
interconnection requests on a serial basis.
---------------------------------------------------------------------------
\770\ APPA-LPPC Initial Comments at 14-15.
---------------------------------------------------------------------------
380. Northwest and Intermountain recommend a limited exception to
the cluster study process requirement to allow existing interconnection
customers seeking to make changes to their proposed generating
facilities to be processed outside of the cluster study process where
the proposed change had no demonstrable incremental impact on the
transmission system.\771\
---------------------------------------------------------------------------
\771\ Northwest and Intermountain Initial Comments at 7-8.
---------------------------------------------------------------------------
381. Xcel argues that proposed generating facilities needed to
serve load should be allowed to be processed
[[Page 61071]]
outside of the annual cluster study process.\772\ AEP argues that
transmission providers with a reserve margin obligation must have the
ability to prioritize the interconnection of needed capacity in the
interconnection process.\773\
---------------------------------------------------------------------------
\772\ Xcel Initial Comments at 24.
\773\ AEP Initial Comments at 42.
---------------------------------------------------------------------------
382. Iowa Commission argues that state commissions should have the
ability to require studies outside of annual cluster studies, which
would help increase the availability of needed generation for resource
adequacy and maintain local reliability needs, particularly as large
intermittent generating facilities are interconnecting to the system at
a rapid pace.\774\ Iowa Commission explains that such studies could
potentially address increased transmission system stability and also
minimize future transmission costs because of the ``transient nature''
of some load and resource changes.
---------------------------------------------------------------------------
\774\ Iowa Commission Initial Comments at 4.
---------------------------------------------------------------------------
383. Similarly, UMPA contends that the Commission should require a
process outside of the annual cluster study process to expedite
interconnection requests that are beyond the exploration phase and
ready for development.\775\ UMPA explains that some load serving
entities search for potential resources to meet their integrated
resource plan based on a request for proposal or certain competitive
criteria, but are then confronted with a choice among proposed
generating facilities that meet the criteria but are lower in the
interconnection queue, or proposed generating facilities that do not
satisfy the criteria, but are higher in the interconnection queue.
Therefore, UMPA argues that it would be helpful to a load serving
entity with a development-ready generating facility to be able to enter
into a parallel process outside of the annual cluster study process in
order to expedite an interconnection request.
---------------------------------------------------------------------------
\775\ UMPA Initial Comments at 3-4.
---------------------------------------------------------------------------
384. AEP also suggests that RTOs/ISOs that have consolidated their
small and large generator interconnection procedures into a single
generator interconnection procedure should be permitted to propose that
all or some smaller-sized generating facilities, such as 20 MW or
smaller generating facilities, would be ``too small'' to need to be
included in the cluster.\776\
---------------------------------------------------------------------------
\776\ AEP Initial Comments at 19.
---------------------------------------------------------------------------
385. Other commenters believe that any exceptions to the cluster
study process requirement should be very limited.\777\ NRECA asserts
that if the final rule provides for any interconnection requests to be
processed outside the annual cluster study process, it should be
limited to a narrow category of interconnection requests, such as
emergency replacements of failed equipment driven by near-term
reliability needs.\778\ MISO asserts that there should be very limited
exceptions, explaining that it has limited its non-queue
interconnection requests to those that are associated with existing
generating facilities that do not seek to add new or additional
interconnection service, or small interconnection requests.\779\
Outside of those limited exceptions, MISO states that it does not
support processing any other interconnection requests outside of the
interconnection queue.\780\
---------------------------------------------------------------------------
\777\ ENGIE Initial Comments at 3; MISO Initial Comments at 44;
NRECA Initial Comments at 19-20.
\778\ NRECA Initial Comments at 20.
\779\ MISO Initial Comments at 44. MISO states that these
limited exceptions are Surplus Interconnection Requests (MISO, FERC
Electric Tariff, attach. X, section 3.2.3 (158.0.0)), a request for
Generating Facility Replacement (MISO, FERC Electric Tariff, attach.
X, section 3.7 (158.0.0)), and Fast Track Processing that is
available to Small Generating Facilities under 5 MW (MISO, FERC
Electric Tariff, attach. X, art. 14 (158.0.0)). Id. n.100.
\780\ Id. at 44.
---------------------------------------------------------------------------
386. ENGIE recommends that exceptions be limited to requests that
``need[ ] to be studied outside of the cluster process, e.g.,
transmission planning and state or public policy issues.'' \781\ ENGIE
states that it is possible that there may be other exceptions made in
emergency situations, in which case, the granting of exceptions should
be very limited in scope, subject to transparent criteria, and the
rationale made publicly available. ENGIE further recommends that every
interconnection request, including emergency requests, enter through
the cluster request window, but that an emergency request be
accelerated if it meets the pre-determined and publicly available
requirements.
---------------------------------------------------------------------------
\781\ ENGIE Initial Comments at 3.
---------------------------------------------------------------------------
387. A number of commenters oppose an option to process
interconnection requests outside of the annual cluster study
process.\782\ A few parties argue that maintaining an option to process
interconnection requests outside of the annual cluster study process
would likely create an administrative burden for transmission providers
without a clear benefit.\783\ Some commenters assert that processing
certain interconnection requests outside of the interconnection queue
could increase the time needed to complete the cluster studies or could
increase restudies.\784\
---------------------------------------------------------------------------
\782\ Bonneville Initial Comments at 9; Enel Initial Comments at
19; PacifiCorp Initial Comments at 21; PJM Initial Comments at 23;
PPL Initial Comments at 12.
\783\ Enel Initial Comments at 19; PacifiCorp Initial Comments
at 21; PJM Initial Comments at 23.
\784\ Bonneville Initial Comments at 9; Enel Initial Comments at
19; NRECA Initial Comments at 20.
---------------------------------------------------------------------------
388. Some commenters express concern that such an option could
become overly used or abused.\785\ Enel asserts that if interconnection
requests could be accepted for processing outside the annual cluster
study process, especially on an individual basis, there would be a high
degree of interest because this would allow interconnection customers
to avoid being allocated the costs of regional upgrades that result
from many cluster studies.\786\ Bonneville asserts that permitting an
interconnection request to be processed outside of the annual cluster
study process would create a ``perverse incentive'' for some
interconnection customers to forgo the cluster study process to avoid
cluster study requirements.\787\
---------------------------------------------------------------------------
\785\ Bonneville Initial Comments at 9-10; Enel Initial Comments
at 19; MISO Initial Comments at 44; NRECA Initial Comments at 20.
\786\ Enel Initial Comments at 19.
\787\ Bonneville Initial Comments at 9-10.
---------------------------------------------------------------------------
389. OMS states that it has considered the benefits of some sort of
a ``fast-lane process'' for resources that are more ``certain,'' like
those that have received all necessary permits and regulatory
approvals.\788\ OMS states that use of such a mechanism may be
important or necessary in the future to address reliability concerns,
but OMS explains that it is neutral on the proposal because bypassing
the interconnection queue invites a myriad of potential unintended
consequences that might not outweigh the value OMS otherwise envisions
in this type of mechanism.
---------------------------------------------------------------------------
\788\ OMS Initial Comments at 8.
---------------------------------------------------------------------------
390. PacifiCorp states that the Commission's proposal on this topic
is not clear.\789\ PacifiCorp states that, if the NOPR refers to an
interconnection customer's ability to request surplus or provisional
interconnection service or an informational interconnection study,
PacifiCorp supports maintaining these options. However, PacifiCorp
requests the Commission clarify that requests for such service will be
evaluated in the order that completed interconnection requests are
received. PacifiCorp states that it does not currently support
expanding non-cluster service and study offerings.
---------------------------------------------------------------------------
\789\ PacifiCorp Initial Comments at 21.
---------------------------------------------------------------------------
[[Page 61072]]
391. Regarding under what time frame and at what priority
interconnection requests should be studied outside of the cluster study
process, as compared to any active clusters, Fervo Energy recommends a
270-day time frame for completion of the study with secondary priority
to the active cluster studies.\790\
---------------------------------------------------------------------------
\790\ Fervo Energy Initial Comments at 3.
---------------------------------------------------------------------------
iii. Commission Determination
392. We decline to include an additional option in the pro forma
LGIP for transmission providers to process some interconnection
requests outside the annual cluster study process adopted in this final
rule. We find that establishing in the pro forma LGIP a separate
interconnection process outside the cluster study process could detract
from transmission providers' efforts to efficiently process cluster
studies--a point persuasively argued by commenters.\791\ A separate set
of interconnection studies outside of the cluster study process could
cause transmission providers to divert resources away from cluster
studies and cluster restudies. Such diversion could hinder the
transmission provider from meeting the cluster study and cluster
restudy deadlines adopted in this final rule, which would be
insufficient to ensure that interconnection customers are able to
interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner. We also find that such an option in the
pro forma LGIP would be too open-ended, as it would leave a significant
amount of discretion to the transmission provider to create new study
processes for processing any types of interconnection requests it
chooses outside the cluster study process and could therefore result in
a separate but unduly discriminatory interconnection process. We
further find that establishing such an open-ended option in the pro
forma LGIP could create an incentive for some interconnection customers
to forgo the cluster study process, which could increase the time and
resources needed for transmission providers to complete the cluster
studies or could increase restudies.\792\
---------------------------------------------------------------------------
\791\ Bonneville Initial Comments at 9; Enel Initial Comments at
19; NRECA Initial Comments at 20; PacifiCorp Initial Comments at 21;
PJM Initial Comments at 23.
\792\ Bonneville Initial Comments at 9-10; Enel Initial Comments
at 19; MISO Initial Comments at 44; NRECA Initial Comments at 20;
PJM Initial Comments at 23.
---------------------------------------------------------------------------
393. A number of commenters see benefits to establishing an option
in the pro forma LGIP for particular types of interconnection requests
to be processed outside of the annual cluster study process, such as
for generator replacement, projects ready for development, emergency
replacements, for certain special circumstances, or for transmission
providers who have too few interconnection requests to justify a
cluster study approach.\793\ However, we are not persuaded that
establishing such processes in the pro forma LGIP is necessary to
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner. We believe that processing such one-off interconnection
requests will be needed less often under the cluster study process
adopted in this final rule, and therefore, any benefits that exist to
processing some interconnection requests outside a transmission
provider's interconnection process may be outweighed by the benefit of
allowing transmission providers to conduct cluster studies efficiently
without diverting resources to a separate set of studies.
---------------------------------------------------------------------------
\793\ AEP Initial Comments at 19; APPA-LPPC Initial Comments at
14-15; Clean Energy Associations Initial Comments at 21; Energy
Keepers Initial Comments at 4-5; Navajo Utility Initial Comments at
13; NRECA Initial Comments at 19-20; UMPA Initial Comments at 3-4.
---------------------------------------------------------------------------
394. In response to the Iowa Commission's argument that state
commissions should be able to require studies outside of annual cluster
studies, we similarly find that any such studies would divert a
transmission provider's resources away from conducting the cluster
studies and cluster restudies.
395. Regarding AEP's suggestion that those RTOs/ISOs that have
consolidated their small and large generator interconnection procedures
should be permitted to propose that all or some smaller-sized
generating facilities would be ``too small'' to be included in the
cluster, we note that the Commission did not propose the cluster study
process for small generating facilities subject to the pro forma SGIP.
396. Finally, because we are not revising the pro forma LGIP to add
a new option for some interconnection requests to be processed outside
of the annual cluster study process, we find moot those comments on the
time frame and priority of interconnection requests studied outside of
the cluster study process.\794\ In response to PacifiCorp,\795\ we
clarify that requests for surplus interconnection service, or an
optional interconnection study, will continue to be processed as
received and outside of the cluster study process, and that this does
not entail an expansion of non-cluster service and study offerings.
---------------------------------------------------------------------------
\794\ Fervo Energy Initial Comments at 3; Tri-State Initial
Comments at 12; Xcel Initial Comments at 24-25.
\795\ PacifiCorp Initial Comments at 21.
---------------------------------------------------------------------------
o. Other Comments
i. Comments
397. Some entities recommend automation or standardization of the
interconnection queue process and studies.\796\ NextEra states that the
proposed cluster study process time frame requires significant
information technology and personnel resources.\797\ NextEra argues
that, despite the lack of such a proposal in the NOPR, automation of
the interconnection queue process and studies is likely the key to
compressing interconnection process timelines. NextEra encourages the
Commission to convene a technical conference or other process to focus
on the root causes of interconnection study delays as well as the
potential to accelerate the interconnection queue process through
enhanced automation.
---------------------------------------------------------------------------
\796\ ACORE Initial Comments at 4-5; Clean Energy Associations
Initial Comments at 26; NextEra Initial Comments at 13.
\797\ NextEra Initial Comments at 13-14.
---------------------------------------------------------------------------
398. Several commenters argue that the Commission should require
transmission providers to provide more cost information to
interconnection customers throughout the interconnection process.\798\
Clean Energy Associations and SEIA argue that cluster studies should
also ensure that interim cost information is made available to
interconnection customers so that they can make more informed decisions
earlier in the interconnection process, which will in turn lead to a
more efficient interconnection process overall.\799\ Clean Energy
Associations argue that as part of the cluster studies provided to
interconnection customers prior to their receiving facilities studies,
the Commission should require transmission providers to provide
interconnection customers with cost estimates for the upgrades required
if they were to request ERIS or NRIS (or long-term firm transmission
service), respectively--and coupled with minimum thresholds for
materiality (such as distribution factor) and transparency regarding
how these costs are derived (detailing the assumptions and criteria
that will be used).\800\ Clean Energy Associations also suggest that
the Commission should provide concrete direction regarding how
[[Page 61073]]
differing service types should be studied, and what outcome an
interconnection customer should receive for making the necessary
transmission system improvements to obtain that interconnection
service.\801\ AEE similarly believes that additional reforms are needed
to bring more transparency and predictability to interconnection costs,
and without this transparency and predictability, interconnection
customers face continued risks of unjust and unreasonable
interconnection study results that derail or delay interconnection
requests and cause increased costs.\802\
---------------------------------------------------------------------------
\798\ ACE-NY Initial Comments at 4; Clean Energy Associations
Initial Comments at 20; Enel Initial Comments at 18; SEIA Initial
Comments at 8.
\799\ Clean Energy Associations Initial Comments at 20; SEIA
Initial Comments at 8.
\800\ Clean Energy Associations Initial Comments at 27.
\801\ Id. at 29.
\802\ AEE Initial Comments at 12.
---------------------------------------------------------------------------
399. Affected Interconnection Customers state that the Commission
should permit interconnection customers to use independent studies to
demonstrate whether the request for limited interconnection service
would result in stability, short circuit, thermal, and/or voltage
issues, if the transmission provider or transmission owner is unable to
complete the studies on time.\803\ Affected Interconnection Customers
argue that allowing interconnection customers to use any available
resources to conduct these studies would enable already built
interconnection facilities to flow power onto the system, as long as
studies show that such interim services will not harm the system.
---------------------------------------------------------------------------
\803\ Affected Interconnection Customers Initial Comments at 21.
---------------------------------------------------------------------------
400. Clean Energy Associations ask that in a final rule, the
Commission adopt a cost threshold (in terms of the anticipated upgrade
cost relative to distribution factor) beyond which upgrades should be
evaluated in the next near-term transmission planning process.
Similarly, Clean Energy Associations argue that cumulative congestion
issues should also be addressed via the transmission planning
process.\804\
---------------------------------------------------------------------------
\804\ Clean Energy Associations Initial Comments at 29.
---------------------------------------------------------------------------
ii. Commission Determination
401. We decline to adopt the remainder of the proposals advocated
for in the comments regarding our requirement for transmission
providers to use a cluster study process. We decline to adopt three of
these proposals because they are outside the scope of the NOPR: (1)
NextEra's request to require or standardize automated processing of
interconnection requests; \805\ (2) Clean Energy Associations' argument
that the Commission should adopt a cost threshold beyond which upgrades
should be evaluated in the next near-term transmission planning
process; \806\ and (3) Clean Energy Associations' argument that the
Commission should provide concrete direction regarding how differing
service types should be studied, and what outcome an interconnection
customer should receive for making the necessary transmission system
improvements to obtain that interconnection service.\807\
---------------------------------------------------------------------------
\805\ NextEra Initial Comments at 14. We also decline to convene
a technical conference to explore the causes of interconnection
study delays and the potential to accelerate the interconnection
queue process through enhanced automation. As discussed above, we
have adequate record of the causes of interconnection study delays
to fashion a remedy with the combination of reforms we adopt in this
final rule.
\806\ Clean Energy Associations Initial Comments at 29.
\807\ Id.
---------------------------------------------------------------------------
402. Regarding Affected Interconnection Customers' arguments
discussing the use of independent studies, we note that interconnection
customers can use independent resources during the interconnection
process. However, the results of independent studies will not be
binding on transmission providers, as the use of studies conducted by
an interconnection customer cannot ensure that the cluster study
process results in a just, reasonable, and not unduly discriminatory or
preferential outcome for all interconnection customers in the cluster.
In addition, transmission providers must be able to conduct the
necessary studies to maintain the reliability of their transmission
system.
403. We will not require transmission providers to provide
additional cost information to interconnection customers that is not
already required to be provided pursuant to the pro forma LGIP, as
modified by this final rule. For example, revised pro forma LGIP
sections 3.4.5 (Customer Engagement Window) and 8.1 (Interconnection
Facilities Study Agreement) require the transmission provider to
provide the interconnection customer with a good faith estimate of the
costs of the cluster study and the interconnection facility study,
respectively. Similarly, revised pro forma LGIP sections 7.3 (Scope of
Cluster Study) and 8.2 (Scope of Interconnection Facilities Study)
require the transmission provider to provide cost estimates for
interconnection facilities and network upgrades. It is unclear what
other ``interim cost information'' \808\ Clean Energy Associations want
transmission providers to provide, nor the value of such information
vis-[agrave]-vis the burden on transmission providers to develop it.
---------------------------------------------------------------------------
\808\ Id. at 20.
---------------------------------------------------------------------------
404. Clean Energy Associations argue that as part of the cluster
studies provided to interconnection customers prior to receiving
facilities studies, the Commission should require transmission
providers to provide interconnection customers with cost estimates for
the upgrades required if they were to request ERIS or NRIS. Section 3.2
of the pro forma LGIP provides that an interconnection customer
requesting NRIS may also request that it be concurrently studied for
ERIS, up to the point when the facility study agreement is executed. As
the pro forma LGIP already provides interconnection customers the
ability to have both ERIS and NRIS studied concurrently, we find Clean
Energy Associations' request moot.
3. Allocation of Cluster Study Costs
a. NOPR Proposal
405. In the NOPR, the Commission proposed to require transmission
providers to allocate the shared costs of cluster studies as follows:
90% of the applicable study costs allocated pro rata to interconnection
customers based on requested MWs included in the applicable cluster,
and 10% of the applicable study costs allocated per capita to
interconnection customers based on the number of interconnection
requests included in the applicable cluster.\809\ The Commission
preliminarily found that this allocation of the costs of cluster
studies would result in just and reasonable Commission-jurisdictional
rates because it appropriately recognizes that the MW size of a cluster
has a dramatic impact on the cost of studying the cluster, while also
recognizing that the number of interconnection requests included in the
cluster also impacts the cost of studying the cluster, but to a lesser
degree. The Commission sought comment on whether a different cost
allocation approach may be appropriate or whether each transmission
provider should be provided additional flexibility to propose a cost
allocation approach on compliance with any final rule.\810\
---------------------------------------------------------------------------
\809\ NOPR, 179 FERC ] 61,194 at P 82.
\810\ Id. P 83.
---------------------------------------------------------------------------
b. Comments
i. Comments in Support
406. Multiple commenters support the proposal.\811\ Clean Energy
Buyers note
[[Page 61074]]
that certainty and consistency in cost allocation for interconnection
studies will be helpful for interconnection customers that site
generating facilities in more than one region.\812\ Idaho Power adds
that a uniform cost allocation would prevent interconnection customers
from ``shopping around'' for the best price for larger generating
facility locations.\813\ Duke Southeast Utilities note that Duke
Carolinas Utilities' currently effective LGIP/LGIA contains the same
90/10 cost allocation, which it states provides a balanced and
equitable study cost allocation based on the Commission's cost
causation principle.\814\ Duke Southeast Utilities assert that the
proposed allocation aligns with study deposits that would be submitted
based on varying assumptions around the number and size of
interconnection requests submitted into the cluster study process.
---------------------------------------------------------------------------
\811\ Clean Energy Buyers Initial Comments at 8; Consumers
Energy Initial Comments at 4; Cypress Creek Initial Comments at 19;
Duke Southeast Utilities Initial Comments at 8-9; Enel Initial
Comments at 20; Fervo Energy Initial Comments at 3; Idaho Power
Initial Comments at 5; Interwest Initial Comments at 5; Public
Interest Organizations Initial Comments at 31; R Street Initial
Comments at 11; Tri-State Initial Comments at 3, 12.
\812\ Clean Energy Buyers Initial Comments at 8-9.
\813\ Idaho Power Initial Comments at 5.
\814\ Duke Southeast Utilities Initial Comments at 8-9.
---------------------------------------------------------------------------
ii. Comments in Opposition
407. Several commenters oppose the proposal. For instance, National
Grid and NRECA argue that any predetermined study cost allocation
method will produce results that do not comport with cost
causation.\815\ National Grid gives the example of a 20 MW generating
facility that has unique or complex engineering features at a
particular point of interconnection that may require considerably more
time to conduct a study than a much larger 100 MW generating facility;
in this situation, according to National Grid, the 90/10 cost
allocation methodology proposed in the NOPR would not align with cost
causation, a problem that would be exacerbated if the interconnection
customer withdraws the interconnection request.\816\ National Grid
asserts that a predetermined cost allocation risks undermining
competitive pressures in the interconnection process, which it states
should be retained to the maximum extent possible consistent with
revisions to mitigate the existing interconnection queue
inefficiencies. Similarly, Xcel and NextEra argue that the size of the
interconnection request does not impact the study costs by a 9:1 ratio
compared to the number of interconnection requests, noting that the
size of the interconnection request does not materially impact the time
to add the generating facility to the model or time to design the
interconnecting substation.\817\ NRECA adds that the Commission has not
produced data showing the fixed costs of processing an interconnection
request or a precise linear correlation between generating facility
size and study costs.\818\ rPlus argues that the proposed 90/10 cost
allocation is ``unduly discriminatory toward pumped storage, and wholly
disincentivizes large capacity projects.'' \819\ rPlus argues that the
assertion that the MW size of a cluster study is significantly more
impactful on the cost and effort required to perform the study is
incorrect. rPlus states that the number of interconnection requests and
the cluster size are both burdensome for the study process, as each
generating facility requires its own project management, technical
review, study implementation, and deliverability assessment.\820\ SDG&E
and SoCal Edison agree that a 90/10 cost allocation would
inappropriately burden larger generating facilities with higher study
costs, as the level of effort to study an interconnection request is
driven more by complexity around the point of interconnection and is
not strongly correlated to the size of the generating facility.\821\
---------------------------------------------------------------------------
\815\ National Grid Initial Comments at 16; NRECA Initial
Comments at 8.
\816\ National Grid Initial Comments at 16-17.
\817\ NextEra Initial Comments at 16; Xcel Initial Comments at
25.
\818\ NRECA Initial Comments at 21.
\819\ rPlus Initial Comments at 5.
\820\ Id.; Hydropower Commenters Initial Comments at 27.
\821\ SDG&E Initial Comments at 7; SoCal Edison Initial Comments
at 15.
---------------------------------------------------------------------------
iii. Alternatives and Requests for Flexibility
408. Several commenters put forth alternatives to the NOPR
proposal. For instance, some commenters generally contend that
transmission providers should allocate study costs based on the
proposed generating facility's impact on the overall study, measured by
the time and resources expended on a particular generating facility
within the study.\822\ National Grid asserts that this process would be
consistent with the current serial study approach, which directly
correlates cost responsibility to cost causation.\823\ AES argues that
the final rule's cost allocation framework should reflect the reality
that study costs are not only a function of generating facility size,
but also the location of the generating facility and the degree to
which that location is constrained.\824\
---------------------------------------------------------------------------
\822\ AES Initial Comments at 12; Clean Energy Associations
Initial Comments at 23; National Grid Initial Comments at 17.
\823\ National Grid Initial Comments at 17.
\824\ AES Initial Comments at 12.
---------------------------------------------------------------------------
409. Several commenters argue that the Commission should allocate
cluster study costs based solely on the number of interconnection
requests in the cluster.\825\ Ameren and SDG&E state that, in their
experience, study costs are not based on the size of the proposed
generating facilities.\826\ In contrast, Fervo Energy argues against
allocating study costs evenly to all interconnection customers within a
cluster, asserting that it is ``not at all clear'' how this proposal is
just and reasonable, as it strays away from allocating costs on a pro
rata basis based on requested MWs.\827\
---------------------------------------------------------------------------
\825\ Ameren Initial Comments at 11; SDG&E Initial Comments at
7; SoCal Edison Initial Comments at 15-16.
\826\ Ameren Initial Comments at 11; SDG&E Initial Comments at
7.
\827\ Fervo Energy Reply Comments at 4.
---------------------------------------------------------------------------
410. CAISO argues that the proposal appears arbitrary and
capricious because the Commission does not adequately explain the basis
for the 90% to 10% ratio.\828\ CAISO asserts that the 10% allocation is
so small as to be de minimis, yet it still increases the administrative
burden to allocate the cluster study costs. CAISO argues that it would
be much simpler and easier if transmission providers simply allocated
all cluster study costs based on the MW capacity alone.
---------------------------------------------------------------------------
\828\ CAISO Initial Comments at 12.
---------------------------------------------------------------------------
411. Enel argues that there are study phases where it would be more
appropriate to assign study costs to individual interconnection
requests, ``such as the [f]acilities [s]tudy for upgrades assigned to
only a single customer.'' \829\ Enel argues that a 90/10 study cost
split may disproportionately exclude very small generating facilities
which still require modeling from study cost responsibility, and
suggests that a minimum MW size be assumed, such as was used to set the
minimum study deposit in proposed pro forma LGIP section 3.1.1.1.
---------------------------------------------------------------------------
\829\ Enel Initial Comments at 20.
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412. Several commenters argue for a cost allocation of 50% of the
study costs based on requested MW and 50% based on the number of
interconnection requests in the cluster.\830\ NextEra states that,
based on its experience, it takes comparable time and effort to study a
small proposed generating facility as a large one.\831\ NextEra and
SoCal Edison argue that allocating study costs based
[[Page 61075]]
mostly on the MW size would likely cause some cross-subsidies from
interconnection customers submitting large proposed generating
facilities to those submitting smaller ones.\832\ SEIA notes that the
MW size of the cluster may be artificially inflated when certain
interconnection customers submit multiple exploratory requests, and
recommends a 50/50 cost allocation to deter such requests.\833\ SEIA
argues that, similar to CAISO's study cost allocation, the Commission
should structure the cost allocation so that interconnection customers
with multiple interconnection requests are responsible for a greater
share of the study costs.\834\
---------------------------------------------------------------------------
\830\ Hydropower Commenters Initial Comments at 26-27; NextEra
Initial Comments at 16; Pattern Energy Initial Comments at 18-19;
rPlus Initial Comments at 5; SEIA Initial Comments at 9-10.
\831\ NextEra Initial Comments at 16.
\832\ Id.; SoCal Edison Initial Comments at 15-16.
\833\ SEIA Initial Comments at 10.
\834\ Id. (citing Cal. Indep. Sys. Operator, Inc., 140 FERC ]
61,070, at P 4 (2012)).
---------------------------------------------------------------------------
413. Clean Energy Associations add that cluster studies should be
conducted in subgroups based on electrical relevance, and that study
costs related to each subgroup should be tracked independently and
allocated only among those interconnection customers within that
subgroup.\835\
---------------------------------------------------------------------------
\835\ Clean Energy Associations Initial Comments at 23.
---------------------------------------------------------------------------
414. Multiple commenters argue that the Commission should not
impose a specific cluster study cost allocation, but instead allow
transmission providers flexibility in proposing their own cost
allocation methods.\836\ For example, APPA-LPPC argue that the use of a
``one-size-fits-all'' approach may result in unreasonable results in
certain circumstances.\837\ APPA-LPPC assert that weighting the
allocation of cluster study costs based on MWs may unfairly burden
interconnection customers proposing large generating facilities in
regions where a cluster is likely to include a large number of
relatively small proposed generating facilities and a small number of
large proposed generating facilities because study costs do not
necessarily track linearly with generating facility size.
---------------------------------------------------------------------------
\836\ AES Initial Comments at 12; Ameren Initial Comments at 11;
APPA-LPPC Initial Comments at 3; Bonneville Initial Comments at 10;
Clean Energy Associations Initial Comments at 24; Dominion Initial
Comments at 19; Indicated PJM TOs Initial Comments at 18-19; ISO-NE
Initial Comments at 25; MISO Initial Comments at 45; National Grid
Initial Comments at 16; NextEra Initial Comments at 16-17; NRECA
Initial Comments at 8; NYISO Initial Comments at 13; Omaha Public
Power Initial Comments at 5; [Oslash]rsted Initial Comments at 9;
Pattern Energy Initial Comments at 19; PPL Initial Comments at 12; R
Street Initial Comments at 11; SEIA Initial Comments at 10; Xcel
Initial Comments at 25.
\837\ APPA-LPPC Initial Comments at 16.
---------------------------------------------------------------------------
415. Several commenters argue that RTOs/ISOs should be able to
retain their existing cluster study cost allocations, where applicable,
because those cost allocations accomplish the purpose of the
Commission's proposal to equitably allocate study costs among
interconnection customers.\838\
---------------------------------------------------------------------------
\838\ Dominion Initial Comments at 19; Indicated PJM TOs Initial
Comments at 18-19; ISO-NE Initial Comments at 25; MISO Initial
Comments at 45; NYISO Initial Comments at 14; Omaha Public Power
Initial Comments at 5; PJM Initial Comments at 35; SPP Initial
Comments at 7. In response, Fervo Energy cautions against permitting
transmission providers too much flexibility, arguing that this opens
the door for undue discrimination against interconnection customers.
Fervo Energy Reply Comments at 4.
---------------------------------------------------------------------------
c. Commission Determination
416. We adopt the NOPR proposal, with modification, to revise
section 13.3 (Obligation for Study Costs) of the pro forma LGIP to
allow each transmission provider to propose its own study cost
allocation ratio for allocating the shared costs of cluster studies
between a per capita basis and pro rata by MW, provided that: between
10% and 50% of study costs must be allocated on a per capita basis,
with the remainder (between 90% and 50%) allocated pro rata by MW.
Under this revised provision, a transmission provider may propose to
retain its existing study cost allocation ratio if it falls within this
range and meets the requirements of this final rule.
417. We are persuaded by comments arguing that it is appropriate to
allow transmission providers a degree of flexibility in proposing on
compliance the method for allocating study costs in their tariff to
adapt to their specific regional circumstances and help avoid
unreasonable outcomes. Some commenters assert that the NOPR-proposed
90%-10% allocation could in some instances unduly burden larger
generating facilities, such as when a cluster includes a large number
of interconnection requests representing relatively small generating
facilities and a small number of large generating facilities.\839\
Conversely, other commenters caution that straying too far from the
NOPR proposal for a 90%-10% allocation could disproportionately burden
smaller generating facilities, given the role that size may play in
determining study costs.\840\ Accordingly, we believe that granting
transmission providers the flexibility to propose in their tariff the
study cost allocation appropriate to their region, within the limits
detailed above, strikes a better balance than the NOPR proposal.
---------------------------------------------------------------------------
\839\ APPA-LPPC Initial Comments at 16.
\840\ Fervo Energy Reply Comments at 4-5.
---------------------------------------------------------------------------
418. The revised study cost allocation requirements that we adopt
in this final rule recognize that cluster study costs are impacted by
both the number of interconnection requests in a cluster and the size
of the proposed generating facilities in each cluster. We find that
requiring transmission providers to allocate between 10% and 50% of
cluster study costs on a per capita basis is just and reasonable
because it ensures that interconnection customers that propose smaller
generating facilities or submit multiple interconnection requests to
explore different interconnection scenarios for a single proposed
generator adequately contribute to study costs, particularly given that
some study costs are incurred independent of the MW size of a specific
proposed generating facility in a cluster.\841\ Further, we agree with
commenters that observe that not all study costs track linearly with
generating facility size because there are other factors, such as the
point of interconnection selected, that can lead to increasingly
complex studies and correspondingly higher study costs.\842\ We believe
that the per capita component of the study cost allocation requirements
addresses this fact. Requiring a per capita component also ensures that
an interconnection customer that proposes a large generating facility
in a cluster of many smaller generating facilities will not bear a
disproportionate amount of the study costs. We likewise find that
requiring transmission providers to allocate between 50% and 90% of
study costs on a pro rata by MW basis prevents a disproportionate
amount of study costs from being allocated to interconnection customers
that propose smaller generating facilities in the cluster. The pro rata
by MW component reflects the fact that, to a significant extent, study
costs correlate to the total MW size of the cluster. In general, even
if the number of interconnection requests in each cluster remains
constant, we expect that a cluster of 10,000 MW will be significantly
more costly to study than a cluster of 100 MW.\843\ Accordingly,
requiring that a substantial share of study costs is allocated based on
each generating facility's contribution to the total MW size of the
cluster study ensures consistency with cost causation principles.
---------------------------------------------------------------------------
\841\ SDG&E Initial Comments at 7; SoCal Edison Initial Comments
at 15.
\842\ AES Initial Comments at 12; APPA-LPPC Initial Comments at
16; NRECA Initial Comments at 21.
\843\ Fervo Initial Comments at 4.
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419. We disagree with CAISO that the Commission should require the
[[Page 61076]]
allocation of all cluster study costs based on the MW capacity because
allocating 10% of study costs on a per capita basis is de minimis and
not worth the administrative burden. First, this final rule now allows
transmission providers to allocate up to 50% of costs on a per capita
basis. Even if a transmission provider chooses to allocate only 10% of
study costs on a per capita basis, as explained above, we believe that
this is an important component that is needed to ensure that study
costs are allocated in a manner that is at least roughly commensurate
with estimated benefits (i.e., consistent with cost causation). We are
unpersuaded that the administrative burden associated with allocating a
potentially small fraction of the study costs among interconnection
customers in a cluster outweighs the benefits, particularly given that
nothing in the record demonstrates that those administrative costs are
significant.
420. In response to commenters' arguments in favor of a uniform
study cost allocation method across regions, we find that the benefits
of allowing transmission providers flexibility to tailor their study
cost allocation to the specific circumstances of their region outweigh
the benefits of uniformity cited by commenters, such as consistency and
preventing ``shopping around.'' We believe that the guardrails that we
provide in this final rule will ensure just, reasonable, and not unduly
discriminatory or preferential rates while at the same time addressing
concerns with the different characteristics of regions. We urge
stakeholders to engage with transmission providers as part of the
compliance process as the transmission providers develop their proposed
study cost allocations.
421. In response to National Grid, AES, and Clean Energy
Associations' comments arguing that costs should be allocated based on
individual calculations of the actual time and resources expended on a
particular interconnection request, we find that such individual
calculations would not only increase the administrative burden on
transmission providers, but also would offer little benefit given the
cluster study context, which requires transmission providers to
evaluate multiple interconnection requests simultaneously.\844\ We are
also unconvinced that a transmission provider could accurately perform
such calculations because, as explained above, some study costs are
unrelated to an individual interconnection request and are instead
incurred as a matter of course as part of studying a cluster of
interconnection requests.
---------------------------------------------------------------------------
\844\ AES Initial Comments at 12; Clean Energy Associations
Initial Comments at 23; National Grid Initial Comments at 17.
---------------------------------------------------------------------------
4. Allocation of Cluster Network Upgrade Costs
a. NOPR Proposal
422. In the NOPR, the Commission proposed to require transmission
providers to allocate network upgrade costs to interconnection
customers within a cluster using a proportional impact method.\845\ The
Commission also proposed to add the defined term proportional impact
method to the pro forma LGIP and require transmission providers to
revise their LGIPs to include the specific technical parameters and
thresholds of their method for cost allocation. The Commission also
proposed to require transmission providers to allocate the costs of
transmission provider's interconnection facilities equally among all
interconnection customers sharing use of the transmission provider's
interconnection facilities. The Commission sought comment on: (1)
whether there are specific types of analyses that the Commission should
require transmission providers to use to determine the proportional
impact attributed to an interconnection request, including the benefits
and drawbacks of any proposed approach; (2) whether there are specific
types of analyses that the Commission should prohibit because they are
known to be inaccurate, provide undue discretion to the transmission
provider, or could otherwise be problematic; (3) whether alternative
methods to allocate the costs of network upgrades within a cluster,
such as the proportional capacity method, can be sufficiently accurate
in certain instances, in a manner consistent with or superior to the
proposed method; and (4) whether there are some circumstances where the
proportional capacity method would not be appropriate, such as
circumstances where there may be potential for discriminatory
treatment.\846\
---------------------------------------------------------------------------
\845\ NOPR, 179 FERC ] 61,194 at P 88.
\846\ Id. P 89.
---------------------------------------------------------------------------
b. Comments
i. General Comments
423. Several commenters support the proposal.\847\ These commenters
state that the proposed proportional impact cost allocation method is
widely used, both by RTOs/ISOs and non-RTO/ISO transmission
providers,\848\ and ensures that each interconnection customer
contributes to the cost of network upgrades in proportion to its impact
on the transmission system.\849\ These commenters assert that other
options (such as a proportional capacity or a pro rata allocation per
interconnection request) would be more likely to shift a
disproportionate share of network upgrade costs to smaller generating
facilities, which may have less impact on the transmission system.\850\
Bonneville and Interwest argue that the proportional impact method
could also reduce the incentive for interconnection customers to submit
multiple speculative requests and reduce the amount of cascading
withdrawals and restudies.\851\ ELCON contends that, should any one
proposed generating facility in the cluster have an outsized impact on
the transmission system compared to other proposed generating
facilities in the cluster, those other proposed generating facilities
should be protected from exorbitant network upgrade costs to
accommodate a proposed generating facility that may not be suitably
located.\852\ CAISO adds
[[Page 61077]]
that it has used distribution factor analysis without controversy.\853\
---------------------------------------------------------------------------
\847\ ACORE Initial Comments at 8; Ameren Initial Comments at
12; Avangrid Initial Comments at 31; Cypress Creek Initial Comments
at 19; Eversource Initial Comments at 15; Fervo Energy Initial
Comments at 3; Interwest Initial Comments at 16-17; Invenergy
Initial Comments at 21; NEPOOL Initial Comments at 15; New Jersey
Commission Initial Comments at 15; Northwest and Intermountain
Initial Comments at 8; NYTOs Initial Comments at 16; Omaha Public
Power Initial Comments at 5; Pennsylvania Commission Initial
Comments at 8-9.
\848\ For example, several transmission providers support the
Commission's proposal, and state that they already use a
proportional impact method or distribution factor analysis. CAISO
Initial Comments at 13; ISO-NE Initial Comments at 25; MISO Initial
Comments at 46-47; NYISO Initial Comments at 14; PJM Initial
Comments at 36; SoCal Edison Initial Comments at 16; Tri-State
Initial Comments at 12.
\849\ ACORE Initial Comments at 8; Ameren Initial Comments at
12; Avangrid Initial Comments at 31; Cypress Creek Initial Comments
at 19; Eversource Initial Comments at 15; Fervo Energy Initial
Comments at 3; Interwest Initial Comments at 16-17; Invenergy
Initial Comments at 21; NEPOOL Initial Comments at 15; New Jersey
Commission Initial Comments at 15; Northwest and Intermountain
Initial Comments at 8; NYTOs Initial Comments at 16; Omaha Public
Power Initial Comments at 5; Pennsylvania Commission Initial
Comments at 8-9.
\850\ ACORE Initial Comments at 8; Ameren Initial Comments at
12; Avangrid Initial Comments at 31; Cypress Creek Initial Comments
at 19, Eversource Initial Comments at 15; Fervo Energy Initial
Comments at 3, Interwest Initial Comments at 16-17; Invenergy
Initial Comments at 21; NEPOOL Initial Comments at 15; New Jersey
Commission Initial Comments at 15; Northwest and Intermountain
Initial Comments at 8; NYTOs Initial Comments at 16; Omaha Public
Power Initial Comments at 5; Pennsylvania Commission Initial
Comments at 8-9.
\851\ Bonneville Initial Comments at 10; Interwest Initial
Comments at 17.
\852\ ELCON Initial Comments at 9.
\853\ CAISO Initial Comments at 13.
---------------------------------------------------------------------------
424. NRECA states that it interprets this proposal to implement--
and not modify, weaken, or permit deviations from--the Commission's
established policy that transmission costs, including network upgrade
costs, must be allocated in a manner at least reasonably commensurate
with estimated benefits.\854\ NRECA states that, based on that
interpretation of the NOPR's proposal, NRECA believes this method is
fair to both interconnection customers and transmission providers and
helps ensure that the costs to implement an interconnection request are
allocated reasonably commensurate with cost causation and expected
benefits. NRECA states that the proportional impact method is also
reasonably transparent and relatively easy for transmission providers
to implement, explain, and defend.
---------------------------------------------------------------------------
\854\ NRECA Initial Comments at 22.
---------------------------------------------------------------------------
425. In response to the Commission's request for comment on whether
there are circumstances in which the proportional capacity method would
be appropriate, some commenters argue that the proportional capacity
method is never appropriate and should be expressly prohibited for
clusters.\855\ MISO argues that network upgrade cost allocation methods
that only consider installed capacity without considering the network
topology do not consider the full picture of what an interconnection
customer's responsibility for the network upgrade costs should be.\856\
Pennsylvania Commission asserts that large generating facilities would
continue to bear high network upgrade costs and would have an incentive
to interconnect wisely, while small generating facilities, which are
becoming the norm in interconnection queues, would not.\857\
Pennsylvania Commission contends that this would create a subsidy
whereby large generating facilities pay a share of unnecessary network
upgrade costs caused by poor siting of smaller generating
facilities.\858\ Longroad Energy illustrates this point by noting that
one of its generating facilities was recently allocated nearly $10
million under the proportional capacity method based solely on the
generating facility's size, despite the fact that relevant
interconnection studies firmly established that its generating
facility, while large, actually reduced the identified overload.\859\
---------------------------------------------------------------------------
\855\ Longroad Energy Initial Comments at 9; MISO Initial
Comments at 45-46; NRECA Initial Comments at 22; Pennsylvania
Commission Initial Comments at 9.
\856\ MISO Initial Comments at 45-46.
\857\ Pennsylvania Commission Initial Comments at 9.
\858\ Id.; see also NRECA Initial Comments at 22.
\859\ Longroad Energy Initial Comments at 9.
---------------------------------------------------------------------------
426. NV Energy urges the Commission to reconsider the application
of pro rata allocation of network upgrade costs over using the
proportional impact method.\860\ NV Energy contends that the
proportional impact method could negatively impact interconnection
customers due to the time and risk of reallocations required by
restudies.\861\ NV Energy argues that assigned network upgrade costs
could change dramatically if a cluster participant withdraws from the
interconnection queue and requires a restudy, potentially resulting in
each participant's cost allocation changing.\862\ NV Energy asserts
that in addition to disintegrating cost reassurance for the
interconnection customer, performing studies using the proportional
impact method defeats the purpose of completing cluster studies where
each interconnection customer in the cluster has the same
interconnection queue position and that this method will require the
transmission provider to review each interconnection request within the
cluster individually to assign the proportional impact.
---------------------------------------------------------------------------
\860\ NV Energy Initial Comments at 12.
\861\ Id.; PacifiCorp Reply Comments at 3.
\862\ NV Energy Initial Comments at 12.
---------------------------------------------------------------------------
427. NV Energy contends that using the proportional impact method
to allocate the costs of network upgrades resulting from cluster
studies will be burdensome in application because of the volume of
interconnection requests being studied and the large number of network
upgrades identified in each study.\863\ NV Energy states that, under a
proportional capacity method, when an interconnection customer
withdraws and the same network upgrades are deemed necessary, the
transmission provider could simply reallocate a pro rata share to the
remaining interconnection customers and expedite the study; however, in
the case of the proportional impact method, the transmission provider
would need to complete a full restudy to review each generating
facility's impact on the system.
---------------------------------------------------------------------------
\863\ Id.
---------------------------------------------------------------------------
428. According to NV Energy, this issue is further exacerbated when
a network upgrade becomes a shared network upgrade with another cluster
and the proportional impact is expanded to include additional
interconnection customers.\864\ NV Energy states that, not only would
the restudy be required for the lower-queued cluster based on the
withdrawal, but also the concurrently queued cluster to modify the
network upgrade cost allocation. NV Energy also argues that, without a
consistent proportional impact cost allocation amongst transmission
providers, there is risk that this could lead to disputes at the
Commission from interconnection customers, which would lead to
increased costs and delays.
---------------------------------------------------------------------------
\864\ Id. at 13.
---------------------------------------------------------------------------
429. PacifiCorp strongly opposes the proportional impact method to
allocate network upgrade costs.\865\ PacifiCorp argues that the
Commission has not made a transmission provider-specific finding that
the proportional capacity method, approved for PacifiCorp by the
Commission in May 2020,\866\ is no longer just and reasonable.
PacifiCorp contends that transmission providers should be permitted to
use proportional capacity-based network upgrade cost allocation
methods.\867\ PacifiCorp claims that the proportional capacity method
it uses is informed by three additional mechanisms within the cluster
study process, all of which work in tandem to ensure that costs are
appropriately allocated: (1) the use of electrically or geographically
relevant subregions; (2) iterative studies that consider ERIS network
upgrades prior to NRIS requests; and (3) a floor of 1% of total MW
within a cluster, under which interconnection requests will be deemed
not to contribute to the network upgrades identified in the cluster
study.\868\
---------------------------------------------------------------------------
\865\ PacifiCorp Initial Comments at 23.
\866\ PacifiCorp, 171 FERC ] 61,112 (2020).
\867\ PacifiCorp Initial Comments at 22, 26.
\868\ Id. at 23-24.
---------------------------------------------------------------------------
430. PacifiCorp states that the proportional capacity method also
assists it in completing cluster studies and restudies on a timely
basis, and minimizes disputes.\869\ PacifiCorp argues that, in sharp
contrast, the proportional impact method involves a complex analysis
that, in addition to being excessively time consuming, will result in
disputes, both of which will put substantial pressure on PacifiCorp's
ability to meet study deadlines.\870\ Therefore, according to
PacifiCorp, requiring use of the proportional impact method will be
counterproductive to the Commission's intent of making processing of
interconnection requests more efficient.
---------------------------------------------------------------------------
\869\ Id.; PacifiCorp Reply Comments at 2.
\870\ PacifiCorp Initial Comments at 24-25.
---------------------------------------------------------------------------
431. PacifiCorp explains that the degree of contribution to a
needed network upgrade can be very difficult to
[[Page 61078]]
determine depending on the size, number of interconnection requests,
and location of proposed generating facilities in a cluster.\871\
PacifiCorp adds that a proportional impact method analysis is
complicated further by the fact that all interconnection requests
within a single cluster are considered equally queued. In addition,
PacifiCorp argues that, given the size of its multi-state system and
the thousands of MWs of interconnection requests entering the cluster
study process each year,\872\ it is simply not possible to both perform
a proportional impact method analysis on each interconnection request
and complete the cluster study process within 150 calendar days.\873\
---------------------------------------------------------------------------
\871\ Id. at 25.
\872\ PacifiCorp states that during the most recent cluster
study, which commenced in May 2022, PacifiCorp received around 40
GW-worth of interconnection requests, which is more than three times
PacifiCorp's peak system load.
\873\ PacifiCorp Initial Comments at 25.
---------------------------------------------------------------------------
ii. Comments on Specific Proposal
(a) Specificity Regarding Technical Parameters and Thresholds
432. Several commenters state that, if the Commission adopts its
proposal for each transmission provider to revise its tariff to include
its specific technical parameters and thresholds for the proportional
impact method for network upgrade cost allocation, the Commission
should at least consider guidance or principles for those technical
parameters and thresholds.\874\ The same commenters ask that the
Commission also require sufficient specificity to provide transparency
and certainty for potential interconnection customers and to avoid
disputes over cost allocation.
---------------------------------------------------------------------------
\874\ Clean Energy Buyers Initial Comments at 9; Cypress Creek
Initial Comments at 19; Invenergy Initial Comments at 21.
---------------------------------------------------------------------------
433. EPSA and Vistra argue that the Commission should provide an
opportunity for comments prior to moving to a final rule with more
detailed parameters.\875\ Vistra contends that without such an
opportunity, the Commission will have not provided sufficient
notice.\876\ Vistra argues that adopting a final rule that contains
only the very high-level requirement to allocate costs based on
proportional impact method simply defers the Commission's determination
on important implementation details to litigation over the individual
compliance filings that will be submitted. Without sufficient detail,
Vistra continues, the Commission will arguably need to accept any set
of technical details as in compliance with the requirement to allocate
network upgrade costs based on proportional impact.
---------------------------------------------------------------------------
\875\ EPSA Initial Comments at 8; Vistra Initial Comments at 12-
13.
\876\ Vistra Initial Comments at 13.
---------------------------------------------------------------------------
434. PPL states that the NOPR did not address the allocation of
network upgrade costs within a cluster after an interconnection
customer withdraws.\877\ PPL states that, prior to the execution of an
interconnection agreement by the interconnection customer(s), the
Commission should provide that any interconnection facility and network
upgrade costs previously allocated to the withdrawing interconnection
customer be reallocated among the remaining interconnection customers
in the cluster to prevent delays and allow the study process to
proceed. PPL states that the Commission should allow for withdrawal to
be treated as an event that allows the transmission provider to retain
or call on the security provided by the withdrawing interconnection
customer. PPL adds that the Commission should allow for an increase in
the cost allocated to remaining interconnection customers in a cluster
to account for the amount previously allocated to the withdrawing
interconnection customer.
---------------------------------------------------------------------------
\877\ PPL Initial Comments at 14.
---------------------------------------------------------------------------
(b) Tariff Requirement for Technical Details
435. PJM states that, while it generally supports the requirement
to describe the cost allocation method in the applicable tariff, the
Commission should clarify that transmission providers may provide the
detailed and specific technical information in business practice
manuals rather than in tariffs.\878\ PJM states that these types of
implementation details change from time to time and, consistent with
Commission precedent, are appropriately addressed in the transmission
provider's manuals. PJM asserts that mandating that these procedures be
placed in the transmission provider's tariff, on the other hand, would
require a transmission provider to submit an FPA section 205 filing
every time the implementation details changed, which would be
inefficient and burdensome.
---------------------------------------------------------------------------
\878\ PJM Initial Comments at 37.
---------------------------------------------------------------------------
436. In contrast, other commenters argue that these thresholds, and
any associated procedures, should be codified in transmission
providers' tariffs.\879\ AES explains that the thresholds used as part
of the proportional impact method are important planning criteria, and
constitute ``practices that affect rates and services significantly,
that are realistically susceptible of specification and that are not so
generally understood as to render recitation superfluous;''
accordingly, AES continues, they should be included in transmission
providers' filed rates, and subject to review and approval by the
Commission pursuant to section 205 of the FPA.\880\ Union of Concerned
Scientists contends that the combination of issues that are expressed
through network upgrade decisions and cost allocations for
interconnection customers are arguably central to this rulemaking and
the fulfillment of the competition amongst interconnection customers as
a regulatory approach to setting wholesale energy prices and must be
subject to notice and review, both initially and for any subsequent
changes, through filings with the Commission.\881\
---------------------------------------------------------------------------
\879\ AES Initial Comments at 8; Union of Concerned Scientists
Reply Comments at 20.
\880\ AES Initial Comments at 8 (citing Pub. Serv. Co. of Colo.,
67 FERC ] 61,371, at 62,267 (1994); Portland Gen. Elec. Co., 144
FERC ] 61,087 (2013)).
\881\ Union of Concerned Scientists Reply Comments at 20-21.
---------------------------------------------------------------------------
437. Xcel states that the Commission should make clear that there
are several just and reasonable approaches to allocating network
upgrade costs to interconnection customers within a cluster.\882\ For
example, states Xcel, if two generating facilities are connecting to a
new a transmission line, a substation must be constructed. Xcel
explains that, using some analysis, a larger generating facility might
be considered to have a larger impact, but the respective size of the
interconnection request did not have any impact on the cost or size of
the substation needed. Xcel states that, for example, the cost of the
substation is not different for a 100 MW and 500 MW generating facility
or for two 300 MW generating facilities if they are interconnecting at
the same voltage, and as a result, the cost of that substation should
be allocated equally to both generating facilities. Xcel states that
there could be a third generating facility (not directly connected to
the substation) from which the power flows through the new substation,
but it is not clear if the Commission is proposing that the
interconnection customer proposing that third generating facility pays
for a portion of the substation costs because its flows ``impact'' the
substation. Xcel states that it does not generally support allocating
network upgrade costs to interconnection customers simply because their
proposed generating facilities have a flow impact if they are not
causing the
[[Page 61079]]
need for the network upgrade under a ``but for'' evaluation.
---------------------------------------------------------------------------
\882\ Xcel Initial Comments at 26.
---------------------------------------------------------------------------
438. Invenergy states that, in the occasional circumstance where a
point of interconnection is shared among more than one interconnection
request within a cluster, which could involve new equipment that does
not vary based on proportional impact, the associated costs at the
point of interconnection (e.g., the substation) could be allocated on a
pro rata basis.\883\ PacifiCorp states that the proportional impact
method would not be necessary to account for costs that are agnostic to
interconnection customer impacts, such as the need to construct a new
substation to connect to a new transmission line regardless of whether
one or several generating facilities are interconnecting.\884\
---------------------------------------------------------------------------
\883\ Invenergy Initial Comments at 21-22.
\884\ PacifiCorp Reply Comments at 2 (citing Xcel Initial
Comments at 26 (describing how a proportional impact analysis is not
necessary to allocate costs for a new station connecting to a
transmission line, as ``[t]he cost of the station is not different
for a 100 MW and 500 MW generator or for two 300 MW generators if
they are interconnecting at the same voltage'')).
---------------------------------------------------------------------------
439. Invenergy states that the NOPR could be read to permit each
transmission provider to adopt different and possibly inconsistent
analyses and that the Commission should be clear that it is requiring a
proportional impact method for allocating network upgrade costs, just
as the NOPR proposes to do with respect to shared network
upgrades.\885\
---------------------------------------------------------------------------
\885\ Invenergy Initial Comments at 21.
---------------------------------------------------------------------------
440. Several commenters state that the final rule should require
transmission providers to submit compliance filings that propose
minimum distribution factor thresholds that will be used to evaluate
NRIS and ERIS requests.\886\
---------------------------------------------------------------------------
\886\ AEE Reply Comments at 10; AES Initial Comments at 8;
Longroad Energy Initial Comments at 9; SEIA Initial Comments at 11.
---------------------------------------------------------------------------
(c) Requests for Flexibility
441. Some commenters support the proportional capacity method only
for certain network upgrades or limited circumstances.
442. Tri-State states that it does not apply a proportional impact
method to transient-stability-driven network upgrades, which cannot be
measured using a proportional impact approach; rather, Tri-State uses a
MW pro rata method approach when allocating the costs of transient-
stability-driven network upgrades.\887\ Longroad Energy states that, to
the extent the Commission allows a transmission provider to use some
method other than a flow-based proportional impact allocation for
transient stability constraints, the transmission provider should be
required to demonstrate that the alternative cost allocation method is
based on sound engineering principles for the specific transient
stability constraint observed in the studies.\888\
---------------------------------------------------------------------------
\887\ PacifiCorp Reply Comments at 2; Tri-State Initial Comments
at 12.
\888\ Longroad Energy Initial Comments at 9.
---------------------------------------------------------------------------
443. R Street states that allocating network upgrade costs based on
proportional capacity is appropriate in situations where clusters are
composed of similar types of generation.\889\ R Street asserts that the
default should be that all thermal network upgrade cost allocations are
based on proportional capacity. R Street states that this leaves open
the possibility for transmission providers to allocate other types of
network upgrade costs (voltage, transient stability, short circuit)
using a different but predefined method.
---------------------------------------------------------------------------
\889\ R Street Initial Comments at 12.
---------------------------------------------------------------------------
444. Several commenters ask the Commission to provide flexibility
for transmission providers to establish a cost allocation method for
network upgrades, rather than mandating a prescriptive approach.\890\
PPL claims that such region-specific cost allocations are necessary to
keep disputes from overwhelming the reform process the Commission
anticipates.\891\ New York State Department asserts that any strict or
limiting requirement for a specific cost allocation method may
undermine and replace existing processes that work well.\892\ National
Grid recommends that the Commission allow for consideration of the
unique circumstances of a region, input from relevant stakeholders in
the region, including the potential for regions to propose cost
allocation methods that allow for broader allocation to load or
transmission customers in addition to interconnection customers.\893\
---------------------------------------------------------------------------
\890\ AES Initial Comments at 7; APPA-LPPC Initial Comments at
16; Bonneville Initial Comments at 10; Dominion Initial Comments at
19; Indicated PJM TOs Initial Comments at 20; ISO-NE Initial
Comments at 25; MISO Initial Comments at 45; National Grid Initial
Comments at 8; NEPOOL Initial Comments at 15; New York State
Department Initial Comments at 8; NYISO Initial Comments at 15; PPL
Initial Comments at 14.
\891\ PPL Initial Comments at 14.
\892\ New York State Department Initial Comments at 8-9.
\893\ National Grid Initial Comments at 18.
---------------------------------------------------------------------------
445. Dominion points out that courts and the Commission have long
recognized that there is not one single just and reasonable method for
establishing cost allocation.\894\ Dominion states that rather, cost
allocation proposals are reviewed to determine whether they meet
certain principles, chiefly that costs are allocated in a manner that
is at least ``roughly commensurate'' with estimated benefits
received.\895\ Accordingly, Dominion recommends that if the Commission
imposes any requirements related to cost allocation, it simply retains
a general definition of proportional impact method and is not overly
prescriptive.\896\
---------------------------------------------------------------------------
\894\ Dominion Initial Comments at 19, 21 (citing Entergy La.,
Inc. v. La. Pub. Serv. Comm'n, 539 U.S. 39, 50 (2003)).
\895\ Id. at 19.
\896\ Id. at 22.
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iii. Requests for Clarification or Technical Conference
446. Pattern Energy generally supports the application of the
proportional impact method, subject to clarification on which form of
distribution factor analysis the Commission is contemplating.\897\
Pattern Energy states that there are two types of distribution factors
used to determine the impact of given power injection flows over a
monitored facility: (1) power transfer distribution factor, which is
the percentage of power that will flow on a specific monitored facility
and does not consider outage/contingent facilities; and (2) outage
transfer distribution factor, which is the percentage of power that
will flow on a specific facility that does consider outage/contingent
facilities. Pattern Energy states that the difference between the two
distribution factors (i.e., the consideration of the outage/contingent
facility) is important because power transfer distribution factor is
usually more relevant for evaluating ``local impacts'' (e.g.,
generating facilities that are connecting in very close electrical
proximity to a given monitored element), compared to outage transfer
distribution factor, which captures impacts that may be more
geographically and electrically distant from a given monitored
facility. Pattern Energy asserts that the Commission should require
outage transfer distribution factor to be the required distribution
factor utilized in the proportional impact method for identifying
impacts to constrained facilities and resultant cost allocation for
network upgrades. Pattern Energy argues that outage transfer
distribution factor is a better measure of power flows on the bulk-
power system, and, in turn, its use ensures that impacts to constrained
facilities are properly mitigated by, and cost allocated to, the
actual, full set of contributors and not just the nearby highest
contributors.
---------------------------------------------------------------------------
\897\ Pattern Energy Initial Comments at 11-12.
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447. Pine Gate contends that certain proposed enhancements to the
NOPR
[[Page 61080]]
proposal would provide much needed certainty to interconnection
customers and mitigate the systematic problem of interconnection queues
being the primary mechanism by which needed transmission infrastructure
is identified, developed, and constructed.\898\ Specifically, Pine Gate
requests that the Commission make the following clarifications: (1)
transmission providers are not permitted to allocate to interconnection
customers network upgrade costs associated with preexisting operating
conditions (such as overloads); (2) transmission providers are not
permitted to allocate network upgrade costs to interconnection
customers for loading that results from the simulation of conditions
that do not reflect typical operating conditions; (3) transmission
providers are required to use consistent, uniform thresholds to measure
the impact on a specific transmission facility caused by an
interconnection request and publish these thresholds, along with the
corresponding scope of the resulting network upgrades; and (4)
establish a 4% impact threshold for NRIS and a 20% impact threshold for
ERIS, unless there is preexisting loading on the facility.\899\ Pine
Gate further requests that the Commission provide transmission
providers guidance on the scope of the network upgrade required to
accommodate an interconnection request. Pine Gate states that, if a
network upgrade benefits other types of customers, interconnection
customers should receive transmission credits or other compensation if
the additional transmission capacity created is used for market
dispatch or by wholesale transmission customers.\900\ Pine Gate states
that, if the Commission does not adopt Pine Gate's proposed
enhancements as part of a final rule in this proceeding, then the
Commission should establish a technical conference to explore these
issues.
---------------------------------------------------------------------------
\898\ Pine Gate Initial Comments at 16-17.
\899\ Id. at 18-19.
\900\ Id. at 20.
---------------------------------------------------------------------------
iv. Miscellaneous
448. Pennsylvania Commission states that limiting the scope of each
cluster to those interconnection customers most likely to share the
same network upgrades may reduce the need for the proportional impact
network upgrade cost allocation method.\901\ According to Pennsylvania
Commission, instead of determining the degree to which interconnection
requests cause specific network upgrades on the back end through cost
allocation, clustering by electrical relevance may accomplish the same
goal, making sure that interconnection customers are sharing the costs
of network upgrades that they cause and from which they benefit.
Pennsylvania Commission contends that the Commission should examine
whether limiting the scope of a cluster or cost allocation, or a
combination of both, is the best method to share costs among
interconnection customers causing the same network upgrades.
---------------------------------------------------------------------------
\901\ Pennsylvania Commission Initial Comments at 9.
---------------------------------------------------------------------------
449. Several commenters state that the NOPR leaves unresolved the
fundamental question of more equitably sharing network upgrade costs
across all beneficiaries, including load.\902\ They argue, for example,
that policies requiring interconnection customers to pay for 100% of
network upgrade costs when the benefits of those upgrades are
distributed among other system users (i.e., participant funding) causes
interconnection customers to pay more than their appropriate share of
the costs.\903\ In contrast, Ameren claims that it is appropriate for
interconnection customers to bear responsibility for the cost of
network upgrades required for their interconnection requests.\904\
Ameren argues that, to ensure the full costs of interconnection are
identified and allocated, network upgrade costs associated with
affected systems must also be included in cluster network upgrade cost
allocation, and interconnection customers should be required to accept
the assigned costs. Ohio Commission Consumer Advocate emphasizes that
the Commission should not change the participant funding mechanisms in
RTO/ISO markets,\905\ while PPL argues that the Commission should allow
non-RTO/ISO transmission providers the option to propose allocating the
costs of network upgrades to interconnection customers without credits
as RTOs/ISOs do.\906\
---------------------------------------------------------------------------
\902\ ACORE Initial Comments at 8-9; AEE Initial Comments at 14-
15; Interwest Initial Comments at 5; Northwest and Intermountain
Initial Comments at 8; Public Interest Organizations Initial
Comments at 31-33.
\903\ AEE Initial Comments at 14 (citing Joint Supplemental
Comments of American Clean Power Association, Advanced Energy
Economy, and Solar Energy Industries Association, Docket No. RM21-
17-000, at 7-8 (filed June 1, 2022)).
\904\ Ameren Initial Comments at 12.
\905\ Ohio Commission Consumer Advocate Initial Comments at 9.
\906\ PPL Initial Comments at 13.
---------------------------------------------------------------------------
450. New York State Department and Shell argue that the Commission
should discontinue the historical practice of allowing interconnection
customers essentially free use of headroom on ratepayer-funded network
facilities.\907\ New York State Department states that this occurs when
transmission ratepayers fund upgrades to the transmission system that
create headroom, from which interconnection customers later benefit
without having to pay for access or use.\908\ In contrast, Invenergy
asserts that the Commission needs to ensure that the transmission
planning and interconnection models are consistent, so that
interconnection customers are not required to pay for the cost of
resolving overloads and other transmission system issues that exist
without the proposed interconnection.\909\
---------------------------------------------------------------------------
\907\ New York State Department Initial Comments at 9; Shell
Reply Comments at 27-28.
\908\ New York State Department Initial Comments at 9.
\909\ Invenergy Initial Comments at 21.
---------------------------------------------------------------------------
451. AEE encourages the Commission to ensure that its proposal
increases cost transparency and establishes a pathway for
interconnection customers to access accurate information about their
network upgrade costs in a timely manner.\910\ For instance, AEE asks
that the Commission also provide guidance regarding which party must
pay if network upgrade costs significantly exceed estimates. AEE states
that one approach to minimizing the construction time and cost of
network upgrades, and consequently the interconnection process as a
whole, is to provide a third-party construction option in the pro forma
LGIA that would allow the interconnection customer to elect for stand
alone network upgrades to be bid out and potentially built by third
parties.\911\
---------------------------------------------------------------------------
\910\ AEE Initial Comments at 15.
\911\ Id. at 15-16 (citing Comments of AEE, Docket No. RM21-17-
000, at 47-49 (filed Oct. 12, 2021)).
---------------------------------------------------------------------------
452. Pine Gate recommends that the Commission require transmission
providers to analyze more holistically the other underlying needs
driving identified network upgrades to the transmission system.\912\
Pine Gate states that the Commission should require transmission
providers to only allocate to interconnection customers the costs
associated with accelerating the construction of the upgrade to
accommodate the interconnection customer's anticipated commercial
operation date.\913\
---------------------------------------------------------------------------
\912\ Pine Gate Initial Comments at 17.
\913\ Id.; Fervo Energy Reply Comments at 5.
---------------------------------------------------------------------------
c. Commission Determination
453. We adopt the NOPR proposal, with modifications, to add new
proposed section 4.2.3, now section 4.2.1, to the pro forma LGIP to
require transmission providers to allocate
[[Page 61081]]
network upgrade costs based on a proportional impact method.\914\ Based
on the record, we modify the NOPR proposal and add definitions for
substation network upgrades and system network upgrades in the pro
forma LGIP and pro forma LGIA. In addition, we modify the definitions
of proportional impact method and stand alone network upgrades proposed
in the NOPR. We also modify proposed section 4.2.1 of the pro forma
LGIP to require transmission providers to allocate the costs of network
upgrades located at substations equally among each generating facility
interconnecting to the same substation (i.e., on a per capita basis),
and to revise the information that a transmission provider's tariff
must include regarding the proportional impact method.
---------------------------------------------------------------------------
\914\ ``Proportional Impact Method shall mean a technical
analysis conducted by Transmission Provider to determine the degree
to which each Generating Facility in the Cluster Study contributes
to the need for a specific System Network Upgrade.'' Pro forma LGIP
section 1.
---------------------------------------------------------------------------
454. We also modify the requirement in proposed section 4.2.1 of
the pro forma LGIP for transmission providers to directly assign the
cost of shared transmission provider's interconnection facilities to
interconnection customers on a per capita basis (i.e., on a per
generating facility basis). Specifically, we modify proposed section
4.2.1 of the pro forma LGIP to make the new provisions applicable to
the interconnection customer's interconnection facilities as well as to
the transmission provider's interconnection facilities. We also modify
this section to provide that interconnection customers may agree to
share interconnection facilities, and that the per capita allocation
will apply only where interconnection customers agree to share
interconnection facilities. We also modify this section to allow the
interconnection customers that share interconnection facilities to
choose a different cost sharing arrangement upon mutual agreement.
455. We find that adopting the modified NOPR proposal will ensure
just and reasonable rates as transmission providers transition to the
cluster study process required by this final rule. We find that the
cost allocation method adopted herein will allow transmission providers
to allocate network upgrade costs among several interconnection
customers that may benefit from (and cause the need for) certain
network upgrades. We also find that allocating shared network upgrade
costs among a cluster of interconnection customers will reduce the
frequency of an individual interconnection customer being allocated the
costs of a large network upgrade that benefits subsequent
interconnection customers; reduce the incentive of interconnection
customers to submit multiple speculative interconnection requests to
avoid shouldering the cost of large network upgrades that may be
triggered by a single interconnection customer in the existing serial
study process; and reduce the number of cascading withdrawals and
restudies, thereby improving the efficiency of the interconnection
process and reducing interconnection queue processing delays.
456. We conclude that a proportional impact method appropriately
reflects the Commission's interconnection pricing policy for facilities
designated as network upgrades needed for the interconnection of the
cluster. However, we are persuaded to adopt a different cost allocation
method for substations at the point of interconnection that are
designated as network upgrades and needed only to facilitate the
interconnection of certain generating facilities within the cluster
seeking interconnection to the specific substation, as demonstrated by
commenters.\915\
---------------------------------------------------------------------------
\915\ Xcel Initial Comments at 26; Invenergy Initial Comments at
21-22.
---------------------------------------------------------------------------
457. In Order No. 2003, the Commission reasoned that ``it is
appropriate for the Interconnection Customer to pay the initial full
cost for Interconnection Facilities and Network Upgrades that would not
be needed but for the interconnection'' (i.e., ``but for''
policy).\916\ Hence, under the serial study process in the existing pro
forma LGIP, the transmission provider allocates network upgrade costs
by assigning the initial full cost responsibility for all network
upgrades identified in a study to a single interconnection customer
that causes those upgrades. However, in transitioning to a cluster
study process in this final rule, the Commission must establish a
method for allocating network upgrade costs among all interconnection
customers within a cluster. Based on the record in this proceeding, we
find that a proportional impact method is the appropriate application
of the Commission's interconnection pricing policy when allocating the
costs of network upgrades needed for an entire cluster of proposed
generating facilities because a proportional impact method allows
transmission providers to assess a generating facility's individual
contribution to the need for the network upgrades identified for the
cluster. However, the need for substation network upgrades is only
generated by a specific generating facility seeking interconnection at
a specific substation and not by all the generating facilities in the
cluster. It would be inconsistent with the Commission's interconnection
pricing policy to allocate the costs of the substation network upgrades
to interconnection customers in the cluster that are interconnecting at
other substations because, in the case of a cluster of new
interconnection requests, only the generating facilities
interconnecting to the same substation generate the need for network
upgrades at that substation.
---------------------------------------------------------------------------
\916\ See id. P 694; Nev. Power Co., 182 FERC ] 61,048, at PP
50-51 (2023) (describing the cost allocation requirements for
network upgrades as the Commission's Order No. 2003 ``but for
requirements'').
---------------------------------------------------------------------------
458. As explained above, the cost of substation network upgrades
must be initially allocated only to those interconnection customers
seeking to interconnect at the same substation,\917\ while the cost of
system network upgrades for all interconnection customers in a cluster
must be initially allocated based on the technical analyses to be
specified under the transmission provider's proportional impact method.
To facilitate these differing cost allocation methods, we modify the
definitions in section 1 of the pro forma LGIP and article 1 of the pro
forma LGIA to distinguish substation network upgrades (including all
switching stations) \918\ from system network upgrades.\919\ Using
these definitions, we further modify the pro forma LGIP and pro forma
LGIA to draw this distinction and to ensure that the costs for the two
types of network upgrades are allocated consistent with the
Commission's interconnection pricing policy, which establishes the
principles for allocating the costs of network upgrades.
---------------------------------------------------------------------------
\917\ For clarity, we note that we are referring to the
transmission provider's substation immediately beyond the point of
interconnection as defined in section 1 of the pro forma LGIP:
``Point of Interconnection shall mean the point . . . where the
interconnection facilities connect to the transmission provider's
transmission system.'' Pro forma LGIP section 1 (Definitions).
\918\ Substation network upgrades shall mean the network
upgrades required at the substation located at the point of
interconnection.
\919\ System network upgrades shall mean the network upgrades
required beyond the substation located at the point of
interconnection.
---------------------------------------------------------------------------
459. We note that we are not modifying the pro forma LGIP's
definition of facilities needed beyond the point of interconnection as
network upgrades; rather, we are providing greater specificity with
regard to how the costs of the two distinct types of network upgrades
identified within a
[[Page 61082]]
cluster study should be initially allocated. We find that this approach
will also lead to greater transparency and ease of administering the
cluster study process by establishing distinct guidelines for how the
costs of the two types of network upgrades will be initially allocated
within a cluster. Also, as commenters note, in instances where a point
of interconnection is shared among more than one interconnection
request within a cluster, the cost of the substation network upgrades
is more directly impacted by the number of generating facilities
proposing to interconnect there because the cost of the equipment used
to interconnect generating facilities to substations does not vary
based on the electrical characteristics of the interconnecting
generating facilities (e.g., the MW size of the generating facility,
fuel type, or services provided).
460. To further implement this modification of the NOPR proposal,
we modify the definition of stand alone network upgrades proposed in
the NOPR to recognize that (1) a substation network upgrade may only be
considered a stand alone network upgrade if it is needed to
interconnect only one generating facility in the cluster and no other
interconnection customer in that cluster is required to interconnect to
the same substation network upgrades, and (2) the proportional impact
analysis will be used in determining whether a system network upgrade
is only needed for one generating facility in the cluster and can be
considered a stand alone network upgrade. Our revisions also seek to
prevent lengthy disputes over which interconnection customer has the
right to exercise the option to build in instances where a network
upgrade could qualify under the existing definition of a stand alone
network upgrade, but the network upgrade is needed for multiple
interconnection customers' generating facilities.
461. Several commenters request that the Commission provide more
specificity and guidance regarding the specific thresholds and metrics
that transmission providers are expected to submit on compliance.\920\
In this final rule, we modify the proposed requirement in pro forma
LGIP section 4.2.1 for transmission providers to revise their LGIPs on
compliance to include specific thresholds and metrics. Instead, we
direct transmission providers on compliance to provide tariff
provisions that describe, for each type of system network upgrade that
a transmission provider would identify in the cluster study process
(e.g., voltage support network upgrades or short circuit network
upgrades), how the costs of each system network upgrade type will be
allocated among the interconnection customers within the cluster.
Transmission providers' revisions on compliance must provide that costs
for a discrete network upgrade identified in the cluster study process
(e.g., reconductoring a portion of a transmission line to accommodate
the interconnection of several generating facilities in the cluster)
are allocated to only the interconnection customers in the cluster that
are shown through technical analyses to contribute to the need for the
discrete network upgrade. For example, the transmission provider must
propose tariff provisions similar to the following: (1) voltage support
related network upgrades shall be allocated using a voltage impact
analysis, which will identify each generating facility's contribution
to the voltage violation; (2) short circuit network upgrade costs
within a cluster will be allocated based on the impact from each
generating facility within the cluster, on the constrained facilities
under the most constraining fault in the relevant study case(s); or (3)
the estimated costs of short circuit related general reliability
network upgrades identified through a cluster study shall be assigned
to all interconnection requests in that group study pro rata on the
basis of the short circuit duty contribution of each generating
facility.
---------------------------------------------------------------------------
\920\ Clean Energy Buyers Initial Comments at 9; Cypress Creek
Initial Comments at 19; EPSA Initial Comments at 8; Invenergy
Initial Comments at 21; Vistra Initial Comments at 12-13.
---------------------------------------------------------------------------
462. PJM requests that the Commission clarify that transmission
providers may provide the detailed and specific technical information
in business practice manuals rather than in tariffs.\921\ In response,
we find that, as noted above, transmission providers must provide
tariff provisions that describe the method they will use for allocating
costs of each type of network upgrade, but specific metrics and
thresholds for implementing the allocation, or other specific technical
information, may be included in business practice manuals, or publicly
posted on the transmission provider's website. We agree with PJM that
such details are appropriate for business practice manuals, consistent
with Commission precedent applying the ``rule of reason'' to determine
whether a detail should be included in a tariff or business practice
manual. In particular, the technical information surrounding
implementation of the proportional impact method by a particular
transmission provider does not need to be included in the transmission
provider's tariff under the rule of reason because these provisions are
properly classified as implementation details that do not significantly
affect rates, terms, and conditions of service.\922\
---------------------------------------------------------------------------
\921\ PJM Initial Comments at 37.
\922\ See, e.g., N.Y. Indep. Sys. Operator, Inc., 179 FERC ]
61,102, at PP 105-114 (2022) (citing, inter alia, Energy Storage
Ass'n v. PJM Interconnection, L.L.C., 162 FERC ] 61,296, at P 103
(2018); City of Cleveland v. FERC, 773 F.2d, 1368, 1376-77 (D.C.
Cir. 1985)).
---------------------------------------------------------------------------
463. Several commenters request that the Commission direct
transmission providers to use a specific type of proportional impact
method or distribution factor analysis and apply minimum distribution
factor thresholds that will be used to evaluate NRIS and ERIS
requests.\923\ We are unpersuaded that such level of prescription is
needed to ensure just, reasonable, and not unduly discriminatory or
preferential rates. Instead, we believe that flexibility for
transmission providers to develop such details as part of their
compliance filings--and in their business practice manuals, where
consistent with the rule of reason, as discussed above--is important to
ensure that the proportional impact method used by each transmission
provider reflects the characteristics of its region (e.g., types of
network upgrade facilities identified in the region, or preferred
analyses in the region for determining the share of the need for the
specific network upgrade type). For the same reason, we decline to
require transmission providers to use consistent, uniform thresholds to
measure impact, as requested by Pine Gate.\924\
---------------------------------------------------------------------------
\923\ AEE Reply Comments at 10; AES Initial Comments at 8;
Invenergy Initial Comments at 21; Longroad Energy Initial Comments
at 9; Pattern Energy Initial Comments at 11-12; Pine Gate Initial
Comments at 16-19; SEIA Initial Comments at 11.
\924\ Pine Gate Initial Comments at 19.
---------------------------------------------------------------------------
464. Based on the record, we decline to require transmission
providers to use the proportional capacity method to allocate the costs
of all system network upgrades, given our decision to instead opt for
the proportional impact method and because it reflects the Commission's
interconnection pricing policy for facilities designated as network
upgrades needed for the interconnection of the cluster. Nonetheless, we
recognize that there may be a tradeoff between simplicity and accuracy
when considering proportional capacity versus proportional impact for
cost allocation for network upgrades. While we require transmission
providers to allocate network upgrade costs based on a proportional
impact method based on the record in this final rule, we
[[Page 61083]]
acknowledge that other allocation methods could potentially meet the
consistent with or superior to standard or the independent entity
variation standard if, among other things, they allocate network
upgrade costs in a manner consistent with the Commission's
interconnection pricing policy.
465. We disagree with NV Energy and PacifiCorp's arguments that the
proportional impact method carries unmanageable time, restudy, and
reallocation risks.\925\ In response to concerns about restudy risk
resulting from withdrawals, we note that the Commission's new cluster
study process requires transmission providers to complete the process
within 150 calendar days, which we believe is sufficiently long for
transmission providers to be able to conduct the rounds of restudy and
reallocation that are needed to achieve a stable interconnection queue
and reduce the risk of further withdrawals before moving to the
individual facilities studies. Further, the proportional impact method
is currently used by most transmission providers that conduct cluster
studies, and several of these transmission providers have adopted study
timelines similar to what we adopt in this final rule.\926\
---------------------------------------------------------------------------
\925\ NV Energy Initial Comments at 12; PacifiCorp Reply
Comments at 3.
\926\ See Dominion Energy S.C., Inc., Docket No. ER22-301-000
(Dec. 28, 2021) (delegated order); Duke Energy Carolinas, LLC, 176
FERC ] 61,075 (2021); Pub. Serv. Co. of Colo., 169 FERC ] 61,182
(2019); Tri-State Generation & Transmission Ass'n, Inc., 173 FERC ]
61,015 (2020).
---------------------------------------------------------------------------
466. We disagree with claims from NV Energy and PacifiCorp that the
proportional impact method must be conducted as if it were a serial
study in that each interconnection request must be studied
individually. When proposing a proportional impact method on
compliance, transmission providers have many methods to choose from and
should adopt a method that allows them to meet the timelines designated
in the cluster study process. In response to PPL,\927\ we confirm that
within the cluster study process, any network upgrade costs previously
allocated to a withdrawing interconnection customer that are still
required after the withdrawal may be reallocated among the remaining
interconnection customers in the cluster based on the relevant cost
allocation method applied to the network upgrade facility type.
---------------------------------------------------------------------------
\927\ PPL Initial Comments at 14.
---------------------------------------------------------------------------
467. Finally, several commenters suggest alternative reforms to the
Commission's network upgrade cost allocation policies: (1) limit the
use of cluster areas as an alternative to the proposed cost allocation
method within a cluster; \928\ (2) change the interconnection pricing
policy or participant funding regime (as allowed in certain RTOs/ISOs)
to limit participant funding and/or require assessment of whether
transmission customers benefit from and should pay for network
upgrades; \929\ (3) establish a process to eliminate the use of
headroom on network transmission facilities; \930\ and/or (4) provide a
third-party construction option.\931\ We find these requests to be
outside the scope of this proceeding and lacking in record support to
adequately consider whether to adopt them in this final rule.
---------------------------------------------------------------------------
\928\ Pennsylvania Commission Initial Comments at 9.
\929\ ACORE Initial Comments at 8-9; AEE Initial Comments at 14-
15; Ameren Initial Comments at 12; Interwest Initial Comments at 5;
Northwest and Intermountain Initial Comments at 8; Ohio Commission
Consumer Advocate Initial Comments at 12; PPL Initial Comments at
13; Public Interest Organizations Initial Comments at 31-33.
\930\ New York State Department Initial Comments at 9; Shell
Reply Comments at 27-28.
\931\ AEE Initial Comments at 15.
---------------------------------------------------------------------------
5. Shared Network Upgrades
a. NOPR Proposal
468. In the NOPR, the Commission preliminarily found that the
absence of network upgrade cost sharing provisions in the pro forma
LGIP may pose a barrier to entry to generation development.\932\ The
Commission stated that absent cost sharing provisions among clusters,
interconnection customers may significantly benefit from earlier-in-
time network upgrades but not share in the cost of those network
upgrades in a manner that is roughly commensurate with benefits. The
Commission therefore proposed to require transmission providers to
allocate the costs of network upgrades between interconnection
customers in an earlier cluster and interconnection customers in a
subsequent cluster that benefit from the same network upgrade in a
manner that is roughly commensurate with the benefits received.\933\
Specifically, the Commission proposed that when the transmission
provider analyzes the network upgrades identified through its cluster
study process, if a generating facility of an interconnection customer
in a later cluster directly connects either to (1) a network upgrade in
service for less than five years or (2) a substation where the network
upgrade in service for less than five years terminates, then the
transmission provider would be required to designate the network
upgrade a shared network upgrade. Upon such a designation, the
interconnection customer in the later cluster would be required to
contribute a pro rata portion of the shared network upgrade's remaining
undepreciated capital cost based on the impact the interconnection
customer in the later cluster has on the network upgrade, as measured
using the same method the transmission provider used to determine the
impact of the interconnection customer(s) in the earlier cluster.
---------------------------------------------------------------------------
\932\ NOPR, 179 FERC ] 61,194 at P 97.
\933\ Id. P 98.
---------------------------------------------------------------------------
469. The Commission proposed that if the new generating facility
does not directly connect to the network upgrade, then the transmission
provider would perform a power flow analysis with a two-step test to
measure the lower-queued interconnection customer's use of and benefit
from the network upgrade funded by interconnection customers from an
earlier cluster. Under the first step, the transmission provider would
determine if the impact of the interconnection customer in the later
cluster exceeds five MW and exceeds one percent of the network
upgrade's rating. Then, if those criteria are met, the transmission
provider would determine if the lower-queued interconnection customer's
impact either exceeds more than 5% of the network upgrade's facility
rating or if the transmission distribution factor is greater than 20%.
Finally, if either of these criteria were met, the transmission
provider would be required to designate that network upgrade a shared
network upgrade, and the interconnection customer in the later cluster
would be responsible for a pro rata share of the network upgrade's
remaining undepreciated capital cost based on the impact the
interconnection customer in the later cluster has on the network
upgrade, as measured using the same method the transmission provider
used to determine the impact of the interconnection customer(s) from
the earlier cluster.
470. The Commission proposed to require the interconnection
customer in the later cluster to pay the transmission provider for the
interconnection customer's share of the shared network upgrade costs
through a one-time lump sum, which the transmission provider would
disburse to the appropriate interconnection customer(s) from the
earlier cluster.\934\ The Commission also proposed that, where
applicable, the interconnection customer from the earlier cluster or
the relevant transmission provider would be required to assign
transmission credits for the portion of the shared network
[[Page 61084]]
upgrade that the interconnection customer in the later cluster funded
to the interconnection customer in the later cluster. Additionally, the
Commission proposed to require that the interconnection customer in the
later cluster not be required to pay for its share of the cost of the
shared network upgrade until that shared network upgrade is in service.
The Commission also proposed to require transmission providers to
provide the list of shared network upgrades to interconnection
customers in subsequent clusters at the conclusion of the cluster study
and to list those network upgrades in the appendix of the relevant
interconnection customer's LGIA. The Commission acknowledged that there
could be scenarios where the network upgrade may be identified as both
a shared network upgrade and a contingent facility; and, thus a
designation of a network upgrade as a contingent facility does not
preclude it from also being a shared network upgrade if the network
upgrade meets the aforementioned criteria and passes the screens.\935\
---------------------------------------------------------------------------
\934\ Id. P 99.
\935\ Id. P 100.
---------------------------------------------------------------------------
b. Comments
i. Comments in Support
471. Multiple commenters support the proposal.\936\ OMS states
that, while cost sharing arrangements can be resource intensive and
contentious, they can be crucial to facilitating an equitable
interconnection process.\937\ NARUC states that the proposal is a
logical extension of the cluster cost sharing concept and could spread
costs over even more interconnection customers benefitting from network
upgrades.\938\ A couple of commenters contend that the proposal will
provide more certainty and result in fewer withdrawals, thus reducing
associated restudies and study processing delays.\939\
---------------------------------------------------------------------------
\936\ AES Initial Comments at 12; Avangrid Initial Comments at
32; Bonneville Initial Comments at 11; Interwest Initial Comments at
17; ISO-NE Initial Comments at 25; MISO Initial Comments at 47;
NARUC Initial Comments at 9; National Grid Initial Comments at 19;
NESCOE Initial Comments at 9-10; New Jersey Commission Initial
Comments at 15-16; NYTOs Initial Comments at 17; SEIA Initial
Comments at 12; Shell Initial Comments at 27; Vistra Initial
Comments at 1; Xcel Initial Comments at 27.
\937\ OMS Initial Comments at 9.
\938\ NARUC Initial Comments at 9.
\939\ New Jersey Commission Initial Comments at 16; Omaha Public
Power Initial Comments at 5-6; SEIA Initial Comments at 2.
---------------------------------------------------------------------------
472. Several commenters believe that the proposal will address the
issue of ``first movers/free riders'' when interconnection customers in
a later cluster study benefit from network upgrades assigned to
interconnection customers in earlier clusters.\940\ Shell claims that
avoiding first mover subsidization of free riders is particularly
important for offshore wind interconnections because of the potential
lack of onshore access points and, therefore, argues that the
Commission should be open to non-traditional cost allocation methods
when contemplating methods to mitigate first mover risk.\941\
---------------------------------------------------------------------------
\940\ ELCON Initial Comments at 9; Longroad Energy Reply
Comments at 13; Pattern Energy Initial Comments at 18; SEIA Initial
Comments at 12; Shell Initial Comments at 27; Xcel Initial Comments
at 27; Vistra Initial Comments at 4.
\941\ Shell Initial Comments at 27.
---------------------------------------------------------------------------
473. Additionally, some commenters believe that the proposal is
consistent with the Commission's cost causation policy.\942\ Avangrid
asserts that, when surplus transmission capacity created by a recent
network upgrade is used by a later generating facility, the lower-
queued interconnection customer should share the costs in a way that is
commensurate with benefits like those allocated using the original
proportional impact method assessment.\943\
---------------------------------------------------------------------------
\942\ Avangrid Initial Comments at 32; Omaha Public Power
Initial Comments at 5-6; Vistra Initial Comments at 5.
\943\ Avangrid Initial Comments at 32.
---------------------------------------------------------------------------
474. Xcel does not believe the proposal will have a significant
impact on the number of interconnection requests submitted but believes
that it will reduce barriers to entry for all interconnection
customers.\944\ Xcel believes that the proposal is appropriate where
there is participant funding.
---------------------------------------------------------------------------
\944\ Xcel Initial Comments at 48.
---------------------------------------------------------------------------
ii. Comments in Opposition
475. Some commenters oppose the proposal.\945\ Several commenters
assert that it will not yield many benefits and that the Commission
should focus on other reforms that are more likely to reduce network
upgrade costs and improve the equity of allocating them among
beneficiaries.\946\ Dominion and Fervo Energy argue that
interconnection customers in subsequent clusters do not ``cause'' the
costs to be incurred, and to the extent the interconnection customers
will benefit, they will contribute through their payment for
transmission service.\947\
---------------------------------------------------------------------------
\945\ APS Initial Comments at 11; Dominion Initial Comments at
22, 28; Dominion Reply Comments at 17; Duke Southeast Utilities
Initial Comments at 9; EEI Reply Comments at 12-13; Enel Initial
Comments at 30; Indicated PJM TOs Initial Comments at 21; PacifiCorp
Initial Comments at 27; Pennsylvania Commission Initial Comments at
10; R Street Initial Comments 12; SPP Initial Comments at 8; U.S.
Chamber of Commerce Initial Comments at 8.
\946\ AEE Initial Comments at 16; Dominion Initial Comments at
23-24; Dominion Reply Comments at 17; Enel Initial Comments at 30;
EEI Reply Comments at 12; Eversource Initial Comments at 15;
Indicated PJM TOs Reply Comments at 40; PacifiCorp Initial Comments
at 29; Pennsylvania Commission Initial Comments at 10; Pine Gate
Initial Comments at 20; SoCal Edison Initial Comments at 17; SPP
Initial Comments at 8; U.S. Chamber of Commerce Initial Comments at
8.
\947\ Dominion Initial Comments at 23; Fervo Energy Reply
Comments at 5-6.
---------------------------------------------------------------------------
476. Other commenters believe that the implementation of the
proposal will be administratively burdensome for transmission
providers.\948\ A few commenters believe that the proposal will lead to
increased disputes and FPA section 206 complaints at the Commission
over cost allocation assignments.\949\
---------------------------------------------------------------------------
\948\ AECI Initial Comments at 5; AEE Initial Comments at 16;
APS Initial Comments at 11; CAISO Initial Comments at 15; Dominion
Initial Comments at 23-24; Dominion Reply Comments at 17; Enel
Initial Comments at 30; Indicated PJM TOs Initial Comments at 21-22;
National Grid Initial Comments at 19; PacifiCorp Initial Comments at
27, 29; Pine Gate Initial Comments at 22; PJM Initial Comments at
37-38; R Street Initial Comments at 12; SPP Initial Comments at 8;
U.S. Chamber of Commerce Initial Comments at 8.
\949\ AECI Initial Comments at 5-6; Dominion Initial Comments at
23-24; Dominion Reply Comments at 18; Duke Southeast Utilities
Initial Comments at 10; Fervo Energy Reply Comments at 5; PacifiCorp
Initial Comments at 28; PJM Initial Comments at 37-38.
---------------------------------------------------------------------------
477. Several commenters express concern that the proposal will lead
to interconnection study delays and/or restudies, which would undermine
the NOPR's goal to reduce interconnection study processing
timelines.\950\ A few commenters state that the proposal would require
transmission providers to track all in-service network upgrades on the
transmission system across all cluster studies over a five-year period,
which they contend would be onerous or nearly impossible.\951\ The U.S.
Chamber of Commerce claims that power flow studies conducted up to five
years after the in-service date of non-adjacent network upgrades will
inevitably fail to accurately divide the relevant interconnection costs
among disparate-in-time interconnection customers due to the many
coinciding yet unrelated system changes that will affect the outcomes
of such analyses.\952\ PacifiCorp contends that this requirement would
require transmission providers to track multiple requests for
[[Page 61085]]
each network upgrade on different timelines, the suspension or
withdrawal of which could trigger cascading revaluations and
corresponding LGIA amendments.\953\ Dominion contends that the NOPR's
proposal would complicate reviews and require additional time-consuming
analysis, which would only worsen for transmission providers with a
high volume of interconnection requests, such as RTOs/ISOs.\954\
---------------------------------------------------------------------------
\950\ CAISO Initial Comments at 13; Dominion Initial Comments at
23; Dominion Reply Comments at 17; Indicated PJM TOs Reply Comments
at 40; PacifiCorp Initial Comments at 27-28; Pennsylvania Commission
Initial Comments at 10; SPP Initial Comments at 9.
\951\ APS Initial Comments at 11-12; Dominion Initial Comments
at 22; Dominion Reply Comments at 17; PacifiCorp Initial Comments at
28; U.S. Chamber of Commerce Initial Comments at 8.
\952\ U.S. Chamber of Commerce Initial Comments at 8.
\953\ PacifiCorp Initial Comments at 28.
\954\ Dominion Initial Comments at 23.
---------------------------------------------------------------------------
478. Some commenters argue that the proposal will not create cost
certainty for interconnection customers in earlier clusters when
deciding whether to move forward with a generating facility because
there would be no guarantee that an interconnection customer in a
subsequent cluster would provide reimbursement.\955\ NextEra and PJM
argue that a benefit of not sharing costs between clusters is that all
the interconnection customers within a cluster simultaneously learn
their network upgrade costs and associated cost responsibility,
creating greater cost certainty.\956\
---------------------------------------------------------------------------
\955\ AEE Initial Comments at 16; Clean Energy Associations
Initial Comments at 25; Dominion Initial Comments at 23-24; EEI
Initial Comments at 22; Enel Initial Comments at 30; Indicated PJM
TOs Initial Comments at 22-23; Indicated PJM TOs Reply Comments at
40; NARUC Initial Comments at 9; NextEra Initial Comments at 18;
Pine Gate Initial Comments at 22; PJM Initial Comments at 38; U.S.
Chamber of Commerce Initial Comments at 8; Xcel Initial Comments at
48.
\956\ NextEra Initial Comments at 18-19; PJM Initial Comments at
38.
---------------------------------------------------------------------------
iii. Alternatives and Requests for Flexibility
479. Several commenters recommend modifications to the
proposal.\957\ A few recommend that the Commission implement a minimum
threshold before a network upgrade would be evaluated as a potential
shared network upgrade.\958\ MISO and Xcel state that changes will be
necessary in RTO/ISO regions where a transmission owner may
unilaterally provide upfront funding for network upgrades to integrate
the cost allocation for such a funding mechanism with the shared
network upgrade proposal.\959\ ENGIE recommends that the Commission set
requirements in the interconnection process to identify interconnection
facilities and network upgrades that are necessary to interconnect the
generating facility, as well as network upgrades needed to mitigate
local transmission constraints, and asserts that interconnection
customers should not be responsible for the costs of distant and
minimally impacted network upgrades.\960\ Xcel also contends that the
interconnection customer in the subsequent cluster should enter into a
multiparty facilities service agreement to reimburse the
interconnection customers in the earlier cluster, rather than pay the
proposed lump sum payment to the transmission provider.\961\ Pattern
Energy recommends that the interconnection customer in the later
cluster be required to repay the earlier interconnection customer at
the time of execution of the subsequent interconnection customer's
interconnection agreement, and not when the relevant shared network
upgrades go into service.\962\
---------------------------------------------------------------------------
\957\ Clean Energy Associations Initial Comments at 25-26; ENGIE
Reply Comments at 3-4; MISO Initial Comments at 48-49; Pattern
Energy Initial Comments at 18; Xcel Initial Comments at 29.
\958\ ENGIE Reply Comments at 3-4; MISO Initial Comments at 48;
R Street Initial Comments 12; Xcel Initial Comments at 29.
\959\ MISO Initial Comments at 48-49; Xcel Initial Comments at
29.
\960\ ENGIE Reply Comments at 3-4.
\961\ Xcel Initial Comments at 29.
\962\ Pattern Energy Initial Comments at 18.
---------------------------------------------------------------------------
480. A few commenters propose alternative methods for cost
allocation for shared network upgrades.\963\ For instance, Xcel argues
that the Commission should be clear that it will accept other proposals
to determine if a network upgrade is shareable to subsequent
interconnection requests.\964\
---------------------------------------------------------------------------
\963\ Clean Energy Associations Initial Comments at 25; ENGIE
Reply Comments at 3; Longroad Energy Reply Comments at 13; Pine Gate
Initial Comments at 20, 23.
\964\ Xcel Initial Comments at 28.
---------------------------------------------------------------------------
481. Some commenters support regional flexibility for transmission
providers to implement any shared network upgrade mechanism.\965\ For
example, NESCOE suggests that allowing transmission providers,
especially RTOs/ISOs, some flexibility in coordinating with their
states on developing proposed approaches to sharing the costs
associated with network upgrades funded by interconnection customers in
earlier clusters could minimize the contentious nature of developing
cost sharing arrangements.\966\
---------------------------------------------------------------------------
\965\ Bonneville Initial Comments at 11; CAISO Initial Comments
at 14; EEI Initial Comments at 22; Indicated PJM TOs Initial
Comments at 21; Indicated PJM TOs Reply Comments at 40; National
Grid Initial Comments at 19; NESCOE Initial Comments at 11; NESCOE
Reply Comments at 7; NRECA Initial Comments at 9, 24; NYISO Initial
Comments at 16; PJM Initial Comments at 37.
\966\ NESCOE Initial Comments at 11.
---------------------------------------------------------------------------
482. Other commenters recommend that the Commission not adopt the
shared network upgrade proposal in non-RTO/ISO regions where
interconnection customers provide upfront funds for the network
upgrades and receive reimbursement through transmission credits from
the transmission provider, plus interest (i.e., the interconnection
pricing policy established in Order No. 2003).\967\ Pine Gate states
that under the NOPR proposal, interconnection customers in later
clusters would potentially reimburse interconnection customers in
earlier clusters sooner than the transmission provider would have via
transmission credits, but with the same result.\968\ Enel asserts that
coupling shared network upgrades with transmission credits creates even
more administrative complexity, as an interconnection customer in a
later cluster providing funds to an interconnection customer in an
earlier cluster would necessitate a partial transfer of transmission
credits, potentially on a partially depreciated asset, which creates an
extremely complex payment, reimbursement, and multiparty crediting
system that would be administratively burdensome.\969\ Similarly, APS
and Duke Southeast Utilities express concern over an additional
complication in the event the earlier interconnection customer has
already been fully reimbursed for the network upgrades through
transmission credits.\970\ In contrast, Vistra contends that the shared
network upgrade proposal will be beneficial in regions with
transmission crediting as it will speed reimbursement relative to the
status quo.\971\ Vistra claims that, when an overlap exists between the
reimbursement of an interconnection customer through transmission
credits and the reimbursement mechanism in this proposal, this proposal
will appropriately charge interconnection customers in subsequent
clusters.
---------------------------------------------------------------------------
\967\ Duke Southeast Utilities Initial Comments at 10-11; Enel
Initial Comments at 30; PacifiCorp Initial Comments at 26-28; Pine
Gate Initial Comments at 22.
\968\ Pine Gate Initial Comments at 22.
\969\ Enel Initial Comments at 30.
\970\ APS Initial Comments at 12; Duke Southeast Utilities
Initial Comments at 10.
\971\ Vistra Initial Comments at 5.
---------------------------------------------------------------------------
483. Other commenters raise additional cost allocation concerns
with the shared network upgrade proposal. Enel argues that, in markets
where transmission credits do not apply, reimbursement for funding
network upgrades is often granted in the form of congestion hedging
mechanisms, and the repayment of network upgrade costs from a lower-
queued interconnection customer to a higher-queued interconnection
customer could create the need for a partial transfer of these
[[Page 61086]]
congestion hedging rights.\972\ SDG&E cautions against allowing
scenarios where an higher-queued interconnection customer with cost
responsibility terminates an executed LGIA but the network upgrades are
still needed for later interconnection customers, thus leaving the
transmission provider as the backstop for financing the network
upgrade.\973\ A few commenters argue that the Commission should limit
its proposal to share network upgrade costs between clusters to areas
whether interconnection customers are not already reimbursed for
network upgrade costs.\974\
---------------------------------------------------------------------------
\972\ Enel Initial Comments at 30.
\973\ SDG&E Initial Comments at 6.
\974\ CAISO Initial Comments at 13; SoCal Edison Initial
Comments at 16.
---------------------------------------------------------------------------
484. Several commenters note that some RTOs/ISOs have similar
existing cost allocation mechanisms to the NOPR proposal and request
that, in those instances, the Commission defer to those transmission
providers when the existing mechanisms are accomplishing the final
rule's objectives.\975\ On a similar note, PJM and Indicated PJM TOs
request that the Commission not require PJM to implement cost sharing
between its clusters.\976\
---------------------------------------------------------------------------
\975\ Ameren Initial Comments at 13; APPA-LPPC Initial Comments
at 17; ISO-NE Initial Comments at 26; MISO Initial Comments at 47-
48; NYISO Initial Comments at 15; NYTOs Initial Comments at 17; OMS
Initial Comments at 9; SDG&E Initial Comments at 5.
\976\ Indicated PJM TOs Initial Comments at 23; PJM Initial
Comments at 37.
---------------------------------------------------------------------------
485. Several commenters request various clarifications of the
proposal and provide their thoughts on specific aspects.\977\
---------------------------------------------------------------------------
\977\ APS Initial Comments at 11-12; Avangrid Initial Comments
at 32-33; Clean Energy Associations Initial Comments at 25; Fervo
Energy Initial Comments at 4; Fervo Energy Reply Comments at 4;
LADWP Initial Comments at 4; Pattern Energy Initial Comments at 18;
Pine Gate Initial Comments at 21-22; Tri-State Initial Comments at
12, 34; Vistra Initial Comments at 5.
---------------------------------------------------------------------------
c. Commission Determination
486. We decline to adopt the NOPR proposal to revise the pro forma
LGIP and pro forma LGIA to implement shared network upgrades between
interconnection customers in an earlier cluster and interconnection
customers in a subsequent cluster. We find that the reforms adopted in
this final rule that require transmission providers to allocate network
upgrade costs to interconnection customers within the same cluster
using a proportional impact method, as discussed above, will provide
interconnection customers with more cost certainty during the
interconnection process and will allow for sharing of network upgrade
costs between interconnection customers that benefit from those network
upgrades within the same cluster.
487. The record demonstrates the complexity of the NOPR proposal
and potentially significant administrative burdens associated with
implementing it for at least some transmission providers, especially
under the Commission's interconnection pricing policy. We agree with
some commenters that adopting the proposal would not provide cost
certainty to interconnection customers in earlier clusters at the point
that they have to proceed in the interconnection process because they
would lack certainty about potential reimbursement for network upgrades
from interconnection customers in subsequent clusters.\978\ Thus, the
NOPR proposal is unlikely to reduce barriers to generation development
due to the absence of network upgrade cost sharing provisions. Further,
the proposal may introduce burdens for lower-queued interconnection
customers that could be faced with reimbursing a higher-queued
interconnection customer for a new shared network upgrade cost late in
the interconnection process. For these reasons, we decline to adopt
this NOPR proposal.\979\
---------------------------------------------------------------------------
\978\ AEE Initial Comments at 16; Clean Energy Associations
Initial Comments at 25; Dominion Initial Comments at 23-24; EEI
Initial Comments at 22; Enel Initial Comments at 30; Indicated PJM
TOs Initial Comments at 22-23; Indicated PJM TOs Reply Comments at
40; NARUC Initial Comments at 9; NextEra Initial Comments at 18;
Pine Gate Initial Comments at 22; PJM Initial Comments at 38; U.S.
Chamber of Commerce Initial Comments at 8; Xcel Initial Comments at
48.
\979\ We note that MISO, ISO-NE, and NYISO, which have
independent entity variations to the Commission's crediting policy,
have similar shared network upgrade mechanisms to the NOPR proposal.
See Midwest Indep. Transmission Sys. Operator, Inc., 133 FERC ]
61,221, at P 336 (2010); ISO New England Inc., 161 FERC ] 61,123, at
PP 92-96 (2017); N.Y. Indep. Sys. Operator, Inc., 124 FERC ] 61,238,
at P 34 (2008).
---------------------------------------------------------------------------
488. We find that the final rule's reforms to conduct cluster
studies and to allocate the costs of any assigned network upgrades to
the cluster's interconnection customers on a proportional basis address
the ``first mover/free rider'' issue.\980\ Under this final rule, a
transmission provider must study interconnection customers in an
earlier cluster study based on the transmission system at that time,
and those interconnection customers will be assigned network upgrades
that would not be needed but for their interconnection to the
transmission system; then, the transmission provider will study
interconnection customers in a subsequent cluster study based on the
transmission system at that point in time, and those interconnection
customers will be assigned any necessary network upgrades that would
not be needed but for their interconnection to the transmission system.
Further, we note that under the Commission's interconnection pricing
policy, interconnection customers receive reimbursement for network
upgrade costs, which helps to mitigate any ``first mover/free rider''
concerns because interconnection customers are reimbursed through
transmission credits. In addition, we find that the aforementioned
reforms to conduct cluster studies and use a proportional impact method
to allocate the costs of network upgrades within a cluster will also
address ``first mover/free rider'' concerns in regions with independent
entity variations to the interconnection pricing policy.
---------------------------------------------------------------------------
\980\ See ELCON Initial Comments at 9; Longroad Energy Reply
Comments at 13; Pattern Energy Initial Comments at 18; SEIA Initial
Comments at 12; Shell Initial Comments at 27; Vistra Initial
Comments at 4; Xcel Initial Comments at 27.
---------------------------------------------------------------------------
489. Because we decline to adopt this proposal, we do not respond
to the requests for clarification or the requests for modifications to
the NOPR proposal that would not address the reasons provided above for
declining to adopt the NOPR proposal as a general matter.
6. Increased Financial Commitments and Readiness Requirements
490. In the NOPR, the Commission stated that the pro forma LGIP
allows an interconnection customer to proceed through the generator
interconnection process without having shown evidence to the
transmission provider of meaningful progress toward achieving
commercial viability.\981\ The Commission stated its concern that,
without requiring this type of evidence, interconnection customers will
continue to submit multiple speculative interconnection requests and
later withdraw those requests, triggering rounds of restudies. The
Commission therefore proposed a set of reforms to adopt more stringent
financial commitments and readiness requirements for interconnection
customers to remain in the interconnection queue to discourage
speculative interconnection requests and allow transmission providers
to focus on processing viable interconnection requests and to better
approximate the cost of the interconnection study process.\982\
---------------------------------------------------------------------------
\981\ NOPR, 179 FERC ] 61,194 at P 102.
\982\ Id. P 103.
---------------------------------------------------------------------------
[[Page 61087]]
a. Increased Study Deposits
i. NOPR Proposal
491. In the NOPR, the Commission proposed to adopt the following
study deposit framework in the pro forma LGIP: \983\
---------------------------------------------------------------------------
\983\ Id. P 106.
------------------------------------------------------------------------
Size of proposed generating facility
associated with interconnection request Amount of deposit
------------------------------------------------------------------------
> 20 MW < 80 MW........................... $35,000 + $1,000/MW.
>= 80 MW < 200 MW......................... $150,000.
>= 200 MW................................. $250,000.
------------------------------------------------------------------------
492. The Commission proposed to require transmission providers to
collect this study deposit before each phase of the new first-ready,
first-served cluster study process (i.e., cluster study, cluster
restudy, and facilities study).\984\ The Commission proposed to require
the interconnection customer to provide: (1) an initial study deposit
along with its interconnection request, which will be used to pay for
the cluster study; (2) the second study deposit of the same amount
within 20 days of receiving the cluster study report from the
transmission provider to cover the cost of any clustered restudies; and
(3) the third study deposit of the same amount along with its executed
facilities study agreement. The Commission explained that study
deposits would be refundable, and that the transmission provider would
refund any portion of the study deposits above the applicable study
costs and withdrawal penalties once the interconnection customer
executes the LGIA, requests the filing of an unexecuted LGIA and
submits the corresponding payment discussed below, or withdraws from
the interconnection queue. The Commission also proposed to delete
section 8.1.1 of the pro forma LGIP to remove the requirement for
transmission providers to invoice interconnection customers on a
monthly basis for the work conducted on the facilities study.
---------------------------------------------------------------------------
\984\ Id. P 107.
---------------------------------------------------------------------------
493. The Commission sought comment on whether: (1) the proposed
study deposit amounts accurately estimate the cost of conducting
cluster studies; and (2) to adopt additional provisions or a different
framework that would require larger proposed generating facilities to
provide a higher deposit amount--such as a per MW framework.\985\
---------------------------------------------------------------------------
\985\ Id. P 110.
---------------------------------------------------------------------------
ii. Comments
494. Several commenters fully support the NOPR proposal to increase
study deposits in order to support more effective interconnection queue
management and reduce speculative interconnection requests.\986\
---------------------------------------------------------------------------
\986\ AEP Initial Comments at 20; APPA-LPPC Initial Comments at
18; CAISO Initial Comments at 15-16; Consumers Energy Initial
Comments at 5; EEI Initial Comments at 6-7; NARUC Initial Comments
at 10; NYTOs Initial Comments at 17; Pennsylvania Commission Initial
Comments at 14; SoCal Edison Initial Comments at 5; U.S. Chamber of
Commerce Initial Comments at 8; UMPA Initial Comments at 5; Vistra
Initial Comments at 6.
---------------------------------------------------------------------------
495. Other commenters express qualified support for the
proposal.\987\ For example, ELCON, New York Commission and NYSERDA, and
NextEra contend that it is important that such measures be carefully
balanced so that they are not overly burdensome or discouraging to
interconnection customers with legitimate proposed generating
facilities that may be delayed for reasons out of their control.\988\
Clean Energy Associations do not oppose the heightened study deposit
requirements, provided that they are paired with real predictability on
the timing of studies and real certainty on the costs of network
upgrades.\989\ CAISO argues that the Commission must raise study
deposits significantly, and contends that it is illusory to argue that
interconnection customers without significant capital can progress to
commercial operation in today's hyper-competitive climate.\990\ PPL
asserts that the Commission's proposed study deposits are likely on the
low end of what is required to ensure proper ``skin in the game,'' but
should work for many regions, including New England.\991\ Tri-State
overall supports the proposed study deposit amounts but notes that
interconnection customers proposing smaller generating facilities will
end up paying a lower study deposit than what Tri-State is currently
charging.\992\ ENGIE, MISO, and SPP would prefer to collect study
deposits only once upon entry into the cluster, rather than at each
stage of the cluster study process, to reduce administrative burden on
them and the interconnection customers.\993\ MISO and Shell argue that
limiting speculative interconnection requests and ensuring more
concrete financial readiness would be better achieved by requiring a
single study deposit at the initiation of the generator interconnection
process.\994\ Shell urges the Commission to base that deposit on the
generating facility's size.
---------------------------------------------------------------------------
\987\ ACE-NY Initial Comments at 4; AES Initial Comments at 14;
Ameren Initial Comments at 14; APPA-LPPC Initial Comments at 18; APS
Initial Comments at 13; Avangrid Initial Comments at 16; Bonneville
Initial Comments at 11; CESA Initial Comments at 8-9; Clean Energy
Associations Initial Comments at 30; Cypress Creek Initial Comments
at 20; Dominion Initial Comments at 24; EEI Initial Comments at 6;
ELCON Initial Comments at 10; ENGIE Initial Comments at 4;
Eversource Initial Comments at 16; Google Initial Comments at 20;
Fervo Energy Initial Comments at 4; Idaho Power Initial Comments at
6; ISO-NE Initial Comments at 27; MISO Initial Comments at 49;
National Grid Initial Comments at 20; NESCOE Reply Comments at 8,
10; New York Commission and NYSERDA Initial Comments at 8; NextEra
Initial Comments at 20; NRECA Initial Comments at 25; NV Energy
Initial Comments at 14; NYISO Initial Comments at 19-20; Omaha
Public Power Initial Comments at 6; Pacific Northwest Utilities
Initial Comments at 4; PJM Initial Comments at 24; PPL Initial
Comments at 15; SEIA Initial Comments at 13; Southern Initial
Comments at 8-9; SPP Initial Comments at 9; Tri-State Initial
Comments at 4, 12.
\988\ ELCON Initial Comments at 10; New York Commission and
NYSERDA Initial Comments at 8-9; NextEra Initial Comments at 20.
\989\ Clean Energy Associations Initial Comments at 30.
\990\ CAISO Initial Comments at 15-16.
\991\ PPL Initial Comments at 15 (noting that PJM's
interconnection queue reform proposal includes higher deposits,
ranging from $75,000 to $400,000 and a 10% nonrefundable component).
\992\ Tri-State Initial Comments at 12.
\993\ ENGIE Initial Comments at 4; MISO Initial Comments at 50;
SPP Initial Comments at 9.
\994\ MISO Initial Comments at 51; Shell Initial Comments at 17;
Shell Reply Comments at 22.
---------------------------------------------------------------------------
496. Several commenters argue that the final rule should provide
each region with flexibility concerning the scope and application of
any modifications to increased study deposits.\995\ Indicated PJM TOs
contend that the transmission provider should be entitled to adjust the
study deposit value if it observes that the actual cost of studies
tends to be materially higher or lower.\996\ Dominion adds that the
Commission should respect the previously accepted reforms made by
transmission providers like Dominion and PJM with regard to study
deposits.\997\
---------------------------------------------------------------------------
\995\ Avangrid Initial Comments at 17; Bonneville Initial
Comments at 11; Dominion Initial Comments at 24; Indicated PJM TOs
Reply Comments at 29; Interwest Reply Comments at 12; ISO-NE Initial
Comments at 28; National Grid Initial Comments at 21; New York
Commission and NYSERDA Initial Comments at 9; NESCOE Reply Comments
at 9-10; NRECA Initial Comments at 26; NYISO Initial Comments at 19;
Pacific Northwest Utilities Initial Comments at 2; SPP Initial
Comments at 10.
\996\ Indicated PJM TOs Reply Comments at 29.
\997\ Dominion Initial Comments at 24.
---------------------------------------------------------------------------
497. APS suggests that any refundable deposits should not include
the Commission interest rate and argues that, by requiring additional
funds to be deposited as described in the NOPR, the Commission's
proposal would lead to an exorbitant increase in the amount of
Commission interest paid back to an interconnection customer as it
moves along through the process at the transmission provider's
expense.\998\
---------------------------------------------------------------------------
\998\ APS Initial Comments at 13.
---------------------------------------------------------------------------
498. Other commenters mostly oppose the NOPR proposal to increase
study
[[Page 61088]]
deposits.\999\ CREA and NewSun agree that a tiered study deposit level
tied to interconnection capacity requested may be warranted and at most
study deposits should be increased to more accurately cover the cost of
the studies, but comment that the rest of the NOPR's proposal appears
to increase the study deposit levels solely to deter interconnection
customers from entering the interconnection queue, not because the
current level of study deposits is insufficient to cover the costs of
the studies.\1000\ CREA and NewSun argue that, if this rulemaking
generates evidence that the current study deposit levels are
insufficient to cover the typical costs of studies, an increase may be
justified, but until then, study deposits should not be increased.
Eversource recommends that the Commission consider making the rate of
increase per MW more gradual, and that based on the current proposed
figures, the deposits may increase too quickly relative to generating
facility size.\1001\ rPlus argues that study deposit requirements are
unduly discriminatory or punitive to pumped storage as compared to
other renewable technologies because a large capacity pumped storage
facility would expect to hit the maximum deposit and/or penalty in
every stage of the interconnection study process, LGIA, and potential
withdrawal.\1002\ RWE Renewables fully supports allocating some risk
for each generating facility entered into the interconnection queue to
interconnection customers, but argues that increased financial deposits
have unfortunately not been an adequate deterrent to a high volume of
non-viable generating facilities entering into the interconnection
queues.\1003\
---------------------------------------------------------------------------
\999\ CREA and NewSun Initial Comments at 51-52; Eversource
Initial Comments at 16; rPlus Initial Comments at 5; RWE Renewables
Initial Comments at 2.
\1000\ CREA and NewSun Initial Comments at 51-52.
\1001\ Eversource Initial Comments at 16.
\1002\ rPlus Initial Comments at 5.
\1003\ RWE Renewables Initial Comments at 2.
---------------------------------------------------------------------------
499. In response to the Commission's request for comment on whether
the proposed study deposit amounts accurately estimate the cost of
conducting cluster studies, Ameren states that, based on its
experience, the proposed study deposits are in line with the cost of
conducting the cluster studies.\1004\ Xcel contends that the proposed
study deposits are more than the cost of studies in its experience, but
as studies will need to be accelerated under the Commission's proposal
(to meet timelines) and may involve more actions, the proposed study
cost may be appropriate.\1005\ NV Energy states that, on average, it
spends between $80,000 and $100,000 between the cluster system impact
study and facilities studies and refunds the remaining deposits with
interest.\1006\ Cypress Creek comments that in its experience, study
costs can vary widely depending on the transmission provider, the staff
resources it has available to conduct the study, and whether it needs
to contract with external resources to conduct the study.\1007\
---------------------------------------------------------------------------
\1004\ Ameren Initial Comments at 14.
\1005\ Xcel Energy Initial Comments at 29-30.
\1006\ NV Energy Initial Comments at 14.
\1007\ Cypress Creek Initial Comments at 20-21.
---------------------------------------------------------------------------
500. CREA and NewSun urge the Commission to maintain a lower study
deposit prior to obtaining the initial cluster study. They argue that
larger study deposits are only justified once the interconnection
customer can realistically assess the commercial viability of its
proposed generating facility within the cluster after obtaining the
potential interconnection costs.\1008\ Fervo Energy contends that more
information is needed before one can conclude that the proposed study
deposit amount framework would not result in deposits that far exceed
the actual cost of the studies, particularly in light of the withdrawal
penalty proposal.\1009\ Cypress Creek suggests that the Commission
should provide additional justification and argues that the NOPR fails
to provide any further justification for study costs (i.e., based on a
market analysis or other method), stating only that the proposed
amounts ``better approximate the cost of the interconnection study
process.'' \1010\
---------------------------------------------------------------------------
\1008\ CREA and NewSun Initial Comments at 53.
\1009\ Fervo Energy Initial Comments at 4.
\1010\ Cypress Creek Initial Comments at 20 (quoting NOPR, 179
FERC ] 61,194 at P 103).
---------------------------------------------------------------------------
501. In response to the Commission's request for comment on whether
the Commission should adopt additional provisions or a different
framework that would require larger proposed generating facilities to
provide a higher study deposit amount, such as a per MW framework, PJM
contends that the Commission should adopt readiness payments or study
deposits based on the costs of the network upgrades necessary to
interconnect the generating facilities in the cluster, which also
contain ``at-risk'' non-refundable provisions.\1011\
---------------------------------------------------------------------------
\1011\ PJM Initial Comments at 24.
---------------------------------------------------------------------------
iii. Commission Determination
502. We adopt, with modification, the NOPR proposal to require
interconnection customers to pay, and transmission providers to
collect, study deposits as part of the cluster study process.\1012\
Specifically, we adopt the NOPR proposal to require the following study
deposit framework in section 3.1.1.1 of the pro forma LGIP:
---------------------------------------------------------------------------
\1012\ Here, we refer to initial study deposits separately from
the LGIA deposit. We discuss the latter in section III.A.6.d below.
In the NOPR, the Commission discussed the deposits together, NOPR,
179 FERC ] 61,194 at P 109, although the proposed pro forma LGIP
treated the initial study deposit, proposed pro forma LGIP section
3.1.1.1 (Initial Study Deposit), separate from the LGIA deposit,
proposed pro forma LGIP section 3.1.1.3 (LGIA Deposit).
------------------------------------------------------------------------
Size of proposed generating facility
associated with interconnection request Amount of deposit
------------------------------------------------------------------------
> 20 MW < 80 MW........................... $35,000 + $1,000/MW.
>= 80 MW < 200 MW......................... $150,000.
>= 200 MW................................. $250,000.
------------------------------------------------------------------------
503. However, we modify the NOPR proposal to require transmission
providers to collect a single study deposit only once upon entry into
the cluster (initial study deposit), rather than requiring transmission
providers to collect a study deposit at each phase of the cluster study
process, as proposed in the NOPR. Therefore, we decline to adopt the
proposed revisions to sections 3.1.1.2, 7.5, and 8.1 of the pro forma
LGIP that would have implemented the phased study deposit approach. As
a result of this modification to the NOPR proposal, the initial study
deposit will be required only at the time the interconnection customer
submits an interconnection request. The amount of the initial study
deposit will be calculated using the tiered approach proposed in the
NOPR based on the proposed MW size of the generating facility, as shown
in the chart above.
504. We adopt the tiered approach based on the proposed MW size of
the generating facility for determining the amount of the initial study
deposit because larger proposed generating facilities within a cluster
generally cost more to study than smaller proposed generating
facilities within a cluster. Further, although we acknowledge that this
approach does not perfectly approximate study costs, we find it
appropriate to require the transmission provider to collect a study
deposit based on a tiered approach because study costs will be trued up
and any excess deposit refunded once the interconnection customer
executes the LGIA or requests the filing of an unexecuted LGIA and
submits the corresponding payment discussed below or withdraws from the
interconnection queue.
505. We modify the NOPR proposal to require only a single initial
study deposit, rather than multiple deposits at
[[Page 61089]]
different stages of the cluster study process, as proposed in the NOPR.
We believe that this modification will appropriately reduce the
administrative burden for transmission providers to collect and manage
the deposits.\1013\ We recognize that the amount of the study deposit
for interconnection customers will be lower than that proposed in the
NOPR because of this modification. We are persuaded by commenters'
arguments that initial study deposits are best used to provide
transmission providers with funds to cover the costs of studies
performed for interconnection customers rather than to serve as a
disincentive against speculative interconnection requests.\1014\ We
therefore adopt an initial study deposit framework that better reflects
the costs of the interconnection studies. For example, NV Energy states
that, on average, it spends between $80,000 and $100,000 between the
cluster system impact study and facilities studies and refunds the
remaining deposits with interest.\1015\ Under the study deposit
framework we adopt, study deposits range between $55,000 and $250,000
for the smallest and largest proposed generating facilities,
respectively, and thus reasonably track likely study costs based on the
record. We believe that other reforms adopted in this final rule--
notably, the commercial readiness deposits and the site control
requirements--will adequately serve as a disincentive against
speculative interconnection requests without unnecessarily duplicating
those efforts through increased study deposits.
---------------------------------------------------------------------------
\1013\ See ENGIE Initial Comments at 4; MISO Initial Comments at
50; SPP Initial Comments at 9.
\1014\ See Order No. 2003, 104 FERC ] 61,103 at P 220.
\1015\ NV Energy Initial Comments at 14.
---------------------------------------------------------------------------
506. Additionally, we adopt the NOPR proposal to delete section
8.1.1 of the pro forma LGIP to remove the requirement for transmission
providers to invoice interconnection customers on a monthly basis for
the work conducted on the facilities study. We find that this monthly
invoicing requirement is burdensome to the transmission provider and
unnecessary given that section 13.3 of the pro forma LGIP includes
policies for invoicing and establishes that interconnection customers
are responsible for the actual costs of interconnection studies.
Accordingly, we also delete from pro forma LGIP Appendix 3
(Interconnection Facilities Study Agreement), the portion of article
5.0 that includes the monthly invoicing requirement.
507. We disagree with rPlus' argument that study deposit
requirements are unduly discriminatory or punitive to pumped storage
because of its large capacity.\1016\ We note that the initial study
deposit reforms we adopt in this final rule are agnostic to the type of
generating facility. Rather, the initial study deposits are based on
the MW size of the proposed generating facility, regardless of the type
of generating facility, such that interconnection customers proposing
larger generating facilities will pay a larger deposit. As explained
above, this reflects the fact that the expected costs to study those
generating facilities are generally higher. Nonetheless, the
modification we adopt here has the effect of lowering the required
study deposit for all interconnection customers relative to the NOPR
proposal, a finding which may partially allay rPlus' concern.
---------------------------------------------------------------------------
\1016\ See rPlus Initial Comments at 5.
---------------------------------------------------------------------------
b. Demonstration of Site Control
i. NOPR Proposal
508. In the NOPR, the Commission stated that it believed that more
stringent site control requirements will help prevent interconnection
customers from submitting interconnection requests for speculative,
commercially non-viable proposed generating facilities.\1017\ The
Commission preliminarily found that an interconnection customer
securing the exclusive land right necessary to construct its proposed
generating facility (or for co-located resources, demonstration of
shared land use) is sufficient evidence of the interconnection
customer's commitment to construct the generating facility.
---------------------------------------------------------------------------
\1017\ NOPR, 179 FERC ] 61,194 at P 115.
---------------------------------------------------------------------------
509. The Commission proposed to revise the pro forma LGIP to
require interconnection customers to demonstrate 100% site control for
their proposed generating facilities when they submit their
interconnection request.\1018\ The Commission proposed to have
transmission providers include in their tariff specific acreage
requirements for each generating facility technology type to
demonstrate site control.
---------------------------------------------------------------------------
\1018\ Id. P 116. In the NOPR, the Commission proposed to define
``site control'' as ``the exclusive land right to develop,
construct, operate, and maintain the Generating Facility over the
term of expected operation of the Generating Facility.''
Specifically, the NOPR definition explained that site control may be
demonstrated by documentation establishing: (1) ownership of, a
leasehold interest in, or a right to develop a site of sufficient
size to construct and operate the Generating Facility or multiple
Generating Facilities on a shared site behind one Point of
Interconnection; (2) an option to purchase or acquire a leasehold
site for such purpose; (3) site of sufficient size to construct and
operate the Generating Facility; or (4) any other documentation that
clearly demonstrates the right of Interconnection Customer to
exclusively occupy a site of sufficient size to construct and
operate the Generating Facility. Site Control for any Co-Located
Resource is demonstrated by a contract or other agreement
demonstrating shared land use for all Co-Located Resources that meet
the aforementioned provisions of the Site Control definition.
---------------------------------------------------------------------------
510. To cut down on multiple interconnection customers leasing the
same site in order to remain in the interconnection queue, the
Commission proposed to revise the pro forma LGIP to require
interconnection customers to demonstrate the exclusive land right
(where the land rights are exclusive to the interconnection customer,
not necessarily the individual generating facility) to develop,
construct, operate, and maintain its generating facility or, where
facilities are co-located, to demonstrate a shared land use right to
develop, construct, operate, and maintain co-located facilities.\1019\
---------------------------------------------------------------------------
\1019\ Id. P 117.
---------------------------------------------------------------------------
511. Additionally, the Commission proposed to include a limited
option for interconnection customers to submit a deposit in lieu of
site control when they submit their interconnection request only when
regulatory limitations prohibit the interconnection customer from
obtaining site control.\1020\ The Commission explained that in such
instances, the interconnection customer would submit an initial deposit
in lieu of site control of $10,000 per MW, subject to a floor of
$500,000 and a ceiling of $2 million, which would be applied toward any
interconnection studies or a withdrawal penalty, if applicable. The
Commission specified that such an interconnection customer must
demonstrate 100% site control prior to the facilities study. The
Commission further proposed that, after the interconnection customer
notifies the transmission provider of a change to its site control
demonstration, the transmission provider must give the interconnection
customer 10 business days to demonstrate that the site control
demonstration meets the applicable requirement after
notification.\1021\
---------------------------------------------------------------------------
\1020\ Id. P 118.
\1021\ Id. P 119.
---------------------------------------------------------------------------
512. The Commission sought comment on: (1) whether there are other
specific situations in which the Commission should accept a deposit in
lieu of site control; (2) whether the definition of site control,
including the requirement to obtain an exclusive land right (or, for
co-located resources, a shared land right), should be broadened or
refined to account for circumstances that may arise in, for example,
the siting
[[Page 61090]]
and permitting of offshore resources in bodies of water and/or
submerged land; (3) whether and how the definition of site control
should be adjusted for interconnection customers to account for any
regulatory requirements they may have associated with proposed
generating facilities developed on sites owned or physically controlled
by a state government entity and/or a Federal Government entity; (4)
the appropriate stage in developing such sites when the Commission
should view completion of such stage as indicative of an
interconnection customer's request being non-speculative and whether
there are substantive differences among interconnection customers
developing sites owned or physically controlled by a state government
entity and/or a Federal Government entity; (5) whether the Commission
should allow transmission providers to accept demonstrations of less
than 100% site control in the initial phases of the interconnection
study process, outside of when regulatory limitations prohibit the
interconnection customer from obtaining site control; and (6) whether
the Commission should instead adopt site control provisions that allow
a deposit in lieu of site control to enter the generator
interconnection process and be evaluated under the first-ready, first-
served cluster study process described above but require
interconnection customers to demonstrate site control to enter the
facilities study.\1022\
---------------------------------------------------------------------------
\1022\ Id. PP 121-123.
---------------------------------------------------------------------------
ii. Comments
(a) General Comments
513. Several parties generally support the proposal to increase
site control requirements.\1023\ These commenters generally agree that
the proposal is reasonable and that these measures can reduce
speculative interconnection requests, represent a reasonable financial
burden, help ensure that the interconnection customer is ready to enter
the interconnection queue,\1024\ help load serving entities have
generating facilities interconnected as quickly and efficiently as
possible,\1025\ and reduce harm to other interconnection customers that
have successfully secured site control for their proposed generating
facility.\1026\
---------------------------------------------------------------------------
\1023\ AEP Initial Comments at 21; AES Initial Comments at 15;
Ameren Initial Comments at 15-16; APPA-LPPC Initial Comments at 17-
18; Avangrid Initial Comments at 9, 18-19; Bonneville Initial
Comments at 11; CAISO Initial Comments at 16; Consumers Energy
Initial Comments at 5; Dominion Reply Comments at 15; ELCON Initial
Comments at 10; Enel Initial Comments at 40-42; Eversource Initial
Comments at 16; Fervo Energy Reply Comments at 6; GSCE Initial
Comments at 1; Hydropower Commenters Initial Comments at 12;
Interwest Energy Alliance Reply Comments at 13; Invenergy Initial
Comments at 9; Longroad Energy Initial Comments at 12; MISO Initial
Comments at 53; NARUC Initial Comments at 10; NRECA Initial Comments
at 27; NV Energy Initial Comments at 15; NYTOs Initial Comments at
18-19; [Oslash]rsted Initial Comments at 10; Pacific Northwest
Utilities Initial Comments at 4; PG&E Initial Comments at 4; Pattern
Energy Initial Comments at 29-30; Pine Gate Initial Comments at 23;
PJM Initial Comments at 21-22; SEIA Initial Comments at 14; SoCal
Edison Initial Comments at 6; Tri-State Initial Comments at 13-15;
U.S. Chamber of Commerce Initial Comments at 8; UMPA Initial
Comments at 5; Xcel Initial Comments at 32.
\1024\ Enel Initial Comments at 40.
\1025\ Ameren Initial Comments at 15-16.
\1026\ PJM Initial Comments at 29.
---------------------------------------------------------------------------
514. CREA and NewSun, on the other hand, argue that the
Commission's proposed site control requirements are anti-competitive
because they allow utilities to erect market barriers to competitors'
generating facilities and because the requirements bar investment by
companies seeking to develop generating facilities using a merchant
generation model.\1027\
---------------------------------------------------------------------------
\1027\ CREA and NewSun Reply Comments at 46.
---------------------------------------------------------------------------
(b) Comments on Specific Proposal
(1) Definition and Reasonable Evidence of Site Control
515. Some commenters support the proposed definition of site
control.\1028\ MISO notes that the proposed requirement for exclusivity
or the demonstration of a right to co-locate generating facilities is
in MISO's current tariff and that these requirements have proven to be
successful at preventing speculative interconnection requests from
entering or continuing in the interconnection queue.\1029\
---------------------------------------------------------------------------
\1028\ MISO Initial Comments at 53; National Grid Initial
Comments at 22.
\1029\ MISO Initial Comments at 53.
---------------------------------------------------------------------------
516. Some commenters suggest modifications to the definition of
site control. ENGIE and Tri-State recommend that the Commission
consider requirements similar to MISO's requirements to identify when
and whether an interconnection request is non-speculative.\1030\ Xcel
supports modifying the definition of site control to ensure exclusivity
and allow for co-ownership.\1031\
---------------------------------------------------------------------------
\1030\ ENGIE Initial Comments at 5; Tri-State Initial Comments
at 14.
\1031\ Xcel Initial Comments at 31.
---------------------------------------------------------------------------
517. PJM requests that the Commission clarify that interconnection
customers are prohibited from submitting evidence of site control that
uses the same land for multiple interconnection requests, unless the
site is large enough to host multiple generating facilities.\1032\
---------------------------------------------------------------------------
\1032\ PJM Initial Comments at 31.
---------------------------------------------------------------------------
518. Enel supports the proposal to require land rights that are
exclusive to one development company, but not necessarily to the
individual generating facility.\1033\ According to Enel, when used
regarding land rights, ``exclusive'' means that only the owner of those
land rights can possess the property, and this interpretation could
prevent co-located resources from being built if one parent company was
using two separate special purpose vehicles for two different
generating facilities sharing land. Enel therefore recommends that the
Commission clarify the intent of this word so that it does not
artificially restrict multi-use applications.
---------------------------------------------------------------------------
\1033\ Enel Initial Comments at 42 (referencing NOPR, 179 FERC ]
61,194 at P 117).
---------------------------------------------------------------------------
519. Cypress Creek believes that, to the extent the Commission
intends that a ``land right'' should involve zoning approval, such a
proposal would be unreasonable because interconnection customers do not
typically initiate local permitting until the system impact study
phase, due to the system impact study's impact to overall generating
facility commercial viability.\1034\
---------------------------------------------------------------------------
\1034\ Cypress Creek Initial Comments at 22.
---------------------------------------------------------------------------
520. Southern requests that the Commission clarify subpart (3) of
the proposed site control definition, arguing that, as written, it
appears to be an incomplete statement that may authorize an
interconnection customer to simply provide evidence that a site is big
enough to host a proposed generating facility rather than evidence that
the interconnection customer actually has any rights to that
property.\1035\ Enel argues that subpart (3) to the definition should
be deleted, because as modified, that item is duplicative of and a
subset of the materials covered under subpart (1).\1036\
---------------------------------------------------------------------------
\1035\ Southern Initial Comments at 34-35.
\1036\ Enel Initial Comments at 82.
---------------------------------------------------------------------------
521. Other parties request that the Commission clarify the
definition of site control to specify what constitutes reasonable
evidence to demonstrate 100% site control \1037\ or provide suggestions
for what should be considered reasonable evidence of site
control.\1038\ NYISO requests that the final rule establish uniform
requirements across regions for making the 100% site control
determination.\1039\ APS requests that the Commission specify what is
considered reasonable evidence in the same manner that the
[[Page 61091]]
Commission defines commercial readiness milestones and argues that
clarification is needed in order to avoid subjectivity regarding what
is considered ``reasonable'' evidence to the transmission
provider.\1040\
---------------------------------------------------------------------------
\1037\ APS Initial Comments at 7; NYISO Initial Comments at 21-
22; Omaha Public Power Initial Comments at 7.
\1038\ EPSA Initial Comments at 8; National Grid Initial
Comments at 22; NRECA Initial Comments at 27; Omaha Public Power
Initial Comments at 7; SoCal Edison Initial Comments at 6.
\1039\ NYISO Initial Comments at 21-22.
\1040\ APS Initial Comments at 7.
---------------------------------------------------------------------------
522. Omaha Public Power requests that the Commission clarify
whether transmission providers will be able to accept lease options,
instead of executed leases, as sufficient evidence of site
control.\1041\ Omaha Public Power notes that it has become industry
standard to use lease options and argues that the Commission should not
enact a rule that conflicts with current industry standard practices.
SoCal Edison supports the NOPR proposal, provided that 100% site
control includes an option to lease up to, and including, the
commercial operation date or acquire the land when the interconnection
request is submitted.\1042\
---------------------------------------------------------------------------
\1041\ Omaha Public Power Initial Comments at 7-8.
\1042\ SoCal Edison Initial Comments at 6.
---------------------------------------------------------------------------
523. EPSA advises the Commission to consider options to demonstrate
site control, including requiring attestations that a lessee or
potential owner is in exclusive negotiations to establish site control,
though it generally supports the development of clearer
demonstrations.\1043\ Interwest Energy Alliance recommends that the
Commission consider evidence of active negotiations as potentially a
sufficient demonstration of site control before the closing of the
cluster request window.\1044\
---------------------------------------------------------------------------
\1043\ EPSA Initial Comments at 8.
\1044\ Interwest Energy Alliance Reply Comments at 13.
---------------------------------------------------------------------------
524. SoCal Edison recommends that the Commission consider requiring
that site control agreements be between the site owner and the same
legal entity that is submitting the interconnection request.\1045\
SoCal Edison explains that it has run into challenges when trying to
determine whether interconnection customers have exclusive site
control, in part due to the fact that companies change over time with
renaming and/or mergers.
---------------------------------------------------------------------------
\1045\ SoCal Edison Initial Comments at 6.
---------------------------------------------------------------------------
525. NRECA suggests that demonstration of site control with
exclusive land rights should be allowed to include provisions that such
rights are contingent upon favorable interconnection study results,
inclusive of cost and schedule.\1046\ NRECA notes that site control
land options on many occasions come with a caveat that the lessee or
purchaser has the ability to terminate within a due diligence period if
interconnection results are unfavorable due to cost or schedule.\1047\
---------------------------------------------------------------------------
\1046\ NRECA Initial Comments at 27.
\1047\ Id. at 27 n.70.
---------------------------------------------------------------------------
526. NV Energy requests clarification on whether an interconnection
request should be deemed withdrawn if the interconnection customer does
not provide demonstration of site control by the execution of the
facilities study agreement.\1048\
---------------------------------------------------------------------------
\1048\ NV Energy Initial Comments at 15.
---------------------------------------------------------------------------
527. [Oslash]rsted urges the Commission to clarify that, for
offshore wind projects, the definition of ``exclusive site control of
the entire generating facility'' means exclusive control of the Bureau
of Ocean Energy Management (BOEM) issued offshore wind lease area, not
cable routes on state submerged land or onshore cable routes to the
point of interconnection.\1049\ [Oslash]rsted reasons that, due to the
extensive state and Federal permitting process, offshore wind
developers may not have authorization in the form of permits or other
land use rights for portions of the offshore wind project on state
submerged land or for the offshore and onshore cable routes during the
interconnection process.
---------------------------------------------------------------------------
\1049\ [Oslash]rsted Initial Comments at 14.
---------------------------------------------------------------------------
528. NYTOs and Pacific Northwest Utilities argue that it is unclear
what would constitute 100% site control and therefore regions should be
allowed to implement appropriate definitions for their regions on
compliance to address their specific circumstances.\1050\
---------------------------------------------------------------------------
\1050\ NYTOs Initial Comments at 19; Pacific Northwest Utilities
Initial Comments at 4.
---------------------------------------------------------------------------
529. ISO-NE states that its existing LGIP and SGIP provisions,
which are consistent with those proposed in the NOPR, have proven to be
effective, and that the Commission should extend flexibility so that
they may be maintained.\1051\ Similarly, Indicated PJM TOs argue that
the final rule should permit PJM to implement its 2022 interconnection
queue reform proposal for demonstrating site control, which is more
rigorous than the NOPR proposal.\1052\
---------------------------------------------------------------------------
\1051\ ISO-NE Initial Comments at 29.
\1052\ Indicated PJM TOs Initial Comments at 25 (citing PJM
Interconnection, L.L.C., Tariff Revisions for Interconnection
Process Reform, Docket No. ER22-2110-000 (filed June 14, 2022)). The
Commission conditionally accepted PJM's filing on November 29, 2022
and accepted PJM's associated compliance filing on February 2, 2023.
See PJM Interconnection, L.L.C., 181 FERC ] 61,162 (2022), order on
reh'g, 184 FERC ] 61,006 (2023); PJM Interconnection, L.L.C., Docket
No. ER22-2110-003 (Feb. 2, 2023) (delegated letter order).
---------------------------------------------------------------------------
530. Several parties support the NOPR proposal to define 100% site
control as an acreage requirement specific to the generating facility
type and to require these acreage requirements in the tariff.\1053\
Enel states that inclusion of acreage requirements in the tariff gives
the Commission visibility into regional requirements to ensure that no
transmission provider is significantly out of line with national
assumptions.\1054\
---------------------------------------------------------------------------
\1053\ AES Initial Comments at 15; Enel Initial Comments at 42;
NYISO Initial Comments at 21; Tri-State Initial Comments at 13.
\1054\ Enel Initial Comments at 42.
---------------------------------------------------------------------------
531. Several commenters request that the Commission create a
process by which an interconnection customer can demonstrate that its
generating facility requires a different amount of acreage than the
default value listed in the tariff.\1055\ AES predicts that this
approach will help ensure viable generating facilities are not
inadvertently removed from the interconnection queue.\1056\ MISO states
that its tariff also allows an interconnection customer to demonstrate
that it can operate the proposed generating facility with fewer
acres.\1057\ National Grid believes that regional flexibility would
certainly be required for each transmission provider's proposed acreage
requirements and requests clarification accordingly.\1058\ Some
commenters suggest that transmission providers be required to update
the acreage requirements periodically to reflect technological
advancements.\1059\
---------------------------------------------------------------------------
\1055\ AES Initial Comments at 16; Clean Energy Associations
Initial Comments at 32-33; Public Interest Organizations Initial
Comments at 27.
\1056\ AES Initial Comments at 16.
\1057\ MISO Initial Comments at 54.
\1058\ National Grid Initial Comments at 23.
\1059\ Clean Energy Associations Initial Comments at 32-33;
Longroad Energy Initial Comments at 12; Pattern Energy Initial
Comments at 29-30.
---------------------------------------------------------------------------
532. Other parties oppose the NOPR proposal to require specific
acreage requirements in the tariff \1060\ or suggest that these
requirements should be included in business practice manuals rather
than tariffs.\1061\ Some commenters argue that these acreage
requirements will likely change with technology advances, and it would
be burdensome if transmission providers are required to submit an FPA
section 205 filing every time they need to change acreage
requirements.\1062\ Fervo Energy argues that the risk in this proposal
is that the acreage requirements may understate the energy
[[Page 61092]]
density of a generating facility and thus overstate the number of acres
required for a given number of MW, resulting in discriminatory
treatment between competing generation technologies.\1063\
---------------------------------------------------------------------------
\1060\ EPSA Initial Comments at 8; Fervo Energy Initial Comments
at 4; [Oslash]rsted Initial Comments at 11; Pine Gate Initial
Comments at 24-25; PJM Initial Comments at 30.
\1061\ MISO Initial Comments at 53-54; Pine Gate Initial
Comments at 24-25; PJM Initial Comments at 30; Tri-State Initial
Comments at 13.
\1062\ [Oslash]rsted Initial Comments at 11; PJM Initial
Comments at 30; Pine Gate Initial Comments at 24-25.
\1063\ Fervo Energy Initial Comments at 4.
---------------------------------------------------------------------------
533. [Oslash]rsted recommends that transmission providers use the
most recent estimates of power density from BOEM when establishing
acreage requirements for offshore wind projects.\1064\ [Oslash]rsted
notes that offshore wind turbines have grown much larger in recent
years, which allows significantly more power production from the same
amount of acreage, and they argue that if transmission providers'
tariffs were not updated frequently enough, the acreage requirements
may become unreasonable.
---------------------------------------------------------------------------
\1064\ [Oslash]rsted Initial Comments at 11.
---------------------------------------------------------------------------
534. Pine Gate recommends that acreage requirements specifically
address how the requirements will be applied to hybrid and co-located
generating facilities.\1065\
---------------------------------------------------------------------------
\1065\ Pine Gate Initial Comments at 24-25.
---------------------------------------------------------------------------
535. Some commenters request that the Commission clarify whether
the site control requirement is limited to the generating facility or
whether it also applies to transmission system elements like
interconnection facilities or other upgrades that may be identified
through the interconnection study process.\1066\ Several parties argue
that, for the initial request and study phase, 100% site control should
not apply to land required to finalize routes for generator ties
lines.\1067\ AES argues that interconnection customers require
flexibility when siting generator tie lines, which usually occurs near
the very end of the interconnection process.\1068\ Enel notes that
there are sometimes crossings of railroads, streams, or other
circumstances that require considerable time to complete and are
outside the interconnection customer's control.\1069\ AEE explains that
issues can occur when interconnection customers have all but one small
parcel on the route of their generating facility secured, with only one
small piece of connectivity missing due to permitting delays or other
issues.\1070\ Similarly, Invenergy argues that it is unreasonable and
impractical to predict and obtain rights to land for facilities that
have not yet been identified.\1071\ Invenergy also states that the
point of interconnection can change during the study process, thus
changing the land needs for the interconnection customer's
interconnection facilities, and this change may be driven by a number
of different factors, including the transmission provider's preference,
which may be outside the interconnection customer's control.
---------------------------------------------------------------------------
\1066\ Interwest Energy Alliance Reply Comments at 13; NYISO
Initial Comments at 22.
\1067\ ACE-NY Initial Comments at 5; AES Initial Comments at 15;
Avangrid Initial Comments at 18; Clean Energy Associations Initial
Comments at 32; Enel Initial Comments at 41; ENGIE Initial Comments
at 5; Equinor Reply Comments at 3; rPlus Initial Comments at 2-3;
Shell Reply Comments at 23.
\1068\ AES Initial Comments at 15.
\1069\ Enel Initial Comments at 41.
\1070\ AEE Initial Comments at 17.
\1071\ Invenergy Initial Comments at 10.
---------------------------------------------------------------------------
536. [Oslash]rsted, ACE-NY, and Equinor Wind note a myriad of
challenges for obtaining site control for interconnection facilities
for offshore wind projects, such as conflicts between Federal and state
permitting entity requirements for project flexibility and
adaptability.\1072\ [Oslash]rsted argues that site control for
interconnection facilities for offshore wind developers is only
obtainable very late in the interconnection process.\1073\
---------------------------------------------------------------------------
\1072\ ACE-NY Initial Comments at 5; Equinor Reply Comments at
4; [Oslash]rsted Initial Comments at 13; [Oslash]rsted Reply
Comments at 2, 4, 5; Shell Reply Comments at 29.
\1073\ [Oslash]rsted Initial Comments at 12.
---------------------------------------------------------------------------
537. Other commenters argue that the Commission should expand the
proposed definition of site control to apply some degree of site
control requirements to interconnection facilities, such as a
requirement to demonstrate 50% site control for interconnection
facilities when submitting the interconnection request.\1074\ MISO
encourages the Commission to require site control for interconnection
facilities at the same time that it requires site control for the
generating facilities.\1075\ AEP explains that some interconnection
customers submit interconnection requests that are not feasible given
where interconnection customer interconnection facilities would have to
be sited to connect the generating facility to the transmission system
at the selected point of interconnection.\1076\ Additionally, AEP
explains that, even if a generation site is suitable, there may not be
``room'' at certain locations for a substation or switchyard due to a
variety of issues, including abandoned mines, surrounding wetlands, or
other geographic impediments.\1077\ According to AEP, site control for
generating facilities can be far less important than feasible control
over the land needed to connect the generating facility to the
transmission system.
---------------------------------------------------------------------------
\1074\ AEE Initial Comments at 18; AEP Initial Comments at 21-
23; Cypress Creek Initial Comments at 22; Enel Initial Comments at
41; MISO Initial Comments at 56; National Grid Initial Comments at
22-23; Shell Reply Comments at 23.
\1075\ MISO Initial Comments at 56.
\1076\ AEP Initial Comments at 22.
\1077\ Id. at 23.
---------------------------------------------------------------------------
538. Enel argues that the addition of a generator tie line site
control requirement will increase the quality of interconnection study
results and increase certainty for interconnection customers as the
interconnection process becomes more costly and risky to
navigate.\1078\ Enel states that it has observed or heard of
interconnection customers submitting existing site control from very
remote locations to secure interconnection queue positions, and later
submitting a modification request to move the generating facility site
close to the point of interconnection after the generating facility's
actual intended site control has been obtained. Enel states that this
is done by interconnection customers to reduce the duration and
subsequently the cost of maintaining site control, as a failed distant
asset can be used for a new interconnection queue position elsewhere
until site control for the new generating facility area is complete. In
addition, Enel states that it supports SPP's approach, which also
requires 75% of generator tie line site control after the first cluster
restudy, to ensure interconnection customers are making reasonable
progress.
---------------------------------------------------------------------------
\1078\ Enel Initial Comments at 41-42.
---------------------------------------------------------------------------
539. National Grid argues that demonstrating site control for
interconnection facilities is crucial for generating facility
development and interconnection queue management particularly in cases
where numerous interconnection requests in the interconnection queue
are reliant on the construction of certain network upgrades.\1079\
National Grid argues that the payment of cash or the provision of other
security in lieu of demonstration of site control of transmission owner
interconnection facilities or network upgrades built by an
interconnection customer does not further the goals of the NOPR.
---------------------------------------------------------------------------
\1079\ National Grid Initial Comments at 23.
---------------------------------------------------------------------------
(2) Site Control Demonstration
540. Several commenters support the NOPR proposal to require
interconnection customers to demonstrate 100% site control for their
proposed generating facilities when they submit their interconnection
request.\1080\ MISO argues that obtaining site control is consistent
with the ``first-ready, first-served'' model and that delaying site
control for interconnection
[[Page 61093]]
requests until later in the interconnection process just increases the
instances of late-stage withdrawals that leads to uncertainty,
unplanned restudies, and delays for the remaining interconnection
requests.\1081\ National Grid asserts that the demonstration of
complete and exclusive site control is necessary at the interconnection
request stage to avoid submission of interconnection requests
prematurely, potential conflicts with other interconnection requests,
and delays in issuing cluster studies.\1082\ GSCE contends that there
should be few exceptions to a site exclusivity requirement to enter the
cluster study process so leniency is not granted to the type of
interconnection requests that linger in the interconnection queue while
they struggle to secure difficult land rights and permitting.\1083\
---------------------------------------------------------------------------
\1080\ ACE-NY Initial Comments at 5; APS Initial Comments at 14;
MISO Initial Comments at 56; National Grid Initial Comments at 22;
[Oslash]rsted Initial Comments at 12.
\1081\ MISO Initial Comments at 56-57.
\1082\ National Grid Initial Comments at 22.
\1083\ GSCE Initial Comments at 7.
---------------------------------------------------------------------------
541. PJM opposes any requirement on transmission providers to
accept demonstrations of less than 100% site control at the time of an
interconnection request, except for accommodations for interconnection
requests for proposed generating facilities to be sited offshore or on
government owned land.\1084\
---------------------------------------------------------------------------
\1084\ PJM Initial Comments at 32.
---------------------------------------------------------------------------
542. MISO notes that its tariff requires redemonstrations of site
control.\1085\ Similarly, Indicated PJM TOs support requiring 100% site
control at more than one decision point,\1086\ and assert that
transmission providers should be allowed to confirm site control
throughout the interconnection process.\1087\ Indicated PJM TOs and
Longroad Energy argue that the Commission should strengthen the
proposed site control requirements to ensure that interconnection
customers are maintaining site control throughout the interconnection
process.\1088\
---------------------------------------------------------------------------
\1085\ MISO Initial Comments at 53.
\1086\ Indicated PJM TOs Initial Comments at 26 (citing PJM
Interconnection, L.L.C., Motion for Leave to Answer and Answer of
PJM Interconnection, L.L.C., Docket No. ER22-2110-000, at 20 (filed
Aug. 2, 2022)).
\1087\ Id. at 8, 26.
\1088\ Indicated PJM TOs Reply Comments at 30; Longroad Energy
Reply Comments at 18.
---------------------------------------------------------------------------
543. On the other hand, APS believes that simultaneous submission
of the interconnection customer-executed LGIA and the continued
demonstration of site control is duplicative and unnecessary if an
interconnection customer demonstrates site control at the time an
interconnection request is made.\1089\
---------------------------------------------------------------------------
\1089\ APS Initial Comments at 7.
---------------------------------------------------------------------------
544. Several commenters oppose the NOPR proposal to require an
interconnection customer to demonstrate 100% site control at the time
of the interconnection request and/or propose alternative site control
requirements.\1090\ A number of commenters express concern that the
NOPR proposal is not compatible with the generating facility
development cycle.\1091\ EPSA argues that a 100% exclusive site control
requirement in advance of the processing of the facilities study is not
reasonable because it overlooks the complicated and extensive process
of negotiating for land leases or purchases.\1092\ Similarly, Cypress
Creek and AEE argue that the NOPR proposal does not reflect realities
of development, which include stringent permitting requirements, and
may disadvantage certain interconnection customers despite being on a
path to full site control and commercial readiness.\1093\ CESA and
Clean Energy Associations argue that the requirement for 100% site
control at the interconnection request stage is excessively stringent
and would significantly favor utility-owned projects.\1094\
---------------------------------------------------------------------------
\1090\ AEE Initial Comments at 17-18; Clean Energy Associations
Initial Comments at 31-32; CREA and NewSun Initial Comments at 54;
Cypress Creek Initial Comments at 22; EPSA Initial Comments at 8;
NextEra Initial Comments at 21; Pine Gate Initial Comments at 24; R
Street Initial Comments at 8; SEIA Initial Comments at 15; Shell
Reply Comments at 23-24.
\1091\ AEE Initial Comments at 17; Clean Energy Associations
Initial Comments at 31; CREA and NewSun Initial Comments at 54;
Cypress Creek Initial Comments at 22; EPSA Initial Comments at 8;
NextEra Initial Comments at 21; R Street Initial Comments at 8.
\1092\ EPSA Initial Comments at 8.
\1093\ AEE Initial Comments at 17.
\1094\ CESA Reply Comments at 5.
---------------------------------------------------------------------------
545. CREA and NewSun argue that the NOPR proposal is not adequately
supported and urge the Commission to maintain the existing site control
requirements.\1095\ CREA and NewSun argue that the proposal is
unreasonable and ``creates a Catch-22'': specifically, that without
reliable visibility as to the interconnection costs and viability for
its proposed generating facility within the specific cluster, the
interconnection customer will not be able to attract investment needed
to secure site control. CREA and NewSun also argue that a landowner
hoping to see property developed may not agree to permanently tie up
land in a lease before the interconnection customer can show
interconnection is viable. CREA and NewSun argue that interconnection
requests may prove uneconomic after receipt of initial interconnection
studies and thereafter cannot finalize site control due to uneconomic
interconnection costs. CREA and NewSun also assert that the Commission
made no effort in the NOPR to ascertain the impact on the market of the
``draconian'' site control rules for such transmission providers that
have been allowed to adopt them.
---------------------------------------------------------------------------
\1095\ CREA and NewSun Initial Comments at 54-55.
---------------------------------------------------------------------------
546. R Street argues that requiring even partial site control at
the time of the interconnection request may create delays and increase
project development costs because it would require more options
contracts to be in place with landowners.\1096\ NextEra argues that
site control is a limited indicator of generating facility
viability.\1097\ rPlus argues that requiring 100% site control at the
interconnection request stage will inhibit the flexibility for
interconnection request design changes that is needed to develop pumped
storage projects.\1098\
---------------------------------------------------------------------------
\1096\ R Street Initial Comments at 13.
\1097\ NextEra Initial Comments at 21-22.
\1098\ rPlus Initial Comments at 2.
---------------------------------------------------------------------------
547. Several commenters recommend that the Commission modify the
site control requirements in the final rule to require less than 100%
site control at the time of the interconnection request. For example,
Clean Energy Associations, SEIA, and Cypress Creek argue that no more
than 75% site control is appropriate at the time of the interconnection
request.\1099\ Shell argues that the Commission should only require
partial site control when the interconnection request is made.\1100\
Clean Energy Associations supports an escalating schedule of site
control through the interconnection process and suggests that the
Commission should modify the NOPR proposal to also require 90% site
control at the post-cluster study decision point and 100% site control
at the post-facilities study decision point.\1101\
---------------------------------------------------------------------------
\1099\ Clean Energy Associations Initial Comments at 31-32;
Cypress Creek Initial Comments at 22; SEIA Initial Comments at 15.
\1100\ Shell Reply Comments at 23-24.
\1101\ Clean Energy Associations Initial Comments at 31-32.
---------------------------------------------------------------------------
548. AEE argues that 90% site control at the time of the
interconnection request provides interconnection customers sufficient
flexibility.\1102\ Additionally, several commenters state that 100%
site control at the post-facilities study decision point would be
appropriate.\1103\ AEE argues that these altered requirements will
reduce speculative interconnection requests while also providing
incentive for
[[Page 61094]]
interconnection customers to pursue remaining land rights after
entering the interconnection queue.\1104\
---------------------------------------------------------------------------
\1102\ AEE Initial Comments at 18.
\1103\ Id.; CESA Reply Comments at 5-6; Clean Energy
Associations Initial Comments at 31-32; Cypress Creek Initial
Comments at 22; Xcel Initial Comments at 32.
\1104\ AEE Initial Comments at 18.
---------------------------------------------------------------------------
549. Some commenters note that less than 100% site control at the
interconnection request stage would allow interconnection customers
flexibility to address the results of interconnection studies or other
regulatory processes, which may lead to changes in the size or design
of a generating facility.\1105\ Additionally, SEIA requests that the
Commission require transmission providers to allow interconnection
customers to change site boundaries or reduce the size of a proposed
generating facility, as long as the point of interconnection remains
the same, in order to accommodate changes resulting from
interconnection studies or regulatory changes.\1106\ Pine Gate notes
that sometimes interconnection customers are still actively negotiating
with landowners close to the deadline for a cluster review window and
requests the Commission to permit interconnection customers to
demonstrate to the transmission prover that they are in active
negotiations to meet the heightened site control requirements.\1107\
---------------------------------------------------------------------------
\1105\ CREA and NewSun Initial Comments at 55; SEIA Initial
Comments at 14-15.
\1106\ SEIA Initial Comments at 15.
\1107\ Pine Gate Initial Comments at 23-24. Pine Gate notes that
this approach is similar to PJM's where, if PJM accepts the
interconnection customer's demonstration, then PJM will add a
condition precedent to the interconnection agreement requiring that
all site control requirements be met within 180 days of execution.
---------------------------------------------------------------------------
550. Some commenters highlight that the NOPR proposal may be
problematic or challenging for interconnection customers of certain
technology types or other circumstances where obtaining site control is
difficult. Hydropower Commenters argue that most new hydropower
facilities are sited at existing non-powered dams and therefore
hydropower interconnection customers face unique challenges when it
comes to obtaining site control.\1108\ The Ohio Commission Consumer
Advocate asserts that the proposal may be problematic for
interconnection customers in Ohio because a recent Ohio law permits
Ohio counties to designate unincorporated areas in a county as an area
in which the development of a renewable energy project is
prohibited.\1109\
---------------------------------------------------------------------------
\1108\ Hydropower Commenters Initial Comments at 13.
\1109\ Ohio Commission Consumer Advocate Initial Comments at 11.
---------------------------------------------------------------------------
551. According to Enel, some states limit the duration of site
control.\1110\ Enel asserts that, if site control is near to expiring
for any reason, whether due to state restriction or simply because the
interconnection customer did not anticipate the length of
interconnection or permitting processes, landowners can demand higher
payments than agreed to in the original site control contract. Enel
states that this can change the economics of a proposed generating
facility and even make a proposed generating facility unprofitable,
potentially leading to a late-stage interconnection request withdrawal.
---------------------------------------------------------------------------
\1110\ Enel Initial Comments at 40.
---------------------------------------------------------------------------
552. Several commenters argue that the Commission should reject
proposals to weaken the site control requirements proposed in the
NOPR.\1111\ APPA-LPPC argue that EPSA's and SEIA's generalized
complaints do not identify a specific obstacle created by the
Commission's proposal, and APPA-LPPC argue that SEIA's proposal to
scale back the site control requirement to not more than 75% was
considered and rejected by MISO's management and stakeholders over
concerns that it may not be rigorous enough to mitigate the entry of
speculative interconnection requests in the queue.\1112\
---------------------------------------------------------------------------
\1111\ APPA-LPPC Reply Comments at 2-3; CREA and NewSun Initial
Comments at 55; Indicated PJM TOs Reply Comments at 30; Ohio
Commission Consumer Advocate Initial Comments at 11-12.
\1112\ APPA-LPPC Reply Comments at 4 (citing Midcontinent Indep.
Sys. Operator, Inc., 169 FERC ] 61,173, at P 9 (2019)).
---------------------------------------------------------------------------
(3) Deposits in Lieu of Site Control
553. Several commenters support the NOPR proposal to eliminate the
option for interconnection customers to submit a deposit in lieu of
site control except in limited circumstances for regulatory
limitations.\1113\ These commenters express that allowing deposits in
lieu of site control is not sufficient to demonstrate readiness or
deter speculative interconnection requests.\1114\ PJM notes that, in
its experience, the option to provide money in lieu of actual site
control is easily abused by interconnection customers with speculative
interconnection requests.\1115\ CAISO notes that its most recent
cluster study was inundated by interconnection requests without site
control because even a $250,000 deposit in lieu of site control has not
proven to be a deterrent for interconnection customers.\1116\
---------------------------------------------------------------------------
\1113\ AES Initial Comments at 15; APPA-LPPC Reply Comments at
4; CAISO Initial Comments at 16-17; CREA and NewSun Reply Comments
at 50; Cypress Creek Initial Comments at 22; Dominion Initial
Comments at 31; ENGIE Initial Comments at 4; EEI Initial Comments at
7-8; Eversource Initial Comments at 17; MISO Initial Comments at 57;
NY Commission and NYSERDA Initial Comments at 8-9; NYTOs Initial
Comments at 18-19; Ohio Commission Consumer Advocate Initial
Comments at 12; SEIA Initial Comments at 15; Shell Initial Comments
at 23; Tri-State Initial Comments at 13.
\1114\ APPA-LPPC Initial Comments at 19; Bonneville Initial
Comments at 11; Idaho Power Initial Comments at 7; PJM Initial
Comments at 26; PPL Initial Comments at 16; Southern Initial
Comments at 8-9; Xcel Initial Comments at 30, 32.
\1115\ PJM Initial Comments at 26.
\1116\ CAISO Initial Comments at 17.
---------------------------------------------------------------------------
554. Some commenters oppose the NOPR proposal and argue that the
option to make deposits in lieu of site control should be available for
all interconnection customers, not just those that demonstrate
regulatory limitations.\1117\ Avangrid believes that an at-risk deposit
in lieu of site control that is set at a reasonable magnitude may be a
good alternative to ensure that an interconnection customer is
rigorously pursuing completion of a proposed generating facility.\1118\
Pacific Northwest Utilities suggest that the Commission should allow
transmission providers the flexibility to determine whether deposits in
lieu of site control are applicable.\1119\
---------------------------------------------------------------------------
\1117\ Avangrid Initial Comments at 19; Clean Energy
Associations Initial Comments at 32; CREA and NewSun Initial
Comments at 55; Interwest Energy Alliance Reply Comments at 13.
\1118\ Avangrid Initial Comments at 19.
\1119\ Pacific Northwest Utilities Initial Comments at 3.
---------------------------------------------------------------------------
(4) Site Control Considerations for Interconnection Customers With
Regulatory Limitations
555. Some commenters contend that the Commission should modify the
proposed definition of site control to reasonably accommodate
interconnection customers developing generating facilities on sites
owned or controlled by a government entity.\1120\ Several commenters
highlight unique circumstances and challenges for obtaining site
control on certain public lands and other regulatory issues that may
affect an interconnection customer's ability to demonstrate site
control under the NOPR definition.\1121\
---------------------------------------------------------------------------
\1120\ PPL Initial Comments at 16; Tri-State Initial Comments at
14; Xcel Initial Comments at 31.
\1121\ Clean Energy Associations Initial Comments at 33-34; CREA
and NewSun Reply Comments at 47-49; Dominion Initial Comments at 31;
ENGIE Initial Comments at 4; Hydropower Commenters Initial Comments
at 14-18, 24-25; Idaho Power Initial Comments at 6-7; NV Energy
Initial Comments at 15-16; [Oslash]rsted Initial Comments at 12;
OSPA Initial Comments at 16-18; rPlus Initial Comments at 2-3.
---------------------------------------------------------------------------
556. Several commenters argue that the Commission should provide
flexibility to allow transmission providers to establish site control
requirements for generating facilities sited on Federal and public
land.\1122\
[[Page 61095]]
Shell notes that securing site control can often be complicated by
fast-changing local, county, and state regulations, and encourages the
Commission to provide sufficient flexibility to enable transmission
providers to make accommodations for local site control
challenges.\1123\
---------------------------------------------------------------------------
\1122\ Dominion Initial Comments at 32; Indicated PJM TOs
Initial Comments at 26; Pacific Northwest Utilities Initial Comments
at 3; PJM Initial Comments at 31; Shell Initial Comments at 23.
\1123\ Shell Initial Comments at 23.
---------------------------------------------------------------------------
557. Some commenters provide recommendations on how the Commission
could clarify what may constitute a sufficient demonstration of site
control for generating facilities being developed on land owned or
controlled by a government entity.\1124\ Pattern Energy argues that
interconnection customers proposing to develop generating facilities on
land owned or managed by state, Federal, or Tribal government entities
should be required to provide evidence that they submitted any required
applications to the relevant government entity or entities in order to
advance the development of their proposed generating facility. Pattern
Energy states that such an interconnection request should provide for
an exclusive right to advance the development of a generating facility,
provided that the relevant government entity or entities allow for such
an exclusive right.\1125\
---------------------------------------------------------------------------
\1124\ Id. at 22-23; CREA and NewSun Reply Comments at 50;
Equinor Reply Comments at 4; Hydropower Commenters Initial Comments
at 15-18; Idaho Power Initial Comments at 7; Indicated PJM TOs Reply
Comments at 31; [Oslash]rsted Initial Comments at 12-13;
[Oslash]rsted Reply Comments at 2, 4-5; OSPA Initial Comments at 18;
Pattern Energy Initial Comments at 30; rPlus Initial Comments at 3-
4.
\1125\ Pattern Energy Initial Comments at 30.
---------------------------------------------------------------------------
558. PJM notes that the proposed site control requirements that PJM
included in its interconnection queue reform filing with the Commission
provide some leeway for generating facilities constructed on Federal or
state lands or water, such as offshore wind projects.\1126\
Alternatively, Dominion requests that the Commission clarify that the
deposit in lieu of site control exception would apply to offshore wind
projects, in addition to other proposed generating facilities subject
to similar government control that may prevent timely demonstration of
site control.\1127\
---------------------------------------------------------------------------
\1126\ PJM Initial Comments at 29-30, 32; see PJM
Interconnection, L.L.C., 181 FERC ] 61,162 at PP 83-105.
\1127\ Dominion Initial Comments at 32.
---------------------------------------------------------------------------
559. Several commenters note that certain interconnection customers
with generating facilities and interconnection facilities on land
controlled by the Bureau of Land Management (BLM) face extended time
frames for obtaining firm site control.\1128\ For example, NV Energy
states that the BLM permitting process can take between 18 months and 5
years.\1129\ Idaho Power states that BLM goes through various stages of
review, but there is no specific stage that is indicative of an
interconnection customer's request having firm site control until the
permit is in hand, which can take up to three years to obtain.\1130\
Idaho Power states that, currently, interconnection customers with
generating facilities on BLM lands typically reference the section of
the site control definition that allows for ``an exclusivity or other
business relationship between interconnection customer and the entity
having the right to sell, lease or grant interconnection customer the
right to possess or occupy a site for such purpose.'' \1131\ Idaho
Power argues that generating facilities on land managed by BLM should
have the same site control requirements as all other generating
facilities, but that they would support an expanded and/or clarified
definition of site control to capture the limitations of these
generating facilities. Idaho Power states that, for example, site
control evidence may include evidence that the necessary application
has been received by the agency, is in process, and the agency has
indicated the generating facility is permittable.
---------------------------------------------------------------------------
\1128\ CREA and NewSun Reply Comments at 49; Idaho Power Initial
Comments at 6; NV Energy Initial Comments at 16.
\1129\ NV Energy Initial Comments at 16.
\1130\ Idaho Power Initial Comments at 6-7.
\1131\ Id.
---------------------------------------------------------------------------
560. NV Energy proposes that the deposit in lieu of site control be
used for lands that are federally managed, and that those deposits be
held until the decision record, record of decision, notice to proceed,
or right-of-way grant is issued for a generating facility, which NV
Energy notes may not be until after the facilities study due to timing
of the BLM process.\1132\ To ensure the generating facility is
progressing in the BLM process, NV Energy also proposes that the
interconnection customer be required to submit with its interconnection
request a schedule of the land rights and permitting as well as
documentation from BLM that the draft environmental assessment or draft
environmental impact statement is expected to be completed by issuance
of the system impact study. NV Energy also proposes that
interconnection customers be required to provide the administrative
draft environmental assessment or draft environmental impact statement
to the transmission provider for review and comment once BLM has issued
it to ensure its interconnection facilities are included in the right-
of-way that BLM will issue.
---------------------------------------------------------------------------
\1132\ NV Energy Initial Comments at 17.
---------------------------------------------------------------------------
561. CREA and NewSun encourage the Commission to modify its
proposed site control requirements, such that an interconnection
customer developing generating facilities on public lands is allowed to
proceed with the interconnection process if it can demonstrate that the
relevant public agency has received and has agreed to process the
necessary permits to develop the interconnection customer's proposed
generating facility.\1133\
---------------------------------------------------------------------------
\1133\ CREA and NewSun Reply Comments at 50.
---------------------------------------------------------------------------
562. For generating facilities on Bureau of Reclamation lands,
Hydropower Commenters argue that a lease of power privilege should be
considered a sufficient demonstration of site control.\1134\
Additionally, Hydropower Commenters note that generating facilities
under a certain size can obtain an exemption from Commission licensing
requirements, and they argue that an exemption from licensing should
also be considered a sufficient demonstration of site control.
Similarly, Hydropower Commenters argue that developers of pumped
storage projects on U.S. Forest Service or BLM lands should not be
required to complete the required Federal Land Policy and Management
Act process before they can be considered to have demonstrated
sufficient evidence of site control.\1135\ Hydropower Commenters
contend that such generating facilities should be allowed to
demonstrate site control by submitting evidence that they have a permit
application pending with U.S. Forest Service or BLM.
---------------------------------------------------------------------------
\1134\ Hydropower Commenters Initial Comments at 16-17.
\1135\ Id. at 25.
---------------------------------------------------------------------------
563. Some commenters argue that the 100% site control requirement
should not apply to generating facilities being developed on Tribal
lands.\1136\ OSPA claims that development on Tribal land is more
challenging than other kinds of development because Tribes have three
different classes of land that have different ownership structures and
regulatory restrictions, including ``Trust'' land, which is held by the
Federal Government on behalf of Tribes and regulated by the Bureau of
Indian Affairs.\1137\ OSPA notes that Tribes' Reservations are often
``checker-boarded'' with the three different classes of land, and that
large wind generating facilities will necessarily be sited on all three
classes of land. OSPA argues that
[[Page 61096]]
securing Bureau of Indian Affairs regulatory approvals can take years
and that the ownership structure of ``Allotted'' lands can make it even
difficult to expediently obtain consent from all owners to lease
certain tracts, which is required as part of the Bureau of Indian
Affairs process.\1138\
---------------------------------------------------------------------------
\1136\ OSPA Initial Comments at 16; rPlus Initial Comments at 2.
\1137\ OSPA Initial Comments at 17.
\1138\ Id. at 17-18.
---------------------------------------------------------------------------
564. OSPA proposes that, for Tribes and Tribal Energy Development
Organizations, the Commission clarify that interconnection queue
positions may be secured if the Tribe has signed a lease, even if the
Bureau of Indian Affairs has not issued a final approval.\1139\
Similarly, rPlus recommends that the filing of a valid preliminary
permit application with the Commission satisfy the site control
requirement for a pumped storage project and for generating facilities
on Tribal lands.\1140\ rPlus notes that suitable pumped storage sites
are limited in availability and are increasingly located on public or
Tribal lands, which involve significant environmental review. rPlus
notes that pumped storage projects located on Federal and Tribal lands
generally cannot achieve full site control until Federal environmental
reviews are complete and the Commission issues a license. For
circumstances where a pumped storage project does not require a
Commission license, rPlus requests that the site control requirement be
only 50% of the land needed for the core generating facility.\1141\
---------------------------------------------------------------------------
\1139\ Id. at 18.
\1140\ rPlus Initial Comments at 2-3.
\1141\ Id. at 4.
---------------------------------------------------------------------------
565. Several commenters state that the proposed site control
requirements may present challenges for offshore wind projects, which
face extensive permitting timelines.\1142\ Clean Energy Associations
argue that the formal issuance of a public lease often requires
multiple preliminary stages and major financial commitments from
interconnection customers and that requiring a lease prior to entering
the interconnection queue would unduly delay generating facilities on
public lands.\1143\ [Oslash]rsted and Clean Energy Associations further
explain that the permitting process for an offshore wind farm often
involves multiple Federal and state agencies and runs concurrently with
the interconnection process. [Oslash]rsted and Clean Energy
Associations note that the permitting process can lead to changes in
the generating facility layout within a lease area, routing of offshore
cables, siting of onshore cable landing, routing of onshore cables, and
siting of the interconnection switchyard.\1144\
---------------------------------------------------------------------------
\1142\ Clean Energy Associations Initial Comments at 33; CREA
and NewSun Reply Comments at 48; Dominion Initial Comments at 31;
[Oslash]rsted Initial Comments at 12.
\1143\ Clean Energy Associations Initial Comments at 33.
\1144\ Id. at 33-34; [Oslash]rsted Initial Comments at 12.
---------------------------------------------------------------------------
566. Shell, Dominion, and CREA and NewSun argue that the high cost
of market entry for offshore wind projects is a substantial financial
commitment and that such generating facilities are by their very nature
not speculative.\1145\ Shell argues that offshore wind generation
should be able to demonstrate site control by showing evidence of
commitments to purchase offshore lease areas from BOEM, as commitments
often demand hundreds of millions of dollars.\1146\
---------------------------------------------------------------------------
\1145\ CREA and NewSun Reply Comments at 48; Dominion Initial
Comments at 31; Shell Initial Comments at 22.
\1146\ Shell Initial Comments at 22.
---------------------------------------------------------------------------
567. CREA and NewSun contend that the site control requirements in
the NOPR would require an offshore developer to win a competitive
solicitation or obtain a term sheet from an off-taker before entering
the interconnection queue, which at best will add years of delay to
developing these generating facilities and at worst will kill the
proposals outright due to a lack of information on interconnection
feasibility and cost.\1147\
---------------------------------------------------------------------------
\1147\ CREA and NewSun Reply Comments at 48.
---------------------------------------------------------------------------
568. MISO notes that it has not interpreted its tariff to mean that
a BOEM-administered Wind Energy Area auction that an offshore wind
interconnection customer can participate in, but which will occur after
the close of an application window, is a regulatory restriction.\1148\
MISO is concerned that broadening the regulatory restriction
interpretation to allow for offshore wind to submit an interconnection
request in such instances would enable speculative interconnection
requests, which will result in withdrawals, restudies, uncertainty, and
study delays. MISO states that interconnection customers that seek to
develop a generating facility on government owned lands that are
awarded to the winner of an auction, and interconnection customers that
seek to develop a generating facility on private land, are held to the
same standard in the MISO process.
---------------------------------------------------------------------------
\1148\ MISO Initial Comments at 55.
---------------------------------------------------------------------------
569. Some commenters request that ``regulatory limitations'' be
more clearly defined.\1149\ CAISO expresses concern that, absent
clarification, the regulatory limitation provision will leave
transmission provider staff as adjudicators of whether obtaining site
control is possible for each proposed generating facility, and
interconnection staff are not experts on real property law or public
permitting requirements.\1150\ CAISO and Indicated PJM TOs argue that
without further clarification, the regulatory limitation provision may
be interpreted too broadly and interconnection customers could argue
site control was impossible where it was simply impractical or
expensive.\1151\ CAISO suggests, as an example, that the Commission
could limit ``regulatory limitations'' only to apply to interconnection
customers sited in offshore areas, public lands, and Tribal
lands.\1152\
---------------------------------------------------------------------------
\1149\ APS Initial Comments at 14; CAISO Initial Comments at 17;
EEI Initial Comments at 7-8; NYISO Initial Comments at 22; PG&E
Reply Comments at 2; Indicated PJM TOs Initial Comments at 26-27;
Shell Reply Comments at 24.
\1150\ CAISO Initial Comments at 17 & n.29.
\1151\ Id. at 17; Indicated PJM TOs Initial Comments at 26-27,
31.
\1152\ CAISO Initial Comments at 17.
---------------------------------------------------------------------------
570. Several parties support the NOPR proposal to allow
interconnection customers with regulatory limitations to submit a
deposit in lieu of site control.\1153\ For projects on government
lands, Indicated PJM TOs argue that the interconnection customer should
be allowed to enter and remain in the interconnection queue, with a
deposit in lieu of site control, if they identify the steps needed to
achieve site control and show how they are exercising due diligence to
obtain a final government determination.\1154\ Indicated PJM TOs argue
that the regulatory limitations exception should be limited to just
government lands.
---------------------------------------------------------------------------
\1153\ APPA-LPPC Initial Comments at 3-4; Cypress Creek Initial
Comments at 22; SEIA Initial Comments at 15-16; NY Commission and
NYSERDA Initial Comments at 8-9.
\1154\ Indicated PJM TOs Reply Comments at 31.
---------------------------------------------------------------------------
571. MISO supports such an option specifically when the
interconnection customer is prevented from obtaining site control by a
regulatory restriction that the passage of time itself will not cure
(e.g., while participating in an auction that occurs after the
interconnection request deadline can be cured by time, a requirement to
obtain an LGIA to participate in an auction cannot be cured by
time).\1155\
---------------------------------------------------------------------------
\1155\ MISO Initial Comments at 57.
---------------------------------------------------------------------------
572. Tri-State suggests modifying section 3.4.[1]2 of the pro forma
LGIP so that the site control for state or federally controlled land
must still be fully attained at the time of LGIA execution.\1156\ For
example, Tri-State states that in Colorado, a state land planning lease
(which does not meet the Commission's proposed definition of
[[Page 61097]]
site control) could be used with a financial deposit during the cluster
study process, and a state land production lease (which does meet the
Commission's proposed definition of site control) would be needed prior
to LGIA execution.\1157\
---------------------------------------------------------------------------
\1156\ Tri-State Initial Comments at 13, 27.
\1157\ Id. at 13.
---------------------------------------------------------------------------
573. APPA-LPPC argue that, if the NOPR proposal is adopted, at a
minimum, the interconnection customer should be required to provide an
affidavit from a company officer, a detailed explanation, and
documentation justifying the proposed regulatory limitation exception
and to demonstrate 100% site control as soon as possible after the
generator interconnection request is submitted, and certainly prior to
the facilities study stage, as the NOPR proposes.\1158\ PPL contends
that, while additional flexibility for interconnection customers that
face regulatory limitation may be appropriate in the early stages of
review, the Commission should require that full site control be
demonstrated before proceeding to an LGIA.\1159\
---------------------------------------------------------------------------
\1158\ APPA-LPPC Initial Comments at 20.
\1159\ PPL Initial Comments at 16.
---------------------------------------------------------------------------
574. A number of commenters oppose the NOPR's proposed option to
allow deposits in lieu of site control where Federal or state
regulatory limitations prohibit the interconnection customer from
obtaining site control.\1160\ Idaho Power argues that any allowance of
a deposit must be accompanied by some evidence of achieving site
control.\1161\ APS asserts that speculative interconnection requests do
not necessarily have financial limitations and extra deposits would not
act as the same deterrent as requiring 100% site control; therefore,
APS requests that the Commission not allow an exception for regulatory
restrictions.\1162\
---------------------------------------------------------------------------
\1160\ APPA-LPPC Initial Comments at 19; APS Initial Comments at
14; Bonneville Initial Comments at 11; Idaho Power Initial Comments
at 7; Indicated PJM TOs Initial Comments at 11; Indicated PJM TOs
Reply Comments at 31; PJM Initial Comments at 26; PPL Initial
Comments at 16; Southern Initial Comments at 9; SPP Initial Comments
at 10; Xcel Initial Comments at 30, 32.
\1161\ Idaho Power Initial Comments at 7.
\1162\ APS Initial Comments at 14.
---------------------------------------------------------------------------
575. OSPA argues that requiring interconnection customers that face
regulatory barriers to submit any deposits, including deposits in lieu
of site control, will create insuperable barriers to renewable energy
development by Native American Tribes and Tribal Energy Development
Organizations on Tribal lands,\1163\ stating that Tribes have limited
access to capital and face other challenges that large developers do
not share.\1164\
---------------------------------------------------------------------------
\1163\ OSPA Initial Comments at 18.
\1164\ OSPA Reply Comments at 12.
---------------------------------------------------------------------------
576. A few commenters support the proposed amounts for the deposit
in lieu of site control.\1165\ MISO agrees that the proposed deposit
thresholds are sufficient, noting that the amount of the deposits under
MISO's tariff are the same amounts the Commission proposed in the
NOPR.\1166\ Tri-State contends that the proposed deposit amounts would
be sufficient to ensure advanced-stage interconnection requests are
able to continue to move toward interconnection.\1167\
---------------------------------------------------------------------------
\1165\ MISO Initial Comments at 57; NV Energy Initial Comments
at 15; Tri-State Initial Comments at 13.
\1166\ MISO Initial Comments at 57.
\1167\ Tri-State Initial Comments at 13.
---------------------------------------------------------------------------
577. Several parties support a deposit in lieu of site control high
enough to deter speculative interconnection requests that are unlikely
to achieve site control.\1168\ Avangrid argues that any deposit in lieu
of site control should be proportionate to the size of the
interconnection request, and ``reflect collateral'' while an
interconnection customer works through site control agreements.\1169\
Eversource similarly argues that the Commission should set the deposit
so that the interconnection customer fully internalizes the risk of
failing to obtain site control.\1170\ Tri-State also argues that the
deposit should not apply to interconnection study costs.\1171\
---------------------------------------------------------------------------
\1168\ Id. at 14; Avangrid Initial Comments at 19; ENGIE Initial
Comments at 4; GSCE Initial Comments at 7; NYTOs Initial Comments at
19; Pacific Northwest Utilities Initial Comments at 3-4.
\1169\ Avangrid Initial Comments at 19.
\1170\ Eversource Initial Comments at 17.
\1171\ Tri-State Initial Comments at 14.
---------------------------------------------------------------------------
578. Some commenters provide alternative suggestions for the
deposit in lieu of site control amounts.\1172\ Longroad Energy argues
that the Commission should consider requiring that such deposits be set
as a multiple of the interconnection study deposit (such as three times
the deposit amount), rather than as a dollar amount per MW of
generating facility size, as proposed in the NOPR.\1173\ NYTOs argue
that the MW capacity of a generating facility is not necessarily
relevant to determining the appropriate deposit requirement and that
deposits should be more closely tied to the generating facility's
potential impact on the interconnection process.\1174\
---------------------------------------------------------------------------
\1172\ Eversource Initial Comments at 17; Longroad Energy
Initial Comments at 12; NYTOs Initial Comments at 19.
\1173\ Longroad Energy Initial Comments at 12; Longroad Energy
Reply Comments at 18.
\1174\ NYTOs Initial Comments at 19.
---------------------------------------------------------------------------
579. A number of entities argue that any deposits in lieu of site
control should be non-refundable.\1175\ Avangrid suggests that the
deposit be non-refundable to avoid gaming by prospective
interconnection customers.\1176\ National Grid argues that absent
circumstances outside the control of the interconnection customer, any
deposit should be non-refundable, and any security should be able to be
drawn upon in the event the interconnection customer withdraws or fails
to demonstrate site control at the required time.\1177\ National Grid
contends that if the Commission intends to permit refunds or returns of
a deposit in lieu of site control, such deposits should be provided
only after deducting the actual costs and fees, e.g., escrow account
initiation and maintenance fees, incurred by the transmission provider
or RTOs/ISOs prior to the time of the withdrawal request or the
demonstration of site control. National Grid also requests that the
Commission clarify that withdrawal penalties are separate and may be
deducted from the deposit amount.
---------------------------------------------------------------------------
\1175\ Avangrid Initial Comments at 19; EEI Initial Comments at
8; Longroad Energy Initial Comments at 12; National Grid Initial
Comments at 23; NYTOs Initial Comments at 19.
\1176\ Avangrid Initial Comments at 19.
\1177\ National Grid Initial Comments at 23-24.
---------------------------------------------------------------------------
580. Similarly, Longroad Energy suggests that to ensure that the
proper incentives exist, the Commission may wish to evaluate if a
security deposit in lieu of site control should become non-refundable
if an interconnection customer withdraws at any point in the
interconnection process or fails to achieve commercial operation.\1178\
EEI argues that the Commission can further reduce potential risks by
making deposits non-refundable, or if the Commission declines to do so,
it should ensure that withdrawal penalties are significant enough to
discourage speculative interconnection requests.\1179\ On the other
hand, NYTOs argue that regions should have the flexibility to determine
whether, under certain circumstances, deposits should become fully non-
refundable.\1180\
---------------------------------------------------------------------------
\1178\ Longroad Energy Initial Comments at 12.
\1179\ EEI Initial Comments at 8.
\1180\ NYTOs Initial Comments at 19.
---------------------------------------------------------------------------
581. Xcel argues that in addition to requiring a deposit,
interconnection customers facing regulatory limitations should be
required to provide status updates to the transmission provider, and
there should be sufficient penalties to ensure interconnection
customers provide accurate information on the
[[Page 61098]]
status of regulatory proceedings.\1181\ Xcel contends that, if
regulatory limitations prohibit an interconnection customer from
obtaining site control, transmission providers should be allowed to
propose constructs that facilitate interconnection, including the
ultimate achievement of site control.
---------------------------------------------------------------------------
\1181\ Xcel Initial Comments at 30-31.
---------------------------------------------------------------------------
(c) Miscellaneous
582. Public Interest Organizations argue that it is unreasonable
that the pro forma LGIP allows interconnection customers to propose a
decrease to the generating facility's output of up to 60% without
losing queue position while also requiring a demonstration of 100% site
control upon entering the interconnection queue.\1182\ Public Interest
Organizations also argue that the NOPR proposal to require
interconnection customers to remedy any change in site control within
10 days or have their interconnection request withdrawn is
unreasonable. In addition, Public Interest Organizations argue that it
is unduly discriminatory to allow interconnection customers proposing a
thermal project to keep their queue position by downsizing the
generating facility's turbines but not allow interconnection customers
proposing wind generating facilities to keep their queue position if
they lose part of a lease. Public Interest Organizations argue that the
cure period should be long enough to allow for routine events that
affect site control, such as the death of a landowner or the change of
ownership at a commercial facility hosting a proposed generating
facility.
---------------------------------------------------------------------------
\1182\ Public Interest Organizations Initial Comments at 27-28.
---------------------------------------------------------------------------
iii. Commission Determination
583. As discussed herein, we adopt in part and modify in part the
NOPR proposal to revise sections 1, 3.4.2, 7.5, 8.1, and 11.3 of the
pro forma LGIP and Appendix B of the pro forma LGIA to add more
stringency to the site control requirements and to help prevent
speculative interconnection requests from entering the interconnection
queue. We believe that, taken together, these reforms will help ensure
that commercially viable interconnection requests with demonstrated
site control or with demonstrated regulatory limitations will be able
to enter the interconnection queue, thereby reducing the negative
impacts of speculative interconnection requests.
(a) Definition and Reasonable Evidence of Site Control
584. We adopt the NOPR proposal to revise the definition of site
control in section 1 of the pro forma LGIP with several modifications.
As modified, the definition states that site control may be
demonstrated by documentation establishing: ``(1) ownership of, a
leasehold interest in, or a right to develop a site of sufficient size
to construct and operate the Generating Facility; (2) an option to
purchase or acquire a leasehold site of sufficient size to construct
and operate the Generating Facility; or (3) any other documentation
that clearly demonstrates the right of Interconnection Customer to
exclusively occupy a site of sufficient size to construct and operate
the Generating Facility.'' Additionally, we agree with commenters'
observations \1183\ that subpart (3) of the pro forma LGIP definition
of site control proposed in the NOPR, which stated ``site of sufficient
size to construct and operate the Generating Facility,'' was
duplicative; therefore, we modify the NOPR proposal to delete this
subpart and provide clarification that all three remaining, enumerated
options to demonstrate site control require control of a site of
sufficient size to construct and operate the generating facility or
multiple generating facilities on a shared site.
---------------------------------------------------------------------------
\1183\ See Enel Initial Comments at 82; Southern Initial
Comments at 34-35.
---------------------------------------------------------------------------
585. To prevent multiple interconnection customers from leasing the
same site in order to remain in the interconnection queue, we adopt the
NOPR's proposed revisions to the pro forma LGIP that require an
interconnection customer to demonstrate the exclusive land right to
develop, construct, operate, and maintain its generating facility or,
where facilities are co-located, to demonstrate a shared land use right
to develop, construct, operate, and maintain co-located facilities. We
further clarify that the right to ``exclusively'' occupy the site to
develop, construct, operate, or maintain a generating facility means
both that the right belongs solely to the interconnection customer (no
other entity shares the right to use the site for those purposes), as
well as that the right is solely for purposes of a single
interconnection request. We find that an interconnection customer
securing the exclusive land right necessary to construct its proposed
generating facility (or for co-located generating facilities,
demonstration of shared land use) is sufficient evidence of the
interconnection customer's commitment to construct the generating
facility.
586. We also modify section 3.4.2 of the pro forma LGIP to provide
that site control for a generating facility that is co-located with one
or more generating facilities on the same site and behind the same
point of interconnection must be demonstrated by a contract or other
agreement that allows for shared land use for all generating facilities
that are co-located that meet the provisions of the site control
definition. We clarify that interconnection customers are prohibited
from submitting evidence of site control that uses the same land for
multiple interconnection requests, unless the site is large enough to
host multiple generating facilities. We note that section 3.4.2 of the
pro forma LGIP that we adopt in this final rule permits shared land use
for co-located generating facilities on the same site and behind the
same point of interconnection, and we clarify below that transmission
providers have flexibility to establish appropriate technology-specific
acreage requirements for generating facilities.\1184\ Permitting
multiple interconnection requests to use the same land to demonstrate
exclusive site control would inherently result in at least one
commercially non-viable interconnection request entering the
interconnection queue and thus would be insufficient to ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner. We
also clarify that the interconnection customer is required to meet the
technology-specific acreage requirement for its generating facility
that is publicly posted by the transmission provider at the time it
submits its interconnection request.
---------------------------------------------------------------------------
\1184\ This is consistent with the practice that several
transmission providers currently follow. See Midcontinent Indep.
Sys. Operator, Inc., 169 FERC ] 61,173 at P 48; Sw. Power Pool,
Inc., 128 FERC ] 61,114 at P 48; PJM Interconnection, L.L.C., 181
FERC ] 61,162 at P 102.
---------------------------------------------------------------------------
587. Likewise, in response to Enel, we clarify that the term
``exclusive land rights'' in the definition of site control applies
only to the exclusivity required to develop, construct, operate, and
maintain the interconnection customer's proposed generating facility;
the term ``exclusive land rights'' does not restrict multi-use
applications of the site in addition to its use for the generating
facility, such as agriculture, ranching, etc.\1185\ Similarly, in
response to Cypress Creek, we clarify that a land right does not
involve zoning approval.
---------------------------------------------------------------------------
\1185\ See Enel Initial Comments at 42.
---------------------------------------------------------------------------
[[Page 61099]]
588. In response to commenters,\1186\ we further clarify that the
adopted definition of site control permits an interconnection customer
to demonstrate site control with lease options, instead of executed
leases, provided that the interconnection customer is the exclusive
holder of such a lease option(s). The adopted definition explicitly
provides for such a lease option, by including the phrase, ``an option
to purchase or acquire a leasehold site.'' However, evidence of active
negotiations for a lease is not a sufficient demonstration of site
control at any time during the interconnection process. Allowing active
negotiations for a lease to serve as a demonstration of site control,
as some commenters suggest,\1187\ would allow speculative, commercially
non-viable interconnection requests to proceed through the
interconnection queue, which would be inconsistent with ensuring that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner.
Likewise, with respect to NRECA's request,\1188\ we clarify that this
final rule permits leases and lease options as sufficient evidence of
site control as discussed above, and transmission providers have
discretion to evaluate the content of such leases and lease options and
any conditions contained therein to determine whether they sufficiently
demonstrate site control.
---------------------------------------------------------------------------
\1186\ Omaha Public Power Initial Comments at 7; SoCal Edison
Initial Comments at 6.
\1187\ EPSA Initial Comments at 8; Interwest Reply Comments at
13.
\1188\ NRECA Initial Comments at 27.
---------------------------------------------------------------------------
589. Several commenters seek clarification as to whether the
proposed pro forma LGIP definition of site control would allow certain
types of generating facilities developed on lands owned or controlled
by a government entity to demonstrate site control. We agree with
commenters that offshore wind interconnection customers must make a
substantial financial commitment to win a competitive auction and
secure a lease from BOEM, and such generating facilities that have
secured a lease agreement are not speculative.\1189\ We therefore
clarify that a lease agreement with BOEM to pursue development of an
offshore wind generating facility can serve as a sufficient
demonstration of site control under the site control definition adopted
in this final rule. This clarification is consistent with our finding
above that a variety of lease options satisfy the site control
requirement. In response to MISO's concerns about allowing multiple
offshore wind interconnection customers to submit an interconnection
request for the same ``Wind Energy Area'' before it has been auctioned
by BOEM, we find that the pro forma LGIP site control definition that
we adopt herein appropriately limits such potentially speculative
interconnection requests by requiring offshore wind interconnection
customers to provide evidence of an exclusive right to develop a lease
area to satisfy the site control requirements.
---------------------------------------------------------------------------
\1189\ CREA and NewSun Reply Comments at 48; Dominion Initial
Comments at 31; Shell Initial Comments at 22.
---------------------------------------------------------------------------
590. With respect to OSPA's concerns regarding the challenges of
demonstrating site control on Tribal lands due to the nature of land
ownership on Reservations and the need for the Bureau of Indian Affairs
to approve certain leases, we clarify that under the site control
definition, interconnection customers developing generating facilities
on Tribal lands can demonstrate site control with a signed lease
agreement with the applicable Tribe-owner.\1190\ As discussed below in
section III.A.6.b.iii.b, an interconnection customer with a
demonstrated regulatory limitation, including those associated with
obtaining a lease on Tribal lands, may submit a deposit in lieu of site
control.
---------------------------------------------------------------------------
\1190\ OSPA Initial Comments at 17-18.
---------------------------------------------------------------------------
591. Similarly, in response to commenters' concerns about
demonstrating site control for hydropower projects on sites owned or
controlled by a government entity, we clarify that certain
documentation can be used to demonstrate site control under the pro
forma LGIP definition of site control. For interconnection customers
developing generating facilities at non-powered dams, we clarify that a
FERC license \1191\ can serve as a demonstration of site control under
subpart (3). However, we also clarify that neither a Memorandum of
Agreement with the U.S. Army Corps of Engineers regarding a proposed
hydropower project at a U.S. Army Corps of Engineers dam nor a
preliminary permit for a pumped storage project or other hydropower
generating facility to be located on Tribal lands would be sufficient
to demonstrate site control because we do not have enough information
in this record to determine that such documentation provides sufficient
evidence of the interconnection customer's exclusive right to occupy a
site of sufficient size to construct and operate a generating facility.
---------------------------------------------------------------------------
\1191\ A FERC license provides the licensee with the power of
eminent domain to secure property rights needed to construct and
operate the project. See 16 U.S.C. 814. While a FERC license does
not explicitly convey an exclusive right to develop a project, the
Commission does not approve more than one license for the same site.
---------------------------------------------------------------------------
592. For hydropower projects that are not subject to the
Commission's hydropower permitting jurisdiction, such as projects on
Bureau of Reclamation lands, we clarify that a lease of power privilege
can serve as a demonstration of site control under the site control
definition. Finally, for hydropower projects that are small enough to
be exempted from FERC licensing requirements, Hydropower Commenters
explain that an exemption from FERC licensing provides an exclusive
right to the recipient to develop a project at the site and the
exemption is issued in perpetuity.\1192\ Because such an exemption
includes an exclusive right to develop, we clarify that providing a
written statement as evidence of an exemption from licensing under the
FPA can serve as a demonstration of site control under subpart (3) of
the site control definition.
---------------------------------------------------------------------------
\1192\ Hydropower Commenters Initial Comments at 17.
---------------------------------------------------------------------------
593. We note NV Energy's explanation that its previous efforts to
allow interconnection customers to demonstrate site control by showing
a draft preliminary plan of development, one of the earlier required
documents in the BLM permitting process, have led to speculative
interconnection requests that slow down the interconnection
process.\1193\ We agree, and we therefore decline to adopt commenters'
proposal to modify the proposed pro forma LGIP definition of site
control to allow interconnection customers to demonstrate site control
by providing documentation indicating that they are pursuing the
necessary permits with the appropriate government entity or
entities.\1194\ As with our finding that active negotiations for lease
agreements are not sufficient to demonstrate site control, discussed
above, we find that such an expansion of the site control definition
could weaken the site control requirements included in the pro forma
LGIP and could undermine the effectiveness of this reform in helping to
prevent speculative interconnection requests.
---------------------------------------------------------------------------
\1193\ NV Energy Initial Comments at 15-16.
\1194\ See CREA and NewSun Reply Comments at 50; Pattern Energy
Initial Comments at 30.
---------------------------------------------------------------------------
(b) Site Control Demonstration and Deposits in Lieu of Site Control
594. We adopt the NOPR proposal, with modification, to revise
section 3.4.2 of the pro forma LGIP to require
[[Page 61100]]
interconnection customers to demonstrate site control at the time of
submission of the interconnection request. However, we modify the
proposal and require interconnection customers to provide evidence of
90% site control for the generating facility at the time of submission
of the interconnection request and, pursuant to revised sections 8.1
and 11.3 of the pro forma LGIP, provide evidence of 100% site control
for the generating facility at the time of execution of the facilities
study agreement and when executing, or requesting the unexecuted filing
of, the LGIA.
595. We decline to adopt the NOPR proposal to require technology-
specific acreages to be listed in the transmission provider's tariff.
As discussed below, instead, we require transmission providers to
establish acreage requirements for each generating facility technology
type and to publicly post these acreage requirements. We adopt the
following aspects of the NOPR proposal to revise sections 3.4.2 and
11.3 of the pro forma LGIP to: (1) eliminate the option to provide a
deposit in lieu of site control demonstration except in limited
circumstances where an interconnection customer demonstrates a
regulatory limitation to obtaining site control, as discussed below,
and eliminate the option to post $250,000 of non-refundable security in
lieu of site control at LGIA execution; and (2) require that
interconnection customers that could not demonstrate the requisite
level of site control at the relevant milestone of the interconnection
process (i.e., 90% for the cluster study and cluster restudy, and 100%
for the interconnection facilities study and when executing, or
requesting the unexecuted filing of, the LGIA) would have their
interconnection request deemed withdrawn and could be subject to
withdrawal penalties under certain circumstances, as discussed below.
596. We adopt the NOPR proposal to revise sections 3.4.2, 7.5 and
8.1 of the pro forma LGIP such that, after notifying the transmission
provider of any change to the interconnection customer's site control
demonstration, the transmission provider must give the interconnection
customer 10 business days to demonstrate satisfaction with the
applicable requirement. We find the adopted approach to require 90%
site control at the time of the interconnection request and 100% site
control at the time of the facilities study and when executing, or
requesting the unexecuted filing of, the LGIA appropriately balances
the concerns identified in the record. In particular, we find that it
will provide sufficiently stringent site control requirements to help
prevent interconnection customers from submitting interconnection
requests for speculative, commercially non-viable proposed generating
facilities, while accommodating development challenges faced by
interconnection customers that may otherwise present unjust and
unreasonable barriers to entering the interconnection queue. We believe
that this approach appropriately recognizes that issues often arise in
developing a generating facility, such that requiring a demonstration
of 90% site control at the time of the interconnection request, rather
than 100%, provides valuable flexibility for interconnection customers
with viable prospective generating facilities to resolve those issues
and continue through the interconnection process.
597. We are persuaded by commenters that contend that there are
significant benefits to allowing interconnection customers to enter the
cluster study process and potentially use the interconnection study
results to better understand their generating facility configuration
before obtaining 100% site control. We agree with commenters that
allowing less than 100% site control at the interconnection request
stage would provide interconnection customers flexibility to address
the results of interconnection studies or other regulatory processes
\1195\ and afford flexibility for interconnection customers that are
still actively negotiating with landowners close to the deadline for a
cluster request window.\1196\ Establishing a requirement for 90% site
control at the time of an interconnection request allows an
interconnection request to be submitted even if a few parcels of land
are still in negotiation or where a different site configuration arises
based on the scoping meeting with the transmission provider. Moreover,
the adopted approach provides flexibility for interconnection customers
to sign certain leases for particularly challenging parcels at a later
point in time, reducing the exposure to risk of expiration of those
leases.\1197\ Additionally, we agree with commenters that shifting the
100% site control requirement until the execution of a facilities study
agreement allows the interconnection customer to put less money at risk
for obtaining particularly challenging land rights and to obtain a more
meaningful understanding of what upgrade costs its generating facility
may be assigned, for instance, from the cluster study report that is
provided before the execution of the facilities study agreement.\1198\
---------------------------------------------------------------------------
\1195\ See CREA and NewSun Initial Comments at 55; SEIA Initial
Comments at 14-15.
\1196\ See Pine Gate Initial Comments at 23-24.
\1197\ Enel Initial Comments at 40.
\1198\ AEE Initial Comments at 18; Clean Energy Associations
Initial Comments at 31-32; CREA and NewSun Initial Comments at 55;
Cypress Creek Initial Comments at 22; SEIA Initial Comments at 15;
Shell Reply Comments at 23-24.
---------------------------------------------------------------------------
598. At the same time, we believe that the approach adopted in this
final rule, along with the other reforms adopted herein, is
sufficiently stringent to help prevent speculative, commercially non-
viable proposed generating facilities from entering and continuing
through the interconnection queue. As an initial matter, we establish a
more stringent requirement for site control at the time of submission
of an interconnection request than required by the pro forma LGIP prior
to this final rule. In particular, obtaining nearly all of the land
rights necessary to develop a proposed generating facility prior to
submitting the interconnection request entails a significant
commitment, both financial and in terms of the time and resources
required to negotiate with landowners. Moreover, the 100% site control
requirement at the time of the execution of the facilities study
agreement adds further stringency to ensure generating facilities that
proceed through the interconnection queue are the most likely to be
commercially viable.
599. We agree with commenters that requiring 100% site control at
the time of submission of an interconnection request may not be
compatible with the project development cycle,\1199\ which includes
stringent permitting requirements, and may disadvantage certain
interconnection customers despite there being a path to full site
control and commercial readiness.\1200\ Further, requiring 100% site
control at submission of the interconnection request would not allow
for minor revisions to the generating facility plan if, upon meeting
with the transmission provider at the scoping meeting, such revisions
would facilitate an improved generating facility design. This could
present a barrier to entry for interconnection customers with viable
proposed generating facilities.
---------------------------------------------------------------------------
\1199\ AEE Initial Comments at 17; CREA and NewSun Initial
Comments at 54; Clean Energy Associations Initial Comments at 31;
Cypress Creek Initial Comments at 22; EPSA Initial Comments at 8;
NextEra Initial Comments at 21; R Street Initial Comments at 8.
\1200\ AEE Initial Comments at 17.
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600. We decline to adopt commenters' suggestions that transmission
providers be allowed to confirm site control
[[Page 61101]]
throughout the interconnection process.\1201\ The adopted site control
requirements require site control demonstrations at three specific
points in the interconnection process--submission of the
interconnection request; at the time of execution of the facilities
study agreement; and when executing, or requesting the unexecuted
filing of, an LGIA. We find that these points are sufficient to help
prevent interconnection customers with commercially non-viable
interconnection requests from entering and proceeding through the
interconnection queue.
---------------------------------------------------------------------------
\1201\ See Indicated PJM TOs Initial Comments at 26; MISO
Initial Comments at 53.
---------------------------------------------------------------------------
601. With respect to eliminating the option for any interconnection
customer to submit a deposit in lieu of site control, except in limited
circumstances where an interconnection customer demonstrates a
regulatory limitation, we find that, because a deposit in lieu of site
control does not demonstrate that an interconnection customer has the
exclusive right to develop a site, it does not indicate that an
interconnection customer is ready to proceed with construction and
commercial operation of the generating facility. As a result, we
believe that allowing deposits in lieu of site control for all
interconnection customers, as requested by some commenters, would not
help to prevent speculative, commercially non-viable interconnection
requests from entering the interconnection queue. Thus, we decline to
include such an option in the pro forma LGIP.
602. We are persuaded by commenters that requiring transmission
providers to publicly maintain per MW acreage requirements for each
generating facility technology type is necessary to afford adequate
transparency and certainty to interconnection customers. At the same
time, we do not believe that such acreage requirements must be
contained within transmission providers' tariffs; rather, we find that,
consistent with the rule of reason, transmission providers may choose
to maintain acreage requirements in their business practice manuals or
may otherwise post them on a publicly accessible website. We find that
acreage requirements are properly classified as implementation details
that do not significantly affect rates, terms, and conditions of
service,\1202\ and we therefore do not require their inclusion in
tariffs. This is consistent with previous Commission orders approving
transmission providers' proposals to specify technology-specific
acreage requirements for site control in their business practice
manuals.\1203\ This will also afford transmission providers more
flexibility in updating acreage requirements to account for
technological advancements without being required to make FPA section
205 filings each time they seek to modify the acreage requirements. On
the other hand, to give the interconnection customer certainty, as
noted above, we clarify that the interconnection customer is required
to meet the technology-specific acreage requirement for its generating
facility publicly posted by the transmission provider at the time it
submits its interconnection request.
---------------------------------------------------------------------------
\1202\ See, e.g., N.Y. Indep. Sys. Operator, Inc., 179 FERC ]
61,102 at PP 105-114.
\1203\ See Midcontinent Indep. Sys. Operator, Inc., 169 FERC ]
61,173 at P 48 (finding MISO's proposal to place resource-specific
acreage requirements in its business practice manuals to be
appropriate because ``these requirements include technical
calculations that may require updates from time to time''); Sw.
Power Pool, Inc., 128 FERC ] 61,114 at P 48; PJM Interconnection,
L.L.C., 181 FERC ] 61,162 at P 102.
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603. To provide clarity for interconnection customers and
transmission providers, we modify the pro forma LGIP definition of
``Generating Facility'' to replace ``device'' with ``device(s)'' to
clarify that this definition includes hybrid generating
facilities.\1204\ We believe this clarification is necessary to ensure
that hybrid generating facilities have the same rights and
responsibilities as other types of generating facilities under the pro
forma LGIP and pro forma LGIA. In response to commenters and consistent
with the modified definition of ``Generating Facility,'' we clarify
that the transmission providers' per MW acreage requirements for each
generating facility technology-type must include specific requirements
for hybrid generating facilities. We also clarify that generating
facilities that are co-located on the same site and behind the same
point of interconnection are subject to the technology-specific acreage
requirements based on the generating facilities' technology-type.
---------------------------------------------------------------------------
\1204\ A hybrid generating facility is a generating facility
composed of more than one device of different technology types for
the production and/or storage for later injection of electricity
that are located on the same site and are operated and dispatched as
a single integrated generating facility.
---------------------------------------------------------------------------
604. In response to requests for clarification as to whether the
site control demonstration at the time of submission of the
interconnection request applies to interconnection facilities as well
as generating facilities, we clarify that the site control
demonstration requirements apply only to the land needed for the
generating facility. In the NOPR, the Commission did not propose site
control requirements for interconnection facilities.\1205\ Based on
this clarification, we decline to address comments suggesting
alternative site control requirements for interconnection facilities or
network upgrades.
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\1205\ Under the pro forma LGIP, interconnection facilities
shall mean the transmission provider's interconnection facilities
and the interconnection customer's interconnection facilities.
Collectively, interconnection facilities include all facilities and
equipment between the generating facility and the point of
interconnection, including any modification, additions or upgrades
that are necessary to physically and electrically interconnect the
generating facility to the transmission provider's transmission
system. Interconnection facilities are sole use facilities and shall
not include distribution upgrades, stand alone network upgrades or
network upgrades.
---------------------------------------------------------------------------
(c) Site Control Considerations for Interconnection Customers With
Regulatory Limitations
605. We adopt the NOPR proposal, with modification, to revise
section 3.4.2 of the pro forma LGIP to include a limited option for
interconnection customers to submit a deposit in lieu of site control
when they submit their interconnection request--only if qualifying
regulatory limitations prohibit the interconnection customer from
obtaining site control. We adopt the NOPR proposal to provide that
interconnection customers with regulatory limitations may submit an
initial deposit in lieu of site control of $10,000 per MW, subject to a
floor of $500,000 and a ceiling of $2 million. As discussed below, this
deposit shall be refundable but may not be applied toward
interconnection studies or withdrawal penalties, if applicable.
However, we decline to adopt the proposed requirement in the NOPR that
an interconnection customer facing regulatory limitations must
demonstrate 100% site control prior to the execution of a facilities
study agreement. Instead, we modify the proposed requirement for an
interconnection customer facing regulatory limitations to provide that
a deposit in lieu of site control will be accepted and held by the
transmission provider until the interconnection customer can
demonstrate 90% site control prior to execution of the facilities study
agreement or 100% site control at execution of the facilities study
agreement or thereafter. Additionally, we modify the NOPR proposal to
specify in Appendix B of the pro forma LGIA that interconnection
customers facing qualifying regulatory limitations must demonstrate
100% site control within 180 calendar days of the effective date of the
LGIA or the LGIA may be terminated per article 17
[[Page 61102]]
(Default) of the pro forma LGIA and the interconnection customer may be
subject to withdrawal penalties per new pro forma LGIP section 3.7.1.1
(Calculation of the Withdrawal Penalty).
606. We adopt the NOPR proposal to revise section 3.4.2 of the pro
forma LGIP to provide how interconnection customers may demonstrate
regulatory limitations. Specifically interconnection customers must
provide to the transmission provider: (1) a signed affidavit from an
officer of the company indicating that site control is unobtainable due
to regulatory limitations as such term is defined by the transmission
provider; and (2) documentation sufficiently describing and explaining
the source and effects of such regulatory limitations, including a
description of any conditions that must be met to satisfy the
regulatory limitations and the anticipated time by which the
interconnection customer expects to satisfy the regulatory
restrictions.
607. With respect to what qualifies as a regulatory limitation, we
require transmission providers to define regulatory limitations
relevant to their service territory, to publicly post the definition,
and to provide a narrative description of how they define regulatory
limitations as part of their compliance filings. While we decline to
require a uniform definition of regulatory limitations for all
transmission providers, we clarify that a regulatory limitation is
generally a Federal, state, Tribal, or local law that makes it
practically infeasible to obtain site control within the time frame
detailed in the pro forma LGIP. We allow transmission providers
flexibility on how to publicly post the definition, such as by
including it in business practice manuals or posting on a publicly
accessible website. We consider the definition of regulatory
limitations to be an implementation detail appropriately housed outside
of transmission providers' tariffs, consistent with the rule of reason.
We expect that the appropriate scope of regulatory limitations may vary
by region and is likely to need to be updated over time as relevant
Federal, state, Tribal, or local laws change. For these reasons, we do
not require transmission providers to include their definitions of
regulatory limitations in their tariffs.
608. We believe that these requirements will ensure a transparent,
consistent, and orderly process to facilitate demonstration of
regulatory limitations by interconnection customers and will establish
minimum requirements to provide transmission providers sufficient
information to evaluate such demonstrations. We agree with commenters
that transmission providers are best positioned to develop appropriate
definitions of regulatory limitations to address the specific
circumstances and unique regulatory limitations that interconnection
customers in their regions may face. We believe that this approach
preserves flexibility for transmission providers to account for
regional diversity.
609. As noted above, we decline to adopt the proposed requirement
in the NOPR that an interconnection customer facing regulatory
limitations must demonstrate 100% site control prior to commencement of
the facilities study. We agree with commenters that the requirement to
demonstrate site control at the facilities study stage could act as a
barrier for generating facilities faced with regulatory limitations in
demonstrating site control because the permitting process may still be
underway at the facilities study stage.\1206\ To account for these
barriers, we clarify that, in such circumstances, interconnection
customers are permitted to proceed through the interconnection process
and execute, or request the unexecuted filing of, an LGIA before
obtaining site control, by providing documentation that demonstrates
they are taking identifiable steps to secure the necessary regulatory
approvals from the applicable Federal, state, and/or Tribal entities,
as described above. Such interconnection customers must provide this
documentation at the time of execution of the facilities study
agreement and when executing, or requesting the unexecuted filing of,
the LGIA, or alternatively, demonstrate site control in accordance with
the requirements of the pro forma LGIP.
---------------------------------------------------------------------------
\1206\ See, e.g., NV Energy Initial Comments at 17.
---------------------------------------------------------------------------
610. We acknowledge that certain interconnection customers
developing generating facilities on sites owned or controlled by a
government entity, such as those who site generating facilities on BLM
lands, may not be able to demonstrate site control under the pro forma
LGIP definition even by the later stages of the interconnection process
because final permitting approval from BLM may not occur until after
the facilities study stage.\1207\ We believe the site control
requirements included in the pro forma LGIP strike an appropriate
balance between disincentivizing speculative interconnection requests
and accommodating interconnection customers facing extensive permitting
requirements by allowing such customers to submit a deposit in lieu of
site control where they demonstrate a qualifying regulatory limitation.
---------------------------------------------------------------------------
\1207\ See, e.g., id.
---------------------------------------------------------------------------
611. In response to commenters' concerns that, without
clarification, the regulatory limitations exception to the site control
requirement may be interpreted broadly to allow interconnection
customers to claim regulatory limitations when obtaining site control
is simply impractical or expensive, we reiterate that transmission
providers may exercise discretion when defining regulatory
limitations--generally a Federal, state, Tribal, or local law that
makes it practically infeasible to obtain site control within the time
frame detailed in the pro forma LGIP--as appropriate for
interconnection customers in their regions. We believe that allowing
flexibility in defining regulatory limitations will enable transmission
providers to account for any local, county, Tribal and state
regulations in their respective region that may delay an
interconnection customer's efforts to obtain site control.
612. With respect to the amount of the deposit in lieu of site
control for interconnection customers with regulatory limitations, we
find that the amounts that we adopt in this final rule will help
prevent speculative interconnection requests without placing an undue
burden on interconnection customers. We are not persuaded by commenters
that argue that the deposit amounts in lieu of site control for
interconnection customers with regulatory limitations need to be even
higher to deter interconnection requests that are not likely to achieve
site control, particularly when considered in conjunction with the
commercial readiness deposits and withdrawal penalties adopted in this
final rule, discussed below. We also find that deposits in lieu of site
control for interconnection customers with regulatory limitations
should be refundable, but may not be applied toward interconnection
studies or withdrawal penalties. We find that making these deposits in
lieu of site control for interconnection customers with regulatory
limitations non-refundable, as some commenters argue, may unduly burden
certain interconnection customers facing regulatory limitations where
certain regulatory constraints may be beyond their control.
c. Commercial Readiness
i. NOPR Proposal
613. In the NOPR, the Commission proposed to revise the pro forma
LGIP to include a commercial readiness
[[Page 61103]]
framework, which included commercial readiness demonstration options
and commercial readiness deposits.\1208\ The Commission explained that
such a framework would encourage interconnection customers that are not
ready to proceed to withdraw from the interconnection queue earlier in
the study process while also providing them the flexibility to enter
and remain in the interconnection queue without an off-take agreement;
reduce the number of times an interconnection customer executes and
suspends an LGIA for a speculative interconnection request, only to
later withdraw the request, leading to the shifting of network upgrade
costs to lower-queued interconnection customers; and reduce the strain
on transmission providers and enable viable interconnection requests to
progress more quickly through a less congested interconnection queue,
thereby remedying the unjust and unreasonable Commission-jurisdictional
rates discussed in section II of this final rule.
---------------------------------------------------------------------------
\1208\ NOPR, 179 FERC ] 61,194 at P 128.
---------------------------------------------------------------------------
614. Therefore, the Commission proposed to establish the defined
terms ``commercial readiness demonstration \1209\ and ``commercial
readiness deposit'' \1210\ in the pro forma LGIP.\1211\ The Commission
also proposed to add to sections 3.4.2, 7.5, and 8.1 of the pro forma
LGIP the following options as acceptable forms of commercial readiness
demonstration to enter into the cluster study and cluster restudy:
---------------------------------------------------------------------------
\1209\ The Commission proposed to revise section 1 of the pro
forma LGIP to provide that commercial readiness demonstration shall
have the meaning set forth in sections 3.4.2, 7.5, and 8.1 of the
pro forma LGIP. Id. P 129 n.204.
\1210\ The Commission proposed to revise section 1 of the pro
forma LGIP to provide that commercial readiness deposit shall mean a
deposit paid in lieu of submitting a commercial readiness
demonstration, as set forth in sections 3.4.2, 7.5, and 8.1 of the
pro forma LGIP. Id. P 129 n.205.
\1211\ Id. P 129.
---------------------------------------------------------------------------
An executed term sheet (or comparable evidence) related to
a contract, binding upon the parties to the contract, for sale of (1)
the constructed generating facility, (2) the generating facility's
energy or capacity, or (3) the generating facility's ancillary
services; where the term of sale is not less than five years;
Reasonable evidence that the generating facility has been
selected in a resource plan or resource solicitation process by or for
a load-serving entity (LSE), is being developed by an LSE, or is being
developed for purposes of a sale to a commercial, industrial, or other
large end-use customer; or
A provisional LGIA which has been filed at the Commission
(executed or unexecuted), which is not suspended and includes a
commitment to construct the generating facility.
615. The Commission also proposed to add to section 8.1 of the pro
forma LGIP the following options to serve as forms of commercial
readiness demonstration to enter the facilities study, to be provided
with the executed facilities study agreement:
An executed contract (as opposed to a term sheet), binding
upon the parties to the contract, for sale of (1) the constructed
generating facility, (2) the generating facility's energy or capacity,
or (3) the generating facility's ancillary services; where the term of
sale is not less than five years;
Reasonable evidence that the generating facility has been
selected in a resource plan or resource solicitation process by or for
an LSE, is being developed by an LSE, or is being developed for
purposes of a sale to a commercial, industrial, or other large end-use
customer; or
A provisional LGIA accepted for filing by the Commission,
which is not suspended, with reasonable evidence that the generating
facility and interconnection facilities have commenced design and
engineering.\1212\
---------------------------------------------------------------------------
\1212\ Id. P 130.
---------------------------------------------------------------------------
616. The Commission also proposed to require the interconnection
customer to inform the transmission provider of any material change to
its commercial readiness demonstration. The Commission proposed to
require the transmission provider to give the interconnection customer
10 business days to demonstrate satisfaction with the applicable
requirement after notification of a change to the interconnection
request's commercial readiness demonstration.\1213\ The Commission
explained that the interconnection customer would have the option to
submit a commercial readiness deposit within the 10-day cure period if
the change to the commercial readiness demonstration meant that the
interconnection request no longer satisfied the criteria.
---------------------------------------------------------------------------
\1213\ Id. P 131.
---------------------------------------------------------------------------
617. The Commission preliminarily concluded that this approach was
appropriate for all transmission providers and therefore proposed to
allow interconnection customers the option to submit a commercial
readiness deposit, in lieu of demonstrating commercial readiness
through the commercial readiness demonstration options required to
enter a cluster study, cluster restudy, and facilities study.\1214\ The
Commission noted that, outside of RTOs/ISOs, transmission providers may
be able to provide certain contractual arrangements to their own
generating facilities or other preferred interconnection customers,
such as the term sheet option noted above, which could lead to unduly
discriminatory behavior. The Commission stated that this deposit in
lieu of demonstrating commercial readiness may potentially prevent any
undue discrimination in the generator interconnection process,
consistent with the adoption of a standard set of procedures in the
first instance.\1215\
---------------------------------------------------------------------------
\1214\ Id. P 132.
\1215\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 1-2).
---------------------------------------------------------------------------
618. The Commission proposed to revise the pro forma LGIP to
include a framework to allow interconnection customers to provide a
commercial readiness deposit in lieu of meeting commercial readiness
requirements in the following amounts:
Two times the study deposit amount to enter the initial
cluster study phase;
Five times the study deposit amount after the initial
cluster study phase and before the system impact restudy phase; and
Seven times the study deposit amount after receipt of the
facilities study agreement.\1216\
---------------------------------------------------------------------------
\1216\ Id. P 133.
---------------------------------------------------------------------------
619. The Commission clarified that the proposed commercial
readiness deposit is separate from the study deposit.\1217\ The
Commission stated that the commercial readiness deposit would be
returned if the interconnection customer later makes a commercial
readiness demonstration. If the interconnection customer withdraws from
the interconnection queue, the Commission proposed that the commercial
readiness deposit would be applied toward any incurred withdrawal
penalties.
---------------------------------------------------------------------------
\1217\ Id. P 134.
---------------------------------------------------------------------------
620. Additionally, the Commission proposed revisions to the list of
development milestones in section 11.3 of the pro forma LGIP to clarify
the following:
A contract for the supply or transportation of fuel and a
contract for the supply of cooling water will not be accepted for wind,
storage, or solar photovoltaic resources;
Comparable evidence of a contract for the sale of energy
or capacity will be accepted; and
Any of the commercial readiness demonstration options
accepted to enter
[[Page 61104]]
the facilities study will be accepted along with the executed LGIA or
within 15 days of the Commission issuing an order on the unexecuted
LGIA filing, while a commercial readiness deposit will not be
accepted.\1218\
---------------------------------------------------------------------------
\1218\ Id. P 135.
---------------------------------------------------------------------------
621. The Commission preliminarily found that this framework would
allow interconnection customers to calculate the exact deposit that
would be required prior to entering the interconnection queue, as it is
based on multiples of the study deposit, and the study deposit is based
on the size of the proposed generating facility, as chosen by the
interconnection customer, leading to predictability in the deposit
amount.\1219\ The Commission explained that this increased transparency
in the deposit amount early in the interconnection process would
discourage speculative interconnection requests from entering the
interconnection queue.
---------------------------------------------------------------------------
\1219\ Id. P 136.
---------------------------------------------------------------------------
622. The Commission sought comment on whether the Commission should
also establish, as other alternative demonstrations of commercial
readiness, evidence of a commitment to participate in RTO/ISO markets,
a site-specific purchase order for generating equipment specific to the
interconnection request, or a statement signed by an officer or
authorized agent of the interconnection customer attesting that the
generating facility is to be supplied with major electric generating
components (such as wind turbines) with a manufacturer's blanket
purchase agreement to which the interconnection customer is a
party.\1220\
---------------------------------------------------------------------------
\1220\ Id. P 137.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
623. Several commenters support the commercial readiness framework
because they believe that it will reduce the submission of exploratory
or speculative interconnection requests.\1221\ These commenters argue
that requiring financial commitments and commercial readiness
requirements early in the interconnection process, as the Commission
proposed, is important to more efficiently allocate transmission
provider resources to generating facilities that are more likely to
achieve commercial operation and to enhance the certainty of
interconnection study results, benefiting all interconnection
customers. Pacific Northwest Utilities similarly assert that requiring
commercial readiness at an appropriate point in the cluster study
process minimizes the cost and inefficiency risk of restudies and
increases the probability that planned network upgrades will be funded
and constructed.\1222\ Navajo Utility also supports the Commission's
use of the commercial readiness requirements to discourage speculative
interconnection requests from slowing the interconnection
process.\1223\
---------------------------------------------------------------------------
\1221\ APPA-LPPC Reply Comments at 5; Avangrid Initial Comments
at 9; Consumer Energy Initial Comments at 5; EEI Initial Comments at
6-7; EEI Reply Comments at 5; NERC Initial Comments at 26; Google
Initial Comments at 20; Idaho Power Initial Comments at 7; MISO TOs
Initial Comments at 28-29; NARUC Initial Comments at 10; NESCOE
Initial Comments at 13; North Carolina Commission and Staff Initial
Comments at 26; Ohio Commission Consumer Advocate Initial Comments
at 12; Omaha Public Power Initial Comments at 9; Pacific Northwest
Utilities Initial Comments at 3, 6; Pennsylvania Commission Initial
Comments at 14; U.S. Chamber of Commerce Initial Comments at 9; UMPA
Initial Comments at 5; Xcel Reply Comments at 6-10.
\1222\ Pacific Northwest Utilities Initial Comments at 6.
\1223\ Navajo Utility Initial Comments at 10.
---------------------------------------------------------------------------
624. Navajo Utility explains that, as an LSE that constructs
generating facilities for the benefit of the Navajo Nation and to
export clean energy to surrounding LSEs, it specifically supports the
second criterion related to generating facilities developed by an
LSE.\1224\ NRECA contends that the proposed commercial readiness
demonstration requirements protect generating facilities that have been
committed to serve load from being hindered by interconnection requests
for generating facilities that are still looking for off-takers,
thereby helping reduce the pressure on transmission provider
interconnection queues.\1225\
---------------------------------------------------------------------------
\1224\ Id. at 10-11.
\1225\ NRECA Initial Comments at 29.
---------------------------------------------------------------------------
625. APPA-LPPC note that there may be power purchase agreements,
asset sales agreements and competitive procurement programs that
currently contemplate full knowledge of interconnection costs before
deals may be finalized.\1226\ However, APPA-LPPC argue that there is
nothing inevitable about the structure and sequencing of these
arrangements. APPA-LPPC state that, assuming the Commission moves ahead
with a commercial readiness requirement, it is not hard to envision
revisions to standard form power purchase agreements, asset sales
agreements, and bids into power procurement programs that are
contingent on specified assumptions regarding interconnection costs.
APPA-LPPC contend that with improvements in the availability of
interconnection costs, along with much-needed stability in the
interconnection queues, it is reasonable to expect that interconnection
costs will be substantially more predictable than is now the case.
---------------------------------------------------------------------------
\1226\ APPA-LPPC Reply Comments at 5.
---------------------------------------------------------------------------
626. SoCal Edison supports the proposals to require the
interconnection customer to notify the transmission provider of any
material change to its commercial readiness demonstration and to
require the transmission provider to give the interconnection customer
10 business days to cure the commercial readiness deficiency.\1227\
---------------------------------------------------------------------------
\1227\ SoCal Edison Initial Comments at 9.
---------------------------------------------------------------------------
(b) Comments in Opposition
627. Several commenters argue that the NOPR proposal is
inconsistent with prevailing commercial practices (especially those in
RTOs/ISOs), sets unreasonable standards for off-take agreements, and
ignores the commercial reality of the competitive solicitation process,
which could create an undue preference for self-build options in areas
that rely on competitive solicitations and undue discrimination against
merchant developers, thereby subverting competition in wholesale power
markets.\1228\ Some commenters contend that the proposed commercial
readiness demonstration options are heavily weighted in favor of
incumbent utility practices, such as evidence of a power purchase
agreement or executed term sheet or evidence that a project has been
selected in a resource plan or resource solicitation process by an
LSE.\1229\
---------------------------------------------------------------------------
\1228\ ACORE Reply Comments at 4; AEE Initial Comments at 20;
AEE Reply Comments at 12; Alliant Energy Initial Comments at 5-6;
Clean Energy Associations Initial Comments at 34-35; Clean Energy
Associations Reply Comments at 4-6; CREA and NewSun Initial Comments
at 57; CREA and NewSun Reply Comments at 22-45; Cypress Creek
Initial Comments at 22-23; Enel Initial Comments at 44; ENGIE
Initial Comments at 5; ENGIE Reply Comments at 2-3; EPSA Initial
Comments at 9; Fervo Energy Reply Comments at 6-7; New Jersey
Commission Reply Comments at 6-8; NextEra Initial Comments at 24;
Pine Gate Initial Comments at 27; NextEra Reply Comments at 14-16;
Public Interest Organizations Initial Comments at 29-30; R Street
Initial Comments at 13; SEIA Initial Comments at 25; Vistra Initial
Comments at 6.
\1229\ EPSA Initial Comments at 9; R Street Initial Comments at
13.
---------------------------------------------------------------------------
628. Enel argues that ratepayers and off-takers benefit from
generating facilities being selected in competitive processes that
consider both a generating facility's inherent characteristics and its
interconnection costs and schedule, which cannot be done if off-take
arrangements are made prior to applying for interconnection
service.\1230\ NextEra asserts that being part of the interconnection
queue is an essential step in the competitive
[[Page 61105]]
process,\1231\ and Public Interest Organizations note that utilities
conducting RFPs for their resource plans often require at least a
position in an interconnection queue as a precondition of
offering.\1232\ Cypress Creek argues that commercial readiness
demonstrations should not apply until an interconnection customer
receives the results from the proposed initial cluster study, which may
be required to bid into a resource solicitation.\1233\ Cypress Creek
contends that it is impractical to include the proposed demonstration
requirements at early stages in the interconnection study process and
that this construct is not workable in markets where merchant sales are
common.
---------------------------------------------------------------------------
\1230\ Enel Initial Comments at 44.
\1231\ NextEra Initial Comments at 24.
\1232\ Public Interest Organizations Initial Comments at 29.
\1233\ Cypress Creek Initial Comments at 22-23.
---------------------------------------------------------------------------
629. Enel, NextEra, and Public Interest Organizations argue that
precluding entry into the interconnection queue due to lack of a
demonstration of commercial readiness would be an anticompetitive
measure favoring entities, such as incumbent transmission providers,
that could favor their own proposed generating facilities ahead of
others because of their enhanced ability to demonstrate their proposed
generating facilities as commercially ready.\1234\ For instance, CREA
and NewSun assert that, unlike independent power producers, an
incumbent, vertically integrated utility can easily meet the second
prong of the readiness criteria to enter the interconnection queue and
proceed to the facilities study by simply identifying its preferred
resource in its own resource plan, selecting it as the winning bid in
its own utility-run RFP, or just attesting that the utility is
``developing'' the generating facility.\1235\
---------------------------------------------------------------------------
\1234\ Enel Initial Comments at 44; NextEra Initial Comments at
24; Public Interest Organizations Initial Comments at 29.
\1235\ CREA and NewSun Initial Comments at 66 (citing NOPR, 179
FERC ] 61,194 at PP 129, 130).
---------------------------------------------------------------------------
630. CREA and NewSun claim that the commercial readiness proposal
would drive most, if not all, independent power producers from the
market, which would raise costs to consumers by eliminating competition
and innovation.\1236\ SEIA asserts that by proposing a commercial
readiness demonstration framework that is nearly impossible for
independent power producers to meet, the Commission is incorrectly
implying that generating facilities developed by independent power
producers are inherently not commercially viable.\1237\ SEIA emphasizes
that independent power producers play a critical role in bringing
robust competition to markets by driving innovation and decreasing the
cost of providing power.\1238\
---------------------------------------------------------------------------
\1236\ Id. at 57.
\1237\ SEIA Initial Comments at 16, 25.
\1238\ Id. at 25.
---------------------------------------------------------------------------
631. Alliant Energy claims that requiring demonstration of
commercial readiness prior to an interconnection customer entering the
interconnection queue may do more harm than good.\1239\ Alliant Energy
argues that the commercial viability of a proposed generating facility
depends heavily on the costs of network upgrades and interconnection
facilities required to accommodate a generating facility's
interconnection, which cannot be known prior to a generating facility
receiving cost estimates that are dependable and enable interconnection
customers to make decisions during the interconnection process.
---------------------------------------------------------------------------
\1239\ Alliant Energy Initial Comments at 5-6.
---------------------------------------------------------------------------
632. Vistra argues that the proposed increase in study deposits,
withdrawal penalties, and exclusive site control requirements will
significantly reduce the number of speculative interconnection requests
entering the interconnection queue, making the commercial readiness
proposal redundant.\1240\ Vistra notes that the Commission has relied
on fact-specific showings to accept requirements to demonstrate
commercial readiness thus far, and Vistra argues that the fact that the
Commission has accepted a transmission provider's revised LGIP under
FPA section 205 does not establish that the pro forma LGIP is unjust
and unreasonable without the commercial readiness proposal.\1241\
---------------------------------------------------------------------------
\1240\ Vistra Initial Comments at 6.
\1241\ Id. at 6, 8.
---------------------------------------------------------------------------
633. Vistra states that, beyond simple timing concerns, procurement
decisions and eligibility to enter the interconnection queue are
interrelated in a way that creates a chicken-and-egg problem.\1242\
Vistra explains that it is difficult for a generating facility to be
shortlisted for procurement without line of sight to obtaining a signed
interconnection agreement because the signed interconnection agreement
brings more certainty to the generating facility's commercial operation
date. Vistra expresses concern that the Commission's proposal to
require an executed term sheet to enter the interconnection queue and
an executed contract to enter the facilities study process will simply
shift the burden of this chicken-and-egg problem to the procurement
process. Vistra asserts that the status quo appropriately balances the
inherent difficulty of coordinating procurement and interconnection.
---------------------------------------------------------------------------
\1242\ Id. at 9.
---------------------------------------------------------------------------
634. Invenergy argues that the proposed requirements are
inappropriate and should not be applied nationally because they are
based on a small subset of transmission providers that have adopted
``readiness'' requirements with little evidence that they are
effective, given the continuing interconnection queue reform efforts in
some of those same regions.\1243\ Invenergy adds that, if additional
assurance of an interconnection customer's intent to pursue its
interconnection request is needed, the Commission should consider a
requirement to post a certain amount of security that becomes
increasingly at risk to move through the interconnection queue, as is
done in some RTO/ISO regions.
---------------------------------------------------------------------------
\1243\ Invenergy Initial Comments at 11-12.
---------------------------------------------------------------------------
635. NextEra asserts that generating facilities may be fully viable
based on criteria that are different from what the NOPR proposes. For
example, NextEra states that it is possible that storage or other types
of generating facilities entering the market will not require power
purchase agreements or designation as network resources to be
commercially viable.\1244\
---------------------------------------------------------------------------
\1244\ NextEra Initial Comments at 24.
---------------------------------------------------------------------------
636. R Street argues that a key to efficient generating facility
development is to enable parallel work flows.\1245\ R Street claims
that, by imposing extensive prerequisites to advance in the
interconnection process, commercial readiness requirements would
introduce greater process dependencies in generating facility
development. R Street adds that granting non-RTO/ISO transmission
providers discretion over commercial readiness requirements could lead
to discriminatory behavior (e.g., non-RTO/ISO transmission providers
withholding off-take contracts to discriminate against other potential
suppliers).
---------------------------------------------------------------------------
\1245\ R Street Initial Comments at 13.
---------------------------------------------------------------------------
637. MISO states that it is concerned about the utility and impacts
of the proposed commercial readiness framework.\1246\ MISO explains
that interconnection customers with commitments from off-takers can be
commercially unready and often cause the greatest interconnection queue
disruption by lingering the longest in the queue. As an example, MISO
posits a proposed generating facility that would be commercially viable
provided it does not incur network upgrade costs
[[Page 61106]]
in excess of $5 million dollars. MISO argues that such a generating
facility is likely to remain in the interconnection queue despite not
having a viable business case, in the hopes that other interconnection
customers will withdraw their requests and costs will decrease. MISO
asserts that, to indicate commercial readiness, a term sheet or
contract would need to show not only that there was an off-taker but
also that the projected income for the proposed generating facility is
sufficient to render the generating facility commercially viable, given
estimated study and network upgrade costs, which would be exceedingly
difficult to require from interconnection customers and nearly
impossible for a transmission provider to evaluate and verify.
---------------------------------------------------------------------------
\1246\ MISO Initial Comments at 62-63.
---------------------------------------------------------------------------
638. Anbaric claims that the proposed core readiness requirements
do not align with the development trajectory of planned transmission
projects for offshore wind generation.\1247\
---------------------------------------------------------------------------
\1247\ Anbaric Initial Comments at 15-16.
---------------------------------------------------------------------------
639. NextEra asserts that commercial readiness requirements at the
interconnection request stage are inappropriate.\1248\ NextEra explains
that interconnection customers do not have a simple test for
distinguishing speculative interconnection requests from other
interconnection requests. Rather, NextEra continues, successful
generating facility development depends on whether the interconnection
customer concludes that the interconnection arrangement is acceptable
and whether the generating facility's location and costs are agreeable
to its customers.
---------------------------------------------------------------------------
\1248\ NextEra Initial Comments at 23-24.
---------------------------------------------------------------------------
640. NextEra also argues that meeting any readiness milestones
after the submission of an interconnection request (e.g., when entering
the facilities study phase) should be premised on the interconnection
customer having received timely and accurate study results, including
from affected systems.\1249\ NextEra asserts that it is not just and
reasonable to impose increasingly strict requirements on
interconnection customers without devising means of accelerating
interconnection queue processing by transmission providers and ensuring
transmission providers comply with their tariffs.
---------------------------------------------------------------------------
\1249\ Id. at 25.
---------------------------------------------------------------------------
641. Longroad recommends that the Commission clearly tie the
interconnection customer's commitment to pay for network upgrades to a
security deposit applied toward the costs thereof during the cluster
study phases, and that the security deposits for network upgrades
progressively increase at each stage of the cluster study
process.\1250\ Longroad asserts that in the initial cluster study, the
security deposit should be a modest percentage of the allocated network
upgrade cost and increase to, for example, 25% of the network upgrade
cost allocation to enter the facilities study. Longroad contends that
the interconnection customer should have the option to either fully
fund the network upgrade as a milestone in the LGIA or to fund in
advance the transmission provider's estimated quarterly spending
towards engineering, procurement, and construction of the network
upgrades.
---------------------------------------------------------------------------
\1250\ Longroad Reply Comments at 13.
---------------------------------------------------------------------------
(c) Comments on Specific Proposals
(1) Proposed Readiness Demonstrations
642. Commenters raise significant issues with the readiness
demonstration options proposed in the NOPR. With respect to the first
proposed readiness demonstration option,\1251\ commenters argue that
providing power purchase agreements or term sheets will be unworkable
for most interconnection customers, particularly merchant developers,
because: (1) developers do not have sufficient information about
interconnection costs to move forward with a term sheet or power
purchase agreement at the time they enter into the interconnection
study process; and (2) the proposals to make more information available
to interconnection customers prior to submitting an interconnection
request will not provide sufficiently granular or certain information
to overcome this barrier.\1252\
---------------------------------------------------------------------------
\1251\ Executed term sheet (or comparable evidence) related to a
contract for sale of (1) the constructed generating facility to a
load-serving entity or to a commercial, industrial, or other large
end-use customer, (2) the generating facility's energy or capacity
where the term of sale is not less than five (5) years, or (3) the
generating facility's ancillary services where the term of sale is
not less than five (5) years.
\1252\ AEE Initial Comments at 21; AES Clean Energy Initial
Comments at 16; CAISO Initial Comments at 18; CESA Initial Comments
at 10; CESA Reply Comments at 6; Clean Energy Associations Initial
Comments at 37; ClearPath Initial Comments at 8; CREA and NewSun
Initial Comments at 57-58; New Jersey Commission Reply Comments at
6-7; Enel Initial Comments at 42-43; Invenergy Initial Comments at
13-15; Invenergy Reply Comments at 1-5; Fervo Energy Initial
Comments at 5; Longroad Energy Reply Comments at 17; SEIA Initial
Comments at 17; SEIA Reply Comments at 7-9; Shell Reply Comments at
20-21; Longroad Energy Initial Comments at 15-16; Omaha Public Power
Initial Comments at 8-9; R Street Initial Comments at 13; Shell
Initial Comments 13-15; Vistra Initial Comments at 8, 10.
---------------------------------------------------------------------------
643. Commenters further note that the vast majority of power
purchasers seek generating facilities with advanced interconnection
queue positions (with preference for a finalized LGIA or SGIA) before
signing a power purchase agreement or finalizing a state
procurement.\1253\ CREA and NewSun, as well as SEIA, argue that a
contract for provision of ancillary services, is almost entirely
foreclosed to many non-synchronous generating facilities because nearly
every transmission provider bars non-synchronous generating facilities
from providing ancillary services, either explicitly or through
operating requirements.\1254\
---------------------------------------------------------------------------
\1253\ Invenergy Initial Comments at 13; Northwest and
Intermountain Initial Comments at 9; Public Interest Organizations
Initial Comments at 28.
\1254\ CREA and NewSun Initial Comments at 62; SEIA Initial
Comments at 17.
---------------------------------------------------------------------------
644. Commenters also assert that, if independent power producers
are forced to enter into contracts before costs are certain, then they
would need to incorporate that uncertainty into the power purchase
agreement offer, which would drive up the costs of these contracts,
resulting in higher consumer costs.\1255\ Commenters contend that, if
the independent power producer does not reflect the costs of the
network upgrades in its power purchase agreement price, either the
independent power producer or the consumer may attempt to break the
contract, which would lead to increased contractual litigation.\1256\
Vistra adds that the purchaser will then need to start the procurement
process over or choose to over-procure as insurance against potential
contract termination, to the detriment of reliability and cost.\1257\
---------------------------------------------------------------------------
\1255\ CREA and NewSun Initial Comments at 57; Clean Energy
Associations Initial Comments at 37; SEIA Initial Comments at 17;
SoCal Edison Initial Comments at 8; Vistra Initial Comments at 9-10.
\1256\ AEE Initial Comments at 21; Longroad Energy Initial
Comments at 15; SEIA Initial Comments at 17; Vistra Initial Comments
at 10.
\1257\ Vistra Initial Comments at 10.
---------------------------------------------------------------------------
645. SoCal Edison argues that, in some regions, an executed
contract option for entering the facilities study could unintentionally
encourage LSEs to sign contracts with developers for more energy or
capacity than they need to secure resources to meet their procurement
targets.\1258\ SoCal Edison contends that competition in certain areas
for particular generation resources may be high, which may force other
LSEs to prematurely enter into contracts with developers to secure
generation without the benefit of the facilities study, which is
currently relied on by LSEs to assess commercial viability of a
generating facility before contracts are signed. AEE asserts that
customers may ultimately bear the cost of the selection of generating
facilities that may not be the least cost options in the market but
[[Page 61107]]
are able to execute a term sheet or power purchase agreement regardless
of the ultimate level of interconnection costs.\1259\
---------------------------------------------------------------------------
\1258\ SoCal Edison Initial Comments at 7-8.
\1259\ AEE Initial Comments at 21.
---------------------------------------------------------------------------
646. Commenters also assert that it is unreasonable to expect that
a buyer and seller will be able to finalize negotiation of a contract
between the time of the cluster restudy (or amendment of the restudy if
additional interconnection customers withdraw upon receipt of the
restudy results) and the time the facilities study agreement must be
executed.\1260\
---------------------------------------------------------------------------
\1260\ CREA and NewSun Initial Comments at 62; Longroad Energy
Initial Comments at 16; SEIA Initial Comments at 17.
---------------------------------------------------------------------------
647. CAISO requests that the Commission describe in detail what
would constitute a term sheet.\1261\ CAISO states that in its
experience with similar tariff provisions, interconnection customers
frequently try to submit questionable or even misleading documentation
to meet the tariff requirements.
---------------------------------------------------------------------------
\1261\ CAISO Initial Comments at 20.
---------------------------------------------------------------------------
648. Invenergy argues that, to the extent an off-take agreement or
term sheet remains an option to demonstrate readiness, the Commission
should clarify that transmission providers are not entitled or even
permitted to review the commercial terms of the term sheet or
agreement, which may be confidential and is not subject to the
transmission provider's discretion.\1262\
---------------------------------------------------------------------------
\1262\ Invenergy Initial Comments at 18.
---------------------------------------------------------------------------
649. GSCE does not dispute that readiness requirements are
important but argues that basing them on contracting status is
misguided for the following reasons: (1) it does not focus on early-
stage developmental steps that drive generating facility viability and
indicate true commercial readiness; (2) it provides incentives for
interconnection customers that have not taken concrete steps toward
readiness to bid low in competitive solicitations, creating fictional
``contracted'' capacity that may never prove viable; (3) the
contracting landscape is evolving, and long-term contracting is no
longer required for successful project financing or the emerging
realities of capital markets, and with the inflationary environment,
long-term contracts may currently be harder to finance than short-term
contracts; and (4) a focus on contracting to enter the interconnection
study process forces commercial negotiations to occur before generating
facilities are studied and have sufficient cost certainty or
development timeline assurances.\1263\
---------------------------------------------------------------------------
\1263\ GSCE Initial Comments at 8-9.
---------------------------------------------------------------------------
650. Commenters also point to significant issues with the second
proposed readiness demonstration option.\1264\ They argue that
requiring evidence that a proposed generating facility is ``selected in
a resource plan or resource solicitation plan by or for [an LSE], is
being developed by [an LSE], or is being developed for purposes of a
sale to a commercial, industrial, or other a large end-use customer''
is discriminatory and preferential without cause or reasonable
support.\1265\
---------------------------------------------------------------------------
\1264\ Reasonable evidence that the generating facility has been
selected in a resource plan or resource solicitation process by or
for an LSE, is being developed by an LSE, or is being developed for
purposes of a sale to a commercial, industrial, or other large end-
use customer.
\1265\ AEE Initial Comments at 23; Clean Energy Associations
Initial Comments at 35; CREA and NewSun Initial Comments at 58-70;
EPSA Initial Comments at 9; Interwest Initial Comments at 19-20;
SEIA Initial Comments at 18; Shell Initial Comments at 16.
---------------------------------------------------------------------------
651. Several commenters argue that the option for interconnection
customers to demonstrate commercial readiness by showing that the
generating facility is being developed for purposes of a sale to an
end-use customer suffers a timing challenge because it is nearly
impossible for the independent power producer to price a sales contract
to a retail customer, or the customer having much interest in
discussing the transaction, without having reasonable certainty as to
the generating facility's likely interconnection costs.\1266\
---------------------------------------------------------------------------
\1266\ AEE Initial Comments at 22-23; CREA and NewSun Initial
Comments at 59; SEIA Initial Comments at 19-20; Shell Initial
Comments at 14; Vistra Initial Comments at 6.
---------------------------------------------------------------------------
652. SoCal Edison recommends that the Commission clarify or give
additional examples of reasonable evidence that a proposed generating
facility has been selected in an LSE's resource solicitation process or
allow a transmission provider to determine how this option can be
met.\1267\ SoCal Edison states that evidence that a proposed generating
facility has been short-listed in an LSE request for offer should be
considered reasonable evidence for moving into the facilities study.
---------------------------------------------------------------------------
\1267\ SoCal Edison Initial Comments at 8.
---------------------------------------------------------------------------
653. Several commenters argue that the third readiness
demonstration option, a provisional LGIA,\1268\ is likely unworkable as
well because it would require independent power producers to assume
almost all the risk of the network upgrade costs without knowing those
costs.\1269\ On the other hand, CAISO asserts that interconnection
customers could escape financial consequences and bypass the NOPR's
requirements through the provisional LGIA option.\1270\ CAISO argues
that, at a minimum, the Commission should allow transmission providers
to provide the provisional LGIA option where they believe it will work,
but not require all transmission providers to enable interconnection
customers to bypass commercial readiness through provisional LGIAs.
---------------------------------------------------------------------------
\1268\ A provisional LGIA that has been filed at the Commission
executed, or requested to be filed unexecuted, which is not in
suspension pursuant to article 5.16 of the LGIA, and includes a
commitment to construct the generating facility.
\1269\ AEE Initial Comments at 23-24; CREA and NewSun Initial
Comments at 59-63; SEIA Initial Comments at 20-23.
\1270\ CAISO Initial Comments at 20-21.
---------------------------------------------------------------------------
654. SoCal Edison and CAISO recommend that the Commission provide
additional guidance on, or more clearly define, the term ``provisional
LGIA.'' \1271\ CAISO also states that it is unclear how interconnection
customers that have yet to be studied could submit provisional LGIAs
because LGIAs describe the network upgrades and facilities from
interconnection studies.\1272\ CAISO states that interconnection
customers are likely to request provisional LGIAs because demonstrating
commercial readiness in RTOs/ISOs is generally impossible until after
studies are complete.
---------------------------------------------------------------------------
\1271\ SoCal Edison Initial Comments at 8; CAISO Initial
Comments at 20.
\1272\ CAISO Initial Comments at 20.
---------------------------------------------------------------------------
655. Commenters claim that the record does not support adopting the
proposed commercial readiness framework within RTOs/ISOs, arguing that
it would be unreasonable and unduly discriminatory.\1273\ These
commenters argue that the record in RTOs/ISOs does not support the
NOPR's assertion that generating facilities are generally not
constructed without some form of off-take agreement. They assert that
the commercial readiness criteria should not be required at all in RTO/
ISO regions (with locational marginal price-based markets), where
generating facilities can move forward in many cases without a specific
off-taker. Some commenters also argue that an RTO/ISO should not have
to evaluate contracts for the sale of a generating facility's output or
determine whether the generating facility has been selected in a
resource plan or resource solicitation process in
[[Page 61108]]
any of the potentially multiple states within its footprint.\1274\
---------------------------------------------------------------------------
\1273\ ACE-NY Initial Comments at 6-7; AEE Initial Comments at
22; AES Clean Energy Initial Comments at 16-17; CESA Initial
Comments at 9-10; Clean Energy Associations Initial Comments at 38;
PJM Initial Comments at 33-34; Public Interest Organizations Initial
Comments at 28-29; SEIA Initial Comments at 23-24.
\1274\ MISO Initial Comments at 63; MISO TOs Initial Comments at
29; PJM Initial Comments at 33.
---------------------------------------------------------------------------
656. Commenters argue that the proposed 10-business day cure period
to resolve potential commercial readiness deficiencies is insufficient
given the complicated business and technical decisions involved.\1275\
Invenergy states the interconnection process often extends for several
years and it is entirely possible that commercial arrangements may
change during that time.\1276\ Invenergy states that these changes may
require additional negotiations, but should not call into question the
customer's commitment to developing its project and risk being
withdrawn from the interconnection queue. [Oslash]rsted requests a 30-
business day cure period instead.\1277\
---------------------------------------------------------------------------
\1275\ Invenergy Initial Comments at 21; [Oslash]rsted Initial
Comments at 13.
\1276\ Invenergy Initial Comments at 21.
\1277\ [Oslash]rsted Initial Comments at 13.
---------------------------------------------------------------------------
(2) Alternative Commercial Readiness Demonstrations
657. Some commenters argue that the Commission should consider
expanding this list of proposed criteria to include other
demonstrations of commercial readiness, such as completion of
environmental, local, state, or Federal permitting processes.\1278\
CREA and NewSun, as well as Northwest and Intermountain, ask the
Commission to provide QFs a more relaxed readiness option than a fully
executed power purchase agreement, especially when a transmission
provider requires qualifying facilities to have a completed
interconnection study result to obtain a draft power purchase agreement
under its state Public Utility Regulatory Policies Act (PURPA)
implementation programs (e.g., PacifiCorp).\1279\ CREA and NewSun
suggest that the Commission could allow QFs to submit an affidavit from
the interconnection customer, stating that the avoided cost rates
offered are sufficient to finance and bring the QF into commercial
operation if interconnection can be obtained.\1280\ CREA and NewSun
contend that this option is consistent with the Commission's obligation
to adopt regulations that encourage development of QFs.
---------------------------------------------------------------------------
\1278\ ClearPath Initial Comments at 9; CREA and NewSun Initial
Comments at 71; Enel Initial Comments at 47; Longroad Energy Initial
Comments at 17; Northwest and Intermountain Initial Comments at 11;
Vistra Initial Comments at 11.
\1279\ CREA and NewSun Initial Comments at 72-73; Northwest and
Intermountain Initial Comments at 11.
\1280\ CREA and NewSun Initial Comments at 73.
---------------------------------------------------------------------------
658. Comments are mixed on the potential additional demonstrations
of commercial readiness on which the Commission requested comment in
the NOPR. Several commenters support the three potential other
readiness options suggested in the NOPR, or a combination
thereof.\1281\
---------------------------------------------------------------------------
\1281\ Id. at 70-71; APS Initial Comments at 15; NERC Initial
Comments at 26-27; ENGIE Initial Comments at 5-6; Clean Energy
Associations Initial Comments at 39; Invenergy Initial Comments at
16-17; NESCOE Initial Comments at 13; NextEra Initial Comments at
25; Pattern Energy Initial Comments at 31-32; R Street Initial
Comments at 13; SEIA Initial Comments at 25; Tri-State Initial
Comments at 15.
---------------------------------------------------------------------------
659. Other commenters oppose the various alternative demonstration
options. With regard to the first--evidence of a commitment to
participate in RTO/ISO markets--several commenters argue that the
proposal would be essentially meaningless because practically all
interconnection requests would qualify.\1282\
---------------------------------------------------------------------------
\1282\ Indicated PJM TOs Initial Comments at 31-32; PJM Initial
Comments at 34.
---------------------------------------------------------------------------
660. As for the second and third potential alternative
demonstration options--a site specific purchase order for generating
equipment specific to the interconnection request, or a statement
signed by an officer or authorized agent of the interconnection
customer attesting that the generating facility is to be supplied with
major electric generating components (such as wind turbines) with a
manufacturer's blanket purchase agreement to which the interconnection
customer is a party--PacifiCorp and Ameren oppose these options.\1283\
PacifiCorp argues that, although it originally adopted a similar
provision in its initial interconnection queue reform process, in the
course of administering its first two cluster studies, it determined
that this readiness option set a low hurdle that speculative
interconnection requests could easily overcome.\1284\ Similarly, SPP
does not support site-specific purchase orders or statements attesting
to supply of major components as evidence of commercial
readiness.\1285\ Enel asserts that it is inappropriate to require
procurement of major power equipment prior to an interconnection
request or, in many cases, even before executing an LGIA.\1286\ Enel
contends that requiring procurement of specific generating equipment
prior to applying for interconnection is detrimental to reliability
because newer technologies procured after the execution of an LGIA
often have advanced features that did not exist a few years earlier.
Enel explains that it procures major wind, solar, and battery
generation equipment between 12 and 24 months prior to energizing a new
generating facility to the transmission system, typically after
execution of an LGIA and a full investment review (including knowledge
of interconnection costs and schedules) are complete. Enel adds that a
generating facility without interconnection results carries too much
risk for interconnection customers and investors to risk significant
financial deposits to reserve site specific generation equipment.
Similarly, Xcel states that interconnection customers want the
flexibility to wait until the last minute to order equipment and start
construction, which results in different equipment being ordered than
initially expected.\1287\
---------------------------------------------------------------------------
\1283\ Ameren Initial Comments at 17; PacifiCorp Initial
Comments at 31.
\1284\ PacifiCorp Initial Comments at 31.
\1285\ SPP Initial Comments at 10.
\1286\ Enel Initial Comments at 46.
\1287\ Xcel Initial Comments at 33.
---------------------------------------------------------------------------
661. Some commenters argue that the proposed commercial readiness
requirements unduly discriminate against pumped storage projects, which
often do not have the commercial pathways and timelines associated with
other types of generating facilities.\1288\ Those commenters explain
that the development of a pumped storage project is an iterative
process of assessment and de-risking that takes several years to
complete, at a cost of tens of millions of dollars. They suggest that
achieving one of the following three criteria would be sufficient
evidence of commercial readiness for a pumped storage project: (1) a
filing of notice of intent to apply for an original license and pre-
application document with the Commission; (2) an executed memorandum of
understanding, letter of intent, or an equivalent term sheet with a
utility; or (3) selection of the project in an integrated resource plan
(IRP) process. They add that, in lieu of having achieved one of these,
a commercial readiness deposit of $2,000 per MW is appropriate. These
commenters ask the Commission to add the receipt of a Commission
license to the list of milestone developments in section 11.3 of the
pro forma LGIP.
---------------------------------------------------------------------------
\1288\ Hydropower Commenters Initial Comments at 9, 25-26; rPlus
Initial Comments at 4.
---------------------------------------------------------------------------
662. Commenters recommend several alternative bases to determine
commercial readiness, including: (1) a 50% generator tie line site
control requirement; \1289\ (2) a project development plan to determine
readiness; \1290\ (3) documentation of developer due diligence,
including
[[Page 61109]]
available transmission capacity and modeling; \1291\ (4) participating
in and meeting the eligibility requirements for a state-mandated
procurement program; \1292\ and (5) an executed firm point-to-point
transmission service agreement from the proposed point of
interconnection to a point of consumption for the generating facility's
output.\1293\
---------------------------------------------------------------------------
\1289\ Enel Initial Comments at 45.
\1290\ Xcel Initial Comments at 33.
\1291\ SEIA Initial Comments at 25.
\1292\ SoCal Edison Initial Comments at 8.
\1293\ Avangrid Initial Comments at 15.
---------------------------------------------------------------------------
663. To address the Commission's concerns while maintaining the
commercial viability of planned transmission projects for offshore
wind, Anbaric asks the Commission to consider requiring such projects
to make the following demonstrations to satisfy the commercial
readiness requirements: (1) site control of property near the point of
interconnection suitable for a converter station of a specified size
(expressed in MWs) needed to enable high voltage direct current (HVDC)
lines carrying offshore wind energy to be put onto the regional
transmission system; (2) site control of a property at a coastline
location suitable for the transition from seabed to terrestrial routes
sufficient to move the specified amount of MWs identified in
interconnection requests; and (3) a state procurement policy or goal to
procure a defined amount of offshore wind generation associated with a
planned transmission project within a defined time frame.\1294\
---------------------------------------------------------------------------
\1294\ Anbaric Initial Comments at 17-18.
---------------------------------------------------------------------------
664. Eversource supports the Commission's proposed commercial
readiness framework but asks the Commission to strengthen it by
requiring the interconnection customer to demonstrate project financing
(along with the current proposed requirements).\1295\ Eversource also
asks the Commission to require interconnection customers to provide a
preliminary project schedule that identifies all key milestones and
timelines.
---------------------------------------------------------------------------
\1295\ Eversource Initial Comments at 18.
---------------------------------------------------------------------------
665. Fervo Energy argues that, for cluster study and restudy
processes, the proposed framework should allow the interconnection
customer to demonstrate readiness by using a combination of options,
such as executed term sheets for a portion of the facility plus
deposits on a $/MW basis calculated from the quotient of the study
deposit amount and the proposed generating facility size.\1296\
---------------------------------------------------------------------------
\1296\ Fervo Energy Initial Comments at 4.
---------------------------------------------------------------------------
666. ENGIE and SEIA ask the Commission to make the commercial
readiness demonstration a requirement for entering into an LGIA.\1297\
ENGIE and SEIA assert that a later-stage commercial readiness
demonstration will allow independent power producers to make rational
business decisions based on reasonably certain network upgrade costs.
---------------------------------------------------------------------------
\1297\ ENGIE Initial Comments at 6; SEIA Initial Comments at 25.
---------------------------------------------------------------------------
(3) Deposit in Lieu of Readiness
667. Some commenters contend that the proposal to allow
interconnection customers to provide a deposit in lieu of demonstrating
commercial readiness does not cure the potential for undue
discrimination that results from retaining commercial readiness options
that are easily attained by incumbent, vertically integrated utilities
but infeasible for independent power producers.\1298\ These commenters
claim that, because it is nearly impossible for an independent power
producer to make any of the commercial readiness demonstrations
currently proposed, the deposit in lieu of meeting the commercial
readiness requirements would not be an ``option'' for independent power
producers but rather would be the only path forward in the
interconnection process.
---------------------------------------------------------------------------
\1298\ AEE Initial Comments at 24; Clean Energy Associations
Initial Comments at 38; NextEra Initial Comments at 24; SEIA Initial
Comments at 22-25; Vistra Initial Comments at 6-7.
---------------------------------------------------------------------------
668. Some commenters support the deposit in lieu of readiness
option, as proposed. For instance, SoCal Edison asserts that an
increased financial requirement via a deposit in lieu of demonstrating
commercial readiness should help to identify those interconnection
requests that are economically viable and to which the transmission
provider should focus its resources.\1299\ Northwest and Intermountain
state that providing interconnection customers with an option to
demonstrate commercial readiness through a deposit is essential to
ensuring a competitive market for generation by providing a way for
independent power producers to enter the interconnection queue.\1300\
MISO supports the concept of commercial readiness deposits, with the
first one due at the time of submission of an interconnection request,
which would then be forfeited if the interconnection request does not
result in an LGIA, and a second, higher deposit due at the time of
execution of an LGIA, to be refunded upon a generating facility
achieving commercial operation.\1301\ MISO also supports the
Commission's proposal to make these deposits separate from, and in
addition to, study deposits, as well as MISO's existing milestone
requirements in its interconnection study process. MISO believes that
these proposals could be a useful deterrent to speculative or unviable
interconnection requests entering into or lingering in MISO's
interconnection queue.
---------------------------------------------------------------------------
\1299\ SoCal Edison Initial Comments at 9.
\1300\ Northwest and Intermountain Initial Comments at 12.
\1301\ MISO Initial Comments at 60.
---------------------------------------------------------------------------
669. MISO TOs argue that, in keeping with the overall theme of
flexibility and respect for regional differences, the Commission should
afford transmission providers flexibility to adopt readiness
requirements and deposit amounts that are appropriate for their
regions.\1302\ MISO suggests deposits could consist of two components:
(1) a minimum amount per interconnection request, regardless of
proposed service levels, and (2) a per MW amount.\1303\ MISO asks that
the commercial readiness deposit increase the pool of money available
to offset cost shifts, and any additional monies be utilized to defray
the study costs of interconnection customers that actually reach
commercial operation.
---------------------------------------------------------------------------
\1302\ MISO TOs Initial Comments at 29.
\1303\ MISO Initial Comments at 61.
---------------------------------------------------------------------------
670. Some commenters argue that allowing deposits and security to
be posted in lieu of demonstrating commercial readiness may not be
sufficient to accomplish the NOPR's goals,\1304\ and may, in fact,
hinder the NOPR's goals.\1305\ APPA-LPPC assert that the financial
commitments proposed in the NOPR, while not insignificant, do not
reflect the potentially substantial cost of continuing to tolerate the
ongoing uncertainty.\1306\ APS claims that, in its experience,
speculative interconnection requests are well-funded but may not be
commercially viable.\1307\ Tri-State asserts that the fact that all 53
applicants in its 2022 interconnection queue elected to provide
additional financial security at phase 1 in its study process, instead
of one of three readiness milestones, demonstrates that deposits are
not effective at deterring unready interconnection requests from
entering the interconnection queue.\1308\
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\1304\ APS Initial Comments at 15; EEI Initial Comments at 7-8;
Idaho Power Initial Comments at 7; Omaha Public Power Initial
Comments at 8; Southern Initial Comments at 8.
\1305\ APPA-LPPC Initial Comments at 19; APS Initial Comments at
15; Omaha Public Power Initial Comments at 8; Southern Initial
Comments at 9-10.
\1306\ APPA-LPPC Initial Comments at 19.
\1307\ APS Initial Comments at 15.
\1308\ Tri-State Initial Comments at 15-16.
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671. Other commenters recommend changes to the Commission's
proposal.
[[Page 61110]]
For instance, North Dakota Commission recommends either removing the
deposits in lieu of demonstrating readiness or increasing readiness
deposit amounts to an amount that provides a quantifiable, evidence-
based reduction in speculative interconnection requests.\1309\
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\1309\ North Dakota Commission Initial Comments at 5.
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672. PacifiCorp states that its interconnection process also allows
an interconnection customer to make a payment of $3,000/MW in lieu of
meeting commercial readiness demonstration requirements.\1310\
PacifiCorp expresses concern that the NOPR proposal would reduce the
payment obligation (in comparison to what is required today under
PacifiCorp's LGIP), thus lowering the bar for more speculative
interconnection requests to enter the interconnection queue and
increasing risks for further study delays.
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\1310\ PacifiCorp Initial Comments at 30.
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673. CAISO contends that the Commission's proposed deposit
requirements are low, such that any modern interconnection customer
could meet them.\1311\ CAISO questions whether the deposit requirements
(or any deposit requirements) would deter uncompetitive interconnection
requests or reduce interconnection queue sizes. CAISO argues that using
arbitrary figures to set deposit requirements is unlikely to yield
meaningful results. CAISO urges the Commission to gather more data or
hold a technical conference to develop meaningful deposit amounts,
based on data provided by transmission providers.
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\1311\ CAISO Initial Comments at 19-20.
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674. EEI and NRECA suggest further reducing potential risks of
speculative interconnection requests by making deposits non-
refundable.\1312\ NRECA argues that the deposit in lieu of readiness
should only be refunded when the interconnection customer has provided
an appropriate commercial readiness demonstration or achieves
commercial operation, adding that allowing any other refund of this
deposit dilutes the effectiveness of this readiness requirement.\1313\
EEI and NYTOs assert that a deposit in lieu of readiness should only be
allowed in limited circumstances.\1314\
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\1312\ EEI Initial Comments at 8; NRECA Initial Comments at 9.
\1313\ NRECA Initial Comments at 29.
\1314\ EEI Initial Comments at 7; NYTOs Initial Comments at 20.
---------------------------------------------------------------------------
675. Commenters urge the Commission to decline to adopt a
commercial readiness standard that is tied to the status of an
interconnection customer's off-take arrangements and instead to adopt
an increasingly ``at-risk'' readiness deposit framework, similar to
what has been accepted in various RTOs/ISOs.\1315\ They contend that
more directly associating readiness deposits to the estimated costs and
likely impact to other interconnection customers if an interconnection
customer withdraws would provide greater accountability for
interconnection customers and transmission providers.\1316\
---------------------------------------------------------------------------
\1315\ AEE Initial Comments at 20, 24-25; AES Clean Energy
Initial Comments at 16-19; Clean Energy Associations Initial
Comments at 39; EPSA Initial Comments at 10; Indicated PJM TOs
Initial Comments at 30-31; Invenergy Initial Comments at 16; MISO
Initial Comments at 64-65; R Street Initial Comments at 13; Shell
Initial Comments at 15-16.
\1316\ AEE Initial Comments at 20, 24-25; AES Clean Energy
Initial Comments at 16- 19; Clean Energy Associations Initial
Comments at 39; EPSA Initial Comments at 10; Indicated PJM TOs
Initial Comments at 30-31; Invenergy Initial Comments at 16; MISO
Initial Comments at 64-65; R Street Initial Comments at 13; Shell
Initial Comments at 15-16.
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676. PJM and Omaha Public Power assert that the Commission should
consider basing the readiness deposit amount on an average cost of
network upgrades in the region determined during previous studies, as
this method would be based on a less arbitrary valuation than as
proposed.\1317\ SEIA urges the Commission to set the value of the
deposit amount as a percentage of the estimated network upgrade costs,
which should be capped at $2 million.\1318\ rPlus recommends a
commercial readiness deposit of $2,000/MW, noting that this figure is
common in industry practice.\1319\
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\1317\ Omaha Public Power Initial Comments at 8; PJM Initial
Comments at 35.
\1318\ SEIA Initial Comments at 25.
\1319\ rPlus Initial Comments at 4.
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677. Some commenters contend that the level of the proposed
readiness deposits is too high and should be significantly
revised.\1320\ Pattern Energy requests that the Commission clarify if
these deposits are additive or whether they would require an
interconnection customer to have available seven times the study
deposit amount by the time the interconnection request reaches the
facilities study phase. Pattern Energy states that if the payments are
additive, then the Commission would be requiring an interconnection
customer to have 14 times its initial study deposit on hand by the time
the interconnection customer reaches the LGIA milestone, which Pattern
Energy contends would be unreasonable.\1321\
---------------------------------------------------------------------------
\1320\ CREA and NewSun Initial Comments at 63; ACE-NY Initial
Comments at 7; Invenergy Initial Comments at 15-16.
\1321\ Pattern Energy Initial Comments at 31.
---------------------------------------------------------------------------
678. Invenergy argues that depositing as much as $3.5 million
before learning how much must be spent on network upgrades is not
reasonable.\1322\ ACE-NY argues that the deposit values for the second
cluster and beyond should be limited to just two times the study
deposit amount.\1323\ CREA and NewSun contend that the hefty deposits
will bar smaller companies with less access to capital from competing
and entering the interconnection study process.\1324\ CREA and NewSun
argue that the NOPR's deposit levels are purely arbitrary and appear
aimed at driving interconnection customers out of the interconnection
process rather than measurably improving the process.
---------------------------------------------------------------------------
\1322\ Invenergy Initial Comments at 15-16.
\1323\ ACE-NY Initial Comments at 7.
\1324\ CREA and NewSun Initial Comments at 65.
---------------------------------------------------------------------------
679. National Grid requests clarification that transmission
providers may deduct from a to-be-returned deposit any expenses
incurred by the transmission provider in administering the respective
escrow account.\1325\
---------------------------------------------------------------------------
\1325\ National Grid Initial Comments at 24-25.
---------------------------------------------------------------------------
680. Pattern Energy contends that the Commission must clarify that
deposits will be applied toward future security obligations if a
generating facility reduces its size as it progresses through the
interconnection process.\1326\ Pattern Energy states that if the size
of an interconnection request is reduced, in accordance with allowable
reduction amounts, then: (1) future deposits should be based on the new
generating facility size; and (2) previous deposits should be credited
toward future deposits based on the portion of those previous deposits
that are associated with the reduced MW quantity.
---------------------------------------------------------------------------
\1326\ Pattern Energy Initial Comments at 31.
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(d) Requests for Flexibility
681. Several commenters generally support the proposed commercial
readiness requirements but ask the Commission to provide flexibility to
allow transmission providers to determine the detailed readiness and
deposit criteria for their footprint.\1327\ These commenters argue that
such measures need to be carefully balanced to avoid overly burdening
interconnection customers with legitimate interconnection requests that
are delayed for reasons out of their control. For example, NY
Commission
[[Page 61111]]
and NYSERDA explain that, in New York, renewable energy certificates
procured by NYSERDA could demonstrate commercial readiness, and a
similar state agency certificate could be used in a different
state.\1328\
---------------------------------------------------------------------------
\1327\ Avangrid Initial Comments at 15; Dominion Initial
Comments at 25; Dominion Reply Comments at 10, 13-14; El Paso
Electric Initial Comments at 4; Invenergy Initial Comments at 12;
ISO-NE Initial Comments at 31; National Grid Initial Comments at 25;
NEPOOL Initial Comments at 14; NESCOE Reply Comments at 8; NY
Commission and NYSERDA Initial Comments at 8; NYISO Initial Comments
at 23; NYTOs Initial Comments at 20; Pacific Northwest Utilities
Initial Comments at 2-4.
\1328\ NY Commission and NYSERDA Initial Comments at 9.
---------------------------------------------------------------------------
682. Pacific Northwest Utilities claim that it would be difficult
for transmission providers to implement the commercial readiness
proposal in regions such as the Northwest without reforming RFP
processes and coordinating amongst multiple transmission owners and
LSEs.\1329\ Pacific Northwest Utilities explain that many generating
facilities in the Pacific Northwest use interconnection and
transmission services crossing multiple balancing authority areas,
which require coordination of timelines, milestones, and off-ramps in
both the RFPs and interconnection queues.
---------------------------------------------------------------------------
\1329\ Pacific Northwest Utilities Initial Comments at 4-5.
---------------------------------------------------------------------------
(e) Miscellaneous
683. Enel supports the proposed modification to pro forma LGIP
section 11.3 to require submission of the development milestones
concurrently with returning the executed LGIA so that the
interconnection customer cannot avoid the demonstration required by pro
forma LGIP section 11.3 by suspending its LGIA.\1330\ However, Enel
notes that it is important for the Commission to retain (and
reinstitute where removed by specific transmission providers) the
ability for interconnection customers to suspend work under their LGIAs
for up to three years.
---------------------------------------------------------------------------
\1330\ Enel Initial Comments at 45.
---------------------------------------------------------------------------
684. Arizona Commission generally supports the prioritization of
commercially ready projects and agrees with the proposed readiness
criteria, but also encourages the Commission to consider the
possibility of allowing market forces to provide discipline to the
interconnection process, such as by allowing transmission owners to
prioritize generation projects through the use of competitive
solicitations.\1331\
---------------------------------------------------------------------------
\1331\ Arizona Commission Initial Comments at 2.
---------------------------------------------------------------------------
685. The Colorado Commission generally supports prioritizing
commercially ready interconnection requests and agrees with the
proposed readiness criteria.\1332\ However, the Colorado Commission
emphasizes that the NOPR does not include a mechanism to prioritize
among the many viable, and competing, interconnection requests when
interconnection service capacity is scarce.\1333\ The Colorado
Commission argues that, under existing RTO/ISO interconnection
processes as well as the proposed revised pro forma LGIP, there is
limited ability in the interconnection process to consider the
generating facility's broader attributes from a system perspective,
including cost, timing, location, and resource type.\1334\ The Colorado
Commission asserts that new proposed generating facilities would likely
be stuck in cluster studies with no clear or timely prioritization that
ensures that the lowest cost or highest value generating facilities
come online quickly and at a reasonable cost. The Colorado Commission
contends that prioritizing native load and end-use customers and third-
party owned generating facilities through competitive bid processes is
the most logical criteria to maintain a reliable system at reasonable
cost.\1335\ To accomplish this, and help the system rationally move
forward in a timely manner, the Colorado Commission suggests adding the
following additional language to the commercial readiness section:
``RTOs and Transmission Providers shall have the ability to create a
separate cluster study process or other mechanisms to prioritize
executed contracts that serve and benefit native load in accordance
with local load-serving resources needs and priorities as determined
through equitable competitive bid processes.'' \1336\
---------------------------------------------------------------------------
\1332\ Colorado Commission Initial Comments at 1.
\1333\ Id. at 2.
\1334\ Id. at 7.
\1335\ Id. at 28.
\1336\ Id. The Colorado Commission also notes that some or all
of this proposed language may be more appropriate for section 4
(Queue Position) of the pro forma LGIP.
---------------------------------------------------------------------------
686. AEE, on the other hand, responds to the Colorado Commission by
arguing that allowing transmission providers to prioritize generating
facilities that are selected through IRP processes or utility
procurements and that benefit native load could allow vertically
integrated utilities to push preferred generating facilities through
the interconnection process and therefore comes with a risk of
discrimination.\1337\
---------------------------------------------------------------------------
\1337\ AEE Reply Comments at 16.
---------------------------------------------------------------------------
687. CESA argues that proposals to prioritize and favor certain
generating facilities and interconnection customers must be rejected as
violating the Commission's long-standing policies on open access and
non-discriminatory interconnection procedures.\1338\ CESA contends that
the Colorado Commission's proposal is therefore unduly discriminatory
and also goes well beyond what the Commission contemplated in the NOPR.
---------------------------------------------------------------------------
\1338\ CESA Reply Comments at 11.
---------------------------------------------------------------------------
688. Clean Energy Associations state that they support the
Commission's instead accepting regionally specific proposals that would
align the interconnection process with competitive procurements
associated with resource planning, rather than placing them at
odds.\1339\ Clean Energy Associations state that projects selected
though competitive procurement processes are ready projects, and these
processes attempt to consider the transmission (interconnection service
and transmission service) costs and the production-related costs. Clean
Energy Associations state that one way to accomplish this might be to
grant resource solicitation clusters a queue position distinct from
other clustered projects, but that concept could be extended to ensure
more certainty to the bidder and the resource planning entity of the
interconnection and delivery requirements and associated rights.
---------------------------------------------------------------------------
\1339\ Clean Energy Associations Initial Comments at 38.
---------------------------------------------------------------------------
689. Bonneville sees value in applying commercial readiness
requirements to the pro forma SGIP and SGIA and contends that failing
to do so could create a perverse incentive for interconnection
customers to break up large projects into smaller projects to avoid
stringent commercial readiness requirements under the pro forma
LGIP.\1340\
---------------------------------------------------------------------------
\1340\ Bonneville Initial Comments at 24-25.
---------------------------------------------------------------------------
iii. Commission Determination
690. We adopt a modified NOPR proposal to revise sections 3.4.2,
7.5, 8.1, and 11.3 of the pro forma LGIP, insofar as they require
interconnection customers to submit commercial readiness deposits, and
we do not adopt the NOPR proposal insofar as it included non-financial
commercial readiness demonstrations in the pro forma LGIP. To
effectuate the requirements that we adopt in this final rule, we modify
the proposed revisions to sections 3.4.2, 7.5, and 8.1 to remove the
proposed readiness demonstrations and to require that the
interconnection customer submit the commercial readiness deposit at the
beginning of each study in the cluster study process (i.e., the initial
cluster study, the cluster restudy, and the facilities study). For the
commercial readiness deposit submitted to enter the cluster restudy and
the commercial readiness deposit to enter the facilities study, we also
modify the NOPR proposal to move from commercial readiness deposits
based on study deposit amounts to commercial
[[Page 61112]]
readiness deposits based on percentages of the interconnection
customer's identified network upgrade costs. We also modify proposed
section 11.3 of the pro forma LGIP to remove the language providing
that one of the proposed readiness demonstrations can be provided when
the interconnection customer returns the executed LGIA or requests that
the LGIA be filed unexecuted. We also adopt the definition of
commercial readiness deposit but do not adopt the definition of
commercial readiness demonstration. We discuss each in turn.
691. We believe that, along with the other reforms adopted in this
final rule, the commercial readiness deposits we require will address
the need for reform underlying this section by helping reduce the
submission of speculative, commercially non-viable interconnection
requests into interconnection queues.\1341\ Further, because the
interconnection customer's total commercial readiness deposit held by
the transmission provider increases as the interconnection process
proceeds, we find that this approach will encourage interconnection
customers not ready to proceed through the interconnection process--or
whose projects become commercially non-viable during the
interconnection process--to withdraw earlier in the process, thereby
lessening the incidence of late-stage withdrawals that result in delays
and restudies. Similarly, by basing the cluster restudy and the
facilities study commercial readiness deposits on the interconnection
customer's identified network upgrade cost assignment, an
interconnection customer will be subject to the cost consequences of
its estimated network upgrades earlier. As a result, this approach will
encourage interconnection customers to withdraw earlier in the
interconnection process if they face large network upgrade initial cost
assignments or encounter other concerns that cause their
interconnection request to be uneconomic. By reducing the number of
speculative interconnection requests submitted into the interconnection
queue and the number of late-stage withdrawals of interconnection
requests, we believe that the commercial readiness deposit requirements
that we adopt herein will also enable commercially viable
interconnection requests to progress more quickly through the
interconnection process. Transmission providers will be able to focus
their resources on those interconnection requests most likely to
achieve commercial operation, to the benefit of all interconnection
customers.\1342\
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\1341\ SoCal Edison Initial Comments at 9, Northwest and
Intermountain Initial Comments at 12, MISO Initial Comments at 60,
PJM Initial Comments at 35.
\1342\ Alliant Energy Initial Comments at 6; Avangrid Initial
Comments at 9; Consumer Energy Initial Comments at 5; EEI Initial
Comments at 6-7; NERC Initial Comments at 26; Google Initial
Comments at 20; Idaho Power Initial Comments at 7; MISO TOs Initial
Comments at 28-29; NARUC Initial Comments at 10; NESCOE Initial
Comments at 13; North Carolina Commission and Staff Initial Comments
at 26; Ohio Commission Consumer Advocate Initial Comments at 12;
Omaha Public Power Initial Comments at 9; Pacific Northwest
Utilities Initial Comments at 3, 6; Pennsylvania Commission Initial
Comments at 14; U.S. Chamber of Commerce Initial Comments at 9; UMPA
Initial Comments at 5.
---------------------------------------------------------------------------
692. The commercial readiness deposit amounts proposed in the NOPR
are tied to generating facility size, as they are based on the initial
study deposit, which is likewise tied to generating facility size. We
adopt the NOPR proposal for the initial commercial readiness deposit,
where the interconnection customer pays a deposit of two times the
study deposit to enter the cluster study. Basing the initial commercial
readiness deposit on the size of the generating facility aligns the
size of the deposit roughly with any impact from a withdrawal of the
interconnection request, as generally, all else equal, increasing the
size of the generating facility increases the likelihood of larger,
more costly network upgrades and a greater change in interconnection
study inputs.
693. However, we are persuaded by several commenters that
commercial readiness deposits should be based on assigned network
upgrade costs.\1343\ Therefore, we modify the remaining commercial
readiness deposits (i.e., the second and third commercial readiness
deposits) such that, rather than relying on multiples of the initial
study deposit, once estimates of network upgrade costs are available,
the commercial readiness deposits equate to increasing percentages of
the interconnection customer's identified network upgrade cost
assignment. Specifically, we adopt a deposit structure where the
commercial readiness deposit to enter the cluster restudy is the amount
required to bring the total amount of the interconnection customer's
commercial readiness deposit to 5% of the interconnection customer's
network upgrade cost assignment identified in the cluster study, and
the commercial readiness deposit to enter the facilities study is the
amount required to bring the total amount of the interconnection
customer's commercial readiness deposit to 10% of the interconnection
customer's network upgrade cost assignment identified in the cluster
study or restudy, as applicable.\1344\ We find that tying the
commercial readiness deposits to the network upgrade cost estimate
requires the interconnection customer to deposit an amount that
corresponds to its network upgrade cost estimates earlier and, thereby,
can incentivize interconnection customers with large network upgrade
cost estimates to withdraw at earlier points in the interconnection
process to the extent the network upgrade cost assignment causes the
interconnection request to no longer be viable. This approach achieves
the Commission's goals of ensuring that interconnection customers are
able to interconnect in a reliable, efficient, transparent, and timely
manner.
---------------------------------------------------------------------------
\1343\ For assertions that more directly associating commercial
readiness deposits to the estimated costs and likely impact to other
interconnection customers in the case of withdrawal would provide
greater accountability for interconnection customers and
transmission providers, see AEE Initial Comments at 24-25; AES Clean
Energy Initial Comments at 16- 19; CAISO Initial Comments at 23-24;
Clean Energy Associations Initial Comments at 39; EPSA Initial
Comments at 10; Indicated PJM TOs Initial Comments at 30-31;
Invenergy Initial Comments at 16; MISO Initial Comments at 64-65; R
Street Initial Comments at 13; Shell Initial Comments at 15-16.
\1344\ See SEIA Initial Comments at 25 (urging the Commission to
set the value of the commercial readiness deposit as a percentage of
the estimated network upgrade costs).
---------------------------------------------------------------------------
694. We decline to adopt the non-financial commercial readiness
demonstrations proposed in the NOPR. We find that the non-financial
commercial readiness demonstrations are not necessary to address the
subject of these reforms--providing additional deterrence of
speculative, commercially non-viable interconnection requests--given
the significant, increasing commercial readiness deposits we adopt
instead.\1345\
---------------------------------------------------------------------------
\1345\ See N.Y. v. FERC, 535 U.S. 1, 27 (2002) (declining to
require reforms where ``FERC determined that the remedy it ordered
constituted a sufficient response to the problems FERC had
identified'').
---------------------------------------------------------------------------
695. We are also persuaded by commenters who express concerns that
the non-financial commercial readiness demonstrations in the NOPR
proposal may not necessarily serve as appropriate indicators of a
proposed generating facility's commercial viability on a national
basis. In some instances, the proposed non-financial commercial
readiness demonstrations may be unavailable to interconnection
customers with commercially viable projects. For example, this may be
true as a result of a misalignment of the timing between resource
procurement
[[Page 61113]]
decisions and interconnection study processes or inconsistency with a
relevant local commercial practice, rather than because the proposed
generating facilities lack commercial viability.
696. As commenters note, resource procurement efforts across the
country all have different timelines, and the timeline to demonstrate
commercial readiness proposed in the NOPR was not tailored to meet the
timelines of multiple state procurement efforts.\1346\ As commenters
explain, an interconnection queue position is often a precondition of
offering into a resource solicitation.\1347\ We agree that, absent a
regionally tailored tariff process pursuant to which commercial
readiness criteria could be aligned with applicable resource
solicitation processes, the commercial readiness criteria proposed in
the NOPR may not be workable in markets where merchant sales are
common, and this generally applicable final rule is not an appropriate
forum to dictate regionally tailored solutions.
---------------------------------------------------------------------------
\1346\ AEE Initial Comments at 21; SoCal Edison Initial Comments
at 7-8; Vistra Initial Comments 6-10.
\1347\ See Cypress Creek Initial Comments at 22-23; NextEra
Initial Comments at 24; Public Interest Organizations Initial
Comments at 29.
---------------------------------------------------------------------------
697. We are further concerned that there may be trade-offs entailed
in requiring the proposed non-financial commercial readiness
demonstrations, which are more appropriately assessed on a regional,
rather than national basis. We agree with Enel that ratepayers may
benefit from generating facilities being selected in competitive
processes that consider the facilities' interconnection costs and
schedule, which cannot be done if off-take arrangements are made prior
to applying for interconnection service.
698. In addition, we are concerned that the proposed non-financial
commercial readiness demonstrations could incentivize power purchasers
in some regions to execute purchase contracts with interconnection
customers whose generating facilities will later be determined to be
commercially non-viable. As commenters note, this could lead to
purchasers having to start the procurement process over or choose to
over-procure as insurance against potential contract termination, to
the detriment of reliability and cost.
699. Therefore, we are persuaded to adopt a framework that requires
a commercial readiness deposit for all interconnection customers,
similar to what the Commission has accepted in various RTO/ISO
regions.\1348\ We find that requiring deposits in amounts substantial
enough to demonstrate commitment to reaching commercial operation at
progressive milestones throughout the interconnection process will be a
sufficient deterrent to speculative behavior--especially when
considered as part of the comprehensive package of reform, including
increased site control requirements, increased study deposits, and
withdrawal penalties, established by this final rule.
---------------------------------------------------------------------------
\1348\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 158
FERC ] 61,003 (2017); Sw. Power Pool, Inc., 178 FERC ] 61,015
(2022).
---------------------------------------------------------------------------
700. In the NOPR, the Commission acknowledged the potential that
certain non-financial commercial readiness demonstrations could provide
an unduly discriminatory or preferential advantage to projects being
developed by transmission providers or their affiliates.\1349\ As
summarized above, several commenters have raised--and elaborated on--
those concerns. Because we find that the commercial readiness deposits
that we adopt in this final rule are sufficient to address the relevant
need for reform, and therefore do not adopt the proposed non-financial
commercial readiness demonstrations, we need not further address those
concerns in this final rule.
---------------------------------------------------------------------------
\1349\ NOPR, 179 FERC ] 61,194 at P 132.
---------------------------------------------------------------------------
701. We recognize that the Commission has previously accepted
proposals that include commercial readiness demonstration requirements
similar to those proposed in the NOPR. Although we find that commercial
readiness deposits are sufficient to address the need for reform in
this proceeding, this finding does not preclude transmission providers
from adopting non-financial commercial readiness demonstrations,
provided they meet the relevant standards when requesting a variation,
as discussed above.
702. Some commenters suggest that the Commission could add
government and environmental permits as commercial readiness
demonstrations as an indicator of commercial readiness that is viable
both for independent power producers and for transmission providers and
their affiliates.\1350\ Although the record provides some support for
this, we are concerned that permits and studies may expire due to the
length of the interconnection process, and those re-permitting and
restudy efforts are still at risk of rejection or failure, which could
lead to late-stage withdrawals.\1351\ We are also concerned about the
possible administrative burden placed on transmission providers, as
they must determine which types of permits should be accepted as
commercial readiness demonstrations and evaluate the validity of
different permits submitted by interconnection customers.
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\1350\ ClearPath Initial Comments at 9; CREA and NewSun Initial
Comments at 71; Enel Initial Comments at 47; Longroad Energy Initial
Comments at 17; Northwest and Intermountain Initial Comments at 11;
Vistra Initial Comments at 11.
\1351\ Enel Initial Comments at 47.
---------------------------------------------------------------------------
703. Pattern Energy requests that the Commission clarify whether
the commercial readiness deposits are additive, meaning that, as each
phase of the interconnection process is reached, the full amount of
each new readiness deposit must be added on top of the full amounts of
earlier readiness deposits (as opposed to merely increasing the total
amount of the aggregate readiness deposit to match the level specified
for that phase). In response, we clarify that, as modified, the
commercial readiness deposits in sections 7.5 and 8.1 of the pro forma
LGIP make clear that for the second and third commercial readiness
deposits, the interconnection customer is only required to submit an
additional deposit that brings the total commercial readiness deposit
to the amount specified in sections 7.5 and 8.1 of the pro forma LGIP
(5% of the interconnection customer's identified network upgrade cost
estimate and 10% of the interconnection customer's identified network
upgrade cost estimate, respectively).
704. In response to comments on the magnitude of commercial
readiness deposits (e.g., too high or too low), we reiterate that the
commercial readiness deposits are part of a package of reforms meant to
deter speculative behavior that also includes site control requirements
and withdrawal penalties. Thus, the commercial readiness deposits are
not intended to be of such magnitude to alone prevent speculative
behavior as they are intended to work together with other reforms
adopted in this final rule, such as site control and withdrawal
penalties. We believe that the deposits should not be so high that
viable projects from smaller developers are unable to enter the queue.
At the same time, they will only achieve the aims if they are
sufficiently high to serve as some deterrent, in concert with the other
relevant reforms adopted in this final rule. In response to National
Grid's request that the final rule provide for the deduction from a to-
be-returned deposit of any expenses incurred by the transmission
provider or RTO/ISO in administering the respective escrow account, we
note that Order No. 2003
[[Page 61114]]
required the collection of various deposits without addressing this
type of administrative expense.\1352\ We find, in this instance, that
there is no need to deviate from Order No. 2003, and we decline to
adopt tariff revisions to address the management of an escrow account.
---------------------------------------------------------------------------
\1352\ Order No. 2003, 104 FERC ] 61,103 at PP 91-92, 100, 101,
218-219.
---------------------------------------------------------------------------
705. In response to Pattern Energy's request for clarification of
the commercial readiness deposit amounts in the event that an
interconnection customer reduces the size of a proposed generating
facility, we clarify that because the modified commercial readiness
deposit structure is based on network upgrade cost estimates, a size
reduction to a proposed generating facility may or may not impact the
remaining commercial readiness deposits, depending on whether the size
reduction reduces the interconnection customer's assigned network
upgrade costs. This is consistent with the requirements for entering
the cluster restudy and facilities study adopted in pro forma LGIP
sections 7.5 and 8.1, respectively, which require commercial readiness
deposits based on percentages of the interconnection customer's
identified network upgrade costs.
706. Pattern Energy's request to require that previous deposits be
credited towards future deposits based on the portion of those previous
deposits that are associated with the reduced MW quantity therefore
represents the modified commercial readiness deposit framework we
adopt. Under this modified framework, an interconnection customer's
previous commercial readiness deposits are effectively credited when it
pays later commercial readiness deposits (i.e., the second and third
commercial readiness deposits); it pays the required amount of a
commercial readiness deposit less the amounts paid for through earlier
commercial readiness deposits.
707. We also decline to adopt Bonneville's suggestion to add the
commercial readiness provisions to the SGIP because the record does not
demonstrate a need for such reform at this time. Because we are not
adopting the proposed non-financial commercial readiness
demonstrations, we do not address comments proposing revisions or
clarifications to those demonstrations. Additionally, several
commenters provide additional suggestions for the NOPR proposal,
including: (1) addressing the Commission's rules for suspending an
LGIA; \1353\ (2) addressing queue priority; \1354\ and (3) better
supporting competitive procurement processes.\1355\ We find these
comments to be outside the scope of the NOPR.
---------------------------------------------------------------------------
\1353\ Clean Energy Associations Initial Comments at 38; PPL
Initial Comments at 10.
\1354\ Arizona Commission Initial Comments at 2; Colorado
Commission Initial Comments at 1-2.
\1355\ Clean Energy Associations Initial Comments at 38;
Colorado Commission Initial Comments at 1-2, 7, 28.
---------------------------------------------------------------------------
d. LGIA Deposit
i. NOPR Proposal
708. In the NOPR, the Commission proposed to require
interconnection customers to submit a deposit equal to nine times the
amount of its study deposit when executing the LGIA or requesting the
filing of an unexecuted LGIA. The Commission explained that this
deposit would be fully refunded once the generating facility achieves
commercial operation, but if the interconnection customer withdraws
after executing the LGIA or after requesting the filing of an
unexecuted LGIA, this deposit would be refunded subject to the
withdrawal penalty.\1356\ The Commission also sought comment on whether
to adopt additional provisions or a different framework that would
require larger proposed generating facilities to provide a higher
deposit amount--such as a per MW framework.\1357\
---------------------------------------------------------------------------
\1356\ NOPR, 179 FERC ] 61,194 at P 108.
\1357\ Id. P 110.
---------------------------------------------------------------------------
ii. Comments
709. MISO supports the proposal to require interconnection
customers to submit a deposit equal to nine times the amount of its
study deposit at LGIA execution because MISO believes it is necessary
to continue the commercial readiness deposit and withdrawal penalty
framework until the interconnection request achieves commercial
operation.\1358\ Shell supports the security deposit obligations used
in MISO's and SPP's generator interconnection processes, which include
a deposit at LGIA execution.\1359\
---------------------------------------------------------------------------
\1358\ MISO Initial Comments at 51.
\1359\ Shell Initial Comments at 19.
---------------------------------------------------------------------------
710. Invenergy argues that requiring more security at LGIA
execution, in addition to the other proposed burdens on interconnection
customers in the NOPR, goes beyond the goal of disincentivizing
speculative interconnection requests to creating potentially
prohibitive burdens on all interconnection customers, including those
with commercially viable proposed generating facilities.\1360\
Invenergy contends that, while a deposit based on study costs may make
sense in earlier stages of the study process when assigned network
upgrade costs are not yet known, it is not appropriate after an LGIA is
executed and assigned network upgrade costs are known and memorialized.
ACE-NY and AES oppose any additional deposits due from an
interconnection customer at the signing of the LGIA that are not tied
to network upgrade costs.\1361\ AES asserts that in many RTOs/ISOs,
interconnection customers have to post security for a portion, if not
all, of the assigned network upgrade costs associated with an
interconnection request, and such posted security is a sufficient
incentive to keep an interconnection customer engaged so that they will
complete a generating facility after the LGIA is executed.\1362\
---------------------------------------------------------------------------
\1360\ Invenergy Initial Comments at 6.
\1361\ ACE-NY Initial Comments at 5; AES Initial Comments at 14.
\1362\ AES Initial Comments at 14.
---------------------------------------------------------------------------
711. Several commenters argue that the Commission's LGIA deposit
proposal is excessive and potentially exposes ratepayers to unjust and
unreasonable costs.\1363\ [Oslash]rsted would support a lower amount,
such as two times the study deposit, because it believes that the
current proposal would not necessarily accurately estimate the costs of
required network upgrades.\1364\ PJM contends that the Commission
should allow transmission providers to adopt security amounts and
structures that are rationally related to relevant costs.\1365\ Cypress
Creek asks the Commission to provide a non-arbitrary basis for its
proposed security deposit of nine times the study deposit.\1366\ Shell
argues that the LGIA deposit appears to be a security deposit and adds
that MISO and SPP use a separate security deposit obligation that the
Commission should consider.\1367\
---------------------------------------------------------------------------
\1363\ Id.; Clean Energy Associations Initial Comments at 30;
ENGIE Initial Comments at 4; [Oslash]rsted Initial Comments at 9;
PJM Initial Comments at 24; Shell Reply Comments at 22.
\1364\ [Oslash]rsted Initial Comments at 9.
\1365\ PJM Initial Comments at 24.
\1366\ Cypress Creek Initial Comments at 53.
\1367\ Shell Initial Comments at 19.
---------------------------------------------------------------------------
712. Several commenters argue that study deposits should be
refunded in certain circumstances.\1368\ Invenergy argues that any
deposit due at LGIA execution should be subject to a $2 million cap and
that deposit should be released dollar for dollar as the
interconnection customer posts security or makes required payments
under the LGIA.\1369\ Invenergy asks that the
[[Page 61115]]
Commission also clarify that, in the event a proposed generating
facility does not achieve commercial operation, any deposit forfeited
under this proposal offsets, and is not in addition to, any withdrawal
penalties that may be imposed. Invenergy adds that it is unreasonable
to require that additional deposits be provided when an interconnection
customer asks that the LGIA be filed unexecuted, and if the Commission
does nonetheless require interconnection customers to post the deposit
as a condition of having the LGIA filed unexecuted, the deposit should
be refundable if the interconnection customer elects to withdraw within
30 days of the date of the Commission's order in the applicable docket.
[Oslash]rsted and Shell assert that, for interconnection customers
withdrawing after executing the LGIA, all deposits should be refunded
in the event that the interconnection customer withdraws as a result of
circumstances outside of its control and the withdrawal does not harm
any other entity.\1370\ AES argues that all study deposits should be
refunded at the time of LGIA execution, and opposes any additional
deposits not tied to network upgrade costs.\1371\
---------------------------------------------------------------------------
\1368\ AES Initial Comments at 14; Invenergy Initial Comments at
7; [Oslash]rsted Initial Comments at 10; Shell Reply Comments at 23.
\1369\ Invenergy Initial Comments at 7-8.
\1370\ [Oslash]rsted Initial Comments at 10; Shell Reply
Comments at 23.
\1371\ AES Initial Comments at 14.
---------------------------------------------------------------------------
713. Southern, on the other hand, argues that making deposits
refundable may not be stringent enough and therefore may not accomplish
the goals set forth in the NOPR.\1372\ NRECA also believes that the
Commission should consider whether to make these study deposits non-
refundable in the case of withdrawal, as a further disincentive for
speculative interconnection requests to enter the interconnection
queue.\1373\
---------------------------------------------------------------------------
\1372\ Southern Initial Comments at 8-9.
\1373\ NRECA Initial Comments at 26.
---------------------------------------------------------------------------
iii. Commission Determination
714. We adopt, with modification, the NOPR proposal to revise new
section 11.3 of the pro forma LGIP to require interconnection customers
to submit a deposit when executing the LGIA, or requesting the filing
of an unexecuted LGIA,and add the new term ``LGIA deposit'' to section
1 of the pro forma LGIP.\1374\ Specifically, we modify the NOPR
proposal to require interconnection customers to provide a deposit that
will increase the total commercial readiness deposit paid to be equal
to 20% of the estimated network upgrade costs identified in the LGIA,
rather than providing a deposit equal to nine times the amount of the
interconnection customer's study deposit, as proposed in the
NOPR.\1375\ Additionally, revised section 11.3 of the pro forma LGIP
requires that interconnection customers submit the LGIA deposit when
returning the executed LGIA to the transmission provider, or within 10
business days of the interconnection customer requesting that the LGIA
be filed unexecuted at the Commission.
---------------------------------------------------------------------------
\1374\ LGIA deposit shall ``mean the deposit Interconnection
Customer submits when returning the executed LGIA, or within 10
Business Days of the LGIA being filed unexecuted at the Commission,
in accordance with Section 11.3 of this LGIP.''
\1375\ At LGIA execution or at the time the request is made to
file the unexecuted LGIA, the interconnection customer must deposit
the difference between its total commercial readiness deposits
submitted at that point and 20% of its estimated network upgrade
cost responsibility.
---------------------------------------------------------------------------
715. In the NOPR, the Commission sought comment on whether to adopt
additional provisions or a different framework for deposits, including
the LGIA deposit.\1376\ In response, commenters provided suggestions,
including suggestions to base deposits on network upgrade costs.\1377\
We agree that tying the LGIA deposit to the network upgrade cost
estimate sends a more accurate cost signal to the interconnection
customer and better aligns the LGIA deposit to its function of ensuring
that network upgrades are paid for and constructed than the NOPR
proposal. We also agree with commenters that a deposit based on the
study deposit amount may make sense in the early stage of the cluster
study process when assigned network upgrade costs are not yet
estimated, but later in the process, when network upgrade cost
estimates are available, the use of percentages of network upgrade cost
estimates more closely indicates interconnection request
viability.\1378\ This approach also addresses comments that the LGIA
deposit, as proposed, may have been arbitrary, excessive, and
unreasonable.\1379\
---------------------------------------------------------------------------
\1376\ NOPR, 179 FERC ] 61,194 at P 110.
\1377\ See, e.g., Longroad Reply Comments at 13; PJM Initial
Comments at 24.
\1378\ ACE-NY Initial Comments at 5; AES Initial Comments at 14;
Invenergy Initial Comments at 6.
\1379\ AES Initial Comments at 14; Clean Energy Associations
Initial Comments at 30; ENGIE Initial Comments at 4; [Oslash]rsted
Initial Comments at 9; PJM Initial Comments at 24; Shell Reply
Comments at 22.
---------------------------------------------------------------------------
716. The NOPR proposed that this deposit would be fully refunded
once the generating facility achieves commercial operation, but we are
modifying the NOPR proposal to remove that statement from pro forma
LGIP section 11.3, and as explained further below, this deposit will be
used as part of the security the interconnection customer must provide
for the construction of network upgrades and transmission provider's
interconnection facilities. However, this LGIA deposit could be
refunded, subject to the withdrawal penalty, if the interconnection
customer withdraws after executing the LGIA or after requesting the
filing of an unexecuted LGIA.
717. We also revise the pro forma LGIP and pro forma LGIA, as
suggested by Invenergy,\1380\ to treat the LGIA deposit as part of the
security the interconnection customer must provide for the construction
of network upgrades and transmission provider's interconnection
facilities. Article 11.5 (Provision of Security) of the pro forma LGIA
requires that, 30 calendar days prior to the commencement of
construction under its LGIA, the interconnection customer must provide
security for a discrete portion of network upgrades and transmission
provider's interconnection facilities, as specified in its LGIA. We
revise section 11.3 of the pro forma LGIP and article 11.5 of the pro
forma LGIA to require the transmission provider to use the LGIA
deposit, in its entirety, before requiring the interconnection customer
to submit additional security for construction of network upgrades and
transmission provider's interconnection facilities. By allowing the
transmission provider to draw down this LGIA deposit as construction
proceeds, the construction of network upgrades and transmission
provider's interconnection facilities can commence quickly thereby
streamlining the interconnection process. With this revision, requiring
the LGIA deposit to be returned at commercial operation is now
unnecessary as there will be no deposit remaining to return; therefore,
we decline to adopt the NOPR proposal to do so.\1381\
---------------------------------------------------------------------------
\1380\ Invenergy Initial Comments at 7.
\1381\ NOPR, 179 FERC ] 61,194 at P 108.
---------------------------------------------------------------------------
718. We also revise article 11.5 of the pro forma LGIA to require
transmission providers to draft Appendix B (Milestones) of the
interconnection customer's LGIA to clearly explain and estimate at
which point of construction the interconnection customer's LGIA deposit
will be depleted, and the interconnection customer must provide
additional financial security. In the event the interconnection
customer requests suspension of the LGIA under article 5.16 of its LGIA
prior to the commencement of construction, the transmission provider is
prohibited from using the LGIA deposit to commence construction until
the
[[Page 61116]]
interconnection customer requests to exit suspension and resume
construction, unless there is a need for the transmission provider to
use a portion of the LGIA deposit to ensure its system is left in a
reliable condition during the period of suspension.
719. We do not adopt the suggestion of [Oslash]rsted and Shell
that, for interconnection customers withdrawing their interconnection
requests after executing an LGIA, all deposits should be refunded if
withdrawal is the result of circumstances outside the interconnection
customer's control and the withdrawal does not harm other
entities.\1382\ We believe that the exceptions to the application of
withdrawal penalties discussed in the section III.A.6.e below
appropriately balance the need to deter withdrawals with the reality
that withdrawal is not always due to circumstances within
interconnection customers' control.
---------------------------------------------------------------------------
\1382\ See [Oslash]rsted Initial Comments at 10; Shell Reply
Comments at 23.
---------------------------------------------------------------------------
720. In response to Southern's comments that making both study and
LGIA deposits refundable may not be stringent enough and therefore may
not disincentivize speculative interconnection requests,\1383\ we
reiterate that, as adopted, the deposits serve different functions. In
this instance, the LGIA deposit serves as a credit towards the security
the interconnection customer must provide for network upgrades and
transmission provider's interconnection facilities. To the extent the
LGIA deposit pays for the construction of network upgrades, such a
deposit would be refunded through transmission credits in regions that
follow the pro forma LGIA provisions on crediting.
---------------------------------------------------------------------------
\1383\ Southern Initial Comments at 8-9.
---------------------------------------------------------------------------
e. Withdrawal Penalties
i. NOPR Proposal
721. The Commission preliminarily found that withdrawal penalties
are needed to account for the harms that can occur when interconnection
customers withdraw from the interconnection queue.\1384\ The Commission
proposed to revise the pro forma LGIP to require transmission providers
to assess withdrawal penalties to interconnection customers in certain
circumstances. Specifically, the Commission proposed to revise the pro
forma LGIP to require transmission providers to assess withdrawal
penalties to interconnection customers that choose to withdraw at any
point in the interconnection process or do not otherwise reach
commercial operation, unless: (1) the withdrawal does not delay the
timing of other proposed generating facilities in the same cluster; (2)
the withdrawal does not increase the cost of network upgrades for other
proposed generating facilities in the same cluster; (3) the
interconnection customer withdraws after receiving the most recent
cluster study report and the costs assigned to the interconnection
customer have increased 25% compared to the previous cluster study
report; or (4) the interconnection customer withdraws after receiving
the individual facilities study report and the costs assigned to the
interconnection customer have increased by more than 100% compared to
costs identified in the cluster study report.\1385\ Thus, the
Commission proposed that interconnection customers would be exempt from
a withdrawal penalty if the withdrawal does not harm other
interconnection customers or if the withdrawal follows a significant
unanticipated increase in network upgrade cost estimates.
---------------------------------------------------------------------------
\1384\ NOPR, 179 FERC ] 61,194 at P 140.
\1385\ Id. P 141.
---------------------------------------------------------------------------
722. The Commission proposed that the withdrawal penalty would
increase as the interconnection customer moves through the study
process and would also increase if an interconnection customer provides
a commercial readiness deposit in lieu of a demonstration of commercial
readiness.\1386\ For an interconnection customer that provides a
commercial readiness deposit in lieu of a demonstration of commercial
readiness, the Commission proposed that its withdrawal penalty would be
higher and increase as the interconnection customer progresses in the
interconnection process.
---------------------------------------------------------------------------
\1386\ Id. P 142 (citing May Joint Task Force Tr. 75:23-76:1
(Kimberly Duffley) (``I think one of the best practices of the new
system that [Duke Energy Progress and Duke Energy Carolinas] have
implemented is the increase of withdrawal penalties as the
interconnection moves through the process.'')).
---------------------------------------------------------------------------
723. The Commission proposed that the withdrawal penalty for an
interconnection customer that provides a commercial readiness deposit
in lieu of a demonstration of commercial readiness will be the greater
of the study deposit or: (1) two times the study cost if the customer
withdraws during the cluster study or after receipt of a cluster study
report, capped at $1 million; (2) three times the study cost if the
customer withdraws during the cluster restudy or after receipt of any
applicable restudy reports, capped at $1.5 million; (3) five times the
study cost if the customer withdraws during the facilities study, after
receipt of the individual facilities study report, or after receipt of
the draft LGIA, capped at $2 million; or (4) nine times the study costs
if the customer withdraws before achieving commercial operation and
after executing the LGIA or filing an unexecuted LGIA.\1387\ The
Commission also proposed that the withdrawal penalty revenues be used
to fund studies conducted under the cluster study process.
---------------------------------------------------------------------------
\1387\ Id. P 143.
---------------------------------------------------------------------------
724. The table below summarizes the proposed withdrawal penalty
structure for both interconnection requests that have demonstrated
commercial readiness and those that have not (by instead submitting a
deposit in lieu of demonstrating commercial readiness).\1388\
---------------------------------------------------------------------------
\1388\ Id. P 144.
----------------------------------------------------------------------------------------------------------------
Total withdrawal
Phase of withdrawal Commercial readiness penalty (if greater Withdrawal penalty cap
demonstration provided? than study deposit)
----------------------------------------------------------------------------------------------------------------
1.................................... Yes.................... 1 times study costs.... No Cap.
2.................................... Yes.................... 1 times study costs.... No Cap.
3.................................... Yes.................... 1 times study costs.... No Cap.
LGIA................................. Yes.................... 9 times study costs.... No Cap.
1.................................... No..................... 2 times study costs.... $1 million.
2.................................... No..................... 3 times study costs.... $1.5 million.
3.................................... No..................... 5 times study costs.... $2 million.
LGIA................................. No..................... 9 times study costs.... No Cap.
----------------------------------------------------------------------------------------------------------------
[[Page 61117]]
725. The Commission also proposed to add the defined term
``withdrawal penalty'' to the pro forma LGIP.\1389\ The Commission
sought comment on: (1) how to define the circumstances in which a
withdrawal is deemed to have delayed the timing or increased the cost
of network upgrades for other proposed generating facilities in the
same cluster, including what criteria should be used to determine
whether the withdrawal caused the delay or increased cost, and whether
to establish a threshold for when a delay or increase in cost will
trigger a withdrawal penalty (and if so, what that threshold should
be); (2) whether the Commission should consider exceptions to the
proposed withdrawal penalties beyond those proposed in the NOPR; (3)
whether withdrawal penalties that increase with proposed generating
facility size (as measured by MW) would more effectively deter
withdrawals that cause the greatest harm; and (4) whether a correlation
exists between the size of a withdrawing proposed generating facility
and the relative level of harm (in terms of delays and increased cost)
to other interconnection customers as a result of the withdrawal.\1390\
---------------------------------------------------------------------------
\1389\ Id. P 145.
\1390\ Id. PP 145-148.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
726. Multiple commenters generally support the Commission's
proposed withdrawal penalties and view the proposal as appropriate to
reduce the volume of speculative interconnection requests.\1391\
Environmental Defense Fund states that, if adopted with certain of the
other NOPR proposals, the Commission's proposed withdrawal penalties
are appropriate to address the delays and costs caused by speculative
interconnection requests.\1392\ Eversource states that properly
calibrated withdrawal penalties are essential to dissuade withdrawals
and reduce study process delays.\1393\
---------------------------------------------------------------------------
\1391\ ACE-NY Initial Comments at 7; Ameren Initial Comments at
18; APPA-LPPC Initial Comments at 17-18; APS Initial Comments at 15;
CAISO Initial Comments at 21; Consumers Energy Initial Comments at
5; Dominion Initial Comments at 33; MISO Initial Comments at 66;
NARUC Initial Comments at 10; National Grid Initial Comments at 26;
NextEra Initial Comments at 6; NRECA Initial Comments at 9; NV
Energy Initial Comments at 6; NYTOs Initial Comments at 20-21; Omaha
Public Power Initial Comments at 9; PPL Initial Comments at 17;
SoCal Edison Initial Comments at 10; U.S. Chamber of Commerce
Initial Comments at 9; UMPA Initial Comments at 3-5; Vistra Initial
Comments at 6-7.
\1392\ Environmental Defense Fund Initial Comments at 4.
\1393\ Eversource Initial Comments at 18.
---------------------------------------------------------------------------
727. MISO supports the Commission's proposal to impose a withdrawal
penalty on withdrawing interconnection customers, a penalty that MISO
suggests should be secured by the commercial readiness deposit.\1394\
That said, MISO asserts that the study cost for interconnection
requests is not that substantial, and MISO does not believe that paying
a withdrawal penalty in the amount of only the study costs would be a
sufficient deterrent to prevent speculative interconnection requests
from entering or remaining in the interconnection queue.
---------------------------------------------------------------------------
\1394\ MISO Initial Comments at 66-67.
---------------------------------------------------------------------------
(b) Comments in Opposition
728. Many commenters oppose the withdrawal penalty proposal.\1395\
CREA and NewSun encourage instead better cost certainty for
interconnection customers earlier in the study process.\1396\ CREA and
NewSun suggest that the Commission incorrectly assumes that the
interconnection customer has adequate visibility into likely
interconnection costs, and thus the financial viability of its proposed
generating facility before entering the interconnection queue and
becoming liable for these penalties. CREA and NewSun state that the
NOPR provides no realistic path to know likely interconnection costs
prior to entering the interconnection queue.\1397\
---------------------------------------------------------------------------
\1395\ CREA and NewSun Initial Comments at 74-77; ENGIE Initial
Comments at 6; Hydropower Commenters Initial Comments at 26;
Interwest Initial Comments at 21; Northwest and Intermountain
Initial Comments at 12; New York State Department Initial Comments
at 11; Pacific Northwest Organizations Initial Comments at 3-4;
rPlus Initial Comments at 5; R Street Initial Comments at 12; SEIA
Initial Comments at 25-27; SEIA Reply Comments at 10-11; Shell
Initial Comments at 25.
\1396\ CREA and NewSun Initial Comments at 74, 77.
\1397\ Id. at 76.
---------------------------------------------------------------------------
729. ENGIE does not support the implementation of withdrawal
penalties and notes that withdrawal penalties without meaningful
opportunity for interconnection customers to exit the interconnection
process are unlikely to incentivize withdrawal.\1398\ New York State
Department is skeptical that a withdrawal penalty program will be
beneficial to ratepayers.\1399\
---------------------------------------------------------------------------
\1398\ ENGIE Initial Comments at 6.
\1399\ New York State Department Initial Comments at 11.
---------------------------------------------------------------------------
730. Pacific Northwest Organizations claim that, without access to
interconnection cost information and with larger withdrawal penalties,
independent power producers may be discouraged from entering the
interconnection queue.\1400\ Some commenters claim that withdrawal
penalties (including in a transitional cluster study process) can
result in the potential for discrimination against independent power
producers.\1401\ These commenters assert that LSEs can recover
withdrawal penalties they incur from their retail ratepayers, whereas
independent power producers must absorb these costs and risks in their
solicitation process bids. Interwest also suggests that the proposed
withdrawal penalties are less likely to apply to LSEs than to
independent power producers because LSEs will likely be able to use the
proposed commercial readiness demonstration path, as opposed to paying
the deposits in lieu of demonstrating commercial readiness, and would
thus not be subject to the harsher withdrawal penalties.\1402\
Interwest urges the Commission to require waiver of, or a substantial
reduction in, withdrawal penalties from the transition cluster or
resource solicitation cluster if the interconnection customer
participated in an RFP or other competitive solicitation process but
was not ultimately selected, or if a permit becomes unavailable due to
some regulatory or regime change.\1403\
---------------------------------------------------------------------------
\1400\ Pacific Northwest Organizations Initial Comments at 3-4.
\1401\ Interwest Initial Comments at 21; Northwest and
Intermountain Initial Comments at 12.
\1402\ Interwest Reply Comments at 13-14.
\1403\ Interwest Initial Comments at 21.
---------------------------------------------------------------------------
731. R Street claims that the proposal risks imposing severe anti-
competitive barriers to entry.\1404\ New York State Department makes
similar anti-competitive impact arguments.\1405\ R Street asserts that
imposing financial commitments and readiness requirements can create
regulatory barriers to entry if they deter interconnection requests for
commercially viable generating facilities or increase financing
costs.\1406\ R Street argues that the proposal is misguided because it
would add another administrative process that increases implementation
complications and costs.\1407\ R Street suggests that the Commission
should instead use a simple loss of deposit as its financial lever.
---------------------------------------------------------------------------
\1404\ R Street Initial Comments at 12.
\1405\ New York State Department Initial Comments at 11.
\1406\ R Street Initial Comments at 12.
\1407\ Id. at 14.
---------------------------------------------------------------------------
732. rPlus argues that withdrawal penalties, particularly when
coupled with the proposed study deposit requirements and study cost
allocations, are unduly discriminatory or punitive to
[[Page 61118]]
pumped storage as compared to other renewable technologies.\1408\ rPlus
and Hydropower Commenters claim that, under these proposals, a large
capacity pumped storage project (ranging from 400 MW to over 1,000 MW
in size, according to rPlus) would expect to hit the maximum deposit
and/or penalty in every stage of the interconnection process.\1409\
rPlus claims that the high cost of entry and the liability associated
with withdrawal may give large utilities an unfair advantage in
commercial negotiations.\1410\
---------------------------------------------------------------------------
\1408\ rPlus Initial Comments at 5.
\1409\ Id.; Hydropower Commenters Initial Comments at 26.
\1410\ rPlus Initial Comments at 5.
---------------------------------------------------------------------------
733. Shell calls for a reconsideration of the withdrawal penalties
proposed in the NOPR, claiming that the proposal could disrupt project
development when paired with the proposed commercial readiness
requirements and financial commitments (for deposits and site
control).\1411\ Shell suggests that the Commission adopt withdrawal
penalties modeled on MISO's framework, which encourages interconnection
customers to withdraw from the interconnection queue with refunded
deposits rather than penalizing interconnection customers for making
justifiable decisions. Shell contends that there should only be a large
penalty for late-stage withdrawals.\1412\ Shell contends that,
otherwise, the Commission is sending the wrong signal and driving out
competition without linking the underlying issue of unexpected network
upgrade costs that typically come from affected system studies that are
provided very late in the study process.
---------------------------------------------------------------------------
\1411\ Shell Initial Comments at 9, 24; Shell Reply Comments at
26.
\1412\ Shell Initial Comments at 25.
---------------------------------------------------------------------------
734. Some commenters contend that increasing the amount of money at
stake for an interconnection customer without providing off-ramps from
the interconnection process at reasonable decision points where
previously unavailable information is supplied does not necessarily
incentivize interconnection customers to exit the interconnection
queue.\1413\ CREA and NewSun suggest that the proposed withdrawal
penalties may incentivize an interconnection customer to remain in the
interconnection queue waiting for other interconnection customers to
withdraw, and the penalty those interconnection customers pay will
eventually be distributed to the remaining interconnection customers in
the cluster, or interconnection customers may elect to remain in the
interconnection queue in the hopes that others in the cluster withdraw
to the point where the cost of network upgrades become more
palatable.\1414\
---------------------------------------------------------------------------
\1413\ CREA and NewSun Initial Comments at 76; SEIA Initial
Comments at 25-27; SEIA Reply Comments at 10-11.
\1414\ CREA and NewSun Initial Comments at 76.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
(1) Withdrawal Penalty Amounts
735. Several commenters oppose the proposed withdrawal penalty
amounts.\1415\ AEE argues that the Commission's proposed withdrawal
penalty amounts are overly punitive, especially for those
interconnection customers that submit a deposit in lieu of
demonstrating commercial readiness, which many interconnection
customers will be forced to do under the Commission's proposed
commercial readiness requirements.\1416\ AEE and Clean Energy
Associations assert that the Commission's proposed withdrawal penalty
amounts also appear arbitrary, with no basis in the costs of conducting
studies or other relevant factors.\1417\ AEE argues that the Commission
should reduce these amounts and tie them more closely to its objectives
and to the study costs that transmission providers are expected to
incur, which it asserts will avoid turning the penalties into a
punitive measure that provides a profit opportunity for transmission
providers.\1418\ AEE contends that the withdrawal penalty frameworks
and time frames should be designed to discipline the decisions of
interconnection customers rather than being punitive. Google does not
support the proposal to impose higher withdrawal penalties on
interconnection customers that submit a deposit in lieu of
demonstrating commercial readiness.\1419\
---------------------------------------------------------------------------
\1415\ AEE Initial Comments at 19; CREA and NewSun Initial
Comments at 75; Interwest Initial Comments at 22.
\1416\ AEE Initial Comments at 19.
\1417\ Id.; Clean Energy Associations Initial Comments at 41.
\1418\ AEE Initial Comments at 19-20.
\1419\ Google Initial Comments at 21.
---------------------------------------------------------------------------
736. Interwest argues that some of the proposed withdrawal
penalties--those in the range of five to nine times the study costs--
far exceed reasonableness, especially in the face of the potential for
a myriad of ways in which an LSE can bias the bid review process and
slow the cluster study process under existing rules without stringent
oversight.\1420\ Interwest argues that the NOPR does not sufficiently
acknowledge the need to reform study processes to prevent inaccurate
studies, which create widely different results from one study to
another.\1421\ Interwest suggests that these inaccurate studies, along
with delayed affected system study results, lead to withdrawals,
strengthening the case that withdrawal penalties should not increase
dramatically toward the end of the study process and around execution
of an LGIA without appropriate recourse for the interconnection
customer. Interwest argues that a 25% increase in study costs from one
study to another should be a sufficient basis for withdrawal without
incurring withdrawal penalties, as part of a tariff with incentives for
transmission providers to provide accurate estimates of network upgrade
costs. Interwest argues that, for these reasons, withdrawal penalties
are redundant and punitive when combined with increasingly large at-
risk deposits as proof of commercial readiness.
---------------------------------------------------------------------------
\1420\ Interwest Initial Comments at 22.
\1421\ Interwest Reply Comments at 13-14.
---------------------------------------------------------------------------
737. SDG&E asserts that a withdrawal penalty of nine times the
study deposit amount will provide a disincentive for late-stage
withdrawals in certain cases, but that a penalty alone should not be
relied on in lieu of other financial security mechanisms.\1422\ SDG&E
maintains that a more reasonable amount for a withdrawal penalty may be
the greater of nine times the study deposit and a CAISO-style financial
security posting that is based on factors such as network upgrade and
interconnection facilities costs.
---------------------------------------------------------------------------
\1422\ SDG&E Initial Comments at 6.
---------------------------------------------------------------------------
738. Some commenters argue that the Commission should adopt the
RTO/ISO model of financial readiness milestones that are tied to
network upgrade costs.\1423\ Clean Energy Associations submit that
tying deposits and penalties to network upgrade costs allocated to the
interconnection customer is superior because network upgrade costs are
a better indicator of the harm that may be caused by a withdrawal than
generating facility size.\1424\
---------------------------------------------------------------------------
\1423\ ACE-NY Initial Comments at 8; AES Initial Comments at 19;
AES Reply Comments at 3-6; Enel Initial Comments at 4; Invenergy
Initial Comments at 24; Pine Gate Initial Comments at 34.
\1424\ Clean Energy Associations Initial Comments at 41.
---------------------------------------------------------------------------
739. AES contends that tying the withdrawal penalty to the
percentage of network upgrade deposit at risk provides a better
incentive for interconnection customers with proposed generating
facilities with high network upgrade costs to withdraw earlier in the
interconnection process, rather than risk losing their posted
security.\1425\ Invenergy suggests that any withdrawal penalty imposed
after LGIA execution should be tied to assigned
[[Page 61119]]
network upgrade costs and should be subject to a $2 million cap to
avoid unnecessarily punitive penalties, as the LGIA may impose
additional financial obligations for construction of the assigned
upgrades.\1426\ CAISO argues that network upgrade-based financial
requirements are far more effective than the withdrawal penalties
proposed in the NOPR because network upgrade-based requirements are
tied to the project's actual interconnection costs, which correlate
with its competitiveness to obtain a power purchase agreement and
therefore its likelihood to remain in the queue.\1427\
---------------------------------------------------------------------------
\1425\ AES Initial Comments at 19.
\1426\ Invenergy Initial Comments at 24.
\1427\ CAISO Initial Comments at 23.
---------------------------------------------------------------------------
740. NYISO argues that the withdrawal penalty amounts proposed in
the NOPR, which are tied to study costs, are unlikely to provide
sufficient capital to cover the costs of constructing the network
upgrades of withdrawn generating facilities on which other
interconnection customers are relying.\1428\ SoCal Edison suggests
that, instead of using study costs as the basis for the withdrawal
penalty amount, which would not be known until completion of the
interconnection studies, the Commission should require that withdrawal
penalties be calculated based on increasing multiples of the study
deposits, which are known and serve as a proxy of the study
costs.\1429\
---------------------------------------------------------------------------
\1428\ NYISO Initial Comments at 25.
\1429\ SoCal Edison Initial Comments at 10.
---------------------------------------------------------------------------
(2) Proposed Withdrawal Penalty Exemptions
741. Some commenters support the NOPR proposal to exempt
interconnection customers from withdrawal penalties in certain
instances, stating that the proposal achieves a workable balance
between the needs of interconnection customers and transmission
providers.\1430\ For example, MISO agrees that interconnection requests
that experience significant cost increases should be able to withdraw
without a penalty.\1431\ Omaha Public Power states that the four
scenarios proposed in the NOPR for interconnection customers to qualify
for exemptions to withdrawal penalties seem to properly acknowledge
instances where other interconnection customers are not negatively
impacted by a withdrawal, or when it is no longer economically viable
for the interconnection customer to move forward with the generating
facility due to drastically increased network upgrade costs.\1432\
---------------------------------------------------------------------------
\1430\ MISO Initial Comments at 68; Omaha Public Power Initial
Comments at 9-10.
\1431\ MISO Initial Comments at 68.
\1432\ Omaha Public Power Initial Comments at 9-10.
---------------------------------------------------------------------------
742. On the other hand, SEIA contends that, although the NOPR
proposal exempts interconnection customers from withdrawal penalties if
there is no impact to other generating facilities in the same cluster,
withdrawals almost always impact other generating facilities in the
cluster, such that withdrawal penalties are likely unavoidable.\1433\
Pine Gate states that the proposed list of withdrawal penalty
exemptions is not reflective of an appropriate balance between
interconnection customer and transmission provider accountability
because it increases the burden on interconnection customers without
any increase to accountability for transmission providers.\1434\
Pattern Energy disagrees with a standard tied to a potential delay of a
lower-queued interconnection customer, given the Commission's proposed
transition to a cluster study approach.\1435\ Pattern Energy contends
that the only impact that should be relevant to granting an exemption
is a financial impact.
---------------------------------------------------------------------------
\1433\ SEIA Initial Comments at 26.
\1434\ Pine Gate Initial Comments at 34.
\1435\ Pattern Energy Initial Comments at 33.
---------------------------------------------------------------------------
743. NRECA supports including the 100% cost increase exemption in
the final rule, which would apply where there is a large late-stage
cost increase, making the interconnection request's success
economically challenging.\1436\ Pattern Energy, on the other hand,
claims that the Commission's proposal incentivizes transmission
providers to overestimate costs in cluster studies for fear that there
will be later, unexpected cost increases in the facilities study, which
Pattern Energy argues presents a barrier to entry.\1437\ Pine Gate also
claims that requiring a 100% increase in costs between the facilities
study phase and the previous cluster study phase in order to allow for
penalty-free withdrawal exposes interconnection customers to withdrawal
penalties in instances where costs increase dramatically due to no
fault of the interconnection customer.\1438\ Several commenters
recommend that the Commission ensure that any penalties for withdrawal
account for unanticipated cost increases.\1439\
---------------------------------------------------------------------------
\1436\ NRECA Initial Comments at 30.
\1437\ Pattern Energy Initial Comments at 34.
\1438\ Pine Gate Initial Comments at 35.
\1439\ Clean Energy Associations Initial Comments at 40 (arguing
that the Commission should allow interconnection customers to
withdraw without penalty if costs in a restudy increase by over 25%
relative to prior study results); CREA and NewSun Initial Comments
at 78 (suggesting that withdrawal penalties should not apply anytime
an interconnection customer withdraws after receipt of a system
impact study, facilities study, or restudy that contains a 25% cost
increase over the prior study or a 50% cumulative increase over the
initial study); ENGIE Initial Comments at 7; Invenergy Initial
Comments at 25 (arguing that the Commission should allow
interconnection customers to withdraw without penalty if affected
system study results cause an interconnection customer's costs to
increase by more than 25% compared to costs allocated to it by the
host transmission provider in a prior study); Longroad Energy
Initial Comments at 18 (recommending that the Commission reduce the
penalty exemption threshold to a cost-increase of only 20% from the
initial cluster study to the restudy and a cost increase of only 10%
from the final restudy to the individual cluster facilities study);
NextEra Initial Comments at 26 (suggesting that a more reasonable
withdrawal penalty exemption threshold for cost increases for late-
stage withdrawals would be in the range of 30%); [Oslash]rsted
Initial Comments at 15 (arguing that the Commission should allow
interconnection customers to withdraw without penalty if costs in a
restudy increase by over 25% relative to prior study results);
Pattern Energy Initial Comments at 33 (suggesting that, if costs
increase by 15% from the first to the second study report, but a
restudy results in an additional 20% increase compared to the second
study report, then the total increase from the first study report to
the restudy report would be 35%, and this total additive percentage
increase should be deemed sufficient to constitute an excusable
withdrawal event); Pine Gate Initial Comments at 35.
---------------------------------------------------------------------------
744. Xcel recommends that the Commission allow an interconnection
request, submitted by a resource planning entity as agent for an
interconnection customer, that is withdrawn by the resource planning
entity because it was not picked in a resource solicitation process, to
be exempt from withdrawal penalties, as the withdrawal was due to no
fault of the interconnection customer.\1440\ Xcel states that, other
than this exemption, the Commission should not expand the exemptions
from withdrawal penalties beyond those proposed in the NOPR.
---------------------------------------------------------------------------
\1440\ Xcel Initial Comments at 35.
---------------------------------------------------------------------------
745. NextEra and Northwest and Intermountain argue that
interconnection customers should be exempt from withdrawal penalties if
the transmission provider's or affected system operator's studies or
posted information are untimely.\1441\
---------------------------------------------------------------------------
\1441\ NextEra Initial Comments at 26; Northwest and
Intermountain Initial Comments at 13.
---------------------------------------------------------------------------
746. NextEra contends that the NOPR does not explain why there are
different withdrawal penalty levels for interconnection customers
demonstrating commercial readiness via the proposed non-financial
demonstration options and those submitting a deposit in lieu of
demonstrating commercial readiness.\1442\
---------------------------------------------------------------------------
\1442\ NextEra Initial Comments at 27.
---------------------------------------------------------------------------
747. Several commenters argue that the proposed exemptions require
[[Page 61120]]
clarification.\1443\ For one, CAISO claims that the exemption criteria,
as written in the NOPR, are not workable.\1444\ CAISO argues that the
Commission's description of the exemptions is problematic due to the
use of ``or,'' which suggests meeting any criterion would relieve the
interconnection customer of withdrawal penalties. CAISO posits that,
under the Commission's criteria, a withdrawal could not affect the
timing of other generating facilities but still increase their costs;
however, the interconnection customer would meet the first exemption
and not be subject to withdrawal penalties. CAISO argues that
withdrawals would never delay the timing of generating facilities in
the same cluster. CAISO states that a cluster's upgrades are a package,
and the construction schedule would not change simply because one
interconnection customer that is sharing upgrades withdraws. CAISO
suggests that the Commission clarify that, to be exempt from withdrawal
penalties, each interconnection customer must meet (1) both criterion
one and two, and (2) criterion three or four.
---------------------------------------------------------------------------
\1443\ CAISO Initial Comments at 21-22; Environmental Defense
Fund Initial Comments at 4-5; EEI Initial Comments at 8; EEI Reply
Comments at 6-7; Eversource Initial Comments at 19; Shell Reply
Comments at 27.
\1444\ CAISO Initial Comments at 21-22.
---------------------------------------------------------------------------
748. Invenergy proposes that the list of exemptions to withdrawal
penalties be revised to include: (1) the withdrawal does not directly
cause material delays in the timing of other interconnection requests
within the same cluster, as determined at the time of withdrawal by the
transmission provider; or (2) the withdrawal does not directly cause a
material increase in the costs assigned to other interconnection
requests within the same cluster, as determined at the time of
withdrawal by the transmission provider.
749. Omaha Public Power contends that the exemption to withdrawal
penalties cannot be applied to the interconnection process as it
currently functions for those transmission providers that allow for
overlapping studies (e.g., when a cluster study is being studied prior
to the conclusion of the preceding cluster study).\1445\ Omaha Public
Power claims that overlapping studies lead to baseline costs in the
subsequent cluster studies that are inherently wrong and do not factor
in the previously existing unfinished cluster studies. Omaha Public
Power claims that this inaccurate starting point for costs is likely
higher than what is accurate, and any subsequent restudy will likely
lead to identification of network upgrades that fall below the
exemption threshold, subjecting interconnection customers to wrongful
withdrawal penalties. Omaha Public Power argues that, until an
interconnection process can be conducted without overlapping studies,
these exemptions will be woefully misapplied. Southern raises similar
concerns.\1446\
---------------------------------------------------------------------------
\1445\ Omaha Public Power Initial Comments at 10.
\1446\ Southern Initial Comments at 21-22.
---------------------------------------------------------------------------
750. Yet other commenters believe that the NOPR proposal is too
lenient.\1447\ NRECA suggests that transmission providers should be
afforded flexibility whether to adopt exemptions to withdrawal
penalties related to: (1) not delaying the timing of other
interconnection requests in the same cluster; (2) not increasing the
cost of network upgrades for other interconnection requests in the same
cluster; and (3) withdrawing if the most recent cluster study report
shows a cost increase of at least 25% compared to the previous cluster
study report.\1448\ NRECA asserts that these exemptions may or may not
be needed for a particular transmission provider and potentially may
allow withdrawals that trigger time-consuming restudy processes. SDG&E
generally opposes exemptions to withdrawal penalties and claims that
material modification provisions in the pro forma LGIP already address
impacts to other interconnection customers.\1449\ SDG&E argues that,
regardless of the impact to other interconnection customers, there are
still costs and resources committed between all entities to study and
assess proposed generating facilities. SDG&E believes that withdrawal
penalties should apply for all generating facilities, and any
exemptions should be sparing.
---------------------------------------------------------------------------
\1447\ NRECA Initial Comments at 30; SDG&E Initial Comments at
6-7.
\1448\ NRECA Initial Comments at 30.
\1449\ SDG&E Initial Comments at 6-7.
---------------------------------------------------------------------------
(3) How To Determine if a Withdrawal Has Delayed or Increased the Cost
of Network Upgrades for Other Generating Facilities in the Same Cluster
751. Some commenters argue that it would be difficult to define the
circumstances under which a withdrawal is deemed to have delayed the
timing or increased the cost of network upgrades for other
interconnection requests in the same cluster.\1450\ APS and Bonneville
argue that attempting to do so would create an undue burden on
transmission providers, and that the withdrawal of an interconnection
request could have an impact on generating facilities in a subsequent
cluster.\1451\ NextEra suggests that one test to determine whether a
withdrawal delays other interconnection requests could be whether the
withdrawal delays the planned in-service date of other interconnection
requests in the same cluster.\1452\ However, NextEra acknowledges that
even this assessment could be difficult to calculate, as delays could
not manifest themselves for months or years, other factors could cause
delays, and interconnection customers could seek to delay their
generating facilities for commercial reasons. Pattern Energy asserts
that the Commission must clearly define the standard for timing delays
and increasing the cost of network upgrades for other interconnection
customers.\1453\
---------------------------------------------------------------------------
\1450\ APS Initial Comments at 16-17; Bonneville Initial
Comments at 12; MISO Initial Comments at 67.
\1451\ APS Initial Comments at 16-17; Bonneville Initial
Comments at 12.
\1452\ NextEra Initial Comments at 26.
\1453\ Pattern Energy Initial Comments at 33.
---------------------------------------------------------------------------
752. Bonneville suggests that, similar to the method used to assess
a material modification under the pro forma LGIP and pro forma SGIP,
the Commission could provide a non-exhaustive list of examples that
would be deemed as delaying the timing or increasing the costs of
network upgrades.\1454\ Bonneville suggests that transmission providers
could be given discretion to determine whether other withdrawal
situations that are not listed should fall under this category by
considering whether the withdrawal has delayed the timing or increased
the cost of network upgrades for other interconnection requests in a
cluster.
---------------------------------------------------------------------------
\1454\ Bonneville Initial Comments at 12.
---------------------------------------------------------------------------
753. Invenergy argues that transmission providers should not be
permitted to simply assume that withdrawals cause some harm to other
interconnection requests and that there should be a requirement for
transmission providers to perform an analysis to determine whether a
withdrawal results in material harm to other interconnection requests,
which interconnection customers could review.\1455\ Invenergy states
that the analysis of whether a withdrawal causes a cost increase or
delays the timing for other interconnection requests should be
performed at each phase of the study process.
---------------------------------------------------------------------------
\1455\ Invenergy Initial Comments at 26-27.
---------------------------------------------------------------------------
754. Invenergy requests that the Commission clarify that a
withdrawal will not delay the timing of another interconnection request
or increase its network upgrade costs if the withdrawal simply requires
the transmission
[[Page 61121]]
provider to account for the withdrawal. Invenergy requests that the
Commission clarify that any delay or cost increase analysis must be
based on a reasonable analysis and show a direct relationship between
the withdrawal and the asserted impact on another interconnection
request.
755. MISO encourages the Commission to impose the withdrawal
penalty whenever an interconnection request withdraws from the
interconnection queue.\1456\ MISO argues that even if after restudy it
turns out that the withdrawal of an interconnection request did not
actually increase network upgrade costs to other interconnection
customers in the cluster, the withdrawal still negatively impacts the
interconnection queue by increasing uncertainty for other
interconnection customers, prompting further withdrawals and adding
administrative cost and burden that impede efficient interconnection
queue processing. Pattern Energy likewise argues that the withdrawal of
any interconnection request from the interconnection queue results in
some form of delay, such as the time taken by a transmission provider
to perform a review of the potential impacts of the withdrawal, which
could be interpreted as causing a delay because the withdrawal impact
analysis could delay the receipt of final study results and
agreements.\1457\ PJM makes similar arguments.\1458\
---------------------------------------------------------------------------
\1456\ MISO Initial Comments at 67-68.
\1457\ Pattern Energy Initial Comments at 33.
\1458\ PJM Initial Comments at 41.
---------------------------------------------------------------------------
756. Xcel contends that, if a withdrawal results in a restudy of a
cluster or subsequent clusters, that restudy will delay the receipt of
study results, LGIA execution, and the construction of required network
upgrades.\1459\ Therefore, Xcel argues that any withdrawal that results
in a restudy should not be exempt from a withdrawal penalty unless the
commercial operation dates of other impacted interconnection requests
in the same or subsequent cluster are not impacted. Xcel asserts that
delaying LGIA execution may negatively impact off-take agreements and
should also be considered harm to equally or lower-queued
interconnection customers. Xcel notes that harm is not limited to the
reallocation of interconnection costs to equally or lower-queued
interconnection requests. Xcel contends that delays, resulting in
clogged interconnection queues, can impact resource decisions and thus
harm interconnection requests not yet in the interconnection queue.
Xcel argues that, if the withdrawal causes restudy, but the restudy
does not impact the timing discussed above, then the restudy results
should be used to determine the impact on costs allocated to equally or
lower-queued interconnection requests.
---------------------------------------------------------------------------
\1459\ Xcel Initial Comments at 33-34.
---------------------------------------------------------------------------
757. Xcel notes that it may be difficult to determine if a single
withdrawal would have caused harm when multiple interconnection
requests are withdrawn in the same time frame.\1460\ Xcel generally
supports penalizing withdrawals if they have a combined impact, as it
would be difficult, if not impossible and time consuming, to determine
each individual withdrawal's impact. According to Xcel, if the
withdrawal penalty was determined on an individual basis, some
interconnection customers may wait for others to withdraw, then argue
that their secondary withdrawals did not have an impact because all
delays and cost impacts were caused by the first withdrawal.
---------------------------------------------------------------------------
\1460\ Id. at 34.
---------------------------------------------------------------------------
758. Indicated PJM TOs state that a withdrawal can impose costs on
other interconnection customers even if it does not delay the timing of
other proposed generating facilities. Indicated PJM TOs argue that if
withdrawals impose more network upgrade costs on other interconnection
customers, it would be unfair to excuse withdrawing interconnection
customers just because the transmission provider can keep to its
original timelines.\1461\ Indicated PJM TOs further claim that,
particularly in a large RTO/ISO, it is not clear how the transmission
provider would determine that a particular withdrawal did or did not
delay the processing of other interconnection requests. Indicated PJM
TOs argue that this criterion for being excused from penalties or
forfeitures should be eliminated.
---------------------------------------------------------------------------
\1461\ Indicated PJM TOs Reply Comments at 35-36.
---------------------------------------------------------------------------
(4) Withdrawal Penalty Collection and Distribution
759. APS seeks clarification on the mechanism the Commission
proposes for transmission providers to collect withdrawal penalties
from interconnection customers.\1462\ APS and MISO express concerns
that, under the withdrawal penalty collection proposal, a transmission
provider would have to act as a collection agency, which is likely
unworkable.\1463\ EEI suggests that the Commission institute financial
assurance requirements for interconnection customers to reduce the
likelihood that penalized entities are unable to pay the penalties they
are assessed.\1464\ Eversource asserts that the Commission should set
clear rules that include policies governing how RTOs/ISOs will collect
penalties and address potential scenarios in which interconnection
customers refuse to pay or declare bankruptcy.\1465\ MISO claims that
interconnection customers can structure the businesses behind the
interconnection request in such a way so that the legal entity would be
very difficult to collect from.\1466\
---------------------------------------------------------------------------
\1462\ APS Initial Comments at 16.
\1463\ Id.; MISO Initial Comments at 69.
\1464\ EEI Initial Comments at 8.
\1465\ Eversource Initial Comments at 19.
\1466\ MISO Initial Comments at 69.
---------------------------------------------------------------------------
760. Some commenters do not support the Commission's proposal to
require withdrawal penalty revenues to be used to fund studies
conducted under the cluster study process.\1467\ CAISO states that
transmission providers already have provisions specifying where non-
refundable funds go, and using them for interconnection studies would
require careful accounting without relieving study burdens.\1468\
NextEra and PJM suggest that transmission providers should be allowed
to use forfeited funds to help pay for increased network upgrade costs
incurred by other interconnection customers due to a withdrawal.\1469\
Invenergy asserts that excess funds should be applied to offset network
upgrade costs assigned through that cluster study process in proportion
to any upgrade costs that were directly shifted from a withdrawn
interconnection customer.\1470\ RWE Renewables assert that withdrawal
penalties should be used to create meaningful decision points for
interconnection customers, to discern whether they are willing to
commit resources to each particular generating facility.\1471\ RWE
Renewables and Interwest contend that withdrawal penalties should be
allocated between and among different clusters for transmission
expansion, so that they benefit load and interconnection customers,
rather than restudies, which they believe will not be needed as
frequently in the proposed cluster study process.\1472\
---------------------------------------------------------------------------
\1467\ CAISO Initial Comments at 22; Interwest Reply Comments at
14; NextEra Initial Comments at 27-28; PJM Initial Comments at 39;
RWE Renewables Initial Comments at 2.
\1468\ CAISO Initial Comments at 22.
\1469\ NextEra Initial Comments at 27-28; PJM Initial Comments
at 39.
\1470\ Invenergy Initial Comments at 27-28.
\1471\ RWE Renewables Initial Comments at 2.
\1472\ Id.; Interwest Reply Comments at 14.
---------------------------------------------------------------------------
761. CAISO opposes the NOPR proposal to cap withdrawal
[[Page 61122]]
penalties.\1473\ CAISO contends that larger projects create the most
churn in queue, and projects that cannot demonstrate commercial
readiness should be the most likely to withdraw. CAISO argues that
withdrawal penalty caps will disproportionately affect smaller and more
competitive interconnection requests more than larger and less
competitive interconnection requests and suggests that the Commission
remove the withdrawal penalty caps so the withdrawal penalties affect
interconnection customers equally.
---------------------------------------------------------------------------
\1473\ CAISO Initial Comments at 24.
---------------------------------------------------------------------------
762. Pattern Energy suggests that, in addition to the Commission's
proposed use of withdrawal penalties to defray future study costs, the
Commission should designate a portion of any withdrawal penalties to be
used for recruitment, retention, and performance bonuses for engineers,
administrators, and/or consultants, who can then be deployed to help
alleviate queue backlogs.\1474\
---------------------------------------------------------------------------
\1474\ Pattern Energy Initial Comments at 34.
---------------------------------------------------------------------------
763. Other commenters request clarification of the proposal for
distribution of withdrawal penalty funds. AES and EDF Renewables argue
that it is critical that the Commission clarify that transmission
providers do not receive any benefits from withdrawal fee and non-
refundable deposit proceeds; otherwise, they argue, transmission
providers would be financially incentivized to force interconnection
customers to withdraw.\1475\ Several commenters request clarification
of the Commission's intent for excess money that remains after funding
any appropriate restudies for the current cluster, and some of these
commenters have suggested uses for this excess.\1476\ AES asserts that
any withdrawal fees and non-refundable deposits collected should go
towards improving the interconnection process.\1477\ EDF Renewables
suggests that any remainder should be refunded to the interconnection
customer.\1478\ On the other hand, Southern opposes refunding excess
penalty amounts to the interconnection customer and proposes that any
remaining amounts be applied to network upgrades needed in the same
cluster or treated as a revenue credit against the revenue requirement
in the determination of transmission rates.\1479\ APS suggests that the
remainder act as a credit towards the transmission provider's
transmission rates, as this method would guarantee that all
transmission customers benefit from the penalties.\1480\
---------------------------------------------------------------------------
\1475\ AES Initial Comments at 19-20; EDF Renewables Initial
Comments at 7.
\1476\ AES Initial Comments at 19-20; APS Initial Comments at
16; EDF Renewables Initial Comments at 7; Invenergy Initial Comments
at 27-28; ISO-NE Initial Comments at 33; Southern Initial Comments
at 22.
\1477\ AES Initial Comments at 19-20.
\1478\ EDF Renewables Initial Comments at 7.
\1479\ Southern Initial Comments at 22.
\1480\ APS Initial Comments at 16.
---------------------------------------------------------------------------
764. Shell claims that withdrawal penalties will accumulate faster
than they may be spent by the relevant transmission provider.\1481\
Therefore, Shell asserts that the Commission must address the
following: (1) the system of independent checks and balances that
transmission providers will employ to ensure that only specific
individuals have access to the withdrawal penalty account; (2) the
average cost of a cluster study from start to finish so that, if a
withdrawal penalty is forfeited, it can be determined how many future
cluster studies the transmission provider could expect to perform with
forfeited funds; (3) if funds from a withdrawal penalty are used to pay
for future study costs, whether future interconnection customers must
still post a study deposit; and (4) if a withdrawal penalty account
balance accumulates faster than funds can be spent, what independent
system of checks and balances transmission providers will use to ensure
that their staff and/or consultants do not overcharge for their
services related to studies.
---------------------------------------------------------------------------
\1481\ Shell Initial Comments at 18-19.
---------------------------------------------------------------------------
(d) Requests for Flexibility, Clarification, or Technical Conference
765. Some commenters would prefer that the Commission allow for
transmission providers to craft and use their own withdrawal penalty
structure instead of having a standardized approach for all
transmission providers.\1482\ AEP supports the adoption of withdrawal
penalties with reasonable penalty-free off ramps but asserts that this
is an area in which flexibility should be permitted, particularly where
alternative approaches already have been through robust stakeholder
processes.\1483\ NYTOs suggest that there should be flexibility
regarding the amount of the withdrawal penalties, which NYTOs argue
should be tied to each transmission provider's and associated
transmission owners' interconnection processes.\1484\ Pacific Northwest
Utilities argue that the Commission should allow flexibility as to the
timing of the penalties.\1485\ Pacific Northwest Utilities also request
flexibility to define their own requirements for withdrawal penalties
to limit interconnection queue overcrowding.\1486\ Interwest contends
that the Commission should not attempt to predetermine the amount of
withdrawal penalties in a rulemaking proceeding with limited evidence;
rather, the Commission should require that transmission providers
develop appropriate mechanisms and determine appropriate monetary
amounts to substantially reduce the risk that the efforts of
interconnection customers are not thwarted or delayed by others' overly
speculative interconnection requests.\1487\
---------------------------------------------------------------------------
\1482\ AEP Initial Comments at 24; Avangrid Initial Comments at
9; Avangrid Reply Comments at 4; CREA and NewSun Initial Comments at
77-78; Dominion Initial Comments at 34; Indicated PJM TOs Initial
Comments at 33; NYISO Initial Comments at 24; NYTOs Initial Comments
at 21; Omaha Public Power Initial Comments at 11; OMS Initial
Comments at 13; Pacific Northwest Utilities Initial Comments at n.6;
PJM Initial Comments at 41; SDG&E Initial Comments at 6; SEIA
Initial Comments at 27; Southern Initial Comments at 20; Shell
Initial Comments at 24-25; SPP Initial Comments at 11.
\1483\ AEP Initial Comments at 23-24.
\1484\ NYTOs Initial Comments at 21.
\1485\ Pacific Northwest Utilities Initial Comments at 2, 4-5, &
n.6.
\1486\ Id. at 2.
\1487\ Interwest Reply Comments at 13.
---------------------------------------------------------------------------
766. Some commenters seek general clarification on several of the
withdrawal penalty proposals. For example, NV Energy requests
clarification on whether, if a withdrawal penalty is deemed appropriate
at the time an interconnection customer withdraws its interconnection
request, that the interconnection customer is charged both the actual
costs incurred to perform studies and the applicable withdrawal penalty
(i.e., two separate charges).\1488\
---------------------------------------------------------------------------
\1488\ NV Energy Initial Comments at 6-7.
---------------------------------------------------------------------------
767. NV Energy seeks clarification, if an interconnection
customer's generating facility does not achieve commercial operation,
whether the nine times the actual study cost deposit would be applied
toward its withdrawal penalties, and whether the interconnection
customer would be charged nine times the actual study costs.
768. Southern suggests that, in the NOPR's proposed definition of
``withdrawal penalty'' and in the exemptions to that penalty, the
phrase ``the commercial operation date in the interconnection request''
should replace the phrase ``commercial operation,'' such that the
definition would read ``the penalty assessed by Transmission Provider
to an Interconnection Customer that chooses to withdraw from the queue
or does not otherwise reach the Commercial Operation Date in the
[[Page 61123]]
Interconnection Request.'' \1489\ Southern argues that to be consistent
and clear with pro forma LGIP section 3.7.1.1, the definition of
withdrawal penalty must be revised to reflect that the withdrawal
penalty is applicable if the interconnection customer is deemed
withdrawn.
---------------------------------------------------------------------------
\1489\ Southern Initial Comments at 21-22.
---------------------------------------------------------------------------
769. Invenergy requests that the Commission clarify that, to the
extent withdrawal penalty amounts are used to fund some portion of an
interconnection study, that it does not reduce the transmission
provider's potential exposure for penalties in the event that study is
not timely completed.\1490\
---------------------------------------------------------------------------
\1490\ Invenergy Initial Comments at 28.
---------------------------------------------------------------------------
770. Invenergy requests that the Commission clarify that, to the
extent any post-LGIA withdrawal penalty is imposed, it is offset by the
deposit posted at LGIA execution and not additional to that deposit,
which would be unreasonable and unnecessarily punitive.\1491\
---------------------------------------------------------------------------
\1491\ Id. at 24.
---------------------------------------------------------------------------
771. MISO encourages the Commission to bolster the definitions of
``commercial readiness deposit,'' ``study deposit,'' and ``withdrawal
penalty'' to clearly enable the transmission provider to apply those
deposits toward the withdrawal penalty.\1492\
---------------------------------------------------------------------------
\1492\ MISO Initial Comments at 68-69.
---------------------------------------------------------------------------
772. CAISO seeks clarification that the NOPR's proposed withdrawal
penalties would not displace transmission providers' other existing
procedures and penalties that incentivize interconnection customers to
withdraw earlier rather than later and cites its own requirement that
interconnection customers post financial security based on their
allocated network upgrade costs.\1493\
---------------------------------------------------------------------------
\1493\ CAISO Initial Comments at 22-23.
---------------------------------------------------------------------------
773. NV Energy requests that the Commission clarify what happens if
only a portion of an interconnection request is brought to commercial
operation, as it relates to withdrawal penalties and the construction
of network upgrades.\1494\
---------------------------------------------------------------------------
\1494\ NV Energy Initial Comments at 7.
---------------------------------------------------------------------------
774. Tri-State requests clarification on the meaning of ``previous
withdrawal penalty revenue received'' in section 3.7.1.1 of the pro
forma LGIP \1495\ and requests clarification on whether section 3.7.1.2
of the pro forma LGIP includes the paragraph after (c) regarding
commercial operation.
---------------------------------------------------------------------------
\1495\ Tri-State Initial Comments at 28.
---------------------------------------------------------------------------
(e) Alternatives and Miscellaneous
775. Some commenters provide comments in response to the
Commission's query on whether a correlation exists between the size of
a withdrawing proposed generating facility and the relative level of
harm, in terms of delays and increased cost, to other interconnection
customers as a result of the withdrawal.\1496\ Some commenters indicate
that there can be a correlation between the size of a withdrawing
proposed generating facility and the relative level of harm caused by
the withdrawal and encourage withdrawal penalties that increase with
the proposed generating facility size.\1497\ For example, Idaho Power
contends that large generating facilities typically trigger more
expensive network upgrades which, when withdrawn, are more likely to
trigger restudies.\1498\ Other commenters do not support withdrawal
penalties that increase based on the size of a generating
facility.\1499\ APS argues that the determinant of ``relative level of
harm'' is entirely subjective to the transmission provider and could
lead to litigation.\1500\ APS argues that the location of the
interconnection request is more closely correlated with the effect on
other interconnection customers than is the size of a proposed
generating facility. Xcel states that, although larger generating
facilities tend to have a larger impact, if the total impact to other
projects is calculated as a combined impact, then the size of the
project should not impact the withdrawal penalty calculation.\1501\
---------------------------------------------------------------------------
\1496\ NOPR, 179 FERC ] 61,194 at P 148.
\1497\ Avangrid Initial Comments at 20; Clean Energy States
Initial Comments at 10; Enel Initial Comments at 35; Idaho Power
Initial Comments at 8; PPL Initial Comments at 17.
\1498\ Idaho Power Initial Comments at 8.
\1499\ APS Initial Comments at 17; Xcel Initial Comments at 35.
\1500\ APS Initial Comments at 17.
\1501\ Xcel Initial Comments at 35.
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776. [Oslash]rsted expresses concern that relatively small
generating facilities (by MW) that fail to demonstrate commercial
readiness and are forced to withdraw from the interconnection queue
pose significant threats to the efficient management of the cluster
study process and recommends that withdrawal penalties be correlated to
an interconnection customer's commercial readiness.\1502\
---------------------------------------------------------------------------
\1502\ [Oslash]rsted Initial Comments at 13.
---------------------------------------------------------------------------
777. AEP supports the idea of off-ramp opportunities at specific
times in the cluster study process rather than having to analyze
individual withdrawal impacts throughout a cluster study process.\1503\
AEP contends that such an approach should limit restudies and minimize
delays to remaining interconnection customers. Similarly, PJM asserts
that only allowing withdrawals during certain decision points ensures
that studies start and finish at the same time and that the cluster
status is maintained during the duration of the study.\1504\ According
to PJM, allowing withdrawals at any point in the study process, as
proposed in the NOPR, even with relevant penalties assessed, will cause
cascading restudies and negative impacts on other interconnection
customers in a cluster.
---------------------------------------------------------------------------
\1503\ AEP Initial Comments at 24.
\1504\ PJM Initial Comments at 41.
---------------------------------------------------------------------------
778. SPP states that, under its current LGIP, interconnection
customers provide progressively increasing financial security deposits
at each stage of the study process, and the amounts of the financial
security deposits required to enter into later stages of the study
process are based on the amount of network upgrade costs assigned in
the previous stage, which it asserts is better related to the risk and
harm of a withdrawal than the NOPR proposal.\1505\
---------------------------------------------------------------------------
\1505\ SPP Initial Comments at 11.
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779. Rather than being assessed withdrawal penalties, CREA and
NewSun assert that interconnection customers should be refunded any
unused study deposits.\1506\ CREA and NewSun argue that penalties
should apply only to deter wrongful conduct that the interconnection
customer can avoid committing and should not be used as an arbitrary
barrier to market entry.\1507\
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\1506\ CREA and NewSun Initial Comments at 77.
\1507\ Id. at 74-75.
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iii. Commission Determination
780. We adopt, with modifications, the NOPR proposal to impose
withdrawal penalties on interconnection customers for withdrawing their
interconnection requests from the interconnection queue, absent
qualification for one of the limited exemptions, as discussed below. We
add the defined term ``withdrawal penalty,'' as modified below, to the
pro forma LGIP; revise section 3.7 of the pro forma LGIP; and add
sections 3.7.1, 3.7.1.1, and 3.7.1.2 to the pro forma LGIP, with the
modifications to the NOPR proposal discussed below. However, we decline
to adopt the withdrawal penalty caps proposed in the NOPR.
781. We find that, along with the other reforms adopted in this
final rule, adopting a withdrawal penalty framework is needed to remedy
the issues regarding speculative interconnection requests, including
[[Page 61124]]
study delays from overcrowded interconnection queues and the harms to
the function of the interconnection queue that occur when
interconnection customers withdraw from the interconnection queue at
various stages of the study process. We believe that withdrawal
penalties--as adopted herein--will encourage interconnection customers
to ensure that their proposed generating facilities are likely
commercially viable when they submit their interconnection requests
because withdrawal, in most instances, will incur a penalty. We adopt
withdrawal penalties that increase in amount as interconnection
customers proceed through the interconnection process in order to
ensure that interconnection customers continue to evaluate whether
their proposed generating facilities are commercially viable, thereby
reducing the number of late-stage withdrawals and accompanying
restudies.\1508\ We additionally modify the proposal, as discussed
below, regarding how the withdrawal penalty funds are distributed.
Specifically, after withdrawal penalty funds are used to fund studies
conducted under the cluster study process in the same cluster, as
proposed in the NOPR, we modify the proposal to require any remaining
withdrawal penalty funds be used to offset net increases to network
upgrade cost assignments experienced by interconnection customers from
the same cluster that remain in the interconnection queue and are
directly affected by the withdrawal of an interconnection request
because they previously shared an obligation to fund a network upgrade
\1509\ with the withdrawn interconnection request in the same
cluster.\1510\ If the interconnection customer withdraws before it
executes its LGIA or requests to file its LGIA unexecuted and after the
interconnection customers in the same cluster that the withdrawn
interconnection customer participated in have executed LGIAs, requested
their LGIAs to be filed unexecuted, or withdrawn (or have been deemed
withdrawn), any remaining withdrawal penalty funds not applied to study
costs or net increases in network upgrade cost assignments must be
returned to the withdrawn interconnection customer.\1511\
---------------------------------------------------------------------------
\1508\ See RWE Renewables Initial Comments at 2 (asserting that
withdrawal penalties should be used to create meaningful decision
points for interconnection customers to demonstrate project
commitment through the interconnection process).
\1509\ Sharing an obligation means (1) interconnecting to the
same substation network upgrade, or (2) in the case of a system
network upgrade, where interconnection customers are identified
through the proportional impact method, as contributing to the need
for the same system network upgrade.
\1510\ See Invenergy Initial Comments at 27-28; NextEra Initial
Comments at 27-28; PJM Initial Comments at 39; Southern Initial
Comments at 22 (suggesting that transmission providers should be
allowed to use forfeited funds to help pay for increased network
upgrade costs incurred by other interconnection customers in the
same cluster due to a withdrawal). We disagree with RWE Renewables
and Interwest that withdrawal penalties should be allocated between
and among different clusters because we find that withdrawal
penalties should only be allocated to interconnection customers that
are directly affected by a withdrawal because they share an
obligation to fund a network upgrade. See RWE Renewables Initial
Comments at 2; Interwest Reply Comments at 14.
\1511\ See EDF Renewables Initial Comments at 7.
---------------------------------------------------------------------------
782. As explained in section II of this final rule, we find that
Commission-jurisdictional rates have been rendered unjust and
unreasonable due to speculative interconnection requests that enter and
remain in the interconnection queue. By incentivizing interconnection
customers to submit interconnection requests only for proposed
generating facilities that they believe will be commercially viable and
to remain in the interconnection queue only as long as that continues
to be true, and by offsetting increases in network upgrade cost
responsibility experienced by interconnection customers directly
affected by a withdrawal because they share an obligation to fund a
network upgrade with the withdrawn interconnection request in the same
cluster, we believe that the withdrawal penalty requirements will work
in tandem with the other reforms adopted in this final rule to remedy
those unjust and unreasonable rates.
783. Specifically, we adopt the NOPR proposal, with modification,
to revise the pro forma LGIP to require the transmission provider to
assess withdrawal penalties, unless an exemption applies at any point
in the interconnection process. The withdrawal penalties will be
applied to an interconnection customer if: (1) the interconnection
customer withdraws its interconnection request at any point in the
interconnection process; (2) the interconnection customer's
interconnection request has been deemed withdrawn by the transmission
provider at any point in the interconnection process; or (3) the
interconnection customer's generating facility does not reach
commercial operation (such as when an interconnection customer's LGIA
is terminated prior to reaching commercial operation). We note that a
withdrawal could trigger minor adjustments to the study results of the
remaining equally- or lower-queued interconnection requests that do not
represent a significant harm to those remaining in the queue.
Therefore, we are modifying the NOPR proposal to require the
transmission provider to assess a withdrawal penalty only if the
withdrawal has a material impact on the cost or timing of any
interconnection requests with an equal or lower queue position. If the
transmission provider determines that the impact of the withdrawal is
immaterial, the transmission provider must not assess a withdrawal
penalty.
784. We adopt this provision in place of the NOPR proposal to
exempt interconnection customers from withdrawal penalties if: (1) the
withdrawal does not delay the timing of other proposed generating
facilities in the same cluster; or (2) the withdrawal does not increase
the cost of network upgrades for other proposed generating facilities.
We adopt the NOPR proposal that the interconnection customer will also
be exempt from paying a withdrawal penalty if (1) the interconnection
customer withdraws its interconnection request after receiving the most
recent cluster study report and the network upgrade costs assigned to
the interconnection customer's request have increased 25% compared to
the previous cluster study report, or (2) the interconnection customer
withdraws its interconnection request after receiving the individual
facilities study report and the network upgrade costs assigned to the
interconnection customer's request have increased by more than 100%
compared to costs identified in the cluster study report. Accordingly,
with these exemptions from the withdrawal penalty, the required
withdrawal penalty approach adopted herein does not allow for penalties
if the impact of the withdrawal is immaterial to other interconnection
customers or if the withdrawal follows significant, unanticipated
increases in network upgrade cost estimates.
785. For the withdrawal penalty exemptions, we clarify that the
relevant cost increases are network upgrade cost estimate increases,
and we adopt revisions to the pro forma LGIP accordingly. This
clarification is consistent with the Commission's description of these
exemptions in the NOPR: ``Thus, under this proposal, interconnection
customers would be exempt from a withdrawal penalty . . . if the
withdrawal follows a significant unanticipated increase in network
upgrade cost estimates.'' \1512\
---------------------------------------------------------------------------
\1512\ NOPR, 179 FERC ] 61,194 at P 141 (emphasis added).
---------------------------------------------------------------------------
[[Page 61125]]
786. We disagree with commenters that the thresholds to trigger the
exemptions--a 25% increase in estimated network upgrade costs above the
cluster study report estimate or a 100% increase in estimated network
upgrade costs in the facilities study report--are too high. As an
initial matter, the potential interconnection customer will have access
to heatmap information, as required in this final rule, that will allow
it to evaluate project feasibility without a financial commitment and
thereby avoid potential withdrawal penalty risk. As stated by Omaha
Public Power and Southern, upon entering the interconnection queue and
receiving the estimates provided in the cluster study report, the
interconnection customer is aware that the estimates may change.
Additionally, we find that the trigger thresholds are set at an amount
that provides sufficient room for estimates to change as the cluster
evolves while limiting interconnection customer exposure to withdrawal
penalties when such estimates change by a significant amount. Moreover,
the increasing threshold triggers reflect the fact that estimates
should improve in accuracy as interconnection customers move through
the interconnection process and should increasingly disincentivize
commercially non-viable generating facilities from staying in the
interconnection queue. An interconnection customer will know to factor
in both the cost estimates and the potential withdrawal penalty but
also the exemption trigger thresholds as it proceeds through the
interconnection queue.
787. We do not believe that interconnection customers will be
subject to ``wrongful withdrawal penalties'' as suggested by some
commenters. In addition, the withdrawal penalty exemptions are designed
to allow penalty-free withdrawal if the withdrawal does not materially
harm other interconnection customers or if the withdrawal follows a
significant unanticipated increase in network upgrade cost estimates.
The withdrawal penalty exemptions are not designed to mitigate all
business risk associated with interconnecting a new generating
facility. The withdrawal penalty structure adopted herein, where the
withdrawal penalty at the earlier stages of the interconnection process
is generally lower than the withdrawal penalty at later stages also
lessens the cost exposure for an interconnection customer that
withdraws at an earlier stage, when the impact of the withdrawal is
less disruptive to the administration of the interconnection queue and
other interconnection customers. We find that, by increasing the
withdrawal penalty amounts as the interconnection customer proceeds
through the interconnection queue, interconnection customers will be
incentivized to withdraw non-viable interconnection requests earlier in
the process, leading to fewer late-stage withdrawals.
788. We also disagree with commenters that request additional
exemptions to the withdrawal penalty structure. We believe that the
withdrawal penalty exemptions and withdrawal penalty structure, as
modified by this final rule, will deter unwarranted assessments of
withdrawal penalties.
789. Regarding commenters' requests for clarification concerning
how to determine whether a withdrawal impacts other interconnection
requests with the same or lower queue positions for purposes of
assessing qualification for an exemption to a withdrawal penalty, we
defer to the transmission provider's discretion because the
transmission provider is best suited to determine whether a withdrawal
has a material impact on the cost or timing of any interconnection
customer with the same or lower queue position.
790. We do not adopt the NOPR proposal regarding withdrawal penalty
calculations for interconnection customers that provide demonstrations
of commercial readiness because we do not adopt the non-financial
commercial readiness demonstration options in this final rule, as
discussed above in section III.A.6.c.iii. Instead, we modify the
proposed penalty structure to base the withdrawal penalty calculation
on an increasing percentage of the cost of the identified network
upgrades assigned to the interconnection customer as the
interconnection customer moves through the interconnection queue.\1513\
We also decline to adopt the withdrawal penalty caps proposed in the
NOPR. We believe that this structure will provide better financial
incentives for interconnection customers to avoid late-stage
withdrawals that cause the greatest disruption to interconnection queue
processing via restudies and delays because interconnection customers
will be subject to higher withdrawal penalties late in the
interconnection process.
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\1513\ See Invenergy Initial Comments at 27-28; NextEra Initial
Comments at 27-28; PJM Initial Comments at 39; Southern Initial
Comments at 22 (suggesting that transmission providers should be
allowed to use forfeited funds to help pay for increased network
upgrade costs incurred by other interconnection customers in the
same cluster due to a withdrawal).
---------------------------------------------------------------------------
791. With regard to the withdrawal penalty calculation structure
more specifically, we modify the NOPR proposal and require that, unless
an interconnection customer qualifies for one of the stated exemptions
discussed above, the transmission provider must assess a withdrawal
penalty on an interconnection customer with a proposed generating
facility that does not reach commercial operation based either on the
actual study costs or on a percentage of the interconnection customer's
assigned network upgrade costs, depending on what phase the
interconnection customer withdraws its interconnection request. Thus,
the withdrawal penalty for an interconnection customer will be
calculated as the greater of the study deposit or: (1) two times the
study cost if the interconnection customer withdraws during the cluster
study or after receipt of a cluster study report; (2) 5% of the
interconnection customer's identified network upgrade costs if the
interconnection customer withdraws during the cluster restudy or after
receipt of any applicable restudy reports; (3) 10% of the
interconnection customer's identified network upgrade costs if the
interconnection customer withdraws during the facilities study, after
receipt of the individual facilities study report, or after receipt of
the draft LGIA; or (4) 20% of the interconnection customer's identified
network upgrade costs if, after executing, or requesting to file
unexecuted, the LGIA, the interconnection customer's LGIA is terminated
before its generating facility achieves commercial operation. The table
below summarizes the withdrawal penalty structure adopted herein.
------------------------------------------------------------------------
Total withdrawal penalty
Phase of withdrawal (if greater than study
deposit)
------------------------------------------------------------------------
Initial Cluster Study..................... 2 times study costs.
Cluster Restudy........................... 5% of network upgrade costs.
Facilities Study.......................... 10% of network upgrade
costs.
After Execution of, or After the Request 20% of network upgrade
to File Unexecuted, the LGIA. costs.
------------------------------------------------------------------------
792. We find that the withdrawal penalty structure adopted herein,
which requires larger withdrawal penalties as the interconnection
customer progresses through the interconnection process, combined with
the exemptions, strikes the proper balance between enabling
interconnection customers that possess
[[Page 61126]]
imperfect information when entering into and remaining in the
interconnection queue to make withdrawal decisions and deterring
speculative interconnection requests from entering into and remaining
in the queue when they are unlikely to be completed, to the detriment
of other interconnection customers, especially when these
interconnection requests are withdrawn at later stages of the
interconnection process.
793. We decline to adopt the withdrawal penalty caps proposed in
the NOPR because such caps would mute the economic signals that
withdrawal penalties are intended to send to interconnection customers
in the interconnection queue. The withdrawal penalty structure is meant
to incentivize interconnection customers to withdraw from the
interconnection queue upon receipt of network upgrade cost assignments
that make the interconnection request commercially non-viable. However,
withdrawal penalty caps would shield interconnection customers that
withdraw due to higher-cost network upgrades from consequences
proportional to the impact of that withdrawal, which can drive
cascading withdrawals, creating the need for restudies and leading to
delays. We accordingly agree with CAISO that the withdrawal penalty
caps proposed in the NOPR would disproportionately benefit
interconnection requests for larger generating facilities.\1514\ We
find that, while withdrawal penalty caps protect interconnection
customers that are allocated relatively high network upgrade costs,
they offer no such commensurate protection for interconnection
customers with lower network upgrade cost assignments, reflecting an
imbalanced withdrawal penalty structure.
---------------------------------------------------------------------------
\1514\ See CAISO Initial Comments at 23-24.
---------------------------------------------------------------------------
794. We also adopt and modify the proposed definition of
``withdrawal penalty'' in section 1 of the pro forma LGIP to address
situations in which it may be unclear what it means to be withdrawn
from the interconnection queue. Specifically, we clarify that a
withdrawal penalty applies when an interconnection customer actively
chooses to withdraw its interconnection request but also when its
interconnection request is deemed to have been withdrawn from the
interconnection queue for one reason or another, or if it otherwise
does not reach commercial operation, per the terms of the pro forma
LGIP.
795. Commenters observe that, under the NOPR proposal,
interconnection customers with large projects (in terms of MW) would be
subject to large withdrawal penalties.\1515\ While this is true for the
initial withdrawal penalty, which continues to be based on project size
because it is tied to study costs, the modification to the NOPR
proposal described above, where later withdrawal penalties are based on
percentages of identified network upgrade costs, reflects the potential
impact of a withdrawal on the remaining interconnection customers in a
cluster. Additionally, as some commenters point out, there is typically
a correlation between the size of the proposed generating facility and
the relative harm to other interconnection customers from the
withdrawal of the interconnection request, so we believe that basing
the initial withdrawal penalty on project size is appropriate.\1516\
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\1515\ See Hydropower Commenters Initial Comments at 26; rPlus
Initial Comments at 5.
\1516\ Avangrid Initial Comments at 20; CAISO Initial Comments
at 24; Idaho Power Initial Comments at 8; National Grid Initial
Comments at 26-27; PPL Initial Comments at 17.
---------------------------------------------------------------------------
796. Because we modify the process for distributing withdrawal
penalty funds in response to comments, as described below, transmission
providers will not accumulate large amounts of funds from withdrawal
penalties, and therefore Shell's concerns are moot.\1517\
---------------------------------------------------------------------------
\1517\ Shell Initial Comments at 18-19.
---------------------------------------------------------------------------
797. Furthermore, we believe the proposed pro forma LGIP section
3.7.1.2 requirement that transmission providers post on their OASIS
site, and update quarterly, the balance of withdrawal penalty revenue
held by them but not yet dispersed, and the instructions of how to
distribute withdrawal penalty funds contained in this provision provide
sufficient transparency to help interested parties understand, monitor,
and review withdrawal penalty funds. Transmission providers have
substantial experience collecting and accounting for fees assessed to
customers, and we will not mandate here what accounting method they
should use for the collection and tracking of withdrawal penalties.
798. With respect to the distribution of withdrawal penalty funds,
we adopt the NOPR proposal to require transmission providers to use
withdrawal penalty funds to fund studies and restudies conducted under
the cluster study process, with modification. Specifically, we adopt a
structure whereby, if interconnection customers withdraw and are
subject to withdrawal penalties, the transmission provider must use the
withdrawal penalty funds as follows: (1) to fund studies and restudies
in the same cluster; (2) if withdrawal penalty funds remain, to offset
net increases in costs borne by other remaining interconnection
customers from the same cluster for network upgrades shared by both the
withdrawing and non-withdrawing interconnection customers prior to the
withdrawal; and (3) if any withdrawal penalty funds remain, they will
be returned to the withdrawing interconnection customer.
799. We believe that using withdrawal penalty funds to reduce
network upgrade cost shifts caused by withdrawals will reduce the risk
that the shifted costs are so large as to cause cascading withdrawals,
thus ensuring that interconnection customers are able to interconnect
in a reliable, efficient, transparent, and timely manner. We agree with
Invenergy that it is appropriate for there to be a relationship between
the impact caused by the withdrawal of an interconnection request and
how the withdrawal penalty funds are distributed. We also are persuaded
by Invenergy, PJM, NextEra, and Southern that there are benefits to
distributing withdrawal penalty funds to other interconnection
customers remaining in the cluster to offset increased network upgrade
costs resulting from the withdrawal.\1518\ We therefore modify the NOPR
proposal and revise section 3.7.1 of the pro forma LGIP consistent with
the discussion below.
---------------------------------------------------------------------------
\1518\ Invenergy Initial Comments at 27-28; NextEra Initial
Comments at 27-28; PJM Initial Comments at 39; Southern Initial
Comments at 20-21.
---------------------------------------------------------------------------
800. In the paragraphs that follow we summarize the steps a
transmission provider must follow in distributing withdrawal penalty
funds, as fully detailed in section 3.7.1.2 of the pro forma LGIP, and
we present an illustrative example.
801. Section 3.7.1.2.1 of the pro forma LGIP describes the
transmission provider's handling of withdrawal penalty funds and the
first step of distributing them to fund studies and restudies. For a
single cluster, the transmission provider shall hold all withdrawal
penalty funds until all interconnection customers in that cluster have:
(1) withdrawn or been deemed withdrawn; (2) executed an LGIA; or (3)
requested an LGIA to be filed unexecuted. Any withdrawal penalty funds
collected shall first be used to fund studies for interconnection
customers in the same cluster that have executed an LGIA or requested
an LGIA to be filed unexecuted. Distribution of the withdrawal penalty
funds for such
[[Page 61127]]
study costs shall not exceed the total actual study costs.
802. Section 3.7.1.2.2 of the pro forma LGIP provides that if,
after the first distribution step is complete, withdrawal penalty funds
remain, the transmission provider must proceed to the second step of
distributing them to offset net increases in network upgrade cost
assignments driven by the withdrawal. The transmission provider will
determine if the withdrawn interconnection customers, at any point in
the cluster study process, shared cost assignment for one or more
network upgrades with any remaining interconnection customers in the
same cluster based on the cluster study report, cluster restudy
report(s), interconnection facilities study report, and any subsequent
issued restudy report for the cluster.
803. If the transmission provider determines that withdrawn
interconnection customers shared cost assignment for network upgrades
with remaining interconnection customers in the same cluster, the
transmission provider will calculate the remaining interconnection
customers' net increase in costs (i.e., financial impact) due to a
shared cost assignment for network upgrades with the withdrawn
interconnection customer. It will then distribute withdrawal penalty
funds as described in section 3.7.1.2.3 of the pro forma LGIP,
depending on whether the withdrawal occurred before the withdrawing
interconnection customer executed an LGIA (i.e., during the cluster
study process) or after.
804. If the transmission provider determines that more than one
interconnection customer in the same cluster was financially impacted
by the same withdrawn interconnection customer, the transmission
provider will apply the relevant withdrawn interconnection customer's
withdrawal penalty to reduce the financial impact to each impacted
interconnection customer based on each withdrawn interconnection
customer's proportional share of the financial impact. Each
interconnection customer's proportional share will be determined by
either the proportional impact method if the net cost increase is
related to a system network upgrade or on a per capita basis if the net
cost increase is related to a substation network upgrade.
805. Section 3.7.1.2.4 of the pro forma LGIP details the process by
which the transmission provider will provide amended LGIAs to any
interconnection customers in the cluster that qualify for distribution
of withdrawal penalty funds under this framework. To account for
withdrawals that occurred during the cluster study process, the
transmission provider must do the following: Within 30 calendar days of
all interconnection customers in the same cluster having: (1) withdrawn
or been deemed withdrawn; (2) executed an LGIA; or (3) requested an
LGIA to be filed unexecuted, determine if, and to what extent, any
interconnection customers qualify to have their increased network
upgrade costs offset by withdrawal penalty funds and provide such
interconnection customers with an amended LGIA that provides the
reduction in network upgrade cost assignment and associated reduction
to the interconnection customer's financial security requirements.
806. To account for withdrawals that occurred in the same cluster
after the withdrawing interconnection customer executed an LGIA, or
requests the filing of an unexecuted LGIA, the transmission provider
must do the following: Within 30 calendar days of such withdrawal or
termination, determine if, and to what extent, any interconnection
customers qualify to have their increased network upgrade costs offset
by withdrawal penalty funds and provide such interconnection customers
with an amended LGIA that provides the reduction in network upgrade
cost assignment and associated reduction to the interconnection
customer's financial security requirements.
807. For any given withdrawal, if the transmission provider
determines that there are no network upgrade cost assignments in the
withdrawn interconnection customer's cluster shared with the withdrawn
interconnection customer, or if the transmission provider determines
that the withdrawn interconnection customer's withdrawal did not cause
a net increase in the shared cost assignment for any remaining
interconnection customers in the cluster, the transmission provider
must return the remaining withdrawal penalty to the withdrawn
interconnection customer. Such remaining withdrawal penalties will be
returned to withdrawn interconnection customers based on the proportion
of each withdrawn interconnection customer's contribution to the total
amount of withdrawal penalty funds collected for the cluster. The
transmission provider must make such disbursement within 60 calendar
days of the date on which all interconnection customers in the same
cluster have either (1) withdrawn or been deemed withdrawn; (2)
executed an LGIA; or (3) requested an LGIA to be filed unexecuted.
808. By way of example, assume that the transmission provider's
proportional impact method identifies that interconnection customers A,
B, and C in the same cluster all contribute to the need for system
network upgrade A, estimated at $40 million, in the proportions of 50%,
25% and 25%, respectively. Interconnection customer C withdraws from
the interconnection queue after the facilities study, but before
executing, or requesting the unexecuted filing of, the LGIA and pays a
withdrawal penalty of $1 million.\1519\ System network upgrade A is
still required for interconnection customers A and B, and when the
transmission provider conducts the proportional impact method in the
cluster restudy for the same cluster, it now determines that
interconnection customer A's revised network upgrade cost allocation
for system network upgrade A would increase to 67% and interconnection
customer B's revised network upgrade cost allocation for system network
upgrade A would increase to approximately 33%. The transmission
provider would base the distribution of this interconnection customer's
withdrawal penalty on the proportional impact analysis and credit 67%
of the $1 million to interconnection customer A and 33% to
interconnection customer B.
---------------------------------------------------------------------------
\1519\ In this example, interconnection customer C paid a $1
million withdrawal penalty because it was allocated $10 million in
network upgrade cost (i.e., 25% of $40 million) and withdrew after
receiving the facilities study report, at which point the withdrawal
penalty is 10% of the amount of network upgrades allocated to the
interconnection customer.
---------------------------------------------------------------------------
809. Finally, section 3.7.1.2.5 of the pro forma LGIP provides that
if, after the first and second distribution steps are complete, some or
all of an interconnection customer's withdrawal penalty remains, the
transmission provider must return the balance of the withdrawn
interconnection customer's withdrawal penalty funds to the withdrawn
interconnection customer.
810. In response to commenter's concerns regarding the ability of
transmission providers to collect withdrawal penalties from
interconnection customers,\1520\ we further clarify that, in addition
to study deposits, transmission providers must apply commercial
readiness deposits received from the interconnection customer that
exceed the costs that the transmission provider has incurred, including
interest calculated in accordance with Sec. 35.19a(a)(2) of the
Commission's regulations, toward any
[[Page 61128]]
withdrawal penalties assessed to the interconnection customer, in
accordance with pro forma LGIP section 3.7.
---------------------------------------------------------------------------
\1520\ APS Initial Comments at 16; EEI Initial Comments at 8;
Eversource Initial Comments at 19; MISO Initial Comments at 69.
---------------------------------------------------------------------------
811. In response to NV Energy and Invenergy, we clarify that an
interconnection customer that withdraws during any time in the
interconnection process is responsible for the applicable withdrawal
penalty as well as the costs incurred to perform studies up to that
point, and withdrawal penalty amounts will not be applied toward
incurred study costs. Additionally, in response to NV Energy, we
clarify that if any portion of a generating facility proposed in an
interconnection request achieves commercial operation, even if less
than the original requested MW amount, the interconnection customer
will not be subject to withdrawal penalties.
812. In response to Tri-State, we clarify that the phrase
``regardless of any previous Withdrawal Penalty revenues received'' in
pro forma LGIP section 3.7.1.1 means that the withdrawal penalty will
be calculated based on actual study costs and will exclude any credits
to the study costs from penalties assessed to and received from other
interconnection customers.
813. We disagree with commenters that assert that a technical
conference is needed to further develop the record on withdrawal
penalties before finalizing requirements in this final rule. For the
reasons explained above, we believe that the record supports the
reforms that we adopt herein and that their adoption is needed to
ensure that interconnection customers are able to interconnect in a
reliable, efficient, transparent, and timely manner.
7. Transition Process
a. NOPR Proposal
814. In the NOPR, the Commission proposed to revise the pro forma
LGIP to require transmission providers to establish a transition
process for moving to a first-ready, first-served cluster study
process.\1521\ Specifically, the Commission proposed to require
transmission providers to offer existing, eligible interconnection
customers the options to either enter a transitional serial
interconnection facilities study or a transitional cluster study,\1522\
with commercial readiness requirements, or withdraw from the
interconnection queue without penalty.
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\1521\ NOPR, 179 FERC ] 61,194 at P 156.
\1522\ In the NOPR, the Commission explained that the
transmission provider would consider all interconnection requests
accepted within a standard cluster study request period have equal
queue priority for purposes of the cluster study. See id. P 67. This
would be true for all interconnection requests accepted for the
transitional cluster study as well, per the NOPR.
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815. To proceed to the transitional serial study, the Commission
proposed that eligible interconnection customers (i.e., interconnection
customers that have executed a facilities study agreement before the
effective date of the transmission provider's compliance filing) would
execute a transitional serial interconnection facilities study
agreement to codify their choice.\1523\ The Commission proposed that at
the time of execution of such agreement, the interconnection customer
would be required to provide a deposit equal to 100% of the
interconnection facility and network upgrade costs allocated to the
interconnection customer in the system impact study report. The
Commission explained that if the interconnection customer's proposed
generating facility reaches commercial operation, this deposit would be
used toward construction costs of the same facilities.
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\1523\ Id. P 158.
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816. The Commission further explained that if the interconnection
customer withdraws, the deposit would be refunded after the final
invoice for study costs and the withdrawal penalty are settled. The
Commission proposed that the transitional serial study withdrawal
penalty would equal nine times the study cost. The Commission also
proposed that transitional serial generating facilities would be
required to provide evidence of exclusive site control for the entire
generating facility and any interconnection customer's interconnection
facilities, as well as demonstrate commercial readiness through one of
the following: (1) an executed term sheet (or comparable evidence)
related to a contract for the sale of the generating facility's output
or its energy/ancillary services; (2) reasonable evidence that the
generating facility is included in a resource planning entity's
resource plan, has received a contract via a resource solicitation
process, or is being developed for a large end-use customer; or (3) a
provisional LGIA that is not suspended and includes a commitment to
build the generating facility. The Commission proposed that the
deadline for the interconnection customer to meet all the provisions
above would be 60 calendar days after the effective date of a
transmission provider's compliance filing to the final rule. Finally,
the Commission proposed that the transmission provider complete
transitional serial studies within 90 calendar days after the deadline
for eligibility requirements to be satisfied.\1524\
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\1524\ NOPR, 179 FERC ] 61,194 at P 158.
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817. The Commission proposed that existing interconnection
customers that opt for the transitional cluster study would execute a
transitional cluster study agreement to codify their choice.\1525\ The
Commission proposed that interconnection customers may make a one-time
extension of their requested commercial operation date upon entry into
the transitional cluster study, where any such extension shall not
result in a commercial operation date later than December 31, 2027. The
Commission proposed that the costs of this study and the identified
facilities would be allocated as the costs are allocated for future
cluster studies, as set forth in this final rule. The Commission also
proposed that the transitional cluster would be subject to an expedited
combined system impact and interconnection facilities study. The
Commission explained that transitional cluster study generating
facilities would be required to select ERIS or NRIS. The Commission
proposed to require interconnection customers opting for a transitional
cluster study to make a $5 million deposit. The Commission proposed to
subject this deposit to the same conditions as the transitional serial
study deposit.
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\1525\ Id. P 159.
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818. The Commission also proposed to require interconnection
customers with interconnection requests in the transitional cluster to
produce evidence of exclusive site control for their entire generating
facilities and demonstrate commercial readiness through one of the same
three options described above for transitional serial studies.\1526\
The Commission proposed that the deadline to satisfy these requirements
would be 60 calendar days after the effective date of a transmission
provider's compliance filing to the final rule. Finally, the Commission
proposed that the transitional cluster study be completed by the
transmission provider within 300 calendar days after the deadline for
eligibility requirements to be satisfied.
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\1526\ Id. P 159.
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819. The Commission sought comment on: (1) whether certain
interconnection customers with pending interconnection requests
submitted prior to the issuance of a final rule should be allowed to
proceed to LGIA execution without entering the transition process; (2)
whether the Commission should require transmission providers to accept
any additional commercial readiness demonstrations for entry into the
[[Page 61129]]
transition process, and whether existing interconnection customers
should be permitted to enter their interconnection requests into the
transitional cluster study process by posting a deposit in lieu of
demonstrating commercial readiness; and (3) whether $5 million is a
reasonable estimate of the costs that would be allocated to the
interconnection customer via the transitional cluster study.\1527\
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\1527\ Id. P 160.
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b. Comments
i. Comments in Support
820. A few commenters fully support the proposed transition
process.\1528\ For example, NRECA states that it strongly supports the
proposed transition process because it fulfills the Commission's goal
of ensuring an efficient way to prioritize and process interconnection
requests, based on how far they have advanced through the
interconnection process and their commercial readiness.\1529\
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\1528\ Affected Interconnection Customers Initial Comments at
13; Consumers Energy Initial Comments at 5; Idaho Power Initial
Comments at 9; Longroad Energy Reply Comments at 16; NRECA Initial
Comments at 9, 31.
\1529\ NRECA Initial Comments at 31.
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821. More commenters support the NOPR's core proposal to require
transmission providers to offer interconnection customers with existing
interconnection requests three options for moving forward (i.e.,
entering a transitional serial study, entering a transitional cluster
study, or withdrawing without penalty).\1530\ For example, Pine Gate
asserts that, given the current interconnection queue backlogs in
multiple regions, it is essential that the Commission craft a
transition process that permits late-stage interconnection requests to
finish the interconnection process under the existing rules, while
transitioning most interconnection requests to the new cluster study
process.\1531\
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\1530\ Clean Energy Associations Initial Comments at 42-43;
ENGIE Initial Comments at 7; NARUC Initial Comments at 10; NextEra
Initial Comments at 28; [Oslash]rsted Initial Comments at 13; Pine
Gate Initial Comments at 35-36.
\1531\ Pine Gate Initial Comments at 35-36; see also NextEra
Initial Comments at-+28.
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822. With respect to the transitional serial study,\1532\ many
commenters, predominantly interconnection customers, support the
proposal to provide this option to interconnection customers that have
executed a facilities study agreement.\1533\ AEE and Pine Gate state
that this provision respects the investments made by interconnection
customers based on current interconnection procedures.\1534\ Similarly,
Pattern Energy argues that, at the facilities study stage, an
interconnection customer has relatively concrete economic expectations
about its potential network upgrade obligations and should not be
required to start the interconnection process over again.\1535\
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\1532\ Note that most commenters refer to this as ``proceeding
to LGIA'' or ``proceeding to LGIA without going through the
transition process,'' while a few use the term ``transitional serial
study.'' These terms are taken to be synonymous because the NOPR
describes the transitional serial study process as permitting
interconnection customers to ``continue under the existing serial
study process, enter into an LGIA, and interconnect.'' See NOPR, 179
FERC ] 61,194 at P 158.
\1533\ AEE Initial Comments at 27; AES Initial Comments at 20;
Affected Interconnection Customers Initial Comments at 9; Idaho
Power Initial Comments at 9; Longroad Energy Reply Comments at 16;
NARUC Initial Comments at 10; NextEra Initial Comments at 28;
Northwest and Intermountain Initial Comments at 5; [Oslash]rsted
Initial Comments at 14; Pattern Energy Initial Comments at 35; Pine
Gate Initial Comments at 37; SEIA Initial Comments at 28.
\1534\ AEE Initial Comments at 27; Pine Gate Initial Comments at
37.
\1535\ Pattern Energy Initial Comments at 35.
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823. Other commenters express qualified support for the proposal.
Noting that significant investments have been made and that generating
facility contracting and financing patterns have been developed based
on existing tariffs, Interwest calls for a structured, well-noticed
transition period, to allow the market sufficient time to adjust to new
processes, especially if the new process dramatically alters
interconnection and cost allocation principles.\1536\ Similarly, the
Pennsylvania Commission agrees that a transition process is necessary
to integrate the Commission's proposed interconnection queue reforms to
allow individual interconnection customers the opportunity to decide,
based on the newly adopted minimum interconnection parameters, whether
to remain in the interconnection queue.\1537\
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\1536\ Interwest Initial Comments at 6, 23-24.
\1537\ Pennsylvania Commission Initial Comments at 15.
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ii. Comments in Opposition
824. CREA and NewSun argue that the proposed transition process is
unnecessary, as a first-ready, first-served cluster study process
places the decision to enter a cluster in the hands of the
interconnection customer regardless of whether there are previously
queued interconnection requests.\1538\ In a similar vein, EEI contends
that it would be reasonable to require transmission providers to
establish their own transition processes or to allow existing
interconnection customers to proceed to LGIA execution without entering
the transition process.\1539\
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\1538\ CREA and NewSun Initial Comments at 79.
\1539\ EEI Initial Comments at 9.
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825. CREA and NewSun also fault the proposal to treat all
interconnection requests in a transitional cluster as having a single
queue priority because it fails to protect the investment expectations
of interconnection customers with interconnection requests that have
entered the interconnection queue.\1540\ CREA and NewSun argue that the
Commission has previously recognized that queue positions should be
respected and either grandfathered or otherwise transitioned into a
cluster study process that avoids devaluing the existing queue
position. CREA and NewSun urge the Commission to modify its proposed
cluster study process so that higher-queued interconnection requests
are given a higher-priority than lower-queued interconnection requests.
CREA and NewSun explain that this has worked in CAISO and Bonneville,
which they assert uses a similar mechanism to respect queue positions
in its transmission planning expansion process.
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\1540\ CREA and NewSun Initial Comments at 45.
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826. Shell requests that the Commission let existing processes
continue for all interconnection customers that have executed a system
impact study agreement or cluster study agreement because such
processes, while not perfect, are functioning ``well enough.'' \1541\
Illinois Commission expresses more general concern about the time
required for a transition process to be completed, noting that PJM's
transition process for a recent set of interconnection queue reforms is
expected to result in significant delays.\1542\ Such delays, Illinois
Commission contends, could prompt withdrawals and less-than-optimal use
of potential new resources, which in turn would undermine state public
policy goals and potentially threaten reliability. Longroad Energy
similarly recommends that the Commission seek to avoid creating a
situation whereby a transmission provider is forced to institute a
pause on reviewing interconnection requests, similar to PJM's recent
proposal to halt its review of interconnection requests for a two-year
period.\1543\
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\1541\ Shell Initial Comments at 37.
\1542\ Illinois Commission Initial Comments at 7.
\1543\ Longroad Energy Reply Comments at 16-17.
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iii. Comments on Specific Proposal
(a) Serial Study Eligibility and Transition Process Exceptions
827. Numerous commenters express support for one or more of the
eligibility
[[Page 61130]]
requirements proposed in the NOPR. To proceed with a transitional
serial study, Affected Interconnection Customers agree that
interconnection customers should provide evidence of exclusive site
control, demonstrate commercial readiness, and fund 100% of their
interconnection facility and network upgrade costs upfront.\1544\
Affected Interconnection Customers reason that delays in processing
interconnection requests occur if speculative interconnection requests
without adequate funding are allowed to enter and clog the serial study
process, only to drop out later and cause the need for restudies.
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\1544\ Affected Interconnection Customers Initial Comments at
10.
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828. However, Bonneville, PJM, OPSI, RWE Renewables, and NextEra
express concern that offering interconnection customers a serial study
option may be inefficient.\1545\ Bonneville states that it has received
52 interconnection requests, totaling 33 GW, in the 90 days since the
NOPR's issuance, and that completing existing studies under the current
process could delay Bonneville's ability to implement a new cluster
study process, thus diminishing its near-term benefits.\1546\ OPSI
calls for the Commission to analyze whether this option could
materially delay the transition process, and if so, consider using a
cluster study process as soon as feasible in the transition.\1547\
Similarly, RWE Renewables assert that all parties should already be on
notice about the pending changes, allowing for swifter movement to new
processes, particularly for those that have not yet had any studies
completed.\1548\ NextEra argues that it is best for all interconnection
customers at the same stage in the interconnection process to abide by
the same transition rules rather than giving them a choice between a
serial or cluster study process.\1549\
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\1545\ Bonneville Initial Comments at 14; NextEra Initial
Comments at 28; OPSI Initial Comments at 6; PJM Initial Comments at
42; RWE Renewables Initial Comments at 1-2.
\1546\ Bonneville Initial Comments at 14.
\1547\ OPSI Initial Comments at 6.
\1548\ RWE Renewables Initial Comments at 2.
\1549\ NextEra Initial Comments at 28.
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829. Several commenters suggest broadening opportunities for a
transitional serial study and/or exempting certain interconnection
requests from transitional study. AEE, Clean Energy Associations, and
Pine Gate support allowing interconnection requests with an executed or
unexecuted facilities study agreement to proceed with a serial
study.\1550\ Clean Energy Associations propose serial study eligibility
for any interconnection request that has a system impact study
underway, provided the interconnection customer can meet commercial
readiness demonstration and deposit requirements on par with what would
be required at the equivalent stage of the standard cluster study
process.\1551\ ENGIE supports a process that exempts interconnection
requests with interconnection costs of $5 million or less from a
transitional study.\1552\ ENGIE also proposes that interconnection
requests that do not contribute to the need for network upgrades and/or
do not need facilities studies be permitted to proceed to an LGIA
early.
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\1550\ AEE Initial Comments at 27; Clean Energy Associations
Initial Comments at 43; Pine Gate Initial Comments at 37.
\1551\ Clean Energy Associations Initial Comments at 43.
\1552\ ENGIE Initial Comments at 7.
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830. Cypress Creek suggests that eligibility for a transitional
serial study \1553\ be based on: (1) a specified interconnection queue
window developed through a stakeholder process that extends to late
stage interconnection requests; and (2) an objective assessment of the
plotted distribution of total network upgrades (in terms of millions of
dollars) to which the candidate interconnection request contributes,
such that the total number of interconnection requests eligible for
transitional serial and transitional cluster studies is known so
transitional studies can be completed by a reasonable deadline.\1554\
Cypress Creek states that the distribution curve of network upgrades
will help support eligibility to those interconnection requests on the
lower half of impacts. Finally, Cypress Creek suggests that the
Commission establish a date by which the transitional serial process
would conclude, and by which the transitional cluster process would
begin. Following these transitional studies, Cypress Creek recommends
that the new cluster study process commence, in lieu of the second
transitional cluster proposed by the Commission. Cypress Creek argues
that this more rapid transition process better balances interconnection
rights of late-stage interconnection requests with the need to move to
the new process compared to the proposed transition process.
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\1553\ The original term used by Cypress Creek, ``transitional
serial cluster,'' is assumed to mean transitional serial study.
\1554\ Cypress Creek Initial Comments at 25-26.
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(b) New Requirements on Existing Interconnection Customers
831. AEE, Invenergy, NESCOE, and Shell argue that it is wrong, or
could be unfairly burdensome, to impose significant new requirements on
interconnection customers that have entered and proceeded through the
interconnection queue in good faith.\1555\ Invenergy adds that this is
especially true of interconnection customers that may have entered the
interconnection queue years before the NOPR was issued.\1556\ Other
commenters make similar points.\1557\
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\1555\ AEE Initial Comments at 26; Invenergy Initial Comments at
37; NESCOE Reply Comments at 10; Shell Initial Comments at 37.
\1556\ Invenergy Initial Comments at 37.
\1557\ AEE Initial Comments at 26; EDF Renewables Initial
Comments at 8; ACE-NY Initial Comments at 4; AEE Initial Comments at
26; EDF Renewables Initial Comments at 8; Northwest and
Intermountain Initial Comments at 2, 5.
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832. AEE and EDF Renewables stress the importance of not disrupting
or further delaying interconnection requests that are well along in the
interconnection process.\1558\ ACE-NY states, more broadly, that
interconnection requests currently in serial interconnection queues
should not be unduly harmed, adding that any transition process should
not delay the commercial operation date of existing and future
generating facilities.\1559\
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\1558\ AEE Initial Comments at 26; EDF Renewables Initial
Comments at 8.
\1559\ ACE-NY Initial Comments at 4.
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833. Clean Energy Associations argue that transition
interconnection customers, whether they be in the serial or cluster
study process, should not be held to higher standards than those
interconnection customers that would proceed with the regular cluster
study process unless the transition process leads to an LGIA and
includes only ready interconnection requests that have been delayed in
the existing interconnection queue.\1560\ Invenergy concurs with this
principle, if the Commission elects to impose requirements on existing
interconnection customers.\1561\
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\1560\ Clean Energy Associations Initial Comments at 43.
\1561\ Invenergy Initial Comments at 38.
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(c) Deposits
834. Several commenters object to the proposal to require that
interconnection customers, at the time of execution of the transitional
serial study agreement, provide a deposit equal to 100% of the
interconnection facility and network upgrade costs allocated to them in
the system impact study report.\1562\ AEE and EDF Renewables argue that
the costs assigned at the system impact study stage often vary
significantly from the network upgrade costs provided at
[[Page 61131]]
the facilities study stage.\1563\ EDF Renewables also argue that the
NOPR proposal is inconsistent with Order No. 2003, which specifically
rejected such a proposal in favor of requiring security for discrete
portions of these costs.\1564\ EDF Renewables adds that requiring a
full deposit imposes a real cost on interconnection customers, which
typically obtain a letter of credit from a bank.
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\1562\ Clean Energy Associations Initial Comments at 43; Cypress
Creek Initial Comments at 26; EDF Renewables Initial Comments at 9;
Invenergy Initial Comments at 38; Pine Gate Initial Comments at 36;
SEIA Initial Comments at 28.
\1563\ AEE Initial Comments at 26-27; EDF Renewables Initial
Comments at 9.
\1564\ EDF Renewables Initial Comments at 9 (citing Order No.
2003, 104 FERC ] 61,103 at P 596).
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835. Likewise, several commenters object to the proposal to require
a $5 million deposit to proceed to the transitional cluster
study.\1565\ Most of these commenters claim that $5 million dollars is
excessive and/or arbitrary; \1566\ fails to reflect the relative impact
of smaller proposed generating facilities; \1567\ likely is not
indicative of costs across all markets; \1568\ and will prompt
otherwise viable interconnection requests to withdraw.\1569\ With
respect to the NOPR's reliance on PSCo's claim that $5 million is
within the range of interconnection costs on its system, CREA and
NewSun question whether PSCo intended the deposit to serve as a barrier
to its competitors in the generation market.\1570\ CREA and NewSun note
that the three orders cited by the Commission in the NOPR mention a $5
million deposit, but none provide a reasoned decision for acceptance of
this deposit amount.\1571\ Conversely, Xcel asserts that $5 million
dollars is a low estimate of costs that may ultimately be allocated to
interconnection customers.\1572\
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\1565\ AEE Initial Comments at 26; Clean Energy Associations
Initial Comments at 43; CREA and NewSun Initial Comments at 81; EDF
Renewables Initial Comments at 9; Invenergy Initial Comments at 38;
Northwest and Intermountain Initial Comments at 5; Pine Gate Initial
Comments at 36.
\1566\ AEE Initial Comments at 26; Clean Energy Associations
Initial Comments at 43; CREA and NewSun Initial Comments at 81; EDF
Renewables Initial Comments at 9; Pine Gate Initial Comments at 36.
\1567\ CREA and NewSun Initial Comments at 81; EDF Renewables
Initial Comments at 9.
\1568\ AEE Initial Comments at 26; CREA and NewSun Initial
Comments at 81; Pine Gate Initial Comments at 36.
\1569\ AEE Initial Comments at 26.
\1570\ CREA and NewSun Initial Comments at 81.
\1571\ Id. at 81-82 (citing Pub. Serv. Co. of Colo., 169 FERC ]
61,182; Tri-State Generation & Transmission Ass'n, Inc., 173 FERC ]
61,015; Tri-State Generation & Transmission Ass'n, Inc., 174 FERC ]
61,021 (2021).
\1572\ Xcel Initial Comments at 36.
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836. AEE, Invenergy, and Pine Gate recommend that the deposit for
either the transitional serial facilities study agreement or
transitional cluster study agreement reflect a percentage of the
network upgrade costs allocated to the interconnection customer, with
Invenergy recommending 20%.\1573\ Northwest and Intermountain and Xcel
recommend that the final rule require transmission providers to propose
a deposit amount for transitional studies that is appropriate to their
interconnection queue and their specific system configurations.\1574\
Xcel suggests that the Commission should accept proposals that use an
average of actual historical estimates of costs allocated to
interconnection customers with executed LGIAs to determine the security
required to enter the transitional cluster.\1575\
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\1573\ AEE Initial Comments at 26; Invenergy Initial Comments at
38; Pine Gate Initial Comments at 36.
\1574\ Northwest and Intermountain Initial Comments at 5; Xcel
Initial Comments at 36.
\1575\ Xcel Initial Comments at 36.
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(d) Commercial Readiness and Site Control
837. Idaho Power and Xcel emphasize the importance of requiring a
commercial readiness demonstration to enter the transition
process.\1576\ Xcel argues that if a readiness demonstration is not
required, unready interconnection requests may be in the study models
for more than three years after they execute an LGIA and when they
ultimately withdraw, which will cause delays and cascading
restudies.\1577\ Idaho Power asserts that commercial readiness
demonstrations for interconnection customers with executed LGIAs are
also critical, as their resource and network upgrades will need to be
modeled in the transitional cluster study.\1578\ NRECA proposes that
interconnection customers that show requisite site control and
commercial readiness proceed to the ``front of the line'' as ``first-
ready'' in the transition cluster process without additional
evaluation.\1579\ Both Idaho Power and EEI recommend that
interconnection customers with LGIAs, but that have suspended
interconnection-related construction, be required to meet the
commercial readiness requirements, with EEI also recommending that they
be required to demonstrate site control.\1580\
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\1576\ Idaho Power Initial Comments at 9; NRECA Initial Comments
at 31; Pattern Energy Initial Comments at 35; Xcel Initial Comments
at 36.
\1577\ Xcel Initial Comments at 36.
\1578\ Idaho Power Initial Comments at 9.
\1579\ NRECA Initial Comments at 31.
\1580\ EEI Initial Comments at 9-10; Idaho Power Initial
Comments at 9.
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838. In addition to the proposed commercial readiness demonstration
requirements, Affected Interconnection Customers recommend that
interconnection customers also be allowed to provide evidence of (1)
major equipment either contracted to purchase or owned as part of an
existing equipment fleet or (2) a completed engineering package under
provisional LGIAs.\1581\ SEIA recommends that interconnection customers
be allowed to demonstrate commercial readiness by providing a
commitment to participate in RTO/ISO markets or an application for a
site permit.\1582\
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\1581\ Affected Interconnection Customers Initial Comments at
10-11.
\1582\ SEIA Reply Comments at 12.
---------------------------------------------------------------------------
839. A number of commenters oppose the NOPR's proposed commercial
readiness requirements, as applied to the transition process.\1583\
SEIA states that the proposed requirements will be nearly impossible
for an independent power producer to meet and ignore the very nature of
a capacity market, which is to allow independent power producers to
sell capacity into a market.\1584\
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\1583\ AEE Initial Comments at 26; CREA and NewSun Initial
Comments at 79; Pine Gate Initial Comments at 36; SEIA Initial
Comments at 29.
\1584\ SEIA Initial Comments at 28.
---------------------------------------------------------------------------
840. Several commenters support allowing a deposit in lieu of
demonstrating commercial readiness, as applied to the transition
process.\1585\ Pattern Energy argues for this option to be available
specifically for the transitional cluster study and recommends a $5
million deposit value.\1586\ Pattern Energy claims that this would
balance the need for interconnection customers that may have been
waiting for years to have their interconnection requests studied with
the need to transition to a new process. SEIA and Pine Gate recommend
that a commercial readiness deposit should be the norm, not the
exception, with SEIA also recommending that interconnection customers
be required to provide evidence of site control.\1587\ Pine Gate
recommends a readiness deposit framework that requires interconnection
customers to make incrementally at-risk payments throughout the
interconnection process.\1588\
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\1585\ AEE Initial Comments at 26; EDF Renewables Initial
Comments at 9; Invenergy Initial Comments at 38; Pattern Energy
Initial Comments at 35.
\1586\ Pattern Energy Initial Comments at 35.
\1587\ SEIA Initial Comments at 29.
\1588\ Pine Gate Initial Comments at 36.
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841. At the same time, several commenters oppose permitting
deposits in lieu of demonstrating commercial readiness, as applied to
the transition process.\1589\ Ameren calls such deposits
``opportunities for delay'' that will not facilitate the
interconnection of
[[Page 61132]]
interconnection requests for which the interconnection customer has
demonstrated commercial readiness.\1590\ Idaho Power opposes the option
because the transitional cluster study is an expedited, combined system
impact and interconnection facilities study.\1591\ If the Commission
does allow a deposit, EEI argues that the option should apply only in
specific circumstances, and should be sufficiently high to deter
interconnection requests that are not ready from entering the
transitional cluster.\1592\
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\1589\ Ameren Initial Comments at 19; EEI Initial Comments at
10; Idaho Power Initial Comments at 9; Xcel Initial Comments at 36.
\1590\ Ameren Initial Comments at 19.
\1591\ Idaho Power Initial Comments at 9.
\1592\ EEI Reply Comments at 10.
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(e) Withdrawal Penalties
842. Many commenters oppose the NOPR's proposed transition process
withdrawal penalties.\1593\ CREA and NewSun, Pine Gate, and
[Oslash]rsted call the penalties harsh or draconian.\1594\
[Oslash]rsted notes that offshore wind project interconnection
customers with contracts awarded via a state-sponsored resource
solicitation process have already spent tens of millions of dollars to
secure leaseholds, conduct extensive geotechnical studies of these
lease areas, and engineering studies.\1595\ Given these investments,
[Oslash]rsted contends that the decision to withdraw from the
interconnection queue is most likely going to be based on some issue
outside of the control of the interconnection customer, such as supply
chain constraints, and not because the interconnection request will not
go forward at some point.
---------------------------------------------------------------------------
\1593\ AEE Initial Comments at 26; AES Initial Comments at 20;
CREA and NewSun Initial Comments at 79; EDF Renewables Initial
Comments at 8; [Oslash]rsted Initial Comments at 14; Pine Gate
Initial Comments at 36; SEIA Initial Comments at 37.
\1594\ CREA and NewSun Initial Comments at 79; [Oslash]rsted
Initial Comments at 14; Pine Gate Initial Comments at 36.
\1595\ [Oslash]rsted Initial Comments at 14.
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843. AES states that withdrawal should be penalty-free if an
interconnection customer decides not to move forward with a proposed
generating facility during the transition.\1596\ EDF Renewables asserts
that a transition process should offer existing interconnection
customers an opportunity to exit the interconnection queue in line with
what they expected when entering.\1597\ SEIA recommends that the
withdrawal penalty for interconnection customers in the transitional
cluster study be capped at the withdrawing interconnection request's
allocation of network upgrade costs.\1598\
---------------------------------------------------------------------------
\1596\ AES Initial Comments at 20.
\1597\ EDF Renewables Initial Comments at 8.
\1598\ SEIA Initial Comments at 37.
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(f) Compliance Timeline
844. NRECA supports the NOPR's proposed timeline for
compliance.\1599\ NRECA states that the 180-day \1600\ period proposed
in the NOPR would be sufficient to allow interconnection customers to
get their deposits, site control, and commercial readiness
demonstrations in order.\1601\ PPL states that transmission providers
should continue moving requests to the LGIA execution stage and have
interconnection customers demonstrate commercial readiness as normal
until the effective date of the transition process.\1602\
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\1599\ NRECA Initial Comments at 32; PPL Initial Comments at 18.
\1600\ Note that the proposed deadline for transmission
providers to submit a compliance filing is within 180 calendar days
of the effective date of the final rule. The proposed deadline for
interconnection customers to meet the requirements for transitional
serial study or transitional cluster study is 60 calendar days after
the Commission-approved effective date of a transmission provider's
filing in compliance with this final rule.
\1601\ NRECA Initial Comments at 32.
\1602\ PPL Initial Comments at 18.
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845. AES, CREA and NewSun, and Invenergy assert that the NOPR's
proposed 60-day deadline for compliance is difficult or impossible to
meet for most interconnection customers.\1603\ Invenergy adds that the
fact of the rulemaking's existence is insufficient to put
interconnection customers on notice of potential reforms, given that
any aspect of the NOPR could be modified in the final rule and be
subject to variations in compliance filings.\1604\ AES states that it
does not oppose requiring interconnection customers to demonstrate site
control and meet commercial readiness criteria but recommends that at
least six months be given for compliance.\1605\
---------------------------------------------------------------------------
\1603\ AES Initial Comments at 20; CREA and NewSun Initial
Comments at 79; Invenergy Initial Comments at 37-38.
\1604\ Invenergy Initial Comments at 37.
\1605\ AES Initial Comments at 20.
---------------------------------------------------------------------------
(g) Alternatives
846. Shell argues that the final rule should allow an opt-out
provision for the transition process under which transmission providers
can demonstrate their existing processes' efficiencies by detailing
their prior performance on certain measures, such as the average
duration of each interconnection study and the average length of time
from submission of an interconnection request to execution of an LGIA
or filing of an unexecuted LGIA.\1606\
---------------------------------------------------------------------------
\1606\ Shell Initial Comments at 37.
---------------------------------------------------------------------------
847. In cases where the transition process is slow due to the sheer
scale of change, Illinois Commission calls for an accelerated process
for interconnection requests that allow states to ensure reliability
and meet statutory obligations and public policy objectives.\1607\
Illinois Commission adds that such a process could be accomplished in a
narrowly tailored manner and would be more efficient than allowing
RTOs/ISOs an extended period to clear out prior interconnection queue
backlogs.
---------------------------------------------------------------------------
\1607\ Illinois Commission Initial Comments at 7-8.
---------------------------------------------------------------------------
848. CREA and NewSun propose, and SEIA supports, a transitional
cluster study process for transmission providers facing an otherwise
unmanageable volume of interconnection requests.\1608\ CREA and NewSun
assert that such a process would expedite interconnection study,
eliminate excessive deposits and penalties, permit withdrawals without
penalty if no burden is imposed on other interconnection customers,
respect queue positions and associated investment expectations of
queued interconnection requests, and avoid ``years of bottlenecks and
market distorting problems'' associated with solutions based on
readiness requirements.\1609\ CREA and NewSun state that this proposed
process draws on Bonneville, CAISO, and MISO's current practices as
examples and would take an estimated 460 days to complete,
incorporating four milestones with increasing deposits and two off-
ramps (or decision points).\1610\
---------------------------------------------------------------------------
\1608\ SEIA Reply Comments at 12.
\1609\ CREA and NewSun Initial Comments at 82, Ex. A at 4.
\1610\ Id., Ex. A at 3.
---------------------------------------------------------------------------
849. CREA and NewSun further propose to respect queue positions by
providing a separate cluster study for existing interconnection
customers that have advanced to the system impact study stage and
having interconnection requests retain queue position even as they are
studied in a cluster.\1611\ CREA and NewSun also propose to allow
interconnection customers to trade queue positions.\1612\
---------------------------------------------------------------------------
\1611\ Id., Ex. A at 2.
\1612\ Id., Ex., at 2-3.
---------------------------------------------------------------------------
(h) Tariff Language
850. Southern notes that under proposed section 5.1.1.2(2) of the
pro forma LGIP, the true-up of actual construction costs must be
completed within 30 days of a generating facility achieving commercial
operation, which appears to conflict with the true-up provisions in pro
forma LGIA article 12.2 (Final Invoice), which, Southern states,
provides that the true-up is due within six months.\1613\ Southern
requests that the Commission make
[[Page 61133]]
these provisions consistent at six months.
---------------------------------------------------------------------------
\1613\ Southern Initial Comments at 35.
---------------------------------------------------------------------------
iv. Requests for Flexibility and Clarification
851. Several commenters argue that a one-size-fits-all transition
plan is not appropriate, given the diversity of processes currently
used by transmission providers and the varying volumes of
interconnection requests in their interconnection queues.\1614\ For
instance, Duke Southeast Utilities references the Commission's
recognition that transmission providers that already have a Commission-
approved LGIP and LGIA based on a first-ready, first-served cluster
study process may not need another transition process. Duke adds that
requiring a second transition process would likely add confusion and
potentially result in waiver requests filed with the Commission.\1615\
ISO-NE states that New England does not currently suffer
interconnection queue backlogs to the same extent as other regions, and
transition provisions could have a significant impact on
interconnection requests that are currently proceeding through the
existing interconnection process.\1616\ WAPA claims that it needs
sufficient flexibility to develop new programs within its existing
appropriations (or to seek additional appropriations or spending
authority) and to accommodate Federal contracting timelines (because it
hires contractors to conduct facilities studies).\1617\
---------------------------------------------------------------------------
\1614\ Ameren Initial Comments at 19; Avangrid Initial Comments
at 8; Bonneville Initial Comments at 13; CAISO Initial Comments at
24; Duke Southeast Utilities Initial Comments at 11; EEI Initial
Comments at 10; Indicated PJM TOs Reply Comments at 42; Invenergy
Initial Comments at 39; ISO-NE Initial Comments at 33; MISO Initial
Comments at 70; NARUC Initial Comments at 10-11; National Grid
Initial Comments at 28; NEPOOL Initial Comments at 14; NYISO Initial
Comments at 12; NYTOs Initial Comments at 21; WAPA Initial Comments
at 8-9; see also Invenergy Initial Comments at 41 (asserting that,
while many of the NOPR proposals should be prospective only,
affected systems reform should apply immediately to all pending
requests and active studies).
\1615\ Duke Southeast Utilities Initial Comments at 11.
\1616\ ISO-NE Initial Comments at 33-34.
\1617\ WAPA Initial Comments at 8-9.
---------------------------------------------------------------------------
852. CAISO, Duke Southeast Utilities, and Invenergy call on the
Commission to permit transmission providers in regions that already use
a first-ready, first-served cluster study process to minimize or omit a
transition process.\1618\ CAISO recommends that transmission providers
be permitted to propose just and reasonable effective dates for each
reform.\1619\ CAISO adds that it anticipates that most reforms should
be effective with the beginning of the next cluster study after a
compliance filing is approved, but some reforms could be implemented
for existing interconnection requests in the queue, especially for
interconnection customers that may not have executed an LGIA.
Conversely, Tri-State states that a transition period will be
necessary, even for those transmission providers already employing a
first-ready, first-served cluster study process, due to changes beyond
the overarching structure of the interconnection queue, such as a
requirement for 100% site control.\1620\
---------------------------------------------------------------------------
\1618\ CAISO Initial Comments at 25.
\1618\ Id.; Duke Southeast Utilities Initial Comments at 11;
Invenergy Initial Comments at 39.
\1619\ CAISO Initial Comments at 25.
\1620\ Tri-State Initial Comments at 17.
---------------------------------------------------------------------------
853. Several commenters ask the Commission to let transmission
providers establish their own transition plans.\1621\ MISO notes that
this previously occurred after the 2008 interconnection queue technical
conference, where transmission providers were able to propose their own
transition plan in adopting a first-ready, first-served model.\1622\
Ameren, National Grid, and NEPOOL call for RTOs/ISOs, in particular, to
be allowed flexibility to develop a transition process with input from
stakeholders.\1623\ Avangrid notes that determining an equitable and
achievable transition plan was among the most challenging aspects of
the stakeholder process that led to PJM's recent interconnection queue
reform filing and asserts that other regions should have the chance for
similar deliberations.\1624\ NYTOs argue that transmission providers
should be allowed to propose: (1) setting an effective date for new
interconnection requests that will be subject to the new cluster study
process; (2) establishing an approach for the existing interconnection
queue to be seen through to completion; and (3) determining a high-
level process, including a high-level time frame for updating tariffs,
if the proposed reforms are approved.\1625\
---------------------------------------------------------------------------
\1621\ Ameren Initial Comments at 19; Avangrid Initial Comments
at 37; MISO Initial Comments at 70; National Grid Initial Comments
at 28-29; NEPOOL Initial Comments at 14; NESCOE Reply Comments at
10; NYTOs Initial Comments at 21-22.
\1622\ MISO Initial Comments at 70.
\1623\ Ameren Initial Comments at 19; National Grid Initial
Comments at 28; NEPOOL Initial Comments at 14.
\1624\ Avangrid Initial Comments at 8, 36-37.
\1625\ NYTOs Initial Comments at 21-22.
---------------------------------------------------------------------------
854. Several commenters request that the Commission clarify how the
NOPR's proposed transition process relates to PJM's transition process
accepted as part of its recent interconnection queue reforms.\1626\
OPSI requests that the final rule not extend any transition process
beyond what PJM proposed.\1627\ Indicated PJM TOs request that the
Commission allow PJM to implement its carefully negotiated transition
process to a first-ready, first-served cluster study process.\1628\ PJM
suggests that the Commission hold in abeyance any compliance filing
obligations in this proceeding until PJM has completed its proposed
transition process.\1629\ PJM argues that this would be in keeping with
the Commission's statement that it will review any filings that result
from transmission provider interconnection queue reform efforts ``based
on the record before us in those proceedings and not based on whether
they comply with the proposed reforms in this NOPR.'' \1630\ PJM also
asserts that, given the size of its interconnection queue backlog,
allowing interconnection customers the option of a transitional serial
study process will delay implementation of PJM's cluster study process
by several years and create uncertainty regarding that process.\1631\
PJM emphasizes that elsewhere in the NOPR, the Commission acknowledges
the importance of allowing transmission providers to clear their
interconnection queue backlogs quickly.\1632\
---------------------------------------------------------------------------
\1626\ Indicated PJM TOs Initial Comments at 34; OPSI Initial
Comments at 7; Pennsylvania Commission Initial Comments at 15; PJM
Initial Comments at 42; see also PJM Interconnection, L.L.C., 181
FERC ] 61,162 at PP 60-69.
\1627\ OPSI Initial Comments at 7.
\1628\ Indicated PJM TOs Initial Comments at 34.
\1629\ PJM Initial Comments at 42.
\1630\ Id. at 42-43 (citing NOPR, 179 FERC ] 61,194 at P 6).
\1631\ Id. at 43.
\1632\ PJM Reply Comments at 8-9.
---------------------------------------------------------------------------
c. Commission Determination
855. We adopt the NOPR proposal to modify section 5 of the pro
forma LGIP to establish a transition process for moving to the first-
ready, first-served cluster study process adopted in this final rule
from the existing first-come, first-served serial study process.
Specifically, we adopt the NOPR proposal to require transmission
providers to offer existing interconnection customers up to three
transition options, depending on which phase of the serial study
process their interconnection requests are in: (1) a transitional
serial study comprised of a facilities study (i.e., a transitional
serial interconnection facilities study), (2) a transitional cluster
study comprised of a clustered system impact study and individual
facilities studies, or (3) withdrawal from the interconnection
[[Page 61134]]
queue without penalty. We also adopt definitions for the reports issued
in association with options (1) and (2), respectively (i.e., a
transitional serial interconnection facilities study report and a
transitional cluster study report). As discussed below, regarding
eligibility for the transitional serial study, we modify the NOPR
proposal to require transmission providers to offer the transitional
serial study option to interconnection customers that have been
tendered a facilities study agreement, even if they have not yet
executed that agreement, as of 30 calendar days after the filing date
of the transmission provider's initial filing to comply with this final
rule. Similarly, regarding eligibility for the transitional cluster
study, we modify the NOPR proposal to require transmission providers to
offer the transitional cluster study option to interconnection
customers with an assigned queue position as of 30 calendar days after
the filing date of the transmission provider's initial filing to comply
with this final rule. We also adopt the NOPR proposals for transition
process deposits, withdrawal penalties, and deadlines. We decline to
adopt the proposal to impose a commercial readiness demonstration
requirement and adopt, with modification, the NOPR proposal for site
control requirements.
856. We concur with commenters that, given current interconnection
queue backlogs in multiple regions, it is essential that the Commission
craft a transition process. Doing so will give interconnection
customers, along with other market participants, time to adjust to new
processes and requirements. We note that many responsive commenters
support the proposed three options and, in particular, support
providing interconnection customers at the facilities study stage the
option for a transitional serial study.\1633\ We concur with NRECA that
the NOPR's proposed transition process will create an efficient way to
prioritize and process interconnection requests, based on how far they
have advanced through the interconnection process and their level of
commercial readiness. We further find that the transition process, as
adopted herein, appropriately balances the need to move expeditiously
to the new cluster study process with the need to respect the
investments and expectations of interconnection customers at an
advanced stage in the existing interconnection process.\1634\
---------------------------------------------------------------------------
\1633\ Clean Energy Associations Initial Comments at 42-43;
Consumers Energy Initial Comments at 5; ENGIE Initial Comments at 7;
Longroad Energy Reply Comments at 16; NARUC Initial Comments at 10;
NextEra Initial Comments at 28; [Oslash]rsted Initial Comments at
13; Pine Gate Initial Comments at 35-36.
\1634\ See e.g., Pub. Serv. Co. of Colo., 169 FERC ] 61,182.
---------------------------------------------------------------------------
857. We disagree with commenters that contend that the NOPR's
proposed transition process is unnecessary, should be optional, or
poses an undue risk of delay. As stated in the NOPR and affirmed in our
findings in section II of this final rule, we believe that
interconnection queue backlogs exist throughout the country, in part,
because the pro forma LGIP creates an incentive for interconnection
customers to submit multiple interconnection requests for a given
potential generating facility and remain in the interconnection queue
to determine which of those interconnection requests has the lowest
costs to interconnect.\1635\ Given this, simply moving to the new
cluster study process, as CREA and NewSun suggest, risks creating large
initial clusters, which may prevent interconnection customers from
being able to interconnect in a reliable, efficient, transparent, and
timely manner. Similarly, if transmission providers only used serial
study processes to transition, it could put existing interconnection
requests at greater risk of cascading withdrawals that would delay the
adoption of standard cluster study processes. With respect to concerns
that a transition process could introduce delays, we note that the
serial study portion of the transition process is limited to 90
calendar days, after which point the transitional cluster study
commences.
---------------------------------------------------------------------------
\1635\ NOPR, 179 FERC ] 61,194 at PP 24-35.
---------------------------------------------------------------------------
858. We decline requests to modify the proposed transitional
cluster study process to give higher-queued interconnection requests a
higher queue position than lower-queued interconnection requests. As
stated above, to address the interconnection queue backlogs that
currently exist, it is necessary to move the bulk of existing
interconnection requests to the cluster study process, and as such,
interconnection requests studied in the same cluster have equal queue
priority to avoid undue discrimination.
859. We also decline calls to modify the NOPR proposal to require
that: (1) interconnection customers electing the transitional serial
study must provide a deposit equal to 100% of the interconnection
facility and network upgrade costs allocated to the interconnection
customer in the system impact study; and (2) interconnection customers
electing the transitional cluster study must provide a deposit equal to
$5 million. As noted earlier, the transition process is anticipated to
involve more interconnection customers than standard annual clusters
(due to existing interconnection queue backlogs), which greatly
increases the risk of late-stage withdrawals. Adopting deposit
requirements for the transitional studies higher than those adopted for
the cluster study process will help to ensure that the transitional
process is used by interconnection customers that intend to proceed
with their proposed generating facilities. In response to arguments
that the proposed deposit amounts are arbitrary and/or excessive, we
note that they are based on expected costs to the extent practicable
and that only a portion of these deposits are ultimately at-risk. That
is, the withdrawal penalty is set at nine times the study cost, as
discussed below, with the remainder of deposits to be refunded.\1636\
We also note that existing interconnection customers that are currently
in an interconnection queue can opt to withdraw their interconnection
requests without penalty and wait for the first standard cluster study
with associated lower deposit requirements. Finally, with respect to
EDF Renewable's claim that the transitional serial study deposit
conflicts with the Commission's intentions in Order No. 2003, we find
that the heightened need to avoid late-stage withdrawals during the
transition process--a need that the Commission could not have
anticipated in Order No. 2003--warrants the transitional use of this
requirement for the transitional serial study.
---------------------------------------------------------------------------
\1636\ See supra section III.A.7.a. Also, as one indicator of
study costs, NV Energy states that, on average, it spends between
$80,000 and $100,000 between the clustered system impact study and
facilities studies. See supra section III.A.6.a.
---------------------------------------------------------------------------
860. We adopt the NOPR proposal that the transitional study
withdrawal penalty should equal nine times the study cost. The
withdrawal penalty plays an important role in deterring speculative
interconnection requests in both the standard cluster study and the
transition process. We disagree with commenters that call for a lower
penalty to apply during the transition process, given that the risk of
withdrawals is heightened during the transition process. With respect
to [Oslash]rsted's contention that offshore wind developers will likely
withdraw interconnection requests solely due to circumstances beyond
their control, we note that, regardless of the cause, a withdrawal may
cause harm to other interconnection customers in the transition
process. Thus, we find it appropriate to impose penalties on
[[Page 61135]]
those that choose to withdraw notwithstanding that withdrawal may at
times be due to circumstances beyond the interconnection customer's
control. Interconnection customers will bear the risk of withdrawal
penalties and consider that risk in deciding whether to elect to join a
transition process.
861. We recognize that some transmission providers have existing
cluster studies in progress and others have Commission-approved
transition plans in progress. We emphasize 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. With
respect to concerns about duplicative transition processes, we clarify
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.
862. We are not persuaded by commenters' requests to permit
transmission providers to establish their own transition plans.
Transmission providers would likely require months-to-years to develop
and execute their own transition plans, given the need for stakeholder
dialogue and internal approval, followed by Commission review and
approval. We find that the benefits of moving forward with an
efficient, standardized transition process outweigh the potential
benefits of relying on tailor-made transition processes developed by
each transmission provider and its stakeholders.
863. Likewise, we decline to adopt any of the alternatives put
forth by commenters. We are not persuaded by Shell's proposal to allow
transmission providers to ``opt-out'' of the transition process based
on their prior performance. We view the existing serial study process
as inherently more prone to cascading withdrawals and delays, and thus
ill-suited to a transition period intended to set the stage for a
standard cluster study process. We view the Illinois Commission's
proposal for an accelerated process (for interconnection requests
related to states' objectives) in regions that may propose a lengthier
transition process timeline, as more appropriately addressed by
transmission providers in individual compliance filings. And, given the
need for even more stringent requirements in a transition process
discussed earlier, we view CREA and NewSun's proposal to use
progressively increasing deposits, during a transition process, as
inherently ill-suited to address major interconnection queue backlogs.
864. Finally, we decline calls to modify the NOPR proposal to
require interconnection customers to meet transitional serial study
eligibility requirements in 60 days after the Commission-approved
effective date of a transmission provider's filing in compliance with
this final rule. Given that we do not adopt the proposed commercial
readiness demonstration requirements, we find that the 60-calendar day
deadline provides interconnection customers with sufficient time to
adjust to the new requirements, i.e., to choose a transition option
and, depending on the option chosen, demonstrate site control and
provide a deposit. Furthermore, we concur with NRECA that this period
will be augmented, in practice, by the 90-calendar day period afforded
to transmission providers to submit their compliance filings.\1637\
---------------------------------------------------------------------------
\1637\ See infra section IV.C.
---------------------------------------------------------------------------
i. Transition Process Eligibility and Exceptions
865. As stated above, we modify the NOPR proposal regarding the
eligibility for the transitional serial study and transitional cluster
study.\1638\ Any interconnection customer that has been tendered a
facilities study agreement as of 30 calendar days after the filing date
of the transmission provider's initial filing to comply with this final
rule (even if it has not yet executed that agreement) may opt to
proceed with a transitional serial study or withdraw its
interconnection request without penalty. Transmission providers are
required to tender an LGIA, pursuant to the requirements of section 11
of the pro forma LGIP, to any interconnection customer that has
received a final facilities study report before the transmission
provider commences transitional serial studies. Any interconnection
customer that has an assigned queue position as of 30 calendar days
after the filing date of the transmission provider's initial filing to
comply with this final rule may opt to proceed with a transitional
cluster study or withdraw its interconnection request without penalty.
---------------------------------------------------------------------------
\1638\ See supra section III.A.7.c.
---------------------------------------------------------------------------
866. We find that an earlier eligibility cut-off for the
transitional studies will allow the transitional studies to begin
sooner, which in turn, will allow transmission providers and
interconnection customers to benefit from the Commission's new cluster
study process sooner. Further, we consider this modification
appropriate because interconnection customers will have 120 calendar
days after the publication of this final rule in the Federal Register
to achieve eligibility for the transition process (90 calendar days for
transmission providers to submit compliance filings, plus the 30-
calendar day eligibility cut-off).
867. Additionally, we modify the NOPR proposal to require the
transmission provider to tender the appropriate transitional study
agreements (serial and/or cluster as applicable) to eligible
interconnection customers no later than the Commission-approved
effective date of the transmission provider's compliance filing with
this final rule. We find that this requirement will help ensure that
interconnection customers are informed about their eligibility for the
transitional studies (including the associated requirements and
deadlines) in a timely manner.
868. Transmission providers are not required to tender transitional
study agreements to interconnection customers that submit an
interconnection request after the 30-calendar day eligibility cut-off
described above. Interconnection customers that submit an
interconnection request after the 30-calendar day eligibility cut-off
will be required to pay for any studies conducted by the transmission
provider under its existing tariff (as required by pro forma LGIP
section 13.3), and their interconnection requests will not be allowed
to enter the transition process, although they may enter their
interconnection requests in the transmission provider's first standard
cluster study, provided that they meet the new requirements for
interconnection requests by the close of the first cluster request
window.
869. We are persuaded by commenters' suggestion to require
transmission providers to offer the transitional serial study option to
interconnection customers that have been tendered a facilities study
agreement, even if they have not yet executed that agreement, as of 30
calendar days after the filing date of the transmission provider's
initial filing to comply with this final rule, and we modify the NOPR
proposal accordingly. We find that interconnection requests at this
point in the interconnection process are at an equivalent point as
those interconnection requests for which interconnection customers have
executed a facilities study agreement, as in both cases, the
transmission provider has completed the system impact study but has not
yet commenced the facilities study. We are not persuaded by commenters
to extend the option for
[[Page 61136]]
transitional serial study to interconnection requests at earlier stages
in the interconnection process, as such modifications may undermine the
ability of the proposed reforms to accelerate interconnection queue
processing and could delay the transition to the new, more efficient
cluster study process. We disagree with the proposal to exempt from the
transition process interconnection requests that appear, based on a
feasibility study, to require limited or no network upgrades. The
results of this feasibility study may no longer be accurate depending
on which higher-queued interconnection customers remain in the
interconnection queue after the transition date.
ii. Commercial Readiness and Site Control
870. We decline to adopt the proposed commercial readiness
demonstration options for transitional studies for the same reasons
that we are not adopting those options for cluster studies going
forward, as discussed above. We adopt with modification the NOPR's
proposed site control requirements. Specifically, we require
interconnection customers electing a transitional study, regardless of
whether they select the transitional serial study or the transitional
cluster study, to demonstrate 100% site control for their proposed
generating facilities. We find that such a requirement will provide
further assurance that such interconnection customers are ready to
proceed to construction. We modify the NOPR proposal by declining to
require that interconnection customers that choose to proceed with a
transitional serial interconnection facilities study must also
demonstrate 100% site control for any interconnection customer's
interconnection facilities because such a requirement would be overly
burdensome for interconnection customers, in addition to the other
requirements we are adopting elsewhere in this final rule. Further, we
find that this requirement is not needed to ensure that such
interconnection customers are ready to proceed to construction.
iii. Tariff Language
871. We agree with Southern's recommendation to align timelines for
truing up construction costs in the proposed pro forma LGIP section
5.1.1.2(2) and current, unmodified by this final rule, pro forma LGIA
article 12.2 (Final Invoice) by making these provisions consistent at
six months, and we modify the NOPR proposal accordingly. We agree with
Southern that consistent timelines for truing up construction costs
will provide clarity and certainty for interconnection customers.
B. Reforms To Increase the Speed of Interconnection Queue Processing
1. Elimination of the Reasonable Efforts Standard
a. Need for Reform and NOPR Proposal
872. As the Commission explained in the NOPR, the pro forma LGIP
does not require transmission providers to meet deadlines for
conducting interconnection studies.\1639\ Rather, transmission
providers are only required to use ``reasonable efforts'' to complete
interconnection studies on time.\1640\ ``Reasonable efforts'' are
defined as ``actions that are timely and consistent with Good Utility
Practice and are substantially equivalent to those a Party would use to
protect its own interests.'' \1641\ There are no explicit consequences
in the pro forma LGIP for transmission providers that fail to meet
their study deadlines.
---------------------------------------------------------------------------
\1639\ NOPR, 179 FERC ] 61,194 at P 28.
\1640\ See pro forma LGIP sections 2.2, 6.3, 7.4, 8.3.
\1641\ Order No. 2003, 104 FERC ] 61,103 at P 67; pro forma LGIP
section 1.
---------------------------------------------------------------------------
873. In the NOPR, the Commission preliminarily found that the use
of the reasonable efforts standard for transmission providers to
complete interconnection studies resulted in Commission-jurisdictional
rates that were unjust and unreasonable because: (1) the timely
provision of interconnection service was critical to maintaining just
and reasonable rates; (2) the data collected pursuant to Order No. 845
demonstrated that the failure to timely complete interconnection
studies was a significant nationwide problem, even for transmission
providers that had implemented other interconnection reforms; and (3)
the reasonable efforts standard did not provide a meaningful incentive
for transmission providers to complete their interconnection studies
within the deadlines established in their tariffs.\1642\
---------------------------------------------------------------------------
\1642\ NOPR, 179 FERC ] 61,194 at PP 165-167 (citing May Joint
Task Force Tr. 89:6-25 (Thad LeVar) (encouraging the Commission to
examine ``appropriate consequences to the transmission providers
when they [do not] comply with the tariffs,'' including by missing
study deadlines)).
---------------------------------------------------------------------------
874. The Commission proposed to revise the pro forma LGIP to
eliminate the reasonable efforts standard for transmission providers
completing interconnection studies and instead impose firm study
deadlines and establish penalties that would apply when transmission
providers fail to meet study deadlines.\1643\ Specifically, the
Commission proposed to require transmission providers that do not
complete a cluster study, cluster restudy, facilities study, or
affected system study by the deadline specified in the pro forma LGIP
to pay a penalty of $500 per each business day that the study is late,
except in situations where force majeure applies. The Commission
proposed that those penalties would be distributed to the delayed
interconnection customers on a pro rata basis to offset their study
costs. Consistent with other penalties, the Commission proposed that
such penalties would not be recoverable in transmission rates.\1644\
---------------------------------------------------------------------------
\1643\ Id. P 168.
\1644\ Id. P 169.
---------------------------------------------------------------------------
875. The Commission also proposed to cap penalties at 100% of the
total study deposit received for the late study to provide a safeguard
against overly large penalties that may be considered punitive.\1645\
The Commission further proposed that no financial penalties on
transmission providers that fail to meet study deadlines would be
assessed until one cluster study cycle (that is not a transitional
study cycle) after the Commission-approved effective date for
implementing the reforms proposed in the NOPR. Additionally, the
Commission proposed a 10-business day grace period such that no
penalties would be assessed for a study that is delayed by 10 business
days or less; for studies that are delayed by more than 10 business
days, the penalty would be calculated based on the first business day
the study was late. Further, the Commission proposed to permit the
transmission provider to extend the deadline for a particular study by
30 business days by mutual agreement of the transmission provider and
all interconnection customers in the relevant study. Finally, the
Commission proposed to require transmission providers to post to their
OASIS or a public website on a quarterly basis the total amount of such
penalties from the previous quarter and the highest amount of such
penalties paid to a single interconnection request from the previous
quarter.
---------------------------------------------------------------------------
\1645\ Id. P 170.
---------------------------------------------------------------------------
876. The Commission acknowledged that the application of penalties
for late interconnection studies in the context of RTOs/ISOs may raise
several unique issues.\1646\ However, consistent with the Commission's
findings in Order No. 890,\1647\ the Commission explained that
[[Page 61137]]
penalties are appropriate in certain circumstances to incentivize
compliance with tariff deadlines, notwithstanding the RTO's/ISO's
status as a not-for-profit entity. To ensure that RTOs/ISOs would be
able to pay any such penalties, the Commission proposed to require
RTOs/ISOs to propose tariff provisions that would require the RTO/ISO
to submit requests to recover the costs of specific interconnection
study penalties under FPA section 205. The Commission explained that,
similar to the ability of RTOs/ISOs to seek to directly assign monetary
penalties for violations of reliability standards to other responsible
entities, RTOs/ISOs could include a provision that the RTO/ISO may make
an FPA section 205 filing seeking to allocate such penalties to the
appropriate transmission owner that is responsible for, or contributed
to, the delay.\1648\ However, the Commission sought comment on whether
there was a more appropriate method for assigning such penalties in
RTOs/ISOs. More generally, the Commission sought comment on whether
penalties would effectively incentivize more timely completion of
interconnection studies in RTOs/ISOs, and/or whether monetary penalties
could have adverse consequences (e.g., compromising accuracy or
increasing waiver requests as transmission providers strive to meet
deadlines).
---------------------------------------------------------------------------
\1646\ Id. P 171.
\1647\ Preventing Undue Discrimination & Preference in
Transmission Serv., Order No. 890, 118 FERC ] 61,119, 72 FR 12226,
order on reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on
reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g,
Order No. 890-C, 126 FERC ] 61,228, order on clarification, Order
No. 890-D, 129 FERC ] 61,126 (2009).
\1648\ NOPR, 179 FERC ] 61,194 at P 172.
---------------------------------------------------------------------------
877. Additionally, the Commission sought comment on: (1) the
proposed penalty structure, including whether the penalty amount for a
cluster study should be $500 per business day or whether an approach
that accounts for the number of interconnection customers affected,
such as $100 per business day per customer in the delayed study, would
be more appropriate; (2) how and when the Commission should require
transmission providers to communicate to interconnection customers the
status of studies that may be delayed; (3) whether to include
exceptions to the penalty other than force majeure, and if so, what
those exceptions should be; and (4) whether Commission staff should
issue periodic reports summarizing the status of transmission
providers' interconnection queues and timeliness of interconnection
studies based on information collected through existing reporting
requirements, and whether this periodic report should be in addition to
or a substitute for the proposed monetary penalties discussed
above.\1649\
---------------------------------------------------------------------------
\1649\ Id. P 173.
---------------------------------------------------------------------------
b. Comments
i. Comments in Support
878. Many commenters support the NOPR proposal to eliminate the
reasonable efforts standard and establish firm interconnection study
deadlines by imposing financial penalties when transmission providers
fail to meet study deadlines.\1650\ Multiple commenters explain that
interconnection studies are often substantially delayed, which creates
uncertainty and risk in the process of bringing new generating
facilities online,\1651\ and ultimately results in an unreasonable
market barrier for new generating facilities.\1652\ NARUC contends that
the timely provision of interconnection service is critical to
maintaining just and reasonable rates.\1653\
---------------------------------------------------------------------------
\1650\ ACE-NY Initial Comments at 11-12; ACE-NY Reply Comments
at 2; ACORE Initial Comments at 4; Affected Interconnection
Customers Initial Comments at 23-25; CESA Initial Comments at 11;
Clean Energy Associations Initial Comments at 43; Clean Energy
States Initial Comments at 9; Consumers Energy Initial Comments at
5; CREA and NewSun Initial Comments at 83; CREA and NewSun Reply
Comments at 56; Cypress Creek Initial Comments at 23; ELCON Initial
Comments at 7; EPSA Initial Comments at 10-11; Evergreen Action
Initial Comments at 2; Fervo Energy Initial Comments at 5; Fervo
Energy Reply Comments at 7; Google Initial Comments at 5; Google
Reply Comments at 3, 5; Illinois Commission Initial Comments at 9;
Individual Signatories Initial Comments at 1; Interwest Initial
Comments at 8; Invenergy Initial Comments at 29-30; Iowa Commission
Initial Comments at 5; Navajo Utility Initial Comments at 12; New
Jersey Commission Initial Comments at 13-14; New Jersey Commission
Reply Comments at 1; Northwest and Intermountain Initial Comments at
14; [Oslash]rsted Initial Comments at 14; Pine Gate Initial Comments
at 38; Public Interest Organizations Initial Comments at 33; SEIA
Initial Comments at 30; TAPS Initial Comments at 3; UMPA Initial
Comments at 6-7.
\1651\ ELCON Initial Comments at 7; EPSA Initial Comments at 11;
Fervo Energy Initial Comments at 5; NARUC Initial Comments at 13-14;
Navajo Utility Initial Comments at 12; SEIA Initial Comments at 33.
\1652\ Pennsylvania Commission Initial Comments at 4; see also
AEE Reply Comments at 21, 30; Fervo Energy Reply Comments at 7;
Public Interest Organizations Initial Comments at 33 (explaining
that the slow pace of interconnection has discouraged incorporation
of new generation and stunted the transition of the transmission
system).
\1653\ NARUC Initial Comments at 13-14.
---------------------------------------------------------------------------
879. Some commenters argue that the interconnection queue backlogs
indicate that the reasonable efforts standard has not been effective in
ensuring timely access to the transmission system for new generating
facilities \1654\ nor in imposing consequences when transmission
providers fail to meet study deadlines.\1655\ Some commenters argue
that the Order No. 845 reporting data supports the conclusion that the
reasonable efforts standard has failed to ensure transmission providers
complete interconnection studies on time.\1656\ AEE argues that the
broad definition of ``reasonable efforts'' presents a high bar to prove
that interconnection study delays were unreasonable.\1657\
---------------------------------------------------------------------------
\1654\ AEE Reply Comments at 20-21; Clean Energy Associations
Initial Comments at 43; CREA and NewSun Initial Comments at 84; Iowa
Commission Initial Comments at 5; New Jersey Commission Reply
Comments at 3; Public Interest Organizations Initial Comments at 34.
\1655\ ACE-NY Reply Comments at 3; Affected Interconnection
Customers Initial Comments at 23; CREA and Newsun Initial Comments
at 83; EPSA Initial Comments at 10; Fervo Energy Initial Comments at
5; Pennsylvania Commission Initial Comments at 2.
\1656\ ACE-NY Initial Comments at 11-12; AEE Reply Comments at
18; Affected Interconnection Customers Initial Comments at 23-24;
Pennsylvania Commission Initial Comments at 2-3; UMPA Initial
Comments at 6-7.
\1657\ AEE Initial Comments at 28.
---------------------------------------------------------------------------
880. Some commenters assert that the reasonable efforts standard
results in an insufficient allocation of transmission provider
resources to process the interconnection queue \1658\ and that the risk
of penalties will provide a needed incentive for transmission providers
to complete interconnection studies on time.\1659\ Some commenters
argue that penalizing transmission providers is appropriate because
they control the staffing and study process and are in the best
position to ensure that studies are timely and accurate.\1660\ CREA and
NewSun assert that the volume of interconnection requests is unlikely
to decrease, so transmission providers need to ensure that they hire
adequate staff to meet this need.\1661\ Google cautions against taking
``implicit threats of reduced cooperation or assertions that
transmission providers cannot do any better'' seriously, noting that
any major reform to interconnection processes will entail growing
pains.\1662\
[[Page 61138]]
AEE argues that some transmission providers have improved their
generator interconnection process, which underscores that it is
feasible to hold all transmission providers to higher standards.\1663\
---------------------------------------------------------------------------
\1658\ ELCON Initial Comments at 7; Fervo Energy Initial
Comments at 5; Invenergy Initial Comments at 29-30; Northwest and
Intermountain Initial Comments at 14; see also Clean Energy
Associations Initial Comments at 43-44; NARUC Initial Comments at
14; SEIA Initial Comments at 33.
\1659\ ACE-NY Initial Comments at 12; ACE-NY Reply Comments at
3; ELCON Initial Comments at 7; EPSA Initial Comments at 11;
Evergreen Action Initial Comments at 2-3; Fervo Energy Initial
Comments at 5; Google Initial Comments at 16; Individual Signatories
Initial Comments at 1; New Jersey Commission Reply Comments at 2;
Northwest and Intermountain Initial Comments at 14; Pine Gate
Initial Comments at 38; Public Interest Organizations Initial
Comments at 34; SEIA Initial Comments at 33; TAPS Initial Comments
at 3.
\1660\ Invenergy Initial Comments at 30; SEIA Initial Comments
at 32; see also Iowa Commission Initial Comments at 5-6 (``RTOs/ISOs
need to prioritize interconnection studies and need to hold their
employees and/or outside entities responsible for delays'').
\1661\ CREA and NewSun Reply Comments at 56.
\1662\ Google Reply Comments at 4.
\1663\ AEE Reply Comments at 26.
---------------------------------------------------------------------------
881. Some commenters point out that the NOPR proposal resolves an
imbalance between interconnection customers, which are held to strict
deadlines, and transmission providers, which are currently not required
to meet study deadlines.\1664\ Some commenters assert that the proposed
penalties complement the stricter financial and readiness requirements
that the NOPR proposed to apply to interconnection customers \1665\ or
that the firm study deadlines and penalty structure are necessary to
ensure that the other NOPR proposals are successful.\1666\
---------------------------------------------------------------------------
\1664\ ACE-NY Initial Comments at 12; CREA and NewSun Initial
Comments at 83-84; ELCON Initial Comments at 8; Fervo Energy Reply
Comments at 7-8; Pennsylvania Commission Initial Comments at 2-3;
Public Interest Organizations Reply Comments at 10; SEIA Reply
Comments at 13.
\1665\ AEE Reply Comments at 19-21; APPA-LPPC Initial Comments
at 21; Clean Energy Associations Initial Comments at 43.
\1666\ ACE-NY Initial Comments at 12; EPSA Initial Comments at
11; Evergreen Action Initial Comments at 2-3; Fervo Energy Initial
Comments at 5; Individual Signatories Initial Comments at 1; New
Jersey Commission Reply Comments at 2; Pine Gate Initial Comments at
38; SEIA Initial Comments at 33.
---------------------------------------------------------------------------
882. Multiple commenters note that long interconnection delays have
economic costs for consumers, so transmission providers should also
face economic costs for failing to meet deadlines.\1667\ Navajo Utility
asserts that interconnection delays prevent it from using 100 MW of
transmission rights that it was granted through settlement, which
leaves it with an obligation to pay for transmission rights without the
ability to use them.\1668\
---------------------------------------------------------------------------
\1667\ AEE Reply Comments at 18, 30; Consumers Energy Initial
Comments at 7 (explaining that interconnection delays could create
additional costs to end-use customers because LSEs may invest in
continued operation of existing assets set to retire while new
generating facilities are delayed); Evergreen Action Initial
Comments at 2; Interwest Initial Comments at 8; Iowa Commission
Initial Comments at 5-6 (asserting that ``[d]elayed studies result
in denial of likely low-cost generation to consumers''); Navajo
Utility Initial Comments at 12 (explaining that study delays
postpone important generation, tax revenue, and construction jobs
for Navajo Nation); Northwest and Intermountain Initial Comments at
14; Public Interest Organizations Reply Comments at 10; SEIA Initial
Comments at 32; SEIA Reply Comments at 13.
\1668\ Navajo Utility Initial Comments at 12.
---------------------------------------------------------------------------
ii. Comments in Opposition
883. Many commenters, particularly transmission providers, oppose
the NOPR proposal to eliminate the reasonable efforts standard and
impose financial penalties on transmission providers for late
studies.\1669\ Further, some commenters assert that the Commission
cannot support a statutory finding under FPA section 206 to justify the
NOPR proposal \1670\ or that the NOPR proposal is not based on
substantial evidence and fails to consider important aspects of the
problem.\1671\
---------------------------------------------------------------------------
\1669\ AECI Initial Comments at 6; AEP Initial Comments at 25-
29; Alliant Energy Initial Comments at 6; Ameren Initial Comments at
20-21; Avangrid Initial Comments at 9; Bonneville Initial Comments
at 15; Dominion Initial Comments at 34; EEI Initial Comments at 14-
15; Indicated PJM TOs Initial Comments at 5, 36; Longroad Energy
Reply Comments at 14; MISO Initial Comments at 13, 71; MISO TOs
Initial Comments at 14; NextEra Initial Comments at 6, 29-30; North
Dakota Commission Initial Comments at 5; NYISO Initial Comments at
25-26; NYTOs Reply Comments at 2; Omaha Public Power Initial
Comments at 11; OMS Initial Comments at 15; Pacific Northwest
Utilities Initial Comments at 9; PacifiCorp Initial Comments at 32-
34; PG&E Initial Comments at 3-5; PJM Initial Comments at 7, 55; PPL
Initial Comments at 19; Puget Sound Initial Comments at 9; SDG&E
Reply Comments at 1; Southern Initial Comments at 5; SPP Initial
Comments at 11; Tri-State Initial Comments at 17-18; U.S. Chamber of
Commerce Initial Comments at 9; Vermont Electric and Vermont Transco
Initial Comments at 2; WAPA Initial Comments at 10; WIRES Initial
Comments at 9-10; Xcel Initial Comments at 38.
\1670\ Indicated PJM TOs Initial Comments at 38.
\1671\ Dominion Reply Comments at 20; MISO TOs Initial Comments
at 23; NYISO Reply Comments at 4-5; PG&E Reply Comments at 2-3.
---------------------------------------------------------------------------
884. Many commenters argue that it is inequitable to penalize
transmission providers for study delays because those delays are
largely due to factors outside the transmission provider's control,
including high volumes of speculative interconnection requests, a
shortage of qualified engineers, delayed data from interconnection
customers, affected system coordination, cascading restudies caused by
withdrawals, and the increasing complexity of studies due to new types
of generating facilities.\1672\ Some commenters contend that the record
supports retaining the reasonable efforts standard because third-party
forces are common to most study delays.\1673\
---------------------------------------------------------------------------
\1672\ AEP Initial Comments at 25-26; Ameren Initial Comments at
20; Avangrid Initial Comments at 9-10, 29; Dominion Reply Comments
at 19; Indicated PJM TOs Reply Comments at 22-24; ISO-NE Initial
Comments at 35-36; ISO/RTO Council Initial Comments at 3-4; MISO
Initial Comments at 73-74; MISO TOs Initial Comments at 15-16, 23-
24; National Grid Initial Comments at 30; NESCOE Reply Comments at
11-12; NRECA Initial Comments at 9, 33-34; NYISO Initial Comments at
26-27; OMS Initial Comments at 15; Pacific Northwest Utilities
Initial Comments at 9-10; PacifiCorp Initial Comments at 32-35; PG&E
Initial Comments at 7; PG&E Reply Comments at 3-4; Puget Sound
Initial Comments at 9; SDG&E Reply Comments at 1; Southern Initial
Comments at 5, 30; State Agencies Initial Comments at 12-14; Tri-
State Initial Comments at 17-18; U.S. Chamber of Commerce Initial
Comments at 10; WIRES Initial Comments at 9; Xcel Initial Comments
at 38.
\1673\ Eversource Initial Comments at 28; MISO TOs Reply
Comments at 13; PacifiCorp Initial Comments at 33; Southern Initial
Comments at 30; U.S. Chamber of Commerce Initial Comments at 10.
---------------------------------------------------------------------------
885. Some commenters argue that data from reports required by Order
No. 845 does not support the NOPR proposal.\1674\ AEP notes that the
data referenced in the NOPR represents only one year and does not
support the conclusion that transmission providers are intentionally
slow in interconnection queue processing.\1675\ MISO notes that its
Order No. 845 reports show that the majority of delays are caused by
the need to wait for affected systems studies.\1676\ NYISO states that
its August 2022 Order No. 845 report, and other recent RTO/ISO reports,
detail the various drivers of delays, which are typically outside their
control.\1677\ NYISO argues that it would not be reasoned decision-
making for the Commission to ignore these reports and draw an overly
simplistic conclusion that the reasonable efforts standard is to blame
for study delays. PG&E and Southern note that their Order No. 845 data
indicates that they have no delayed studies.\1678\
---------------------------------------------------------------------------
\1674\ AEP Initial Comments at 25; MISO Initial Comments at 72.
\1675\ AEP Initial Comments at 25-27.
\1676\ MISO Initial Comments at 14, 72.
\1677\ NYISO Initial Comments at 27-29.
\1678\ PG&E Initial Comments at 4-6; Southern Initial Comments
at 30-31.
---------------------------------------------------------------------------
886. Conversely, AEE and Public Interest Organizations respond that
commenters that claim that study delays are caused by factors beyond
transmission providers' control fail to acknowledge the availability of
potential solutions, such as increasing expenditures to attract and
retain staff and policy and process improvements.\1679\ ACE-NY asserts
that, while other parties can cause delays, transmission providers are
also responsible for delays.\1680\ SEIA argues that interconnection
request withdrawals are often similarly outside interconnection
customers' control.\1681\ AEE contends that accepting high
interconnection queue volumes as a legitimate cause for delays would
amount to providing a permanent free pass to transmission providers to
exceed study deadlines.\1682\
---------------------------------------------------------------------------
\1679\ AEE Reply Comments at 34-35; MISO TOs Initial Comments at
18; Public Interest Organizations Reply Comments at 2-4.
\1680\ ACE-NY Reply Comments at 3.
\1681\ SEIA Reply Comments at 16.
\1682\ AEE Reply Comments at 27.
---------------------------------------------------------------------------
887. Several commenters who oppose the NOPR proposal assert that
transmission providers engage in good
[[Page 61139]]
faith efforts to process the interconnection queue in a timely manner
\1683\ and that there is no evidence to the contrary.\1684\ Commenters
argue that transmission providers already have sufficient motivation to
process the interconnection queue in a timely manner because: (1) their
own interconnection requests are processed in the exact same manner as
third parties; (2) they need to ensure an adequate amount of generation
to meet load and reserve margin requirements; and (3) they have to file
reports with the Commission and can face complaints or enforcement
action for poor performance.\1685\ Commenters assert that penalties
will be ineffective in speeding interconnection queue processing time
because the main causes of study delays will remain.\1686\ MISO TOs
contend that the Commission proposes to compound the problem of study
delays by requiring transmission owners and providers to manage delays
that are out of their control, while simultaneously proposing to
require transmission providers to offer additional studies.\1687\
---------------------------------------------------------------------------
\1683\ AEP Initial Comments at 26; Avangrid Initial Comments at
29; Dominion Initial Comments at 34; EEI Initial Comments at 15;
Eversource Initial Comments at 21-22; Indicated PJM TOs Initial
Comments at 5-6, 38; MISO TOs Initial Comments at 15-17; NextEra
Initial Comments at 29; NYISO Initial Comments at 26-27; OMS Initial
Comments at 15; Puget Sound Initial Comments at 9-10; State Agencies
Initial Comments at 12; Vermont Electric and Vermont Transco Initial
Comments at 2.
\1684\ AEP Initial Comments at 26; Avangrid Initial Comments at
29; Dominion Initial Comments at 34; EEI Initial Comments at 15;
Eversource Initial Comments at 21-22; Indicated PJM TOs Initial
Comments at 5-6, 38; MISO TOs Initial Comments at 15-17; NextEra
Initial Comments at 29; NYISO Initial Comments at 26-27; Puget Sound
Initial Comments at 9-10; State Agencies Initial Comments at 12.
\1685\ AEP Initial Comments at 26; Dominion Initial Comments at
36; Indicated PJM TOs Initial Comments at 37-38; MISO TOs Initial
Comments at 16; PJM Initial Comments at 56; Puget Sound Initial
Comments at 10.
\1686\ Ameren Initial Comments at 20; Bonneville Initial
Comments at 15; Dominion Initial Comments at 34-35; Eversource
Initial Comments at 20-21; Indicated PJM TOs Initial Comments at 39-
40; MISO Initial Comments at 13, 71; NextEra Initial Comments at 30;
NextEra Reply Comments at 11; North Dakota Commission Initial
Comments at 5; PacifiCorp Initial Comments at 34; PG&E Reply
Comments at 3; PJM Initial Comments at 7-8, 56; R Street Initial
Comments at 14; Southern Initial Comments at 30; State Agencies
Initial Comments at 12.
\1687\ MISO TOs Reply Comments at 12.
---------------------------------------------------------------------------
888. NextEra argues that penalties will be counterproductive if not
paired with constructive guidance to transmission providers on how to
perform interconnection studies in a timelier manner because penalties
could either divert resources away from interconnection studies and
lead to conflict about allocating penalties in RTOs/ISOs or be accepted
as a cost of doing business.\1688\
---------------------------------------------------------------------------
\1688\ NextEra Initial Comments at 29-30.
---------------------------------------------------------------------------
889. Indicated PJM TOs contest the NOPR's citation to testimony
provided by Utah Public Service Commission Chairman Thad LeVar, noting
that Chairman LeVar also acknowledged that best practices vary between
RTO/ISO and non-RTO/ISO regions and that penalties do not always result
in the best consequences.\1689\
---------------------------------------------------------------------------
\1689\ Indicated PJM TOs Initial Comments at 38 (citing May
Joint Task Force Tr. 46:11-13, 89:17-18 (Thad LeVar)).
---------------------------------------------------------------------------
890. Some commenters argue that the NOPR proposal is an unsupported
shift from recent precedent.\1690\ Commenters note that the Commission
expressly declined to impose penalties for study delays in Order No.
845 and argue that there is no change in circumstance or concrete
evidence to justify reversal of that prior finding.\1691\
---------------------------------------------------------------------------
\1690\ EEI Initial Comments at 14; MISO Reply Comments at 21.
\1691\ MISO TOs Initial Comments at 21-22; NYISO Initial
Comments at 26; PG&E Initial Comments at 6; PG&E Reply Comments at
3.
---------------------------------------------------------------------------
891. Commenters also note that, although the Commission based its
penalty proposal on Order No. 890, there are significant
differences.\1692\ First, commenters explain that the Order No. 890
penalties only apply when a transmission provider fails to meet
multiple study deadlines, whereas the NOPR proposes to impose penalties
each time a study deadline is missed.\1693\ Second, commenters point
out that the Order No. 890 penalty structure protects due process
through an opportunity to present evidence that delays were outside the
transmission provider's control or due to extenuating circumstances,
whereas the NOPR proposal does not.\1694\ Third, PacifiCorp explains
that interconnection studies are more complex, numerous, and
susceptible to delays than the transmission service studies at issue in
Order No. 890.\1695\ Affected Interconnection Customers argue that the
Commission's comparison to Order No. 890's penalty structure for
transmission service requests is misplaced because the size and scale
of the current interconnection queue backlog is significantly different
than transmission queues when Order No. 890 was issued.\1696\
Similarly, Invenergy notes that the reference to transmission service
requests is inapplicable because the interconnection process uses a
cluster study.\1697\
---------------------------------------------------------------------------
\1692\ MISO TOs Initial Comments at 19; PacifiCorp Initial
Comments at 33-34.
\1693\ MISO TOs Initial Comments at 19; MISO Reply Comments at
21; Tri-State Initial Comments at 18.
\1694\ Eversource Initial Comments at 30; MISO Reply Comments at
21; MISO TOs Initial Comments at 19-21.
\1695\ PacifiCorp Initial Comments at 33-34.
\1696\ Affected Interconnection Customers Initial Comments at
25.
\1697\ Invenergy Initial Comments at 30.
---------------------------------------------------------------------------
892. EEI and Eversource state that the NOPR proposal represents a
departure from the good utility practice standard, which the Commission
uses in many other contexts and is part of the definition of reasonable
efforts.\1698\ EEI and Eversource assert that the Commission has not
adequately explained why reliance on good utility practice remains
sufficient in other situations, but not for interconnection studies.
---------------------------------------------------------------------------
\1698\ EEI Initial Comments at 15; Eversource Initial Comments
at 22-24.
---------------------------------------------------------------------------
893. Commenters contend that firm study deadlines are not
reasonable or feasible because interconnection studies are complex and
each study is different in scope, size, and needed coordination.\1699\
Some commenters also note that the current deadlines were established
almost 20 years ago, when the transmission providers had significantly
fewer interconnection requests to study.\1700\ SPP contends that
cluster studies are more prone to study delays given the
interdependencies between interconnection requests and number of
parties that need to cooperate.\1701\ Commenters also assert that the
other NOPR proposals, including the optional resource solicitation
study, informational studies, and evaluation of advanced transmission
technologies, add significant burdens to the study process that will
make it even more challenging to comply with strict deadlines.\1702\
---------------------------------------------------------------------------
\1699\ AECI Initial Comments at 6; Avangrid Initial Comments at
28-29; Bonneville Initial Comments at 15; Clean Energy States
Initial Comments at 10-11; Eversource Initial Comments at 27; Idaho
Power Initial Comments at 10; ISO-NE Initial Comments at 35-36; ISO/
RTO Council Reply Comments at 2; MISO TOs Initial Comments at 15;
National Grid Initial Comments at 30; PJM Initial Comments at 58;
Puget Sound Initial Comments at 10; SPP Initial Comments at 13; U.S.
Chamber of Commerce Initial Comments at 10; WIRES Initial Comments
at 10.
\1700\ Eversource Initial Comments at 27; Indicated PJM TOs
Initial Comments at 37-38.
\1701\ SPP Initial Comments at 11-12.
\1702\ Id. at 13; Indicated PJM TOs Initial Comments at 36; MISO
Reply Comments at 7; PPL Initial Comments at 24.
---------------------------------------------------------------------------
894. Some commenters express concern that the penalties could
reduce coordination between transmission providers, interconnection
customers, and affected systems.\1703\ Commenters
[[Page 61140]]
note that the enforcement of deadlines could be expensive, involve
contentious disputes, and disrupt ongoing studies.\1704\ Commenters
state that transmission providers will also likely provide less
flexibility to interconnection customers to remedy deficiencies or
modify interconnection requests.\1705\ MISO TOs assert that this could
threaten reliability.\1706\ NESCOE points out that firm penalties may
impede the interconnection of emerging technologies by limiting
flexibility to work on modeling and data requirements.\1707\
---------------------------------------------------------------------------
\1703\ Alliant Energy Initial Comments at 6; EEI Initial
Comments at 15; Eversource Initial Comments at 25-26; MISO Reply
Comments at 21; North Dakota Commission Initial Comments at 6.
\1704\ Clean Energy Associations Initial Comments at 45; EEI
Initial Comments at 15; MISO Initial Comments at 13, 71; MISO TOs
Initial Comments at 24; MISO TOs Reply Comments at 10; National Grid
Initial Comments at 30; NextEra Initial Comments at 30; OMS Initial
Comments at 15; PacifiCorp Initial Comments at 35; R Street Initial
Comments at 14; SPP Initial Comments at 14.
\1705\ Dominion Reply Comments at 21; EEI Initial Comments at
15; Eversource Initial Comments at 25-26; NYISO Initial Comments at
38-39; WIRES Initial Comments at 10.
\1706\ MISO TOs Reply Comments at 18-19.
\1707\ Id.; NESCOE Initial Comments at 17.
---------------------------------------------------------------------------
895. PJM argues that using penalties to offset study costs for
interconnection customers introduces perverse incentives for the
interconnection customer to dispute and thereby delay its study reports
to receive the penalty money.\1708\ In response, however, AEE notes
that interconnection customers bear greater costs due to delays, which
creates an incentive to move forward as quickly as possible.\1709\
---------------------------------------------------------------------------
\1708\ PJM Initial Comments at 57.
\1709\ AEE Reply Comments at 35-36.
---------------------------------------------------------------------------
896. Commenters note that the same engineers that conduct
interconnection studies also have other responsibilities such as
transmission planning \1710\ and responding to extreme weather
events.\1711\ Ameren states that penalties could motivate transmission
providers to redirect resources towards interconnection studies to the
detriment of other necessary functions.\1712\ Some commenters argue
that penalties will deprive transmission providers of financial
resources or harm work environments and employee morale, making it more
difficult to recruit and retain personnel qualified to perform the
studies.\1713\
---------------------------------------------------------------------------
\1710\ Indicated PJM TOs Initial Comments at 6.
\1711\ National Grid Initial Comments at 30.
\1712\ Ameren Initial Comments at 21.
\1713\ Eversource Initial Comments at 25-26; Indicated PJM TOs
Initial Comments at 24, 40; MISO TOs Initial Comments at 24; Pacific
Northwest Utilities Initial Comments at 12; PJM Initial Comments at
57.
---------------------------------------------------------------------------
897. A number of commenters express concern that the NOPR proposal
may result in less accurate studies because transmission providers may
prioritize meeting deadlines over accuracy and identification of the
most efficient solutions.\1714\ Some commenters further assert that
penalties may impair system reliability because the study timelines are
too short to carry out sufficient analysis.\1715\ Some commenters argue
that the penalties could force transmission providers to complete
studies without necessary data, which could also lead to inaccurate
results and cause restudy.\1716\ Some commenters state that less
accurate studies would harm interconnection customers because
interconnection customers cannot rely on them to make sound business
decisions.\1717\ Avangrid states that transmission providers could use
more conservative assumptions and ``stock solutions'' to streamline
studies, which could increase interconnection costs.\1718\ However, in
response to these comments, AEE states that the implementation of
timelines and penalties does not inherently determine the evaluation
process for clusters.\1719\ AEE notes that inaccurate study results
occur today without firm deadlines and that accuracy can be improved
even with deadlines.\1720\ New Jersey Commission disagrees that there
is an inherent tradeoff between system reliability and holding
transmission providers accountable, arguing that failing to bring
sufficient new generating facilities online can create considerable
reliability and economic risks.\1721\
---------------------------------------------------------------------------
\1714\ AECI Initial Comments at 6; Alliant Energy Initial
Comments at 6; Avangrid Initial Comments at 9-10, 30; Bonneville
Initial Comments at 15-16; CESA Reply Comments at 8; Clean Energy
Buyers Initial Comments at 10-11; Enel Initial Comments at 48;
Indicated PJM TOs Reply Comments at 26; ISO/RTO Council Initial
Comments at 8; Longroad Energy Reply Comments at 14; MISO Initial
Comments at 13, 71, 77-78; MISO TOs Initial Comments at 14, 24;
National Grid Initial Comments at 30; NESCOE Reply Comments at 13;
NextEra Reply Comments at 11; North Dakota Commission Initial
Comments at 6; NRECA Initial Comments at 34; NYISO Initial Comments
at 38-39; NYTOs Initial Comments at 24-28; Omaha Public Power
Initial Comments at 12; OMS Initial Comments at 15; [Oslash]rsted
Initial Comments at 15; PacifiCorp Reply Comments at 6; PJM Initial
Comments at 8, 56-57; PPL Initial Comments at 19; SPP Initial
Comments at 11-12; Tri-State Initial Comments at 18; Xcel Initial
Comments at 38.
\1715\ AEP Initial Comments at 28; Dominion Reply Comments at
21; NYISO Initial Comments at 39; PJM Initial Comments at 8, 56-57.
\1716\ Ameren Initial Comments at 21; MISO Initial Comments at
78; SPP Initial Comments at 12-13.
\1717\ Enel Initial Comments at 48-49; MISO Initial Comments at
78; OMS Initial Comments at 15; SPP Initial Comments at 12.
\1718\ Avangrid Initial Comments at 30.
\1719\ AEE Reply Comments at 33.
\1720\ Id. at 31-32.
\1721\ New Jersey Commission Reply Comments at 3.
---------------------------------------------------------------------------
898. Commenters express concern that the cost of penalties and
compliance mechanisms may be passed down to customers and increase
transmission costs.\1722\ Clean Energy Buyers argue that the penalties,
if they flow through to interconnection customers, could outweigh the
benefits gained from other reforms and lead to disputes over the
allocation of penalty amounts.\1723\ R Street points out that the
Commission will have to ensure that transmission providers cannot
translate penalties into cost recovery at either the Federal or retail
level.\1724\
---------------------------------------------------------------------------
\1722\ Alliant Energy Initial Comments at 6-7; NARUC Initial
Comments at 19; NYISO Reply Comments at 6-7, 9; R Street Initial
Comments at 14; SEIA Reply Comments at 17; State Agencies Initial
Comments at 12; Tri-State Initial Comments at 18; Vermont Electric
and Vermont Transco Initial Comments at 2.
\1723\ Clean Energy Buyers Initial Comments at 10.
\1724\ R Street Initial Comments at 15; see also SEIA Reply
Comments at 17.
---------------------------------------------------------------------------
899. Some commenters characterize the NOPR proposal as a strict
liability approach to penalties and argue that it is unjust and
unreasonable, arbitrary and capricious, and a violation of due process
rights and the Administrative Procedures Act to impose penalties
without a fact-based finding of fault.\1725\ Some commenters emphasize
that the NOPR proposal provides no possibility for the transmission
provider to explain the circumstances for the delay, even though the
delay is often outside of the transmission provider's control.\1726\
Dominion argues that there are three practical concerns with the NOPR
proposal: (1) how disputes about who is at fault will be resolved; (2)
who decides fault; and (3) whether the interconnection study should be
delayed while the dispute is resolved.\1727\
---------------------------------------------------------------------------
\1725\ MISO Initial Comments at 13, 71; MISO Reply Comments at
19-20; MISO TOs Initial Comments at 18; SPP Initial Comments at 14;
NYISO Initial Comments at 40 (citing Motor Vehicle Mfrs. Ass'n of
U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43
(1983); Enforcement of Statutes, Reguls. & Orders, 123 FERC ]
61,156, at PP 50-71 (2008)); WIRES Initial Comments at 10.
\1726\ ISO-NE Initial Comments at 35; ISO/RTO Council Initial
Comments at 2; MISO Initial Comments at 7.
\1727\ Dominion Reply Comments at 24.
---------------------------------------------------------------------------
900. Some commenters argue that the reasonable efforts standard is
the right approach considering the complex dynamics of the
interconnection study process and constantly changing
circumstances.\1728\ EEI asserts that the reasonable efforts standard
is the best approach to govern the interconnection process, which is
flexible to allow for the optimum exercise of engineering judgement
while ensuring
[[Page 61141]]
accountability for egregious delays or what is not consistent with good
utility practice.\1729\ MISO TOs note that, in Order No. 2003, the
Commission explained that the reasonable efforts standard was a high
standard because parties use it when protecting their own interests and
applying this standard to all parties would ``ensure comparable
treatment.'' \1730\
---------------------------------------------------------------------------
\1728\ Avangrid Initial Comments at 10, 30-31; Bonneville
Initial Comments at 16; Indicated PJM TOs Initial Comments at 36;
NYISO Initial Comments at 30-31; PG&E Reply Comments at 3-4; WIRES
Initial Comments at 10.
\1729\ EEI Reply Comments at 16.
\1730\ MISO TOs Reply Comments at 6-7 (citing Order No. 2003,
104 FERC ] 61,103 at P 69).
---------------------------------------------------------------------------
901. NYISO contends that the reasonable efforts standard and Order
No. 845 reporting requirements provide the Commission and stakeholders
with information to evaluate the length of time taken by RTOs/ISOs to
finish studies, compare their performance, and identify and investigate
when a particular entity is systematically delaying studies, which will
allow the Commission and stakeholders to take appropriate action.\1731\
SPP proposes that the Commission retain the reasonable efforts standard
and make improvements to it or enforce it more strictly.\1732\
---------------------------------------------------------------------------
\1731\ NYISO Initial Comments at 31.
\1732\ SPP Initial Comments at 15.
---------------------------------------------------------------------------
902. WAPA notes that, as a Federal power marketing administration,
it has statutory duties that take precedence over deliverables
established by the Commission and cannot be subject to monetary
penalties without a waiver of sovereign immunity.\1733\ Avangrid notes
that many transmission providers and transmission owners do not earn
rates of return for interconnection facilities or network upgrades and
do not profit from interconnection studies, so penalties would reduce
shareholder return on equity.\1734\
---------------------------------------------------------------------------
\1733\ WAPA Initial Comments at 10.
\1734\ Avangrid Initial Comments at 30.
---------------------------------------------------------------------------
iii. Comments on Specific Proposal
903. Some commenters support eliminating the reasonable efforts
standard but do not support the proposed financial penalties.\1735\
CAISO argues that the Commission should simply prohibit late studies
and mandate firm study deadlines because the proposed penalties will
enable transmission providers to continue completing studies late if
they are willing to pay the price.\1736\ CAISO explains that, if a
transmission provider cannot meet its study deadlines, it should be
required to amend its tariff.\1737\ Other commenters, as described
below, have various comments on the specific penalty proposal.
---------------------------------------------------------------------------
\1735\ CAISO Initial Comments at 25-26; Clean Energy Buyers
Initial Comment at 9-10; MISO Initial Comments at 13, 71, 79; Shell
Initial Comments at 10.
\1736\ CAISO Initial Comments at 25-26; PG&E Reply Comments at
4.
\1737\ CAISO Initial Comments at 25-26.
---------------------------------------------------------------------------
(a) Penalty Amount
904. Some commenters advocate for larger penalties than the NOPR
proposal.\1738\ Some commenters contend that the proposed penalty
amount is de minimis \1739\ or that a $500 per business day penalty is
likely too small to prompt a change in behavior.\1740\ Cypress Creek
argues that penalties should be commensurate with the magnitude of
liquidated damages that interconnection customers face if they do not
meet their contractual deadlines.\1741\ ACE-NY proposes a penalty of
$5,000 to $25,000 per day, depending on cluster size, if the Commission
chooses a per-cluster-per-day penalty structure.\1742\ Affected
Interconnection Customers propose that the Commission adopt a penalty
of $2,500 per day capped at $2 million.\1743\ Public Interest
Organizations state that there is not sufficient consensus in the
record to move forward with the $500 per day penalty amount and suggest
that the Commission hold a technical conference to determine the final
amount.\1744\
---------------------------------------------------------------------------
\1738\ ACE-NY Initial Comments at 12; Affected Interconnection
Customers Initial Comments at 25-26; CESA Initial Comments at 11;
CESA Reply Comments at 9; Consumers Energy Initial Comments at 6;
CREA and NewSun Reply Comments at 56; Cypress Creek Initial Comments
at 24; EPSA Initial Comments at 11; Fervo Energy Initial Comments at
6; Invenergy Initial Comments at 29; Pine Gate Initial Comments at
39.
\1739\ CESA Reply Comments at 8; Invenergy Initial Comments at
29; NARUC Initial Comments at 14.
\1740\ ACE-NY Initial Comments at 12; Affected Interconnection
Customers Initial Comments at 24-26; CESA Initial Comments at 11;
Clean Energy Associations Initial Comments at 44; Consumers Energy
Initial Comments at 6; ELCON Initial Comments at 7-8; Pine Gate
Initial Comments at 39.
\1741\ Cypress Creek Initial Comments at 24.
\1742\ ACE-NY Initial Comments at 12.
\1743\ Affected Interconnection Customers Initial Comments at 5,
26; CESA Reply Comments at 9.
\1744\ Public Interest Organizations Reply Comments at 5-6.
---------------------------------------------------------------------------
905. Some commenters argue that the penalties should increase
through the study process because later-stage study delays have greater
impacts on interconnection customers, which are required to make
increasing commitments throughout the study process.\1745\ Invenergy
recommends penalty amounts of $5,000 per day for cluster studies,
$6,000 per day for cluster restudies, and $7,000 per day for facilities
studies.\1746\
---------------------------------------------------------------------------
\1745\ CESA Initial Comments at 11; Clean Energy Associations
Initial Comments at 44; CREA and NewSun Reply Comments at 57;
Invenergy Initial Comments at 30.
\1746\ Invenergy Initial Comments at 30.
---------------------------------------------------------------------------
906. Pine Gate expresses concern that the proposed penalty amounts
do not correspond to the costs imposed on interconnection customers as
a result of the late study results, explaining that the penalty amount
is dwarfed by the overall cluster study cost and that the low daily
rate would require an interconnection study to be delayed years before
the amounts would approach the study deposit amounts.\1747\ As an
example, Pine Gate refers to the most recent MISO interconnection queue
submissions: MISO received 956 interconnection requests, totaling 170.8
GW of new generation, and collected $687,980,000 in study deposits.
Pine Gate notes that, under a late study fee of $500 per day, a study
would have to be delayed 1,375,960 days--or 3,770 years--before
equaling the cost of study deposits. Further, Pine Gate explains that
the daily carrying cost on the study deposit cost at the prevailing
development loan interest rate of 10% is approximately $188,487.67.
Thus, Pine Gate states that, before the proposed 10-day grace period
has elapsed, interconnection customers will have spent $1,884,876 in
additional interest costs.
---------------------------------------------------------------------------
\1747\ Pine Gate Initial Comments at 39-40.
---------------------------------------------------------------------------
907. In response to requests for higher penalties, some commenters
argue that there is no legal or policy justification for making the
proposed penalty scheme harsher and more inequitable.\1748\ MISO argues
that NERC reliability penalties are typically assessed at under $500
per day, if at all, and NERC non-critical infrastructure protection
penalties are also assessed at far lower values. MISO contends that,
because these ``moderate risk'' violations merit such low penalties,
there is no support for $500 per day penalties for delayed
interconnection studies.\1749\
---------------------------------------------------------------------------
\1748\ MISO TOs Reply Comments at 19; NYISO Reply Comments at 1.
\1749\ MISO Reply Comments at 23.
---------------------------------------------------------------------------
908. NARUC supports the proposal to cap the penalty amount at 100%
of the total study deposit received.\1750\ Several commenters argue
that the penalty amount should be capped at an amount greater than 100%
of the total study deposit received.\1751\ Invenergy requests that the
Commission clarify that the cap is not reduced by any withdrawal
penalties.\1752\ Public Interest
[[Page 61142]]
Organizations propose that transmission providers that reach the cap
issue a compliance statement explaining in detail the source of the
delay and use penalty amounts above the cap to hire third-party
consultants to conduct interconnection studies.\1753\
---------------------------------------------------------------------------
\1750\ NARUC Initial Comments at 15.
\1751\ Interwest Initial Comments at 8; Invenergy Initial
Comments at 31; Northwest and Intermountain Initial Comments at 14.
\1752\ Invenergy Initial Comments at 31.
\1753\ Public Interest Organizations Initial Comments at 36.
---------------------------------------------------------------------------
909. Several commenters argue that the penalty amount should not be
capped.\1754\ Some commenters note that financial penalties for
interconnection customers are not capped at their study deposits.\1755\
Other commenters argue that the study deposit amount cap is not
commensurate with the harm late studies cause interconnection
customers.\1756\
---------------------------------------------------------------------------
\1754\ Id. at 35-36; ACE-NY Initial Comments at 13; AEE Reply
Comments at 37; Consumers Energy Initial Comments at 6; CREA and
NewSun Initial Comments at 84; Cypress Creek Initial Comments at 23-
24; SEIA Initial Comments at 34.
\1755\ AEE Initial Comments at 31; Northwest and Intermountain
Initial Comments at 15.
\1756\ CREA and NewSun Initial Comments at 84; SEIA Initial
Comments at 34.
---------------------------------------------------------------------------
(b) Penalty Structure
910. Some commenters suggest a per-customer per-day penalty
structure, rather than the NOPR proposal for a per-cluster per-day
structure.\1757\ AEE suggests that the Commission assess penalties
based on the higher value of $500 per day or $100 per customer per
day.\1758\ Multiple commenters oppose a penalty structure based on the
number of interconnection customers because transmission providers have
no control over the number of interconnection requests they receive and
higher request volumes lead to more complex studies with more potential
for delay.\1759\
---------------------------------------------------------------------------
\1757\ ACE-NY Initial Comments at 13; SEIA Initial Comments at
34. PG&E seeks clarification on whether the penalties will apply
per-customer per-day or per-cluster per-day. PG&E Initial Comments
at 8.
\1758\ AEE Initial Comments at 31.
\1759\ CAISO Initial Comments at 27; MISO Reply Comments at 24;
Xcel Initial Comments at 38.
---------------------------------------------------------------------------
911. Some commenters suggest a penalty structure based on the
cluster's characteristics.\1760\ Public Interest Organizations suggest
a penalty structure set as a percentage of the total study deposit
received per day.\1761\ Google recommends the penalty structure take
into account both the size of the interconnection request and the
magnitude of a study delay's impact on other interconnection requests
in the interconnection queue, which would focus penalties on delays
that have the most impact on overall processing of the interconnection
queue.\1762\ NARUC explains that the penalty should not be targeted at
the number of interconnection customers in a cluster that are delayed
but at the desirable characteristics of the generating facilities being
delayed.\1763\
---------------------------------------------------------------------------
\1760\ Google Initial Comments at 17; NARUC Initial Comments at
20-21; Public Interest Organizations Initial Comments at 34.
\1761\ Public Interest Organizations Initial Comments at 34.
\1762\ Google Initial Comments at 17.
\1763\ NARUC Initial Comments at 20-21.
---------------------------------------------------------------------------
912. Some commenters suggest that the Commission require
transmission providers to discount study costs for delayed studies by
the percentage of time they are delayed in completing such study,
subject to a maximum discount set by the Commission.\1764\ Clean Energy
States propose that, if an interconnection study is late, the
transmission provider could not charge the interconnection customers
for the cost of the study, providing the interconnection customer a
modest amount of compensation for the delay.\1765\ PacifiCorp argues
that neither the host transmission provider nor affected system
operator should be penalized if either party delays the work of the
other, especially if the delays are caused by transmission providers
that are not public utilities.\1766\
---------------------------------------------------------------------------
\1764\ AEE Initial Comments at 28-29; AEE Reply Comments at 36-
37; Clean Energy Associations Initial Comments at 45 (explaining
that, under their preferred approach, if a study took 30 calendar
days past a 150-calendar day deadline, that would result in a 20%
discount on study costs); Longroad Energy Reply Comments at 14; Pine
Gate Initial Comments at 40; SEIA Reply Comments at 17.
\1765\ Clean Energy States Initial Comments at 10-11.
\1766\ PacifiCorp Initial Comments at 37.
---------------------------------------------------------------------------
913. NRECA and Tri-State assert that the final rule should allow
transmission providers to stop or reset the clock in the event of
interconnection customer-initiated delays.\1767\ Similarly, APPA-LPPC
state that the clock should not start running on study deadlines until
after the interconnection customer submits all necessary information,
including curing any deficiencies.\1768\ Tri-State asserts that a delay
should not be penalized if it is caused by a higher-queued cluster
going through a restudy.\1769\ Tri-State also suggests that, if the
Commission moves forward with penalties for late studies, additional
language should be added requiring interconnection customers to provide
needed information within a specified time frame in order to complete
the studies. R Street claims that transmission providers can game
requirements that trigger penalties, such as by forcing requesting
parties to resubmit specifications to restart the processing
clock.\1770\
---------------------------------------------------------------------------
\1767\ NRECA Initial Comments at 34; Tri-State Initial Comments
at 19.
\1768\ APPA-LPPC Initial Comments at 21.
\1769\ Tri-State Initial Comments at 18.
\1770\ R Street Initial Comments at 15.
---------------------------------------------------------------------------
(c) Penalty Allocation and Distribution
914. Many commenters agree that transmission providers, including
RTOs/ISOs, must not pass on penalty costs to ratepayers.\1771\ Public
Interest Organizations support enabling transmission providers to
allocate penalty costs to responsible parties but recommend maintaining
presumption of fault with the transmission providers themselves and
disallowing transmission providers from recovering penalty
amounts.\1772\
---------------------------------------------------------------------------
\1771\ Clean Energy Associations Initial Comments at 44;
Consumers Energy Initial Comments at 6; Cypress Creek Initial
Comments at 24; Google Initial Comments at 18; Illinois Commission
Initial Comments at 9; NARUC Initial Comments at 15; New Jersey
Commission Initial Comments at 13-14; OPSI Initial Comments at 8-9;
SEIA Initial Comments at 34; see also Ohio Commission Consumer
Advocate Initial Comments at 13 (``Although FERC states that the
proposed penalties would not be recoverable in transmission rates,
we believe such imposition will inevitably impact ratepayers, and
not rightfully so, unless it can be clearly demonstrated that the
proposed $500/day penalty is not passed along[.]''). But see Iowa
Commission Initial Comments at 5-6 (``[I]t is not correct to assume
that the penalties would result in ultimate costs to the customers/
ratepayers as some of the stakeholders contend[.]'').
\1772\ Public Interest Organizations Reply Comments at 6, 8-9.
---------------------------------------------------------------------------
915. Several commenters support distributing the penalties
collected from transmission providers to the impacted interconnection
customers.\1773\ PG&E seeks clarification on how the penalty would be
distributed (i.e., equal distribution to each interconnection
customers, equal distribution among interconnection requests, or
distributed based on project size).\1774\ Fervo Energy supports the
proposal to require transmission providers to provide quarterly public
reports on total amounts of penalties and the highest penalty for a
single interconnection request.\1775\ Google argues that transmission
providers should make such a report available annually to state
commissions to ensure penalties are not paid by consumers.\1776\
---------------------------------------------------------------------------
\1773\ ACE-NY Initial Comments at 12; Interwest Initial Comments
at 9; NARUC Initial Comments at 14-15; Northwest and Intermountain
Initial Comments at 15.
\1774\ PG&E Initial Comments at 8.
\1775\ Fervo Energy Initial Comments at 6.
\1776\ Google Initial Comments at 20.
---------------------------------------------------------------------------
916. National Grid argues that the Commission should allow
transmission providers to recover penalties from an interconnection
customer if the customer is responsible for the delay.\1777\
---------------------------------------------------------------------------
\1777\ National Grid Initial Comments at 33.
---------------------------------------------------------------------------
[[Page 61143]]
(d) Penalty Recovery in RTOs/ISOs
917. Some commenters support the proposal to allow RTOs/ISOs to
recover the cost of specific interconnection study penalties from
transmission owners responsible for study delays through FPA section
205 filings.\1778\ ACORE recommends that RTOs/ISOs provide explicit
criteria for how they will determine which parties are responsible for
or contributed to study delays.\1779\ AEE suggests that the Commission
assign RTO/ISO penalties to transmission owners by default.\1780\ In
response to AEE's proposal, MISO TOs assert that imposing penalties on
transmission owners that did not have control over the causes of study
delays does not follow cost causation principles.\1781\
---------------------------------------------------------------------------
\1778\ ACE-NY Initial Comments at 12; CESA Reply Comments at 8-
9; Google Initial Comments at 19; NARUC Initial Comments at 17;
Public Interest Organizations Initial Comments at 35; SEIA Initial
Comments at 34.
\1779\ ACORE Initial Comments at 8.
\1780\ AEE Initial Comments at 30.
\1781\ MISO TOs Reply Comments at 20-21 (citing K N Energy, Inc.
v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992)).
---------------------------------------------------------------------------
918. Some commenters express concerns about how RTOs/ISOs will pay
penalties if no member is found responsible.\1782\ OPSI contends that,
because RTOs/ISOs rely on transmission owners to process
interconnection queues, they may be reluctant to seek penalty recovery
from them.\1783\
---------------------------------------------------------------------------
\1782\ Alliant Energy Initial Comments at 6-7; APPA-LPPC Initial
Comments at 22; NARUC Initial Comments at 18; NESCOE Initial
Comments at 16.
\1783\ OPSI Initial Comments at 9.
---------------------------------------------------------------------------
919. Several commenters oppose the proposal to allow RTOs/ISOs to
recover the cost of specific interconnection study penalties from
transmission owners responsible for study delays through FPA section
205 filings.\1784\ Such commenters assert that the proposal does not
provide sufficient detail on how penalties will work in RTO/ISO
regions.\1785\ Some commenters contend that imposing penalties on RTOs/
ISOs will not expedite interconnection studies because the penalties
will not address the actual source of study delays and will disrupt
processing of interconnection queues.\1786\ ISO-NE and MISO note that
delays may not be the fault of the RTO/ISO because transmission owners
often conduct the studies.\1787\
---------------------------------------------------------------------------
\1784\ AEP Initial Comments at 27-28; CAISO Initial Comments at
26; Dominion Initial Comments at 35-36; EEI Initial Comments at 17;
ISO-NE Initial Comments at 34-36; SPP Initial Comments at 15; TAPS
Initial Comments at 3.
\1785\ Eversource Initial Comments at 29; PJM Initial Comments
at 57.
\1786\ ISO/RTO Council Initial Comments at 2; WIRES Initial
Comments at 11.
\1787\ ISO-NE Initial Comments at 35; MISO Initial Comments at
14, 73-74.
---------------------------------------------------------------------------
920. Commenters argue that the proposed penalty system would impose
administrative and litigative burden on RTOs/ISOs and the
Commission.\1788\ Indicated PJM TOs argue that the process before the
Commission will need to be a complete de novo review.\1789\ SoCal
Edison and New York State Department note that the penalty system would
likely require additional resources to track and allocate penalties,
which could increase the cost of administering interconnection
queues.\1790\ The ISO/RTO Council claims that, under the NOPR proposal,
RTOs/ISOs will need to act as fact-finding tribunals to fairly assign
penalties before making an FPA section 205 filing, which would be a
time- and resource-consuming process at odds with the goal of reducing
interconnection study delays.\1791\ TAPS avers that RTOs/ISOs would
need precise and well-supported cases to successfully assign penalties
to responsible transmission owners.\1792\
---------------------------------------------------------------------------
\1788\ Avangrid Reply Comments at 8; CAISO Initial Comments at
26; Indicated PJM TOs Reply Comments at 27; ISO-NE Initial Comments
at 35; ISO/RTO Council Initial Comments at 3-4; MISO Initial
Comments at 16, 77; MISO TOs Reply Comments at 21-22; New York State
Department Initial Comments at 10-11; NYISO Initial Comments at 33;
PJM Initial Comments at 57-58; SoCal Edison Initial Comments at 19.
\1789\ Indicated PJM TOs Initial Comments at 44.
\1790\ New York State Department Initial Comments at 10-11;
SoCal Edison Initial Comments at 19.
\1791\ ISO/RTO Council Initial Comments at 5; see also Indicated
PJM TOs Initial Comments at 37 (explaining that it would be
difficult for RTOs to determine who is at fault for study delays).
\1792\ TAPS Initial Comments at 6-7.
---------------------------------------------------------------------------
921. Commenters contend that having RTOs/ISOs assign penalties to
responsible entities would harm coordination or create tension between
RTOs/ISOs, transmission owners, interconnection customers, and other
parties.\1793\ AEP and TAPS assert that the proposal could discourage
RTO/ISO participation.\1794\
---------------------------------------------------------------------------
\1793\ AEP Initial Comments at 27; Dominion Initial Comments at
35-36; Indicated PJM TOs Reply Comments at 6-7, 27; NextEra Initial
Comments at 30; NYISO Initial Comments at 39-40; PJM Initial
Comments at 57-58.
\1794\ AEP Initial Comments at 27-28; TAPS Initial Comments at
6.
---------------------------------------------------------------------------
922. Commenters express concern around imposing penalties on non-
profit RTOs/ISOs, which have no ability to pay fines without collecting
them from another party.\1795\ MISO contends that, for RTOs/ISOs,
penalties without specified payees are effectively a tax on LSEs.\1796\
---------------------------------------------------------------------------
\1795\ MISO Initial Comments at 13, 71; MISO TOs Reply Comments
at 20; NYISO Reply Comments at 10.
\1796\ MISO Initial Comments at 13, 72.
---------------------------------------------------------------------------
923. NYISO contends that penalties would threaten RTOs'/ISOs'
financial viability.\1797\ NYISO explains that RTO/ISO penalties and
challenges to penalty recovery have been rare. NYISO claims that there
are no examples of Commission denials of penalty cost recovery, so
RTOs/ISOs would be subject to considerable uncertainty about their
ability to recover study penalties.\1798\ NYISO argues that, if the
Commission is likely to accept RTO/ISO penalty recovery proposals, then
the penalties would serve no purpose because they would be passed to
customers and fail to incentivize RTOs/ISOs to complete studies in a
more timely manner.
---------------------------------------------------------------------------
\1797\ NYISO Initial Comments at 32.
\1798\ Id. at 37.
---------------------------------------------------------------------------
924. NYISO argues that it is unjust and unreasonable and unduly
discriminatory to apply the same level of penalties to RTOs/ISOs as
other transmission providers because they are differently situated than
other transmission providers.\1799\ NYISO states that an identical
penalty would be much more punitive on RTOs/ISOs than other
transmission providers, so any financial penalties imposed on RTOs/ISOs
should be smaller in size and slower to trigger. NYISO requests that,
if the Commission requires penalties, it allow RTOs/ISOs to propose in
their compliance filings appropriate rules for their own regions.
---------------------------------------------------------------------------
\1799\ Id. at 41.
---------------------------------------------------------------------------
925. NYISO further argues that Order Nos. 672 \1800\ and 890 do not
support subjecting RTOs/ISOs to the same penalties as non-independent
transmission providers.\1801\ NYISO argues that the proposed penalties
pose a greater risk to RTOs/ISOs than reliability penalties, which have
been assessed in rare circumstances and are subject to the Commission's
close scrutiny.\1802\ NYISO also notes that it does not conduct the
kinds of transmission studies addressed in Order No. 890, so the formal
applicability of the Order No. 890 penalty regime to RTOs/ISOs does not
mean that application of penalties to RTOs/ISOs is practicable.\1803\
---------------------------------------------------------------------------
\1800\ Rules Concerning Certification of the Elec. Reliability
Org.; & Procs. for the Establishment, Approval, & Enf't of Elec.
Reliability Standards, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006),
114 FERC ] 61,104 (2006).
\1801\ NYISO Initial Comments at 32-33.
\1802\ Id. at 33-34.
\1803\ Id. at 36.
---------------------------------------------------------------------------
926. Many commenters express concerns that RTOs/ISOs may pass
[[Page 61144]]
penalty costs through to transmission owners or ratepayers who did not
contribute to study delays, which they claim is unjust and
unreasonable.\1804\ New York State Department does not support
penalties unless they can be recovered from RTO/ISO bonuses or
shareholder profits.\1805\
---------------------------------------------------------------------------
\1804\ Id. at 32; Alliant Energy Initial Comments at 6-7; EEI
Initial Comments 17; Indicated PJM TOs Initial Comments at 37; ISO/
RTO Council Initial Comments at 3-4; NARUC Initial Comments at 18;
NEPOOL Initial Comments at 16; NESCOE Reply Comments at 11; New York
State Department Initial Comments at 10; North Dakota Commission
Initial Comments at 6; Omaha Public Power Initial Comments at 11;
OMS Initial Comments at 15; R Street Initial Comments at 14; State
Agencies Initial Comments at 12-13; TAPS Initial Comments at 3-5;
WIRES Initial Comments at 11.
\1805\ New York State Department Initial Comments at 10.
---------------------------------------------------------------------------
927. Some commenters also argue that the proposal to allow RTOs/
ISOs to recover penalties from transmission owners ignores that other
entities may be responsible for study delays.\1806\ MISO explains, for
example, that it has no mechanism to recover penalties from affected
systems and that, even for entities subject to MISO's tariff, consensus
on a penalty pass through mechanism is likely to be elusive.\1807\
Several commenters argue that, because RTOs/ISOs will have to pass
through the penalty, it will not accomplish the Commission's
goals.\1808\ NESCOE, however, disagrees that RTOs/ISOs will have to
pass through penalty costs but notes that the Commission required RTOs/
ISOs to file proposals to recover penalties incurred for reliability
standard violations case-by-case.\1809\
---------------------------------------------------------------------------
\1806\ ISO/RTO Council Initial Comments at 3-4; MISO Initial
Comments at 74.
\1807\ MISO Initial Comments at 14, 74-75.
\1808\ AEE Initial Comments at 29; APPA-LPPC Initial Comments at
22; Clean Energy States Initial Comments at 9-10; ISO/RTO Council
Initial Comments at 3-4; NESCOE Reply Comments at 12-13; Omaha
Public Power Initial Comments at 11; Public Interest Organizations
Initial Comments at 35; WIRES Initial Comments at 11.
\1809\ NESCOE Reply Comments at 12 n.44 (citing Reliability
Standard Compliance & Enf't in Regions with Reg'l Transmission Orgs.
or Indep. Sys. Operators, 122 FERC ] 61,247, at P 16 (2008)).
---------------------------------------------------------------------------
928. TAPS distinguishes NERC reliability penalties as part of a
congressionally mandated regimen, whereas the proposed penalties are
not.\1810\ TAPS notes that, while NERC reliability penalty amounts are
used to offset operational costs of NERC or other relevant entities,
the NOPR proposes to distribute penalty costs back to interconnection
customers, who are not required to use those funds to offset costs for
consumers or ratepayers.
---------------------------------------------------------------------------
\1810\ TAPS Initial Comments at 5 (citing 16 U.S.C. 824o).
---------------------------------------------------------------------------
929. TAPS also seeks clarification because the NOPR proposal
provided that penalties should not be recoverable in transmission rates
but also noted that penalties imposed on RTOs/ISOs could be handled
similarly to NERC reliability penalties, which the Commission has
previously allowed RTOs/ISOs to recover from ratepayers.\1811\ TAPS
contends that the Commission should not allow RTOs/ISOs to pass
penalties through to ratepayers or LSEs; to the extent the Commission
allows RTOs/ISOs to recover costs through FPA section 205 proceedings,
TAPS recommends that the Commission automatically waive any penalty
amount the RTO/ISO would otherwise pass to ratepayers.\1812\
---------------------------------------------------------------------------
\1811\ Id. at 3-5.
\1812\ Id. at 7-8.
---------------------------------------------------------------------------
930. Commenters argue that the proposed penalty structure lacks the
due process and fact finding associated with the RTO/ISO recovery of
NERC reliability penalties.\1813\ MISO and ISO/RTO Council explain that
NERC uses a fact-finding tribunal, which avoids the potential conflicts
of interest and process disruptions that would stem from requiring the
transmission provider to judge disputes.\1814\ Indicated PJM TOs
explain that RTOs/ISOs can only recover NERC reliability penalties from
another entity if that entity was identified and allowed to participate
in the NERC process.\1815\ Commenters note that NERC reliability
penalty amounts are calculated based on specific circumstances and that
financial penalties are not always imposed.\1816\ Further, the ISO/RTO
Council argues that the NOPR proposal to allow FPA section 205 filings
to allocate penalties is unworkable because it assumes the RTO/ISO will
be able to identify a transmission owner that is responsible for the
delay.\1817\
---------------------------------------------------------------------------
\1813\ Indicated PJM TOs Initial Comments at 43-44; ISO/RTO
Council Initial Comments at 2; MISO Initial Comments at 15, 76;
NYISO Initial Comments at 35-36.
\1814\ ISO/RTO Council Initial Comments at 6; MISO Initial
Comments at 15, 75-76.
\1815\ Indicated PJM TOs Initial Comments at 43.
\1816\ ISO/RTO Council Initial Comments at 7; MISO Initial
Comments at 15, 76-77; NYISO Initial Comments at 36.
\1817\ ISO/RTO Council Initial Comments at 4.
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931. ISO-NE and MISO explain that transmission providers are in no
position to perform fact-finding, which would require a time- and
resource-consuming process to hear from all involved parties.\1818\
MISO states that it has no procedures beyond its alternative dispute
resolution process for adjudicating disputes and even these procedures
call for multi-month processes.\1819\ MISO notes that it is unclear who
would make the findings and how penalties would be assigned if multiple
parties contribute to a delay.\1820\ MISO and ISO/RTO Council note that
the personnel able to determine the cause of a delay are the
interconnection study engineers, who would need to divert their
resources from performing studies to provide evidence.\1821\
---------------------------------------------------------------------------
\1818\ ISO-NE Initial Comments at 36; MISO Initial Comments at
15, 75.
\1819\ MISO Initial Comments at 15, 75.
\1820\ Id. at 76.
\1821\ Id.; ISO/RTO Council Initial Comments at 7.
---------------------------------------------------------------------------
932. MISO TOs state that, if the Commission adopts penalties, it
should also adopt the requirement that RTOs/ISOs make an FPA section
205 filing before allocating any penalties to a transmission owner in
order to provide due process to the transmission owner and to be
consistent with the Commission's approach to RTO/ISO recovery of NERC
reliability penalty costs.\1822\
---------------------------------------------------------------------------
\1822\ MISO TOs Initial Comments at 26.
---------------------------------------------------------------------------
933. Indicated PJM TOs argue that it is unclear whether PJM has the
authority to recover penalty costs from transmission owners.\1823\
Indicated PJM TOs state that the consolidated transmission owners
agreement (CTOA) specifies that PJM has the right to file ``charges for
recovery of PJM costs'' under FPA section 205, but they argue that
penalties are not a cost of operation. Indicated PJM TOs explain that
the CTOA reserves rights not specifically transferred to PJM to
transmission owners. Therefore, Indicated PJM TOs conclude that the
right to recover penalties was not conferred on PJM and that PJM lacks
the contractual authority to seek recovery of penalties from
transmission owners under FPA section 205. Indicated PJM TOs add that
modifying the CTOA would implicate the Mobile-Sierra presumption.\1824\
---------------------------------------------------------------------------
\1823\ Indicated PJM TOs Initial Comments at 44-45.
\1824\ Id. at 45 n.126 (citing Morgan Stanley Cap. Grp. Inc. v.
Pub. Util. Dist. No. 1, 554 U.S. 527 (2008); NRG Power Mktg., LLC v.
Me. Pub. Utils. Comm'n, 558 U.S. 165 (2010)).
---------------------------------------------------------------------------
934. Further, Indicated PJM TOs argue that the Commission lacks the
authority under FPA section 205 to require RTOs/ISOs to seek cost
recovery of interconnection study penalties.\1825\ SEIA disagrees and
asks the Commission to establish a regime in which it can recover
penalties for late studies in Order No. 890.\1826\
---------------------------------------------------------------------------
\1825\ Id. at 45 (citing Atl. City Elec. Co. v. FERC, 329 F.3d
856, 859 (D.C. Cir. 2003) (per curiam)).
\1826\ SEIA Reply Comments at 13.
---------------------------------------------------------------------------
(e) Study Deadline Extension
935. Several commenters support the NOPR proposal to allow for the
[[Page 61145]]
extension of a study deadline by mutual agreement.\1827\ Some
commenters argue that this extension will promote cooperation between
interconnection customers and transmission providers.\1828\ Further,
AEE argues that the extension option will provide a buffer for studies
that warrant more time and that the two study cycle transition will
give transmission providers time to adjust to the cluster model and
deadlines, to understand possible variability in each cluster, and to
develop strategies for times when extra bandwidth is needed, such as
hiring third-party assistance.\1829\ AEE suggests that the Commission
require that the mutual agreements be publicly available.\1830\
---------------------------------------------------------------------------
\1827\ Consumers Energy Initial Comments at 6; NEPOOL Initial
Comments at 16; Pine Gate Initial Comments at 38.
\1828\ Consumers Energy Initial Comments at 7.
\1829\ AEE Reply Comments at 30-31.
\1830\ AEE Initial Comments at 31-32.
---------------------------------------------------------------------------
936. NARUC supports the proposal so long as the transmission
provider certifies to the Commission that the extension will not delay
unrelated interconnection requests outside the cluster.\1831\
---------------------------------------------------------------------------
\1831\ NARUC Initial Comments at 15.
---------------------------------------------------------------------------
937. Several commenters propose modifications to the NOPR deadline
extension proposal. NYISO states that it is unreasonable to allow
individual interconnection customers to veto extensions and instead
proposes that 30-day extensions should be available if the RTO/ISO
notifies the Commission that there is good cause to take additional
time to complete the study.\1832\ Indicated PJM TOs argue that it will
be virtually impossible to obtain mutual agreement in a region with a
large number of interconnection customers and instead propose that the
transmission provider determine the appropriate extension on
compliance.\1833\ Tri-State notes that there is no incentive for
interconnection customers who have agreed to a study deadline to re-
negotiate and mutually agree upon an extended deadline.\1834\ SoCal
Edison suggests that the Commission allow transmission providers to
extend study deadlines in the event of a larger than usual
cluster.\1835\
---------------------------------------------------------------------------
\1832\ NYISO Initial Comments at 42.
\1833\ Indicated PJM TOs Initial Comments at 42.
\1834\ Tri-State Initial Comments at 19.
\1835\ SoCal Edison Initial Comments at 18.
---------------------------------------------------------------------------
(f) Transition
938. Duke Southeast Utilities request that the Commission clarify
that transmission providers already using a cluster study process will
not be subject to penalties until after the completion of two study
cycles, which will encourage transmission providers not to employ an
unnecessary transition process.\1836\ Other commenters argue that
financial penalties should be in effect during the first transitional
cluster study.\1837\
---------------------------------------------------------------------------
\1836\ Duke Southeast Utilities Initial Comments at 11.
\1837\ ACE-NY Initial Comments at 13; AEE Initial Comments at
32; Cypress Creek Initial Comments at 24.
---------------------------------------------------------------------------
(g) Force Majeure Exception
939. Several commenters support the NOPR proposal to only permit
exceptions to the penalty in instances of force majeure, arguing that
additional exceptions make the penalty less effective.\1838\ Invenergy
argues that there should be a process for transmission providers to
declare force majeure to prevent the overuse of this exception.\1839\
CREA and NewSun argue that any force majeure exception should also
apply to interconnection customers when they fail to meet
deadlines.\1840\
---------------------------------------------------------------------------
\1838\ Cypress Creek Initial Comments at 24; Google Reply
Comments at 3.
\1839\ Invenergy Initial Comments at 31-32.
\1840\ CREA and NewSun Initial Comments at 84-85.
---------------------------------------------------------------------------
940. Many commenters argue that the Commission should extend
exemptions beyond force majeure, such as to events outside the
transmission provider's control or for good cause.\1841\ NARUC and
National Grid argue that transmission providers should have an
opportunity to request a penalty exemption on a case-by-case
basis.\1842\ NESCOE argues that the Commission should provide a list of
presumptive no-fault delays.\1843\
---------------------------------------------------------------------------
\1841\ Indicated PJM TOs Initial Comments at 42; MISO TOs
Initial Comments at 25; National Grid Initial Comments at 32; NESCOE
Initial Comments at 16; NYISO Initial Comments at 42; PPL Initial
Comments at 19; SoCal Edison Initial Comments at 19; Tri-State
Initial Comments at 18; WIRES Initial Comments at 10; Xcel Initial
Comments at 38.
\1842\ NARUC Initial Comments at 21; National Grid Initial
Comments at 33.
\1843\ NESCOE Initial Comments at 16.
---------------------------------------------------------------------------
(h) Requests for Alternatives, Clarification, or Technical Conference
941. A number of commenters suggest that the Commission evaluate
whether the other reforms are successful before implementing a penalty
regime.\1844\ NYTOs and Eversource similarly ask that the Commission
allow the changes in the ANOPR to take effect before imposing
penalties.\1845\ Some commenters suggest that the Commission hold a
technical conference prior to penalties becoming effective to discuss
experiences with the new cluster study process and focus the penalties
on the causes of delays.\1846\ SPP and NYISO also note that some
transmission providers are undergoing their own interconnection queue
reform efforts; therefore, the Commission should focus on ensuring
those efforts are successful instead of imposing automatic
penalties.\1847\ TAPS suggests that the Commission delay implementation
of penalties by at least five years from the effective date of
compliance filings to the final rule.\1848\
---------------------------------------------------------------------------
\1844\ AEP Initial Comments at 29; Avangrid Reply Comments at
14; Clean Energy Buyers Initial Comments at 10-11; Eversource
Initial Comments at 30-31; Idaho Power Initial Comments at 10; ISO/
RTO Council Reply Comments at 5; Longroad Energy Reply Comments at
15; NY Commission and NYSERDA Initial Comments at 6; NYISO Initial
Comments at 30; Pacific Northwest Utilities Initial Comments at 9-
10; PacifiCorp Initial Comments at 34; Puget Sound Initial Comments
at 11; State Agencies Initial Comments at 14; TAPS Initial Comments
at 9.
\1845\ Eversource Initial Comments at 30-31; NYTOs Initial
Comments at 23-24.
\1846\ ISO/RTO Council Initial Comments at 9; NARUC Initial
Comments at 15-22; NESCOE Reply Comments at 14; PJM Initial Comments
at 9; TAPS Initial Comments at 9.
\1847\ NYISO Initial Comments at 30; SPP Initial Comments at 14-
15.
\1848\ TAPS Initial Comments at 9.
---------------------------------------------------------------------------
942. NARUC argues that any penalty structure should be applied
equally to transmission providers delaying interregional affected
system studies and seeks clarification on how penalties will be
assessed when delays are caused by affected systems.\1849\
---------------------------------------------------------------------------
\1849\ NARUC Initial Comments at 14, 17.
---------------------------------------------------------------------------
943. Some commenters suggest that, instead of or in addition to
penalties, the Commission could improve reporting by issuing Commission
staff reports or requiring additional reporting from transmission
providers.\1850\ Indicated PJM TOs explain that the Commission or an
interested party could initiate an FPA section 206 proceeding if it
believes PJM is not exercising due diligence in performing studies
based on its reporting.\1851\ In response to arguments that entities
could pursue FPA section 206 filings before the Commission if they
believe
[[Page 61146]]
reasonable efforts have been violated, New Jersey Commission argues
that study delays result from systemic failures, so it is inappropriate
to address such issues through individual FPA section 206
filings.\1852\
---------------------------------------------------------------------------
\1850\ Id. at 16; AEE Initial Comments at 32-33; AEE Reply
Comments at 32; APPA-LPPC Initial Comments at 23; Avangrid Initial
Comments at 31; Bonneville Initial Comments at 16; Clean Energy
Associations Initial Comments at 47; Clean Energy Buyers Initial
Comments at 11; CREA and NewSun Initial Comments at 85-86; EPSA
Initial Comments at 11; Fervo Energy Initial Comments at 6; Google
Reply Comments at 4; MISO TOs Initial Comments at 27; National Grid
Initial Comments at 31-32; NESCOE Reply Comments at 14; NYISO
Initial Comments at 31, 43; NYISO Reply Comments at 10; NYTOs
Initial Comments at 23; OMS Initial Comments at 15; PacifiCorp
Initial Comments at 35; PacifiCorp Reply Comments at 6; Pine Gate
Initial Comments at 41; PG&E Initial Comments at 4, 9; R Street
Initial Comments at 14; Shell Initial Comments at 11; TAPS Initial
Comments at 9; UMPA Initial Comments at 7.
\1851\ Indicated PJM TOs Initial Comments at 41.
\1852\ New Jersey Commission Reply Comments at 5.
---------------------------------------------------------------------------
944. MISO proposes that, if a transmission provider misses a
deadline by more than a threshold grace period, the transmission
provider should be required to self-report the circumstances around the
delay to the Commission, and, in response to that self-report, the
Commission could issue a show cause order to require the transmission
provider and any other relevant entities to respond with specific
information about the causes for the delays and propose a mitigation
plan.\1853\ MISO states that, at the conclusion of the show cause
proceeding, the Commission would issue an order that could require
transmission providers, transmission owners, or other entities to take
specific actions to mitigate the delay, require process changes, and/or
impose penalties.\1854\ MISO argues that its proposal has several
advantages over the NOPR penalty proposal, including providing
accountability tied to entities actually causing the delay, as
determined by the Commission. Public Interest Organizations support the
self-reporting concept but do not support conditioning penalty
assignment on a show cause proceeding, arguing that this would be
administratively burdensome.\1855\ AEE also states that MISO's approach
could be helpful if paired with binding timelines and a clear penalty
structure.\1856\
---------------------------------------------------------------------------
\1853\ MISO Initial Comments at 79-80; see also MISO TOs Initial
Comments at 27 (explaining that targeted intervention through a show
cause order is more appropriate than broadly applicable penalties).
\1854\ MISO Initial Comments at 80-81.
\1855\ Public Interest Organizations Reply Comments at 8-9.
\1856\ AEE Reply Comments at 38.
---------------------------------------------------------------------------
945. Clean Energy Associations suggest that, if the Commission does
not adopt penalties, it should consider requiring remedial action
plans, including specific staffing plans, for transmission providers
with persistently late or inaccurate studies.\1857\
---------------------------------------------------------------------------
\1857\ Clean Energy Associations Initial Comments at 45.
---------------------------------------------------------------------------
946. Some commenters argue that the Commission should incentivize
transmission providers to meet deadlines rather than penalize them for
failing to do so.\1858\ Shell proposes that the Commission provide
favorable rate treatment for transmission providers that meet study
timeliness conditions; specifically, Shell suggests that the Commission
create a rebuttable presumption that transmission providers can recover
their investments in interconnection queue processing resources if the
transmission provider satisfies deadlines at least 90% of the time over
two years.\1859\ Shell further suggests that these costs can be
eligible for inclusion in transmission rate base, with corresponding
return on equity, if the transmission provider meets study deadlines at
least 95% of the time over two calendar years.\1860\ Affected
Interconnection Customers propose that the Commission allow RTOs/ISOs
to create a monetary incentive for transmission owners that complete
their interconnection studies on time.\1861\
---------------------------------------------------------------------------
\1858\ Id. at 46; ACE-NY Initial Comments at 14 (recommending a
structure with both penalties and incentives); Affected
Interconnection Customers Initial Comments at 26 (same); CREA and
NewSun Reply Comments at 57 (same); Shell Initial Comments at 10;
Longroad Energy Reply Comments at 14; Vermont Electric and Vermont
Transco Initial Comments at 2.
\1859\ Longroad Energy Reply Comments at 14-15; Shell Initial
Comments at 11.
\1860\ Shell Initial Comments at 11.
\1861\ Affected Interconnection Customers Initial Comments at
29-30.
---------------------------------------------------------------------------
947. However, R Street notes that rate incentives, like bonuses on
returns on equity, would induce financial motivation but would require
a performance baseline that transmission owners could game.\1862\ MISO
TOs argue that incentives would fail because study delays are caused by
factors beyond transmission providers' control.\1863\
---------------------------------------------------------------------------
\1862\ R Street Initial Comments at 15.
\1863\ MISO TOs Reply Comments at 15-16.
---------------------------------------------------------------------------
948. ACE-NY requests that the Commission clarify whether a failure
to meet the pro forma LGIP study deadlines would constitute a tariff
violation, which could have implications for executive and staff
compensation.\1864\ MISO TOs argue that such a proposal has no basis
and would constitute an even stricter standard because penalties for
tariff violations can amount to over $1 million per day, exceeding the
proposed $500 per day proposal.\1865\
---------------------------------------------------------------------------
\1864\ ACE-NY Initial Comments at 13.
\1865\ MISO TOs Reply Comments at 14 (citing 16 U.S.C. 825o-1).
---------------------------------------------------------------------------
949. Clean Energy States and TAPS recommend tying executive
compensation to interconnection queue deadlines,\1866\ noting that SPP
and MISO currently tie compensation to reliability performance.\1867\
However, MISO TOs note that the Commission has previously found that it
lacks such jurisdiction.\1868\
---------------------------------------------------------------------------
\1866\ Clean Energy States Initial Comments at 10-11; CREA and
NewSun Reply Comments at 57; TAPS Initial Comments at 8.
\1867\ TAPS Initial Comments at 8.
\1868\ MISO TOs Reply Comments at 15.
---------------------------------------------------------------------------
950. Some commenters argue that the Commission should allow
transmission providers to set their own deadlines for interconnection
studies because the current deadlines are not reasonable or advocate
for regional flexibility.\1869\ Some commenters recommend allowing
transmission providers to adjust study deadlines based on
interconnection queue size.\1870\ Public Interest Organizations and
Google support such proposals to the extent that the deadlines are
subject to Commission review.\1871\ AEE does not oppose giving
transmission providers flexibility to set their study timelines but
requests that the Commission set a maximum allowable study
timeline.\1872\
---------------------------------------------------------------------------
\1869\ APPA-LPPC Initial Comments at 21; Bonneville Initial
Comments at 16; Indicated PJM TOs Reply Comments at 39; ISO-NE
Initial Comments at 35-37; NY Commission and NYSERDA Initial
Comments at 5; NYISO Initial Comments at 29, 33.
\1870\ Bonneville Initial Comments at 16; Google Reply Comments
at 5; NYISO Initial Comments at 29; SEIA Reply Comments at 17.
\1871\ Public Interest Organizations Reply Comments at 9.
\1872\ AEE Reply Comments at 38.
---------------------------------------------------------------------------
951. National Grid suggests that the Commission adopt a minimum
time frame approach, which would start the overall interconnection
study timeline upon finalizing the base case study models and provide
minimum study time frames for scope and result reviews.\1873\
---------------------------------------------------------------------------
\1873\ National Grid Initial Comments at 31.
---------------------------------------------------------------------------
952. PJM suggests that the transmission provider develop a targeted
study completion date based on an analysis of that particular
interconnection queue, with the target completion date available for
public comment.\1874\ PJM states that, under this approach, as studies
become delayed further and further past the target date, the
transmission provider would be required to meet increasing burdens
(e.g., public posting of the missed date, filing a report with the
Commission, being subject to FPA section 206 action). PJM states that
if, despite the FPA section 206 action, the transmission provider
misses a subsequent study deadline at the same level, then the
Commission could impose penalties for any proven malfeasance by the
transmission provider. PJM also suggests that the Commission could
allow transmission providers to cap the number of interconnection
requests in a given cluster to an amount commensurate with available
resources. In response, AEE argues that PJM's
[[Page 61147]]
proposed approach would cause unnecessary administrative burden, which
could further harm interconnection customers.\1875\
---------------------------------------------------------------------------
\1874\ PJM Initial Comments at 59-61.
\1875\ AEE Reply Comments at 38-39.
---------------------------------------------------------------------------
953. Some commenters claim that the NOPR proposal is vague and
raises profound implementation issues (e.g., how or whether the penalty
structure will accommodate different cluster sizes, study complexities,
or restudies).\1876\ R Street suggests, and ISO/RTO Council agrees,
that the Commission and stakeholders would benefit from a root cause
analysis to identify the cause of study delays, which could inform more
reasonable performance expectations.\1877\
---------------------------------------------------------------------------
\1876\ EEI Reply Comments at 17; Eversource Initial Comments at
20, 28.
\1877\ ISO/RTO Council Reply Comments at 5; R Street Initial
Comments at 14.
---------------------------------------------------------------------------
954. Some commenters seek clarity regarding who bears financial
penalties for late affected system studies and related affected system
obligations.\1878\ ENGIE states that it is unclear who bears the
financial penalties for late affected system studies.\1879\ In
contrast, MISO interprets the NOPR proposal to apply penalties only to
the affected system operator, though MISO also recommends that the
Commission recognize that some delays may be beyond the control of the
affected system operator and recommends that affected system operators
not be penalized for third-party delays.\1880\ Similarly, Duke
Southeast Utilities express concern that penalties could be levied
against affected system operators for delays beyond their control and
further argue that, instead of unilaterally imposing financial
penalties on one entity, which, to Duke Southeast Utilities, seems
arbitrary and unfounded, the Commission should consider imposing
multilateral penalties on all entities in accordance with their
individual obligations set forth in the proposed process.\1881\
---------------------------------------------------------------------------
\1878\ Duke Southeast Utilities Initial Comments at 17-18; ENGIE
Initial Comments at 9; MISO Initial Comments at 92.
\1879\ ENGIE Initial Comments at 9. Additionally, ENGIE states
that transmission owners typically have responsibilities for
affected system studies and, therefore, argues that the Commission
should consider language that distributes financial risk and
penalties to both transmission owners and transmission providers,
including an ability for transmission providers to recover costs
from transmission owners. Id.
\1880\ MISO Initial Comments at 92. WAPA also is generally
concerned about the imposition of monetary penalties for failure to
meet deadlines and questions whether federal agencies like WAPA
should or even can be subject to monetary penalties. See WAPA
Initial Comments at 10, 14.
\1881\ Duke Southeast Utilities Initial Comments at 17-18.
---------------------------------------------------------------------------
955. Cypress Creek suggests that, in addition to financial
penalties for missed study deadlines, the Commission should also impose
penalties for inaccurate study results.\1882\ AEE and Clean Energy
Associations argue that the Commission should provide guidelines and
reporting requirements regarding acceptable study accuracy.\1883\
---------------------------------------------------------------------------
\1882\ Cypress Creek Initial Comments at 23.
\1883\ AEE Initial Comments at 34; Clean Energy Associations
Initial Comments at 47.
---------------------------------------------------------------------------
956. CREA and NewSun propose an overall ``reasonableness'' standard
to ensure the quality of the studies and that there is no ongoing
failure to provide adequate staffing or to employ reasonable study
assumptions.\1884\
---------------------------------------------------------------------------
\1884\ CREA and NewSun Initial Comments at 85.
---------------------------------------------------------------------------
957. National Grid argues that the Commission should permit
transmission providers to assign a dedicated person to monitor the
progress of each entity (i.e., interconnection customer, transmission
owner, and RTO/ISO) during the interconnection process.\1885\ National
Grid argues that the cost of this person and any other additional costs
needed to satisfy the NOPR proposal should be recoverable in rates so
that transmission providers would be able to recover costs incurred to
reduce penalty risk.
---------------------------------------------------------------------------
\1885\ National Grid Initial Comments at 33.
---------------------------------------------------------------------------
958. Some commenters suggest that the Commission allow third-party
consultants to complete studies, which would conserve transmission
provider resources and provide a pathway for interconnection customers
to move forward.\1886\ Dominion argues in response that there is a
general lack of qualified professionals to perform interconnection
studies, so a third party will not have access to the personnel,
knowledge, or resources to perform them.\1887\
---------------------------------------------------------------------------
\1886\ AEE Initial Comments at 34; Clean Energy Associations
Initial Comments at 46; Public Interest Organizations Reply Comments
at 4; SEIA Initial Comments at 33.
\1887\ Dominion Reply Comments at 19-20.
---------------------------------------------------------------------------
959. Pacific Northwest Utilities argue that the reasonable efforts
standard should not be eliminated for facilities studies, which require
an individual study, noting that the number of facilities studies
needed can vary greatly between clusters.\1888\
---------------------------------------------------------------------------
\1888\ Pacific Northwest Utilities Initial Comments at 11-12.
---------------------------------------------------------------------------
960. NYISO suggests that the Commission adopt features of the NERC
model, including the use of non-financial sanctions for minor or
excusable violations and penalty reductions for cooperative and
remedial actions.\1889\
---------------------------------------------------------------------------
\1889\ NYISO Initial Comments at 41-42.
---------------------------------------------------------------------------
961. Tri-State supports the NOPR proposal not to assess financial
penalties until one cluster study cycle (that is not a transitional
study cycle) after the compliance effective date. Tri-State seeks
clarification on when penalties would be imposed for transmission
providers already using a cluster study process.\1890\
---------------------------------------------------------------------------
\1890\ Tri-State Initial Comments at 19.
---------------------------------------------------------------------------
c. Commission Determination
962. We adopt the NOPR proposal to eliminate the reasonable efforts
standard set forth in sections 2.2, 3.5.4(i), 7.4, 8.3, and Attachment
A to Appendix 4 of the pro forma LGIP. In its place, we adopt the NOPR
proposal, with modification, to add new section 3.9 to the pro forma
LGIP that imposes study delay penalties, as further discussed below:
delays of cluster studies beyond the tariff-specified deadline will
incur a penalty of $1,000 per business day; delays of cluster restudies
beyond the tariff-specified deadline will incur a penalty of $2,000 per
business day; delays of affected system studies beyond the tariff-
specified deadline will incur a penalty of $2,000 per business day; and
delays of facilities studies beyond the tariff-specified deadline will
incur a penalty of $2,500 per business day.\1891\
---------------------------------------------------------------------------
\1891\ The penalties that we adopt in this final rule in section
3.9 of the pro forma LGIP for late affected system studies only
apply to affected system operators that are public utilities.
---------------------------------------------------------------------------
963. As explained in greater detail in this section, we adopt the
following features of the study delay penalty structure for late
interconnection studies: (1) no study delay penalties will be assessed
until the third cluster study cycles (including any transitional
cluster study cycle, but not transitional serial studies) after the
Commission-approved effective date of the transmission provider's
filing in compliance with this final rule; (2) there will be a 10-
business day grace period, such that no study delay penalties will be
assessed for a study that is delayed by 10 business days or fewer; (3)
deadlines may be extended for a particular study by 30 business days by
mutual agreement of the transmission provider and all interconnection
customers with interconnection requests in the relevant study; (4)
study delay penalties will be capped at 100% of the initial study
deposits received for all of the interconnection requests in the
cluster for cluster studies and cluster restudies, 100% of the initial
study deposit received for the single interconnection request in the
study for facilities studies, and 100% of the study deposit(s) that the
transmission provider acting as an affected system operator
[[Page 61148]]
(affected system transmission provider) collects for conducting the
affected system study; (5) transmission providers will have the ability
to appeal any study delay penalties to the Commission, with the
Commission determining whether good cause exists to grant the relief
requested on appeal; (6) transmission providers must distribute study
delay penalties to interconnection customers in the relevant study on a
pro rata per interconnection request basis to offset their study costs;
(7) non-RTO/ISO transmission providers and transmission-owning members
of RTOs/ISOs may not recover study delay penalties through transmission
rates; (8) RTOs/ISOs may submit an FPA section 205 filing to propose a
default structure for recovering study delay penalties and/or to
recover the costs of any specific study delay penalties; \1892\ (9)
transmission providers must pay the penalty for each late study on a
pro rata basis per interconnection request to all interconnection
customers or affected system interconnection customers included in the
relevant study that did not withdraw, or were not deemed withdrawn,
from the interconnection queue before the missed study deadline; and
(10) transmission providers must post quarterly on their OASIS or other
publicly accessible website (a) the total amount of study delay
penalties from the previous reporting quarter and (b) the highest study
delay penalty paid to a single interconnection customer in the previous
reporting quarter. We also add new paragraph (f)(1)(ii) to 18 CFR 35.28
to specify that any public utility that conducts interconnection
studies shall be liable for and eligible to appeal penalties following
that public utility's failure to complete an interconnection study by
the appropriate deadline. We also decline to adopt the NOPR's proposed
force majeure penalty exception. We first discuss our overarching
rationale for this set of reforms, and then discuss each of these
reforms in greater detail and our rationale for each.
---------------------------------------------------------------------------
\1892\ We note that the typical standard of review under FPA
section 205 would apply to these filings: i.e., the filer must show
that any proposal to recover study delay penalties is just,
reasonable, and not unduly discriminatory or preferential. See 16
U.S.C. 824d.
---------------------------------------------------------------------------
964. We adopt these reforms to remedy the unjust and unreasonable
rates stemming from interconnection queue backlogs and to ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner.
Specifically, these reforms will help ensure more timely processing of
interconnection requests by incentivizing transmission providers to
meet interconnection study deadlines.\1893\
---------------------------------------------------------------------------
\1893\ Invenergy Initial Comments at 30; Iowa Commission Initial
Comments at 5-6 (``RTOs/ISOs need to prioritize interconnection
studies and need to hold their employees and/or outside entities
responsible for delays''); SEIA Initial Comments at 32.
---------------------------------------------------------------------------
i. Eliminating the Reasonable Efforts Standard
965. We adopt the NOPR proposal to eliminate the reasonable efforts
standard set forth in sections 2.2, 3.5.4(i), 7.4, 8.3, and Attachment
A to Appendix 4 of the pro forma LGIP. In these revised sections, we
specifically eliminate the reasonable efforts standard for conducting
cluster studies, cluster restudies, facilities studies, and affected
system studies.
966. The lengthy interconnection study delays and interconnection
queue backlogs throughout the country support our conclusion that the
reasonable efforts standard does not provide an adequate incentive for
transmission providers to complete interconnection studies on time. As
discussed in section II above, transmission providers are experiencing
significant interconnection queue backlogs, as evidenced, for example,
by their Order No. 845 reports.\1894\ There is every reason to believe
that many of the factors contributing to significant interconnection
queue backlogs and delay--including the rapidly changing resource mix,
market forces, and emerging technologies--will persist. In response to
those ongoing challenges, we find that it is just, reasonable, and not
unduly discriminatory or preferential to eliminate the reasonable
efforts standard and adopt a penalty structure that reasonably
incentivizes transmission providers to ensure the timely processing of
interconnection requests. We note that we are not finding that
transmission providers have necessarily acted in bad faith or that
their actions are the sole reason for the queue delays. Indeed,
throughout this final rule, we adopt numerous reforms to appropriately
incentivize interconnection customers to help reduce interconnection
delays that may result from their conduct. Nevertheless, we find that
the elimination of the reasonable efforts standard and the adoption of
penalties for late studies are needed to create an incentive for
transmission providers, which will help reduce interconnection delays
and ensure that Commission-jurisdictional rates are just, reasonable,
and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\1894\ See appendix B to this final rule (showing that over
2,800 interconnection studies were delayed as of the end of the
fourth quarter (Q4) 2022 and that over 1,900 interconnection studies
were delayed as of the end of Q4 2021); see also Queued Up 2023 at 6
(showing growth in number of interconnection requests from 2013 to
2022) and Queued Up 2023 at 3 (noting that generating facilities
built in 2008 spent, on average, less than two years in
interconnection queues, whereas generating facilities built in 2022
spent, on average, five years in interconnection queues). Although
some commenters argue that Order No. 845 data do not provide
sufficient support (AEP Initial Comments at 25-26; MISO Initial
Comments at 72), the data demonstrate that interconnection queue
delays have continued to worsen over recent years and industry
reports have similarly concluded that interconnection queues are
seeing increasingly severe delays. We cite evidence that contradicts
such comments and that, instead, supports our findings. See, e.g.,
supra section II.C.
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967. The reasonable efforts standard worsens current-day
challenges, as it fails to ensure that transmission providers are
keeping pace with the changing and complex dynamics of today's
interconnection queues. Contrary to the assertions of some commenters,
we believe that there are steps within transmission providers' control,
from deploying transmission providers' resources to exploring
administrative efficiencies and innovative study approaches,\1895\ to
better ensure timely processing of interconnection studies to remedy
existing deficiencies.
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\1895\ See Public Interest Organizations Reply Comments at 4
(``any claim that an individual transmission provider has done
absolutely everything in its power to improve the processing rate of
interconnection requests . . . almost certainly comes from a lack of
imagination''); R Street Initial Comments at 14 (explaining that
advances in computing fields have the potential to reduce queue
processing times).
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968. As discussed above, we adopt several reforms to address
speculative interconnection requests by imposing stricter requirements
on interconnection customers for entering and remaining in the
interconnection queue (e.g., site control requirements, commercial
readiness deposits, and withdrawal penalties). We also adopt reforms to
improve the efficiency of interconnection studies and interconnection
queue processing for all transmission providers (e.g., first-ready,
first-served cluster study process). In this section, we adopt reforms
to ensure that transmission providers are doing their part as well by
eliminating the reasonable efforts standard and imposing study delay
penalties on transmission providers when they fail to meet the
interconnection study deadlines we adopt in this final rule. Based on
the record, we find that the elimination of the reasonable efforts
standard and its replacement with firm deadlines and penalties are
needed to remedy unjust and unreasonable rates
[[Page 61149]]
and ensure that interconnection customers are able to interconnect to
the transmission system in a reliable, efficient, transparent, and
timely manner. Thus, we disagree with commenters that contend that the
reasonable efforts standard continues to be appropriate or that the
Commission's past orders, including Order No. 845, mean that the
reasonable efforts standard continues to ensure just and reasonable
rates.\1896\
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\1896\ See, e.g., Avangrid Initial Comments at 10, 30-31;
Bonneville Initial Comments at 16; EEI Reply Comments at 16;
Indicated PJM TOs Initial Comments at 36; MISO TOs Reply Comments at
6-7; NYISO Initial Comments at 30-31; PG&E Reply Comments at 3-4;
WIRES Initial Comments at 10.
---------------------------------------------------------------------------
969. We similarly disagree with commenters that support eliminating
the reasonable efforts standard but that do not support imposing study
delay penalties on transmission providers for failing to meet
interconnection study deadlines.\1897\ We do not believe that this
result would remedy the unjust and unreasonable rates, nor would it
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner by aligning incentives properly.
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\1897\ CAISO Initial Comments at 25-26; Clean Energy Buyers
Initial Comment at 9-10; MISO Initial Comments at 13, 71, 79; Shell
Initial Comments at 10; see also NARUC Initial Comments at 13-14,
20; Pennsylvania Commission Initial Comments at 2-3 (supporting the
proposal to eliminate the reasonable efforts standard but taking no
position on the need for monetary penalties).
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970. As we are eliminating the reasonable efforts standard, we also
must adopt a replacement rate that remedies the problems just
described. The sections below set forth a study delay penalty structure
and why we believe it is justified. In short, we adopt provisions in
the pro forma LGIP that impose firm interconnection study deadlines and
corresponding study delay penalties on transmission providers that fail
to meet those deadlines.
971. Interconnection customers face financial harm when study
deadlines are not met, ultimately inhibiting their ability to
interconnect to the transmission system in a reliable, efficient,
transparent, and timely manner. We find that holding transmission
providers to firm interconnection study deadlines is likely to
accelerate the interconnection study process and provide greater
certainty to interconnection customers, allowing them to make more
informed business decisions around whether to proceed with or withdraw
from the interconnection queue, which will also ultimately improve
interconnection queue management and remedy the unjust and unreasonable
rates otherwise created by study delays.
972. At the same time, we do not believe that the study delay
penalty structure that we adopt in this final rule is unduly harsh for
transmission providers, either in penalty amount or the form of its
application. The study delay penalty structure adopted in this final
rule balances the harm to interconnection customers of interconnection
study delays and the associated need to incentivize transmission
providers to timely complete interconnection studies with the burdens
on transmission providers of conducting interconnection studies and
potentially facing penalties for delays, including those that may be
caused or exacerbated by factors beyond their control. In particular,
we adopt the following safeguards for transmission providers: (1) a
transition period rather than imposing study delay penalties as soon as
transmission providers begin implementing the reforms in this final
rule; (2) a 10-business day grace period where no study delay penalties
will be assessed; (3) a provision that allows a 30-business day
deadline extension upon mutual agreement of the transmission provider
and interconnection customers; (4) caps on study delay penalties; and
(5) a transmission provider ability to appeal. We also adopt provisions
governing distribution of study delay penalties to interconnection
customers and prohibiting recovery of study delay penalties through
transmission rates, along with transparency-related posting
requirements to the benefit of interconnection customers and consumers
alike. We believe that the study delay penalty structure adopted herein
aligns transmission provider and interconnection customer incentives
while providing appropriate built-in flexibility and safeguards for
transmission providers, thereby achieving a balance that ensures just
and reasonable rates and ensures that interconnection customers are
able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner.
ii. Penalty Amount
973. We modify the pro forma LGIP to adopt a study delay penalty
structure whereby penalties increase through the interconnection study
process. Delays of cluster studies beyond the tariff-specified deadline
will incur a penalty of $1,000 per business day; delays of cluster
restudies beyond the tariff-specified deadline will incur a penalty of
$2,000 per business day; delays of affected system studies beyond the
tariff-specified deadline will incur a penalty of $2,000 per business
day; and delays of facilities studies beyond the tariff-specified
deadline will incur a penalty of $2,500 per business day.
974. We agree with the numerous commenters who argue that the NOPR
penalty proposal of $500 per business day is too low to create an
incentive for transmission providers to meet study deadlines.\1898\ We
find it necessary to modify the NOPR proposal to establish a higher
penalty amount and a structure of increasing penalties that reflects
the greater harm caused by delayed studies at later interconnection
stages.
---------------------------------------------------------------------------
\1898\ ACE-NY Initial Comments at 12; Affected Interconnection
Customers Initial Comments at 24-26; CESA Initial Comments at 11;
CESA Reply Comments at 8-9; Clean Energy Associations Initial
Comments at 44; Consumers Energy Initial Comments at 6; CREA and
NewSun Reply Comments at 56; Cypress Creek Initial Comments at 24;
ELCON Initial Comments at 7-8; EPSA Initial Comments at 11; Fervo
Energy Initial Comments at 6; Invenergy Initial Comments at 29;
NARUC Initial Comments at 14; Pine Gate Initial Comments at 39.
---------------------------------------------------------------------------
975. We reach this conclusion for several reasons. First, we find
persuasive the comments asserting that a penalty of $500 per business
day is insufficient to incentivize transmission provider actions that
will reduce the incidence of study delays.\1899\ At $500 per business
day, a study that is delayed by six months--or roughly 126 business
days--would produce a penalty of only $63,000. We view such a penalty
as insufficient considering that the purpose of the penalty is to
incentivize timely study completion that may be achieved, for example,
by hiring additional personnel or investing in new software.
---------------------------------------------------------------------------
\1899\ See, e.g., Invenergy Initial Comments at 29-30 (``[T]he
proposed penalty amount is woefully insufficient to create any real
incentive'' . . . ``While a study that is six months late may
severely impact an interconnection customer's development efforts,
it would amount to only a $90,000 penalty, which is de minimis for
transmission providers which may have annual revenues of $25 billion
if not more''); Affected Interconnection Customers Initial Comments
at 24-25 (``[A] $500 per day penalty imposed upon transmission
providers with hundreds of millions, if not billions of dollars of
transmission assets, is a drop in the bucket that will be highly
unlikely to deter continued missed interconnection study
deadlines''); Cypress Creek Initial Comments at 24 (``[P]enalties
should . . . be substantially larger so that they serve as
meaningful deterrents to delayed and inaccurate study results'');
Pine Gate Initial Comments at 39 (``A daily penalty rate that is too
low will do little to incentivize transmission providers to complete
studies in a timely manner, even in a situation where the penalty
equals the full 100 percent of total study deposits received'').
---------------------------------------------------------------------------
976. Some commenters advocate for penalty amounts that more closely
approximate the costs that delays impose in interconnection
[[Page 61150]]
customers,\1900\ while others propose penalty amounts ranging from
$2,500 per day to $7,000 per day.\1901\ Based on the record before us,
we believe the $1,000/$2,000/$2,500 per business day penalty structure,
combined with the transition, grace period, cap on penalties, and
ability to appeal that we adopt below, strikes an appropriate balance
because it creates an incentive for transmission providers to meet
study deadlines while not being overly punitive.
---------------------------------------------------------------------------
\1900\ Cypress Creek Initial Comments at 24; Pine Gate Initial
Comments at 39-40.
\1901\ ACE-NY Initial Comments at 12; Affected Interconnection
Customers Initial Comments at 5, 26; CESA Reply Comments at 9;
Invenergy Initial Comments at 30.
---------------------------------------------------------------------------
977. Second, adopting progressively higher penalty amounts for
delayed cluster restudies and facilities studies reflects the
progressively greater harm to interconnection customers of delayed
studies at those later stages--at which they will have made greater
investments in advancing their projects toward commercial development
through steps such as obtaining site control, securing permits, and
contracting for equipment. This is especially true given the new site
control requirements, commercial readiness deposits, and withdrawal
penalties we adopt in this final rule, which also become increasingly
stringent as the study process progresses. These reforms will require
that interconnection customers have greater capital at risk at each
stage to affirm their commitment to reaching commercial operation. We
find it appropriate that transmission providers face study delay
penalties structured in a similar manner to provide adequate incentives
to complete interconnection studies on time.
978. Third, the penalty structure we adopt here will impose more
stringent study delay penalties at later stages when reasons for study
delays should be fewest. That is, we expect the volume of
interconnection requests to decrease as they progress through the study
process, with fewer interconnection requests reaching the cluster
restudy and facilities study stages. This reduction in volume will
reduce the likelihood transmission providers are unable to complete
those studies on time. We find it reasonable to hold transmission
providers most accountable for timely study completion in the stages
where delays should be most avoidable.
iii. Transition
979. We modify proposed section 3.9(6) of the pro forma LGIP, which
provided that no study delay penalties shall be assessed until one
cluster study cycle (that is not a transitional study cycle) after the
Commission-approved effective date of the transmission provider's
filing in compliance with this final rule. Instead, we modify that
section to provide that no study delay penalties shall be assessed
until the third cluster study cycle after the Commission-approved
effective date of the compliance filing (including any transitional
cluster study cycle, but not transitional serial studies).\1902\ We
believe that giving transmission providers time to adapt to the new
processes without imposing study delay penalties immediately will help
ensure that transmission providers' implementation of this final rule
has begun to reduce backlogged interconnection queues: i.e., we expect
transmission providers to meet the interconnection study deadlines once
they are implementing the cluster study process, with the increased
requirements on interconnection customers (e.g., site control
requirements, commercial readiness deposits, and withdrawal penalties)
to help prevent speculative interconnection requests from entering and
remaining in the interconnection queue.
---------------------------------------------------------------------------
\1902\ See supra section III.A.7.c regarding the transition to
the cluster study process.
---------------------------------------------------------------------------
980. We adopt Duke Southeast Utilities' request to specify that
transmission providers already using a cluster study process will not
be subject to penalties until the third cluster study cycle after the
Commission-approved effective date of the transmission provider's
filing in compliance with this final rule.\1903\ We agree that
transmission providers that already use a cluster study process should
not be incentivized to employ an unnecessary transition process in
response to this final rule simply to delay the possibility of study
delay penalties. Accordingly, we modify the NOPR proposal such that no
transmission providers will be assessed study delay penalties until the
third cluster study cycle after the Commission-approved effective date
of the compliance filing.
---------------------------------------------------------------------------
\1903\ Duke Southeast Utilities Initial Comments at 11.
---------------------------------------------------------------------------
iv. Grace Period
981. In addition to adopting a study delay penalty amount that we
believe balances incentivizing transmission providers while not being
overly punitive, we adopt in pro forma LGIP section 3.9(4) a 10-
business day grace period, such that no study delay penalties will be
assessed for a study that is delayed by 10 business days or fewer, and
if the study is delayed by more than 10 business days, the penalty
amount will be calculated from the first business day the transmission
provider exceeds the applicable study deadline. We believe that this
10-business day grace period will provide an appropriate level of
flexibility for transmission providers to address unforeseen
circumstances or complexities that arise in the study process. We also
believe that this grace period will lessen any administrative burden
associated with the appeals process or RTO/ISO recovery of study delay
penalty costs, as studies with short delays will not incur study delay
penalties that may trigger appeals filings or the need for RTO/ISO
penalty recovery.
v. Study Deadline Extension
982. We adopt the NOPR proposal in pro forma LGIP section 3.9(5) to
allow extensions of the deadline for a particular study by 30 business
days by mutual agreement of the transmission provider and all
interconnection customers with interconnection requests in the relevant
study. We believe that this reform will promote cooperation between
transmission providers and interconnection customers and incentivize
transmission providers to keep interconnection customers informed of
the status of study processes.
983. We decline to adopt AEE's suggestion to require transmission
providers to publicly post when a study deadline is extended by mutual
agreement.\1904\ We do not find it necessary to require such public
posting because transmission providers are being given sufficient
incentive to minimize delays and manage all interconnection studies
fairly. We also decline to adopt NARUC's suggestion to require
transmission providers to certify that extensions will not delay
unrelated interconnection requests outside the cluster.\1905\
Transmission providers will be sufficiently incentivized to ensure that
such extensions do not delay other studies because any such delays may
incur study delay penalties, as described in this section. In response
to commenters that argue that it will be difficult to obtain mutual
agreement in large regions, we do not view that as a reason to decline
to adopt or to modify the proposal.\1906\ If an interconnection study
is delayed, and mutual agreement cannot be obtained, the transmission
provider will be assessed the
[[Page 61151]]
corresponding study delay penalties and may file an appeal with the
Commission to explain any relevant circumstances.
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\1904\ AEE Initial Comments at 31-32.
\1905\ NARUC Initial Comments at 15.
\1906\ Indicated PJM TOs Initial Comments at 42; Tri-State
Initial Comments at 19.
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vi. Cap on Penalties
984. We modify proposed section 3.9(2) of the pro forma LGIP, which
capped study delay penalties at 100% of the total study deposit
received for the late interconnection study, to instead cap penalties
at: (1) 100% of the initial study deposits received for all of the
interconnection requests in the cluster for cluster studies and cluster
restudies; \1907\ (2) 100% of the initial study deposit received for
the single interconnection request in the study for facilities studies;
and (3) 100% of the study deposit(s) that the affected system
transmission provider collects for conducting the affected system
study. As discussed in the section III.A.2.6.a above, we modify the
NOPR proposal and require transmission providers to collect a single
study deposit from interconnection customers only upon entry into the
cluster (initial study deposit), rather than a study deposit at each
phase of the study process, as proposed in the NOPR. Accordingly, we
modify the study delay penalty cap to reflect this change in the study
deposit requirements. By tying the study delay penalty cap to the study
deposits, we ensure that the maximum penalty bears a relationship to
the costs of the study that was late and is not unnecessarily punitive.
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\1907\ Under section 3.1.1.1 of the pro forma LGIP, initial
study deposits will range from $25,000 to $250,000, depending on the
size of the proposed generating facility.
---------------------------------------------------------------------------
985. In response to commenters who argue that study delay penalties
should not be capped,\1908\ or that the cap should be higher than 100%
of the study deposits for the late interconnection study,\1909\ we
believe that imposing study delay penalties that exceed the amount of
the study deposit collected for the late interconnection study will be
unnecessarily punitive to transmission providers.
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\1908\ ACE-NY Initial Comments at 13; AEE Reply Comments at 37;
Consumers Energy Initial Comments at 6; CREA and NewSun Initial
Comments at 84; Cypress Creek Initial Comments at 23-24; Public
Interest Organizations Initial Comments at 35-36; SEIA Initial
Comments at 34.
\1909\ Interwest Initial Comments at 8; Invenergy Initial
Comments at 31; Northwest and Intermountain Initial Comments at 14.
---------------------------------------------------------------------------
986. In response to Invenergy's request for clarification, we
confirm that the cap will not be impacted by any withdrawal
penalties.\1910\
---------------------------------------------------------------------------
\1910\ Invenergy Initial Comments at 31.
---------------------------------------------------------------------------
vii. Ability To Appeal
987. We further modify the NOPR proposal to include, in section
3.9(3) of the pro forma LGIP, the ability for transmission providers to
appeal any study delay penalties to the Commission.\1911\ Any such
appeal must be filed no later than 45 calendar days after the late
study has been completed. The Commission will evaluate whether good
cause exists to grant relief from the study delay penalty and will
issue an order granting or denying relief. In evaluating whether there
is good cause to grant such relief, the Commission may consider, among
other factors: (1) extenuating circumstances outside the transmission
provider's control, such as delays in affected system study results;
(2) efforts of the transmission provider to mitigate delays; and (3)
the extent to which the transmission provider has proposed process
enhancements either in the stakeholder process or at the Commission to
prevent future delays. The filing of an appeal will stay the
transmission providers' obligation to distribute the study delay
penalty funds to interconnection customers until 45 calendar days after
(1) the deadline for filing a rehearing request has ended, if no
requests for rehearing of the Commission's decision on the appeal have
been filed, or (2) the date that any requests for rehearing of the
Commission's decision on the appeal are no longer pending before the
Commission.
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\1911\ We note that these appeals should not be filed under FPA
section 206. Contra Hanwha Q-CELLS USA Corp., 174 FERC ] 61,013, at
PP 9-10 (2021) (interpreting CAISO's open access transmission tariff
provision, which allows market participants that receive specific
CAISO-imposed sanctions to obtain immediate review of CAISO's
determination by directly appealing to the Commission ``in
accordance with [the Commission's] rules and procedures,'' as a
reference to 18 CFR 385.206 and 385.218); Mission Solar LLC, 174
FERC ] 61,014, at PP 10-11 (2021); Cal. Indep. Sys. Operator Corp.,
184 FERC ] 61,009, at P 24 (2023).
---------------------------------------------------------------------------
988. By providing an appeal process, we balance the need to ensure
that transmission providers have an incentive to meet interconnection
study deadlines with protections to ensure that any such penalties are
fair and not triggered if good cause justifies the delay. The
protections embedded in this appeal process address commenters'
concerns that there be adequate due process and/or fact-finding before
imposing a study delay penalty on transmission providers.\1912\
---------------------------------------------------------------------------
\1912\ Indicated PJM TOs Initial Comments at 43-44; ISO/RTO
Council Initial Comments at 2; MISO Initial Comments at 15, 76;
NYISO Initial Comments at 35-36.
---------------------------------------------------------------------------
989. In response to commenters that oppose study delay penalties
because interconnection study delays are often caused by factors
outside transmission providers' control,\1913\ we note that the
penalties adopted herein are an integral element of a just and
reasonable replacement rate to ensure that transmission providers are
properly incentivized to address these factors. We do not find it
appropriate to impose penalties only where a factor can be conclusively
demonstrated to be within a transmission provider's control, as this
would impose significant administrative burden. It may be difficult to
precisely determine the cause of any given delay, especially where
delay occurs due to multiple factors. Further, transmission providers'
concerns are addressed to some extent through the ability to appeal
described above, which provides an opportunity for relief from any
study delay penalties. Further, we note that many of the reforms
adopted in this final rule will help to mitigate factors that may
prolong the study process, such as the submission of speculative
interconnection requests. In addition, the reforms adopted regarding
affected system coordination--discussed later in this final rule--will
address delays resulting from affected system studies. We disagree with
Indicated PJM TOs that a complete de novo review is needed to assess
study delay penalties.\1914\ We find that the good cause standard
adopted in this final rule \1915\ provides an adequate framework
through which the Commission can evaluate whether it is appropriate to
grant relief from any applicable penalties.
---------------------------------------------------------------------------
\1913\ AEP Initial Comments at 25-26; Ameren Initial Comments at
20; Avangrid Initial Comments at 9-10, 29; Dominion Reply Comments
at 19; Indicated PJM TOs Reply Comments at 22-24; ISO-NE Initial
Comments at 35-36; ISO/RTO Council Initial Comments at 3-4; MISO
Initial Comments at 73-74; MISO TOs Initial Comments at 15-16, 23-
24; National Grid Initial Comments at 30; NESCOE Reply Comments at
11-12; NRECA Initial Comments at 9, 33-34; NYISO Initial Comments at
26-27; OMS Initial Comments at 15; Pacific Northwest Utilities
Initial Comments at 9-10; PacifiCorp Initial Comments at 32-35; PG&E
Initial Comments at 7; PG&E Reply Comments at 3-4; Puget Sound
Initial Comments at 9; SDG&E Reply Comments at 1; Southern Initial
Comments at 5, 30; State Agencies Initial Comments at 12-14; Tri-
State Initial Comments at 17-18; U.S. Chamber of Commerce Initial
Comments at 10; WIRES Initial Comments at 9; Xcel Initial Comments
at 38.
\1914\ Indicated PJM TOs Initial Comments at 44.
\1915\ See supra PP 987-988.
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viii. Distribution of Study Delay Penalties to Interconnection
Customers
990. We adopt the NOPR proposal, with modification, set forth in
pro forma LGIP section 3.9(1), to require transmission providers to
distribute study delay penalties on a pro rata basis per
interconnection request to the
[[Page 61152]]
interconnection customers and affected system interconnection customers
included in the relevant study that did not withdraw, or were not
deemed withdrawn, from the interconnection queue before the missed
study deadline. Unless the transmission provider files an appeal to the
study penalty, the study delay penalty must be distributed no later
than 45 calendar days after the late study has been completed.
Specifically, a study delay penalty for a delayed cluster study or
cluster restudy must be distributed on a pro rata basis per
interconnection request to all interconnection customers in the
cluster, per the requirements above. A study delay penalty for a
delayed facilities study must be distributed to the interconnection
customer whose facilities were being studied, per the requirements
above. Further, a study delay penalty for a delayed affected system
study must be distributed to the affected system interconnection
customer(s) whose generating facility was being studied by an affected
system transmission provider, per the requirements above. In response
to PG&E's request for clarification,\1916\ the study delay penalties
are on a per business day basis and will be distributed equally to each
delayed interconnection customer per the requirements above.
---------------------------------------------------------------------------
\1916\ PG&E Initial Comments at 8.
---------------------------------------------------------------------------
991. We find the distribution of the study delay penalties imposed
due to a delay in the study, which defray the study costs of the
interconnection customers affected by that delay, to be just and
reasonable, as they will ensure that interconnection customers are able
to interconnect in a reliable, efficient, transparent, and timely
manner.
ix. No Recovery in Transmission Rates or From Interconnection Customers
992. Regarding recovery of study delay penalties, we modify the
NOPR proposal to prohibit non-RTO/ISO transmission providers and
transmission-owning members of RTOs/ISOs from recovering study delay
penalty amounts through transmission rates. This treatment of study
delay penalties is consistent with the treatment of penalties imposed
pursuant to Order No. 890 \1917\ and will ensure that the study delay
penalties have the incentivizing effect discussed above. Because the
at-fault transmission provider's shareholders will pay the penalty,
this prohibition addresses commenters' concerns \1918\ that study delay
penalty costs will ultimately be borne by customers and ratepayers
through increased transmission costs.\1919\
---------------------------------------------------------------------------
\1917\ See Order No. 890, 118 FERC ] 61,119 at P 1357 (``We will
prohibit all jurisdictional transmission providers from recovering
penalties for late studies from transmission customers.'').
\1918\ Alliant Energy Initial Comments at 6-7; National Grid
Initial Comments at 33; NYISO Reply Comments at 6-7, 9; R Street
Initial Comments at 14; SEIA Reply Comments at 17; State Agencies
Initial Comments at 12; Tri-State Initial Comments at 18.
\1919\ See Order No. 2003, 104 FERC ] 61,103 at P 884
(``[B]ecause liquidated damages liability will not have to be paid
unless the Transmission Provider is at fault, we conclude that these
damages will not be considered just and reasonable costs of service
and will not be recoverable in transmission rates.'').
---------------------------------------------------------------------------
993. Additionally, we decline to allow any transmission provider to
recover study delay penalties from interconnection customers to the
extent the interconnection customers cause delays. If a study delay is
caused by an interconnection customer, and not the transmission
provider, that would represent a potentially compelling basis for the
Commission to find that good cause exists to waive the study delay
penalties. Further, we note that, in the event that an interconnection
request is incomplete or an interconnection customer misses a deadline,
those interconnection requests are subject to the withdrawal provisions
of pro forma LGIP section 3.7.
x. Penalty Recovery in RTOs/ISOs
994. We decline to adopt the NOPR proposal to require RTOs/ISOs to
submit requests to recover the costs of specific study delay penalties
under FPA section 205. RTOs/ISOs may instead submit an FPA section 205
filing to propose a default structure for recovering study delay
penalties and/or make individual FPA section 205 filings to recover the
costs of any specific study delay penalties. We believe that this
discretion for RTOs/ISOs will reduce the administrative burden
associated with study delay penalty cost recovery and will allow RTOs/
ISOs the flexibility to craft rules that work for their region. In
response to ACORE's recommendation that RTOs/ISOs provide criteria for
how they will assign study delay penalties, we note that RTOs/ISOs may
file FPA section 205 proposals to explain how they will recover study
delay penalties.\1920\
---------------------------------------------------------------------------
\1920\ ACORE Initial Comments at 8.
---------------------------------------------------------------------------
995. We modify the NOPR proposal to adopt 18 CFR 35.28(f)(1)(ii) to
specify that, for RTOs/ISOs in which the transmission-owning members
perform certain interconnection studies, the study delay penalties
imposed under the new pro forma LGIP will be imposed directly on the
transmission-owning member(s) that conducted the late study, thereby
mooting the issue of how RTOs/ISOs recover those specific penalties. We
believe that this change will also reduce the administrative burden, as
RTOs/ISOs will typically not need to seek cost recovery for late
facilities studies because those studies are often conducted by
transmission-owning members. This change will also ensure that the
study delay penalties are imposed on the public utility with the most
control over whether the study deadline is met, i.e., the public
utility conducting the study. Doing so aligns the incentive created by
the study delay penalty with the entity most in control of the study
timeline. This change also responds to AEE's suggestion to assign RTO/
ISO study delay penalties directly to transmission owners, OPSI's
contention that RTOs/ISOs may be reluctant to seek cost recovery from
transmission owners, and TAPS' concern that RTOs/ISOs would need well-
supported cases to assign study delay penalties to transmission
owners.\1921\
---------------------------------------------------------------------------
\1921\ AEE Initial Comments at 30; OPSI Initial Comments at 9;
TAPS Initial Comments at 6-7.
---------------------------------------------------------------------------
996. In response to commenters concerned about how study delay
penalties will be assigned if no fault is found among RTO/ISO
members,\1922\ the study delay penalties are imposed automatically on
the RTO/ISO under the pro forma LGIP. As explained above, RTOs/ISOs may
file an FPA section 205 proposal to recover the costs of study delay
penalties. Concerns about any such proposals are best addressed in the
relevant FPA section 205 proceedings. For the same reason, we decline
to adopt TAPS' recommendation that the Commission provide an automatic
waiver of any study delay penalty amount the RTO/ISO would otherwise
pass to ratepayers,\1923\ as such determinations are best made on a
case-by-case basis. In response to Indicated PJM TOs argument that PJM
lacks the contractual authority to seek recovery of study delay
penalties from transmission owners,\1924\ PJM's authority to recover
costs from its transmission-owning members can be properly addressed in
any future FPA section 205 proceeding.
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\1922\ Alliant Energy Initial Comments at 6-7; APPA-LPPC Initial
Comments at 22; ISO/RTO Council Initial Comments at 4; NARUC Initial
Comments at 18; NESCOE Initial Comments at 16.
\1923\ TAPS Initial Comments at 7-8.
\1924\ Indicated PJM TOs Initial Comments at 45.
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997. We acknowledge commenters' concerns that the study delay
penalty structure may impose an administrative and litigative burden on
RTOs/ISOs and
[[Page 61153]]
the Commission,\1925\ and that RTOs/ISOs may be in a fact-finding
position in order to be able to assign study delay penalties not
attributable to an RTO/ISO transmission owning member.\1926\ As an
initial matter, we believe that any such burden is outweighed by the
need to create an incentive to ensure that transmission providers
timely complete interconnection studies. Also, we find that RTOs/ISOs
do not face differing or greater burdens that warrant different
treatment than non-RTO/ISO transmission providers. The pro forma LGIP
applies to all transmission providers, RTO/ISO and non-RTO/ISO alike.
To the extent that RTOs/ISOs elect to create a tariff mechanism for
recovering study delay penalties, rather than relying on individual
filings, as noted above, the RTO/ISO may submit an FPA section 205
filing to propose such a default structure. Finally, where the
transmission-owning members of an RTO/ISO perform interconnection
studies, there is little-to-no ``fact-finding'' to be done to determine
to which public utility to assign study delay penalties, as the
transmission owner will be automatically assigned the penalty pursuant
18 CFR 35.28(f)(1)(ii).
---------------------------------------------------------------------------
\1925\ Avangrid Reply Comments at 8; CAISO Initial Comments at
26; Indicated PJM TOs Reply Comments at 27; ISO-NE Initial Comments
at 35; ISO/RTO Council Initial Comments at 3-4; PJM Initial Comments
at 57-58; MISO Initial Comments at 16, 77; MISO TOs Reply Comments
at 21-22; New York State Department Initial Comments at 10-11; NYISO
Initial Comments at 33; SoCal Edison Initial Comments at 19.
\1926\ ISO-NE Initial Comments at 36; ISO/RTO Council Initial
Comments at 5-6; MISO Initial Comments at 15, 75.
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998. In response to concerns that RTOs/ISOs have no ability to pay
study delay penalties without collecting them from another party,\1927\
we note that RTOs/ISOs have several options under this final rule for
collecting study delay penalties. As discussed above, RTOs/ISOs may
submit FPA section 205 filings to seek recovery for study delay
penalties from public utilities contributing to study delays. The FPA
section 205 filing could propose either to establish a tariff mechanism
for assigning costs generally or for assigning costs for specific study
delay penalties. RTOs/ISOs also have other ways to fund study delay
penalties beyond the revenue they collect for sales of transmission
service: for example, RTOs/ISOs collect administrative fees from market
participants.\1928\
---------------------------------------------------------------------------
\1927\ Alliant Energy Initial Comments at 6-7; EEI Initial
Comments 17; Indicated PJM TOs Initial Comments at 37; ISO/RTO
Council Initial Comments at 3-4; MISO Initial Comments at 13, 71;
MISO TOs Reply Comments at 20; NARUC Initial Comments at 18; NEPOOL
Initial Comments at 16; NESCOE Reply Comments at 11; New York State
Department Initial Comments at 10; North Dakota Commission Initial
Comments at 6; NYISO Initial Comments at 32; Omaha Public Power
Initial Comments at 11; OMS Initial Comments at 15; R Street Initial
Comments at 14; State Agencies Initial Comments at 12-13; TAPS
Initial Comments at 3-5; WIRES Initial Comments at 11.
\1928\ For example, MISO recovers the costs of providing
financial transmission rights (FTR) administrative service from FTR
holders under its Rate Schedule 16 (MISO Tariff, Schedule 16). SPP
recovers the costs of administering its transmission administration
service, transmission congestion rights administrative service, and
integrated marketplace clearing administrative service from
transmission customers and market participants under its Rate
Schedule 1-A (SPP Tariff, Schedule 1-A). PJM recovers the costs of
its control area administration service, which includes ``preserving
the reliability of the PJM Region and administering Point-to-Point
Transmission Service and Network Integration Transmission Service''
from users of the service under Schedule 9-1 (PJM Tariff, Schedule
9-1).
---------------------------------------------------------------------------
999. We disagree with NYISO that study delay penalties would
threaten the financial viability of RTOs/ISOs or fail to incentivize
RTOs/ISOs to complete studies by the required deadlines. The evidence
in this record does not demonstrate that the study delay penalty
structure that we adopt in this final rule, combined with the multiple
adopted safeguards, including a total cap on study delay penalty
amounts, would threaten the financial viability of an RTO/ISO,
particularly given that RTOs/ISOs may submit FPA section 205 filings to
recover study delay penalties. Additionally, as noted, we find that it
is appropriate to incentivize RTOs/ISOs to meet study deadlines in the
same manner as non-RTO/ISO transmission providers. Thus, we also
disagree with NYISO that the study delay penalties for RTOs/ISOs should
be smaller in size and slower to trigger.\1929\ As discussed above, we
believe that the study delay penalty structure strikes a reasonable
balance by providing an adequate incentive without being punitive.
---------------------------------------------------------------------------
\1929\ NYISO Initial Comments at 32, 37, 41.
---------------------------------------------------------------------------
1000. AEP and TAPS assert that the imposition of study delay
penalties will disincentivize RTO/ISO participation.\1930\ We are not
persuaded that any such disincentive outweighs the benefits of adopting
study delay penalties. We expect that an incentive for transmission
providers to meet interconnection study deadlines will result in more
efficient interconnection queue processing, which will benefit
competition and, in the long run, customers within a transmission
provider's region, including within RTO/ISO regions. We continue to
believe that customers are more likely to experience lower overall
costs if the industry relies on robust wholesale competition to
determine the appropriate level of generation and related transmission
development.\1931\
---------------------------------------------------------------------------
\1930\ AEP Initial Comments at 27-28; TAPS Initial Comments at
6.
\1931\ See Order No. 2003-A, 106 FERC ] 61,220 at P 507.
---------------------------------------------------------------------------
1001. We find that applying study delay penalties to RTOs/ISOs for
failing to meet interconnection study deadlines is consistent with
Commission precedent and continues to be appropriate, particularly
given the extent of interconnection queue backlogs in RTOs/ISOs. We
disagree with NYISO that, because RTOs/ISOs may be at greater risk of
being assessed study delay penalties than reliability penalties, this
meaningfully distinguishes study delay penalties from the Commission's
findings in Order Nos. 672-A and 890 related to reliability
penalties.\1932\ In response to NYISO's comment that reliability
penalties receive the Commission's close scrutiny, we note that
transmission providers will have an opportunity to seek relief from a
penalty by filing an appeal, which the Commission will closely
scrutinize and in response to which the Commission will issue an
order.\1933\
---------------------------------------------------------------------------
\1932\ Order No. 672-A, 114 FERC ] 61,328 at P 56 (``it is not
arbitrary and capricious to treat all operators alike, including
RTOs and ISOs, in terms of their liability for violation of a
Reliability Standard.''); Order No. 890, 118 FERC ] 61,119 at P 1357
(``we believe that all entities administering the tariff should
operate under the same rules, reporting obligations, and performance
metrics . . . Non-profit transmission providers have other sources
of money to pay penalties beyond the revenue they collect for sales
of transmission service.'').
\1933\ NYISO Initial Comments at 33-34.
---------------------------------------------------------------------------
xi. Posting Requirements
1002. For transparency purposes, we adopt the proposed requirements
in pro forma LGIP section 3.9(7) that transmission providers must post
on their OASIS or other publicly accessible website on a quarterly
basis, within 30 calendar days of the end of the calendar quarter, (1)
the total amount of study delay penalties from the previous reporting
quarter, and (2) the highest amount of such study delay penalties
repaid to a single interconnection customer during the previous
reporting quarter. We also adopt the proposed requirements in pro forma
LGIP section 3.9(7) that transmission providers must maintain the
quarterly measures posted on their OASIS or website for three calendar
years, with the first required posting to be the third cluster study
cycle (including any transitional cluster study cycle, but not
transitional serial studies) after the transmission provider
transitions to the cluster study process. We believe that this
additional
[[Page 61154]]
information will be helpful to the public and the Commission in
tracking the status of interconnection queue delays and that the burden
on transmission providers of posting this information will be minimal.
xii. Force Majeure Exception
1003. We decline to adopt the NOPR proposal to exempt transmission
providers from study delay penalties where force majeure applies. We
believe that this exemption is unwarranted: transmission providers may
explain in any appeal to the Commission any circumstances that caused
the delay, including any events that qualify as force majeure, and the
Commission will consider such circumstances as part of its evaluation
of whether good cause exists to grant relief from the otherwise
applicable study delay penalties.
xiii. Transmission Provider Resources
1004. In response to commenters that raise concerns about
transmission provider resources to complete studies on time, we first
emphasize that the overall set of reforms in this final rule should
significantly streamline and reduce the number of interconnection
studies that a transmission provider must conduct, easing the burden on
transmission providers. With the benefit of fewer studies and fewer
speculative generating facilities in the interconnection queue, we
expect that a transmission provider that faces the potential of a study
delay penalty for failing to meet interconnection study deadlines will
be able to allocate sufficient resources to conduct interconnection
studies, in addition to implementing reforms to ensure that its study
process is efficient. In this final rule, we adopt interconnection
study deadlines for a transmission provider to complete cluster
studies, cluster restudies, facilities studies, and affected system
studies. As discussed above, we believe that the interconnection study
deadlines will give transmission providers sufficient time to conduct
the relevant studies, e.g., 150 calendar days for the completion of the
cluster study, and we have demonstrated that the existing pro forma
generator interconnection procedures and agreements are insufficient to
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner.\1934\ We therefore believe that the record supports the
imposition of study delay penalties for failure to meet those
deadlines.
---------------------------------------------------------------------------
\1934\ See supra section II.C.
---------------------------------------------------------------------------
1005. Some commenters argue that other NOPR proposals, such as the
optional resource solicitation studies, optional informational
interconnection studies, and evaluation of advanced transmission
technologies, will consume transmission provider resources otherwise
dedicated to interconnection studies.\1935\ Similarly, other commenters
argue that imposing firm study deadlines will force transmission
providers to redirect resources and personnel away from other necessary
functions such as transmission planning or deprive them of financial
resources and make it harder to retain qualified personnel.\1936\ We
note that we do not adopt the NOPR proposals to implement optional
informational interconnection studies or optional resource solicitation
studies and adopt a modified version of the NOPR proposal to require
evaluation of certain enumerated advanced transmission technologies,
which should reduce the burden on transmission providers as compared to
that under the NOPR. Further, to these arguments, we note that it is
the transmission provider's responsibility to manage its organizational
resources--including attracting and retaining sufficient qualified
personnel to meet its responsibilities--and that it is within the
transmission provider's ability to improve how it manages its internal
resources. If, for whatever reason, the transmission provider is not
able to meet firm study deadlines, that is an issue the transmission
provider is free to raise in appealing any penalties it incurs. While
we are not persuaded that transmission providers will necessarily need
to reassess their organizational needs to meet study deadlines, given
the suite of reforms adopted in the final rule, to the extent that such
steps are required, they are warranted to fulfill our responsibility
under the FPA to ensure just and reasonable rates and to ensure that
interconnection customers are able to interconnect in a reliable,
efficient, transparent, and timely manner.
---------------------------------------------------------------------------
\1935\ Indicated PJM TOs Initial Comments at 36; MISO Reply
Comments at 7; PPL Initial Comments at 24; SPP Initial Comments at
13.
\1936\ Ameren Initial Comments at 21; Eversource Initial
Comments at 25-26; Indicated PJM TOs Initial Comments at 6, 24, 40;
MISO TOs Initial Comments at 24; National Grid Initial Comments at
30; Pacific Northwest Utilities Initial Comments at 12; PJM Initial
Comments at 57.
---------------------------------------------------------------------------
1006. We disagree with SoCal Edison and New York State Department
that transmission providers will require additional resources to track
and allocate study delay penalties, potentially increasing the cost of
administering interconnection queues.\1937\ We note that transmission
providers already track the progress of their interconnection queues
and should be aware of study deadlines, especially as their tariffs
currently require reasonable efforts to meet such deadlines. As a
result, determining when study delay penalties apply will be as
straightforward as determining how many studies are late and past the
10-business day grace period from the applicable study deadline. As
explained above, we anticipate that other provisions of this final rule
will result in improved interconnection queue management and
processing, which should ease the burden on transmission providers over
time.
---------------------------------------------------------------------------
\1937\ New York State Department Initial Comments at 10-11;
SoCal Edison Initial Comments at 19.
---------------------------------------------------------------------------
1007. We also disagree with commenters that firm study deadlines
with study delay penalties will necessarily reduce interconnection
study flexibility \1938\ and accuracy,\1939\ as well as system
reliability.\1940\ We reiterate that it is within transmission
providers' ability to improve interconnection study processes and
policies and take other measures, such as hiring additional staff, to
efficiently process interconnection queues without sacrificing
accuracy, flexibility, or reliability. Study delay penalties will
incentivize these actions, especially given transmission providers'
independent responsibilities to deliver accurate studies and to ensure
system reliability. Thus, we agree with the New Jersey Commission that
there is not an inherent tradeoff between holding
[[Page 61155]]
transmission providers accountable and transmission system reliability.
In addition, we further agree that the failure to bring new generating
facilities online in a timely manner can also create reliability and
economic risk.\1941\ Moreover, interconnection customers, rather than
transmission providers, ultimately bear the costs of interconnection
studies. To the extent that it is more costly to complete studies in a
timely and accurate fashion, these interconnection study costs will be
passed on to interconnection customers. Further, as noted above, the
study delay penalty structure includes significant safeguards for the
transmission provider, such as the transition period, the 10-business
day grace period, the penalty cap, the ability to extend deadlines by
mutual agreement, and the ability to appeal any study delay penalties
to the Commission.
---------------------------------------------------------------------------
\1938\ Dominion Reply Comments at 21; EEI Initial Comments at
15; Eversource Initial Comments at 25-26; NYISO Initial Comments at
38-39; WIRES Initial Comments at 10.
\1939\ AECI Initial Comments at 6; Alliant Energy Initial
Comments at 6; Avangrid Initial Comments at 9-10, 30; Bonneville
Initial Comments at 15-16; CESA Reply Comments at 8; Clean Energy
Buyers Initial Comments at 10-11; Enel Initial Comments at 48;
Indicated PJM TOs Reply Comments at 26; ISO/RTO Council Initial
Comments at 8; Longroad Energy Reply Comments at 14; MISO Initial
Comments at 13, 71, 77-78; MISO TOs Initial Comments at 14, 24;
National Grid Initial Comments at 30; NESCOE Reply Comments at 13;
NextEra Reply Comments at 11; NYTOs Initial Comments at 24-28; North
Dakota Commission Initial Comments at 6; NRECA Initial Comments at
34; NYISO Initial Comments at 38-39; Omaha Public Power Initial
Comments at 12; OMS Initial Comments at 15; [Oslash]rsted Initial
Comments at 15; PacifiCorp Reply Comments at 6; PJM Initial Comments
at 8, 56-57; PPL Initial Comments at 19; SPP Initial Comments at 11-
12; Tri-State Initial Comments at 18; Xcel Initial Comments at 38.
\1940\ AEP Initial Comments at 28; Dominion Reply Comments at
21; MISO TOs Reply Comments at 18-19; NYISO Initial Comments at 39;
PJM Initial Comments at 8, 56-57.
\1941\ New Jersey Commission Reply Comments at 3.
---------------------------------------------------------------------------
xiv. Coordination Among Transmission Providers, Interconnection
Customers, and Affected Systems
1008. Several commenters raise concerns related to affected
systems, and coordination among transmission providers, interconnection
customers, and affected systems. In response to NARUC's request for
clarification regarding affected system studies, we note that new pro
forma LGIP section 3.9 will apply to all transmission providers when
they are acting as an affected system operator (affected system
transmission providers).\1942\ As a result, affected system
transmission providers are also subject to a study delay penalty for a
late affected system study. Thus, contrary to commenters' arguments
that the NOPR proposal ignores that other entities, such as affected
systems, may be responsible for study delays,\1943\ affected system
transmission providers will face the same incentive as the host
transmission provider to timely complete their studies. In addition,
where a delay for a host transmission provider's cluster or facilities
studies is caused by affected system study delays, the host
transmission provider can file an appeal of any applicable study delay
penalty with the Commission and include such details in its claim of
good cause for relief.
---------------------------------------------------------------------------
\1942\ NARUC Initial Comments at 14, 17.
\1943\ ISO/RTO Council Initial Comments at 3-4; MISO Initial
Comments at 74.
---------------------------------------------------------------------------
1009. We disagree with commenters' concerns that the study delay
penalty structure would decrease or harm coordination between
transmission providers, interconnection customers, and affected
systems,\1944\ and/or create tension between RTOs/ISOs, transmission
owners, developers, or other parties.\1945\ The incentive for
transmission providers to timely complete interconnection studies
created by the study delay penalty structure should improve
coordination among transmission providers and interconnection customers
to ensure that transmission providers have the information needed to
complete the studies and, if there is an issue, to pursue a potential
extension of the deadline via mutual agreement. We note that other
reforms adopted in this final rule will improve clarity and efficiency
around affected system studies, which should improve coordination with
affected systems. In addition, affected system transmission providers
are also subject to study delay penalties for delayed affected system
studies, which should encourage better coordination. We also believe
that an ability to appeal study delay penalties will provide a
structured forum for parties to dispute claims, placing the Commission
in the position of decisionmaker when it comes to determining whether
to excuse study delay penalties.
---------------------------------------------------------------------------
\1944\ Alliant Energy Initial Comments at 6; EEI Initial
Comments at 15; Eversource Initial Comments at 25-26; MISO Reply
Comments at 21; North Dakota Commission Initial Comments at 6.
\1945\ AEP Initial Comments at 27; Dominion Initial Comments at
35-36; Indicated PJM TOs Reply Comments at 6-7, 27; NextEra Initial
Comments at 30; NYISO Initial Comments at 39-40; PJM Initial
Comments at 57-58.
---------------------------------------------------------------------------
1010. We disagree with AECI that there is no benefit to imposing
penalties on affected system transmission providers for failure to
timely complete affected system studies. These studies equally affect
interconnection customer certainty and interconnection process
efficiency, and as such, we believe that the penalty structure
enumerated above will also incentivize transmission providers to
complete affected system studies in a timely manner. Indeed, the
Commission has addressed several instances where affected system
studies have delayed or otherwise affected interconnection study
timelines and processes,\1946\ and therefore, without imposing a
penalty structure, we are not convinced that transmission providers
will timely complete their affected system studies. In the same vein,
we agree with Interwest that monetary penalties for failure to meet the
affected system study deadline will incentivize discipline and support
investment needed to meet affected system study timelines.
---------------------------------------------------------------------------
\1946\ See, e.g., Tenaska Clear Creek Wind, LLC v. Sw. Power
Pool, Inc., 177 FERC ] 61,200 (2021); EDF Renewable Energy, Inc. v.
Midcontinent Indep. Sys. Operator, Inc., 168 FERC ] 61,173 (2019).
---------------------------------------------------------------------------
1011. In response to ENGIE, MISO, and Duke Southeast Utilities'
comments on the distribution of study delay penalties for failure to
timely complete affected system studies, we note that any study delay
penalties will be distributed on a pro rata basis per interconnection
request to the affected system interconnection customers included in
the relevant study that did not withdraw, or were not deemed withdrawn,
from the interconnection queue before the missed study deadline.
xv. Commission Authority and Precedent
1012. Some commenters argue that the proposed study delay penalty
structure is an unjustified shift from precedent established in Order
No. 845, in which the Commission expressly declined to impose
penalties.\1947\ We disagree. As we explain above, interconnection
queue delays in many parts of the country have worsened since Order No.
845, and the record indicates that the failure of transmission
providers to timely complete studies is a significant part of the
reason why. For example, in the single year between 2021 and 2022,
there was marked increase in the average length of time customers have
been waiting in the interconnection queue, increasing from roughly 4 to
5 years, while at the same time seeing the total interconnection queue
size increased from 1,400 GW to more than 2,000 GW.\1948\ Based on the
recent interconnection study metrics transmission providers posted in
compliance with Order No. 845, of the 2,179 interconnection studies
completed in 2022, 68% were issued late.\1949\ Furthermore, at the end
of 2022, an additional 2,544 studies were delayed (i.e., ongoing and
past their deadline).\1950\ All of the RTOs/ISOs except CAISO and 14
non-RTO/ISO transmission providers reported delayed studies at the end
of 2022.\1951\ We believe that this large number of delayed studies is
a significant part of
[[Page 61156]]
the explanation for the extensive delays and growing interconnection
queues documented above and in the Overall Need for Reform section.
Accordingly, based on the evidence in this record, we find that study
delay penalties are an appropriate component of a just, reasonable, and
not unduly discriminatory or preferential replacement rate to remedy
these interconnection delays and the consequences they have for
Commission-jurisdictional rates.\1952\
---------------------------------------------------------------------------
\1947\ MISO TOs Initial Comments at 21-22; NYISO Initial
Comments at 26; PG&E Initial Comments at 6; PG&E Reply Comments at
3.
\1948\ Queued Up 2022 at 3; Queued Up 2023 at 3, 31.
\1949\ Based on data provided by transmission providers in
compliance with Order No. 845. See appendix B to this final rule for
the underlying data.
\1950\ Id. Note that the vast majority of these studies (2,211)
were in PJM.
\1951\ Id. CAISO revised the interconnection study deadlines of
their queue cluster 14 to account for the unprecedented increase in
interconnection requests. Cal. Indep. Sys. Operator Corp., 176 FERC
] 61,207.
\1952\ See Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm
Mut. Auto. Ins. Co., 463 U.S. at 56-57 (``[T]he agency is entitled
to change its view . . . [if it] explain[s] its reasons for doing
so.'').
---------------------------------------------------------------------------
1013. Similarly, in response to commenters who argue that the
proposed study delay penalty structure differs from the penalty
structure implemented in Order No. 890 for transmission service
studies,\1953\ we believe that such differences are warranted by the
significant and growing interconnection queue backlogs. We agree with
PacifiCorp that, compared to transmission service requests,
interconnection studies are more numerous, complex, and susceptible to
delays.\1954\ Further, as noted above, there is a growing number of
interconnection customers affected by study delays. We believe that
these factors underscore the need for transmission providers to meet
study deadlines and the need to provide an incentive, in the form of
study delay penalties. We find that the other reforms adopted in this
final rule will streamline interconnection processes: for example, the
cluster study process will reduce the number of interconnection studies
that any transmission provider must conduct at a given time, thus
reducing the potential for study delay penalties to accumulate relative
to the serial study process in place today. We find that the
elimination of the reasonable efforts standard and adoption of the
study delay penalty structure will incentivize transmission providers
to take appropriate steps to meet the study deadlines in their tariffs.
---------------------------------------------------------------------------
\1953\ Eversource Initial Comments at 30; MISO Reply Comments at
21; MISO TOs Initial Comments at 19-21; PacifiCorp Initial Comments
at 33-34; Tri-State Initial Comments at 18.
\1954\ PacifiCorp Initial Comments at 33-34.
---------------------------------------------------------------------------
1014. We also disagree with TAPS' assertion that reliability
penalties are permissible because they are part of a congressionally
mandated regime, whereas the study delay penalties are not.\1955\ We
find that FPA section 206 provides us with the authority to establish a
structure to impose study delay penalties because such delays render
Commission-jurisdictional rates unjust and unreasonable, as explained
in the Overall Need for Reform section, and we believe that this
structure reflects a just and reasonable replacement rate.\1956\ As
discussed above, an RTO/ISO has different options for recovering those
penalties, and we are not in this final rule dictating which option an
RTO/ISO must choose. Further, TAPS' argument that reliability penalties
are used to offset NERC's operation costs but the interconnection study
delay penalties will not be used to offset costs for consumers or
ratepayers does not change our conclusion.\1957\ We do not believe that
our authority to require study delay penalties as part of a just and
reasonable replacement rate turns on the entity whose costs are offset
by the penalties collected, and as discussed above, we find it
appropriate in this circumstance to use study penalties to offset the
interconnection study costs for interconnection customers that are
affected by the study delays.
---------------------------------------------------------------------------
\1955\ TAPS Initial Comments at 5 (citing 16 U.S.C. 824o).
\1956\ 16 U.S.C. 824e.
\1957\ TAPS Initial Comments at 5.
---------------------------------------------------------------------------
1015. Moreover, automatic tariff-based penalty mechanisms similar
to that which we adopt in this final rule exist in a variety of other
contexts. For example, RTO/ISO tariffs include penalties for ``traffic
ticket'' violations that are penalized without referral to the
Commission.\1958\ In that context, the Commission has approved such
automatic penalties where (1) the activity is expressly set forth in
the tariff, (2) the activity involves objectively identifiable
behavior, and (3) the activity does not subject the actor to sanctions
or consequences other than those expressly approved by the Commission
and set forth in the tariff, with the ability to appeal \1959\ to the
Commission.\1960\ That is the same structure we are adopting here: the
study delay penalties (1) will be expressly set forth in the tariff,
(2) will be based on objectively identifiable behavior (i.e., whether a
study is late), and (3) will only trigger consequences expressly
approved by the Commission (i.e., the $1,000/$2,000/$2,500 per business
day penalties with the ability to appeal to the Commission.
---------------------------------------------------------------------------
\1958\ See, e.g., Cal. Indep. Sys. Operator Corp., 134 FERC ]
61,050, at PP 34-35 (2011); N.Y. Indep. Sys. Operator, Inc., 131
FERC ] 61,225, at P 16 (2010). Also, in Order No. 890, the
Commission approved other tariff-based ``operational penalties'' on
customers where it similarly did not require notification or review
by the Commission of the assessed penalty. See Order No. 890, 118
FERC ] 61,119 at PP 834-36.
\1959\ See, e.g., Cal. Indep. Sys. Operator Corp., 175 FERC ]
61,043 (2021) (excusing penalties for late meter data revisions);
Lathrop Irrigation Dist., 161 FERC ] 61,243 (2017) (denying request
for waiver of CAISO tariff provisions that impose penalties on late
submission by LSEs of required information for resource adequacy
plans).
\1960\ Cal. Indep. Sys. Operator Corp., 134 FERC ] 61,050 at PP
34-35.
---------------------------------------------------------------------------
1016. In response to Indicated PJM TOs' argument that the
Commission lacks the authority to require RTOs/ISOs to seek cost
recovery of study delay penalties from transmission owners within the
RTO/ISO,\1961\ we note that this concern is moot because we are
declining to adopt the NOPR proposal to require RTOs/ISOs to submit
requests to recover the costs of specific study delay penalties.
Further, we modify our proposal to adopt revisions to 18 CFR
35.28(f)(1)(ii) to automatically apply study delay penalties to
transmission owners within RTOs/ISOs when those transmission owners
have conducted the delayed studies. Finally, as discussed above, RTOs/
ISOs may submit an FPA section 205 filing to propose a default
structure for recovering study delay penalties or make individual FPA
section 205 filings to recover the costs of any specific study delay
penalties.
---------------------------------------------------------------------------
\1961\ Indicated PJM TOs Initial Comments at 44-45.
---------------------------------------------------------------------------
xvi. Miscellaneous
1017. We also decline to adopt alternative proposals for study
delay penalty structures. We find the penalty structure that we adopt
in this final rule to be a just and reasonable replacement rate, which
is all that the Commission is required to show under FPA section
206.\1962\
---------------------------------------------------------------------------
\1962\ Entergy Ark., LLC v. FERC, 40 F.4th 689, 701 (D.C. Cir.
2022) (explaining that in setting the replacement rate under FPA
section 206, ``FERC is not required to choose the best solution,
only a reasonable one'') (quoting Petal Gas Storage, LLC v. FERC,
496 F.3d 695, 703 (D.C. Cir. 2007)).
---------------------------------------------------------------------------
1018. In response to EEI's and Eversource's comments concerning why
the good utility practice standard, which is contained within the text
of the definition of the reasonable efforts standard in the pro forma
LGIP, would no longer apply to interconnection processes,\1963\ we
clarify that the elimination of the reasonable efforts standard does
not eliminate the requirement that transmission providers act
consistent with good utility practice when conducting interconnection
studies. Therefore, we adopt revisions to section 4.2 of the pro forma
LGIP to indicate that transmission providers must continue to conduct
interconnection studies consistent with good utility practice.
---------------------------------------------------------------------------
\1963\ EEI Initial Comments at 15; Eversource Initial Comments
at 22-24.
---------------------------------------------------------------------------
[[Page 61157]]
1019. Some commenters argue that interconnection study deadlines
should be extended in cases of interconnection customer-caused delays
and that the timeline for completing such studies should not restart
until after an interconnection customer submits all necessary
information and cures any deficiencies; they also argue that
transmission providers should not be penalized if study delays are
caused by a higher-queued cluster being restudied.\1964\ We decline to
adopt these modifications. As an initial matter, we note that if an
interconnection customer fails to adhere to all requirements in the pro
forma LGIP, except in the case of disputes, the transmission provider
shall deem the interconnection customer's interconnection request to be
withdrawn pursuant to section 3.7 of the pro forma LGIP. To the extent
that study delays result from an interconnection customer's actions or
higher-queued cluster restudies, transmission providers may record the
length of those delays and report that information in any appeal of
study delay penalties filed with the Commission.
---------------------------------------------------------------------------
\1964\ APPA-LPPC Initial Comments at 21; NRECA Initial Comments
at 34; Tri-State Initial Comments at 18-19.
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1020. We disagree with PJM that interconnection customers will be
incentivized to delay studies of their interconnection requests in
order to offset their study costs via study delay penalties being
allocated to them from the transmission provider.\1965\ We agree with
AEE that the economic harms of delaying the interconnection process for
an interconnection customer with a commercially viable interconnection
request, especially given the reforms adopted in this final rule (e.g.,
increased study deposits, commercial readiness deposits, and withdrawal
penalties) significantly outweigh any economic incentive for
interconnection customers to delay the interconnection process in hopes
of a study delay penalty to offset study costs.\1966\ For example, a
cluster study delayed by 100 business days would generate $100,000 in
study delay penalties to be distributed among all interconnection
customers in the cluster, yet such a lengthy delay could force an
interconnection customer to withdraw from the interconnection queue due
to commercial obligations and carries an interconnection customer
withdrawal penalty risk of two times the study cost.
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\1965\ PJM Initial Comments at 57.
\1966\ AEE Reply Comments at 35-36.
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1021. We decline requests to delay implementation of the study
delay penalty reforms until other reforms in this rulemaking and
related rulemakings, such as those in Docket No. RM22-17, take
effect.\1967\ As explained above, our modification to the NOPR's
proposed transition mechanism for study delay penalties, which will
allow transmission providers to complete two cluster study cycles
before being subject to study delay penalties, will provide sufficient
time for transmission providers to implement the other reforms adopted
in this final rule. This transition mechanism will also give
transmission providers currently undergoing their own interconnection
queue reform efforts, as SPP and NYISO explain they are, time to
implement those reforms.\1968\ In addition, we find that the study
delay penalties are just and reasonable based on the record in this
proceeding and that it would not be appropriate to delay their effect
until action is taken in other proceedings. To the extent the
Commission finalizes the proposed reforms in separate proceedings, the
Commission will consider how to address potential interactions between
the reforms adopted in this final rule and elsewhere.
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\1967\ AEP Initial Comments at 29; Avangrid Reply Comments at
14; Clean Energy Buyers Initial Comments at 10-11; Eversource
Initial Comments at 30-31; Idaho Power Initial Comments at 10; ISO/
RTO Council Reply Comments at 5; Longroad Energy Reply Comments at
15; NY Commission and NYSERDA Initial Comments at 6; NYISO Initial
Comments at 30; Pacific Northwest Utilities Initial Comments at 9-
10; PacifiCorp Initial Comments at 34; Puget Sound Initial Comments
at 11; State Agencies Initial Comments at 14; TAPS Initial Comments
at 9.
\1968\ NYISO Initial Comments at 30; SPP Initial Comments at 14-
15.
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1022. In response to WAPA's comment that Federal agencies should
not be subject to study delay penalties absent a specific congressional
waiver of sovereign immunity,\1969\ we clarify that the penalties will
apply to the extent that a non-public utility has adopted the proposed
penalty provisions as a part of its reciprocity tariff.\1970\ Under the
safe harbor procedure set out in Order No. 888, non-public utilities
may voluntarily submit to the Commission an open access transmission
tariff; if the Commission finds that the tariff contains terms and
conditions that substantially conform or are superior to those in the
pro forma open access transmission tariff, the Commission will deem it
an acceptable reciprocity tariff and will require public utilities to
provide open access transmission service to that particular non-public
utility (safe harbor treatment).\1971\ We find that, where such non-
public utilities voluntarily file a reciprocity tariff, they consent to
abide by the Commission's open access principles and the various
provisions of the pro forma tariff, which would include the penalties
we are adopting in this final rule (unless the Commission were to find
that a safe harbor tariff without those penalty provisions
substantially conforms or is superior to the pro forma tariff).\1972\
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\1969\ WAPA Initial Comments at 10.
\1970\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission on Servs. by Pub. Utils.; Recovery of
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888,
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036, at 31,760-
763 (1996) (cross-referenced at 75 FERC ] 61,080), order on reh'g,
Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ]
31,048 (cross-referenced at 78 FERC ] 61,220), order on reh'g, Order
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C,
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002).
\1971\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,761.
\1972\ Where, as here, the Commission makes changes to the pro
forma tariff, a non-public utility that already has a reciprocity
tariff and wishes to maintain its safe harbor treatment must amend
its tariff so that its provisions substantially conform or are
superior to the revised pro forma tariff. See Order No. 2003, 104
FERC ] 61,103 at P 842.
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1023. WAPA cites to Southwestern Power Admin. v. FERC \1973\ for
its proposition that, absent a specific waiver of sovereign immunity,
Federal agencies are not subject to monetary penalties.\1974\ We find
that case inapposite because the penalties adopted here are not civil
monetary penalties imposed by the Commission and paid to the U.S.
Treasury. Instead, they would be penalties imposed pursuant to a
voluntarily submitted reciprocity tariff and would be distributed to
the delayed interconnection customer(s) in the relevant study that
remained in the interconnection queue at the time the penalty would be
distributed. WAPA and other Federal agencies, if they file reciprocity
tariffs, would voluntarily choose to abide by the terms of those
tariffs and thus would consent to any penalty structures contained in
them.
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\1973\ Sw. Power Admin. v. FERC, 763 F.3d 27 (D.C. Cir. 2014).
\1974\ WAPA Initial Comments at 10 n.12.
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1024. We decline to adopt commenters' suggestions to create generic
exceptions to study delay penalties.\1975\ Not only do we lack record
support for some of the suggestions, but we also believe that
[[Page 61158]]
transmission provider requests for an exception to a study delay
penalty are best addressed on a case-by-case basis via the appeal
process outlined above.
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\1975\ Indicated PJM TOs Initial Comments at 42; MISO TOs
Initial Comments at 25; National Grid Initial Comments at 32; NESCOE
Initial Comments at 16; NYISO Initial Comments at 42; PPL Initial
Comments at 19; SoCal Edison Initial Comments at 19; Tri-State
Initial Comments at 18; WIRES Initial Comments at 10; Xcel Initial
Comments at 38.
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1025. We decline to adopt alternative proposals suggested by
various commenters. For example, we do not believe that imposing only a
reporting requirement on study delays is sufficient to resolve the
problem of interconnection queue backlogs and repeatedly delayed
interconnection studies. Similarly, we decline to condition study delay
penalties on the outcome of a show cause proceeding conducted by the
Commission, as suggested by MISO,\1976\ because it would be
administratively burdensome and may not create a sufficient incentive
for transmission providers to meet interconnection study deadlines. We
also decline to adopt suggestions such as creation of favorable rate
treatment for transmission providers that meet interconnection study
deadlines \1977\ or tying interconnection study performance to
executive compensation,\1978\ which we do not believe would ensure that
interconnection customers are able to interconnect in a reliable,
efficient, transparent, and timely manner as effectively as the study
delay penalty structure that we adopt instead.
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\1976\ MISO Initial Comments at 79-80.
\1977\ Longroad Energy Reply Comments at 14-15; Shell Initial
Comments at 11.
\1978\ Clean Energy States Initial Comments at 10-11; CREA and
NewSun Reply Comments at 57; TAPS Initial Comments at 8.
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2. Affected Systems
a. Need for Reform
i. NOPR Proposal
1026. In the NOPR, the Commission preliminarily found that the
affected system study process lacks consistency between transmission
providers.\1979\ The Commission stated that, without any requirement
for a timely cost determination, affected system operators may not
return study results in time for interconnection customers to make
informed decisions to facilitate interconnection of their generating
facilities. The Commission added that, due to this lack of information,
there may continue to be late-stage withdrawals resulting from
unexpected high costs for affected system network upgrades that create
restudies and delays.\1980\ The Commission also noted that
interconnection customers recommended standardization of the affected
system study process in both the technical conference in Docket No.
AD18-8-000 and in comments on the ANOPR in Docket No. RM21-17-000,
specifically asking for standardization of the timing of study results,
the amount of study costs, and modeling criteria used in affected
system studies.\1981\
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\1979\ NOPR, 179 FERC ] 61,104 at P 179 (citing May Joint Task
Force Tr. 67:6-8 (Dan Scripps) (``Specifically, there may be an
opportunity to create a general framework that would be consistent
across RTO seams.''); id. 68:12-18 (Ted Thomas) (agreeing with Chair
Scripps that ``the most effective place that FERC can operate is in
the area where you have two RTOs and the real issue is getting them
on the same page'')).
\1980\ Id. (citing May Joint Task Force Tr. 67:14-17 (Dan
Scripps) (``[W]e expect the affected systems study process to become
increasingly critical as more renewable resources come online in
renewable rich areas and transmission capacity becomes ever more
scarce.'')).
\1981\ Id. P 180 (referencing May Joint Task Force Tr. 64:18-24
(Dan Scripps) (stating that ``FERC may have a larger role to play in
issues that cross RTO boundaries, particularly, around cross-RTO
affected system studies where individual RTOs have limited control''
and certainty ``around the timing of affected systems studies'')).
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1027. The Commission noted that, currently, detailed information
about any two transmission providers' affected system study processes
is found in multiple transmission provider documents and is not
necessarily cohesive, which appears to create confusion and
uncertainty.\1982\ The Commission further preliminarily found that,
despite these documents, much of the affected system study process is
ad hoc and, therefore, unclear to interconnection customers. In
addition, the Commission explained that affected system study processes
are highly variable based on region and transmission provider, and they
may not be uniform even across a single transmission provider's
footprint.
---------------------------------------------------------------------------
\1982\ Id. P 181.
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1028. The Commission preliminarily found that the lack of an
affected system study process results in Commission-jurisdictional
rates that are unjust and unreasonable because an interconnection
customer cannot evaluate its costs in a timely manner, which increases
uncertainty and may result in late-stage withdrawals and subsequent
restudies, delays, and increased costs to the remaining interconnection
customers in the interconnection queue.\1983\ The Commission stated
that, without a transparent affected system study process, it appears
that neither an interconnection customer nor the Commission can
evaluate whether the affected system operator has acted in an unduly
discriminatory manner. The Commission further stated that reforms to
improve transparency and coordination, therefore, may be necessary to
establish a just, reasonable, and not unduly discriminatory or
preferential affected system study process.
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\1983\ Id. P 182.
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ii. Comments
1029. Multiple commenters generally support action to address the
Commission's identified need to reform affected system study
processes.\1984\ For example, AEE asserts that existing affected system
study processes are plagued by uncertainty and a lack of transparency,
which, in turn, create delays, interconnection queue withdrawals, and
cost increases.\1985\ Invenergy, Enel, and SEIA assert that current
misalignments in and lack of coordination of affected system study
processes can lead to uncertain, duplicative, or unexpected study
results.\1986\ Some commenters support synchronization and
harmonization of affected system study processes, with NextEra alleging
that study processes across several regions lack transparency,
consistency, coordination, and accountability, which results in errors
and delays.\1987\ Similarly, Google contends that current affected
system study processes lack deadlines or structure, which exacerbates
anticipating interconnection costs and, in turn, stifles
investments.\1988\ National Grid asserts that host transmission system
and affected system study processes can be significantly misaligned
with project development, investment, and financing timelines and
decision points, resulting in unmanageable risk for interconnection
customers.\1989\
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\1984\ ACE-NY Initial Comments at 8-9; AEE Initial Comments at
34-35; Enel Initial Comments at 58; Google Initial Comments at 5-6,
22; Invenergy Initial Comments at 40; Omaha Public Power Initial
Comments at 12; SEIA Initial Comments at 34-35; Shell Initial
Comments at 30.
\1985\ AEE Initial Comments at 34-35; see also ELCON Initial
Comments at 7; SEIA Initial Comments at 34-35; Shell Initial
Comments at 30.
\1986\ Enel Initial Comments at 58; Invenergy Initial Comments
at 40; SEIA Initial Comments at 34-35. Invenergy states that many
commenters acknowledge the need for improvements to current affected
system study processes. Invenergy Reply Comments at 7-8.
\1987\ APS Initial Comments at 19; ELCON Initial Comments at 7;
NextEra Initial Comments at 31-32; NextEra Reply Comments at 4;
Omaha Public Power Initial Comments at 12.
\1988\ Google Initial Comments at 5-6, 22; U.S. Chamber of
Commerce Initial Comments at 10-11.
\1989\ National Grid Initial Comments at 35.
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1030. Several commenters highlight the shortcomings of current pro
forma LGIP requirements and their contribution to affected system study
process problems.\1990\ ACE-NY emphasizes that nothing in the pro forma
LGIP binds the affected system
[[Page 61159]]
study process, and, as a result, interconnection customers are open to
significant impacts and unreasonable timelines.\1991\ OMS highlights
the limited control that RTOs/ISOs have regarding the timing of
affected system studies.\1992\ NYISO and Ameren assert that more
specific requirements regarding roles and responsibilities of parties
in the affected system study process are needed.\1993\ According to
Invenergy, the Commission has until now declined to impose any
organized structure around the affected system study process because
affected system network upgrades and associated costs were thought to
be a relatively rare occurrence.\1994\ Invenergy contends that this has
resulted in transmission providers conducting studies using variable
study assumptions and standards and assigning significant system
upgrade costs at any time, even after an interconnecting generating
facility is already in operation.
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\1990\ See, e.g., Clean Energy Associations Initial Comments at
47-48; UMPA Initial Comments at 5-6.
\1991\ ACE-NY Initial Comments at 9.
\1992\ OMS Initial Comments at 16; see also PJM Reply Comments
at 10 (arguing that an RTO/ISO has no authority to compel other
RTOs/ISOs to complete interconnection studies on its deadline).
\1993\ Ameren Initial Comments at 22; NYISO Initial Comments at
44.
\1994\ Invenergy Initial Comments at 39 (citing Order No. 2003,
104 FERC ] 61,103 at P 120).
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1031. On the other hand, several commenters doubt whether
standardization of affected system study processes is warranted and
argue that adopting the NOPR proposal will cause timeline problems and
delays.\1995\ SDG&E contends that, based on its experience, affected
system studies infrequently trigger the need for construction of new
network upgrades, and thus it does not find the current process
deficient.\1996\ AECI states that its current coordination process is
not in need of reform because it effectively coordinates with several
affected systems and recognizes the unique situations presented at
different seams.\1997\
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\1995\ Dominion Initial Comments at 36-37; PJM Initial Comments
at 63; SPP Initial Comments at 17; WAPA Initial Comments at 10.
\1996\ SDG&E Reply Comments at 3.
\1997\ AECI Initial Comments at 6.
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iii. Commission Determination
1032. We affirm the Commission's preliminary findings in the NOPR
that there is a compelling need for affected system study process
reforms. The record demonstrates that, absent reforms, affected system
studies will likely remain ad hoc, continuing to create and increase
delays in the interconnection process, which leads to increased costs
for both interconnection customers and consumers, thereby failing to
ensure just and reasonable rates. As discussed by commenters, the
existing affected system study processes lack certainty and
transparency, which, in turn, create interconnection queue delays,
interconnection customer withdrawals, and cost increases.\1998\
Affected system study delays continue to be a major reason for
interconnection queue delays.\1999\ We concur with commenters that
better coordination and more specific requirements concerning the role
and responsibilities of affected system transmission providers are
required to address the lack of certainty and transparency.\2000\
Additionally, we agree with commenters that affected system study
process reforms will ensure that interconnection customers are able to
connect in a reliable, efficient, transparent, and timely manner.\2001\
We are unpersuaded by comments that standardizing the affected system
study process will result in timeline problems and delays; \2002\ we
find such claims to be speculative and contrary to the Commission's
experience with standardizing host transmission provider study
processes via the pro forma LGIP.\2003\ We discuss specific aspects of
the affected system-related NOPR proposals and final rule
determinations below.
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\1998\ AEE Initial Comments at 34-35; ELCON Initial Comments at
7; SEIA Initial Comments at 34-35; Shell Initial Comments at 30.
\1999\ See MISO, Informational Report Regarding Interconnection
Study Delay for 4th Quarter 2022, Docket No. ER19-1960-004, attach.
A at 8 (filed Feb. 14, 2023).
\2000\ Ameren Initial Comments at 22; NYISO Initial Comments at
44.
\2001\ MISO Initial Comments at 8 n.20, 12.
\2002\ Dominion Initial Comments at 36-37; PJM Initial Comments
at 63; SPP Initial Comments at 17; WAPA Initial Comments at 10.
\2003\ See Order No. 2003, 104 FERC ] 61,103 at PP 10-12; Order
No. 845, 163 FERC ] 61,043 at PP 4, 8, 39, 221, 239, 559.
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1033. In this final rule, an affected system transmission provider
refers to a public utility transmission provider as the Commission does
not have jurisdiction over the rates, terms, or conditions of service
of non-public utility transmission providers. Thus, the requirements
adopted in this final rule pertaining to affected system transmission
providers are limited to public utility transmission providers.
b. Affected System Study Process
i. NOPR Proposal
1034. In the NOPR, the Commission proposed to revise the pro forma
LGIP to include an affected system study process.\2004\ The proposed
process includes an initial notification, an affected system scoping
meeting, a study process, the establishment of interconnection queue
priority for the purposes of network upgrade cost allocation, the
presentation of study results and an assessment of those results, and
imposition of penalties if an affected system transmission provider
fails to meet a study deadline. The Commission also proposed to add
several definitions to the pro forma LGIP, including ``affected system
interconnection customer,'' ``affected system network upgrade,''
``affected system scoping meeting,'' and ``affected system study.''
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\2004\ NOPR, 179 FERC ] 61,194 at P 183.
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1035. The Commission proposed to require that the host transmission
provider notify the affected system operator of a potential affected
system impact caused by an interconnection request within 10 business
days after the close of the first event giving rise to the
identification of an affected system impact.\2005\ The Commission
explained that, for host transmission providers using a cluster study
process, this event could be (1) the cluster request window, (2) the
customer engagement window, (3) the cluster study, or (4) the cluster
restudy as part of the first-ready, first-served cluster study process.
At the same time that the host transmission provider notifies the
affected system operator, the Commission proposed to require the host
transmission provider to provide the interconnection customer with a
list of potential affected systems, along with relevant contact
information. The Commission also proposed to require the host
transmission provider to provide the affected system operator with data
on a monthly basis, or more frequently as needed, about its
transmission system and generation in its interconnection queue for the
duration of the affected system study process.
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\2005\ Id. P 184.
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1036. The Commission proposed several requirements on transmission
providers acting as an affected system operator, whose transmission
systems may be impacted by the proposed interconnection of a generating
facility to a transmission system other than the transmission
provider's transmission system.\2006\ The Commission proposed to
require the affected system transmission provider, within 15 business
days of receiving notification from the host transmission provider of
an impact on its transmission system, to respond in writing indicating
whether it intends to perform an affected system study.
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\2006\ Id. P 185.
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[[Page 61160]]
1037. The Commission proposed to require that the affected system
transmission provider schedule an affected system scoping meeting
within seven business days after providing written notification that it
intends to conduct an affected system study.\2007\ The Commission also
proposed to require that the affected system scoping meeting be held
within seven business days after it is scheduled. The Commission
further proposed to require that the affected system transmission
provider include the affected system interconnection customer in the
scoping meeting and use best efforts to include the transmission
provider with whom interconnection has been requested. The Commission
proposed to require the affected system transmission provider to share
the schedule to complete the affected system study with all scoping
meeting attendees within 15 business days after the close of the
scoping meeting.
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\2007\ Id. P 186.
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1038. The Commission proposed to require that the affected system
transmission provider tender an affected system study agreement to the
affected system interconnection customer within five business days of
sharing the schedule for the affected system study.\2008\ The
Commission also proposed to require the affected system interconnection
customer to return the executed affected system study agreement within
10 business days of receipt.
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\2008\ Id. P 188.
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1039. The Commission proposed to require the affected system
transmission provider to use what it referred to as a ``first-ready,
first-served interconnection queue priority approach,'' which would
also determine how affected system network upgrade costs will be
allocated by that transmission provider amongst interconnection
customers in separate transmission systems.\2009\ Specifically, the
Commission explained, in some situations, both affected system
interconnection customers and interconnection customers on the
transmission system of the affected system transmission provider cause
the need for affected system network upgrades; in this case, each
interconnection customer's relative interconnection queue priority must
be determined. The NOPR's proposed first-ready, first-served
interconnection queue priority approach would require the affected
system transmission provider to assign the affected system
interconnection customer a queue position in its interconnection queue
according to when the affected system interconnection customer executes
an affected system study agreement, rather than when the affected
system interconnection customer entered its host transmission
provider's interconnection queue. The Commission explained that such a
position would be equivalent to that of a transmission provider's own
interconnection customer that had just received its cluster study
report. The Commission also proposed to require the affected system
transmission provider to allocate network upgrade costs among equally
queued interconnection customers using a proportional impact method.
---------------------------------------------------------------------------
\2009\ Id. P 189.
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1040. The Commission proposed that the affected system transmission
provider must provide the affected system interconnection customer with
affected system study results within 90 calendar days after the receipt
of the executed affected system study agreement.\2010\ The Commission
proposed to require that the affected system transmission provider
include in the study results both the estimated costs for any network
upgrades identified in the study and the timing for the construction of
those network upgrades.
---------------------------------------------------------------------------
\2010\ Id. P 190.
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1041. The Commission proposed to require that the affected system
transmission provider provide the affected system interconnection
customer with an affected system facilities construction agreement
within 30 calendar days after providing the affected system study
results.\2011\ The Commission proposed that the affected system
interconnection customer would then be required to notify the affected
system transmission provider within five business days of executing the
generator interconnection agreement with its host transmission provider
whether it would like to execute the affected system facilities
construction agreement or request that it be filed unexecuted with the
Commission. The Commission proposed that the affected system
transmission provider would then be required to execute, or file
unexecuted, the affected system facilities construction agreement
within five business days after receiving such direction from the
affected system interconnection customer.
---------------------------------------------------------------------------
\2011\ Id. P 191.
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1042. The Commission proposed to impose financial penalties on
affected system transmission providers that fail to timely complete
affected system studies.\2012\ The Commission explained that a host
transmission provider would not be penalized for a late affected system
study and did not require a host transmission provider to wait on the
results of an affected system study to conduct its cluster study, so
that any affected system study delay would not delay such a cluster
study. The Commission clarified that the affected system transmission
provider was the only entity that would be penalized for failure to
timely complete an affected system study.
---------------------------------------------------------------------------
\2012\ Id. P 192.
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ii. Comments
(a) Comments in Support
1043. Multiple commenters support the NOPR proposal to create a
standardized affected system study process in the pro forma LGIP.\2013\
Consumers Energy asserts that standardization and better
synchronization of timelines and processes between transmission
providers will improve the interconnection process,\2014\ and in
ACORE's opinion, will help to prevent the use of potentially unjust,
unreasonable, and unduly discriminatory or preferential ad hoc
approaches.\2015\
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\2013\ ACE-NY Initial Comments at 8-9; AEE Initial Comments at
34-35; AEP Initial Comments at 31; AES Initial Comments at 21; APPA-
LPPC Initial Comments at 23; CREA and NewSun Initial Comments at 86;
Duke Southeast Utilities Initial Comments at 12; EDF Renewables
Initial Comments at 10; ELCON Initial Comments at 7; Enel Initial
Comments at 2, 57; ENGIE Initial Comments at 8; Fervo Energy Initial
Comments at 6; Google Initial Comments at 5-6; Idaho Power Initial
Comments at 11; NextEra Initial Comments at 31; Ohio Commission
Consumer Advocate Initial Comments at 13; PacifiCorp Initial
Comments at 36; Pattern Energy Initial Comments at 24; Pine Gate
Initial Comments at 41; PPL Initial Comments at 19; SEIA Initial
Comments at 34; Shell Initial Comments at 29.
\2014\ Consumers Energy Initial Comments at 8; see also Clean
Energy Associations Initial Comments at 47-48; Illinois Commission
Initial Comments at 9; CREA and NewSun Initial Comments at 86-87;
ENGIE Initial Comments at 8; U.S. Chamber of Commerce Initial
Comments at 10-11.
\2015\ ACORE Initial Comments at 4-5; see also EDF Renewables
Initial Comments at 11; Invenergy Initial Comments at 41.
---------------------------------------------------------------------------
1044. Multiple commenters support most or all of the proposed
reforms.\2016\ Pine Gate strongly supports the NOPR proposal's
definitive deadlines for affected system study completion and
associated incentives, arguing that consistent, published criteria will
help determine whether an affected system study is needed and will
provide interconnection customers with the opportunity to conduct their
own engineering analyses applying the criteria in order to better
determine suitable locations for prospective
[[Page 61161]]
generating facilities.\2017\ AEP supports the deadlines related to
initiating the affected system study process, stating that deadlines
would help to provide transparency and ensure that the process is
initiated in a timely fashion.\2018\ Interwest, National Grid, and
Invenergy support the proposal to standardize the affected system study
engagement and participation process, asserting that the reforms are a
significant improvement over the status quo.\2019\
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\2016\ ACE-NY Initial Comments at 9; Google Initial Comments at
23; Pine Gate Initial Comments at 42.
\2017\ Pine Gate Initial Comments at 42-43; see also ENGIE
Initial Comments at 9-10.
\2018\ AEP Initial Comments at 31.
\2019\ Interwest Reply Comments at 16-17; Invenergy Initial
Comments at 40; National Grid Initial Comments at 35.
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(b) Comments in Opposition
1045. Multiple commenters oppose the NOPR's affected system study
process proposal.\2020\ Some commenters assert that the proposed
process will impose arbitrary and strict deadlines and will be
unworkable.\2021\ Dominion and SDG&E assert that timing for affected
system studies should not be standardized because the necessary study
assumptions depend on timing of studies in the cluster study
process.\2022\ Dominion contends that, if an affected system study is
performed too early, modeling assumptions may not yield meaningful
results, resulting in incorrect cost estimates likely to cause
restudies and late-stage withdrawals.\2023\ PJM argues that studying
affected system interconnection requests before all studies have been
completed, or studying them for ERIS, could cause operational problems,
require curtailment, or lead to late-stage withdrawals after the full
scope of necessary network upgrades is known.\2024\ Similarly, SPP
states that, because the NOPR proposal does not prescribe any
particular level of precision for the cost and timing estimates
associated with affected system upgrades, the results received by the
interconnection customer could lack sufficient detail and lead to
higher-than-anticipated costs.\2025\
---------------------------------------------------------------------------
\2020\ Dominion Initial Comments at 36-37; National Grid Initial
Comments at 37; NextEra Initial Comments at 32; NextEra Reply
Comments at 4; North Carolina Commission and Staff Initial Comments
at 24; Pacific Northwest Utilities Initial Comments at 15; PJM
Initial Comments at 63-64; SDG&E Reply Comments at 3; SPP Initial
Comments at 17; WAPA Initial Comments at 10-11.
\2021\ Dominion Initial Comments at 37; NextEra Initial Comments
at 32; NextEra Reply Comments at 4; PJM Initial Comments at 63;
SDG&E Reply Comments at 3.
\2022\ Dominion Initial Comments at 36-37; SDG&E Reply Comments
at 3.
\2023\ Dominion Initial Comments at 37.
\2024\ PJM Initial Comments at 64.
\2025\ SPP Initial Comments at 17.
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1046. Several commenters argue that certain elements of the NOPR
proposal do not achieve the goal of increased efficiency.\2026\
Recognizing that affected system studies require separate case
preparations and a greater level of coordination between parties, SDG&E
agrees with CAISO that the proposal has the potential to increase the
number of affected system studies, with limited benefit.\2027\ National
Grid cautions that standardizing the affected system study process will
necessitate host and affected system transmission providers to devote
more resources to that process, which could cause delays.\2028\ PJM
contends that, although the NOPR proposal provides that transmission
providers conducting cluster studies are not required to delay those
studies by waiting for the results of affected system studies, such
delays will be inevitable under the proposed process due to the
additional steps and coordination required and the overlap in personnel
and deadlines.\2029\ PJM and National Grid both express concerns
regarding the justness and reasonableness of the NOPR's penalty regime
given the potential for additional delays in affected system
studies.\2030\
---------------------------------------------------------------------------
\2026\ Id.; CAISO Initial Comments at 28; Dominion Initial
Comments at 36-37; National Grid Initial Comments at 37; PJM Initial
Comments at 63; SDG&E Reply Comments at 3; WAPA Initial Comments at
10.
\2027\ SDG&E Reply Comments at 3.
\2028\ National Grid Initial Comments at 37.
\2029\ PJM Initial Comments at 63.
\2030\ Id.; National Grid Initial Comments at 37.
---------------------------------------------------------------------------
1047. Other commenters argue that the NOPR proposal does not go far
enough to improve efficiency in the affected system study process.
North Carolina Commission and Staff call for more comprehensive
reforms, recognizing the need for coordination between transmission
providers to avoid unnecessary expense and system disruption.\2031\
WAPA recommends that the Commission consider an alternative strategy in
which the host transmission provider includes contingencies and
sensitivity scenarios involving potentially affected systems in its own
studies.\2032\ PJM suggests that, rather than the NOPR's ``overly
prescriptive'' approach, the Commission should require a stated
affected system coordination structure with defined steps and
checkpoints, similar to the process PJM has been working to implement
with neighboring systems through its joint operating agreements.\2033\
---------------------------------------------------------------------------
\2031\ North Carolina Commission and Staff Initial Comments at
24.
\2032\ WAPA Initial Comments at 10-11.
\2033\ PJM Initial Comments at 64.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
(1) Definitions
1048. PPL argues that the proposed term ``affected system
interconnection customer'' is confusing and recommends that the
Commission either remove ``interconnection'' or consider the term
``direct connect system customer,'' asserting that the affected system
interconnection customers are not interconnection customers working
their way through the affected system transmission provider's
interconnection process.\2034\ PPL states that some transmission
providers combine interconnection and transmission and argues that
removing the word ``interconnection'' better accommodates such a
combined group.
---------------------------------------------------------------------------
\2034\ PPL Initial Comments at 19-20.
---------------------------------------------------------------------------
1049. Several commenters ask for clarification or modification of
the terms ``affected system'' or ``affected system operator.'' National
Grid asserts that the Commission should clarify whether an affected
system solely includes transmission owners in each region or also
includes neighboring RTOs/ISOs or transmission providers in neighboring
regions.\2035\ NRECA requests that the Commission clarify the scope of
several definitions so that transmission providers will not overlook a
proposed interconnection request's impact on an electric cooperative's
affected system.\2036\
---------------------------------------------------------------------------
\2035\ National Grid Initial Comments at 35.
\2036\ NRECA Initial Comments at 9, 36-39. More specifically,
NRECA contends that because some transmission providers interpret
the definition of ``Affected System'' to mean a Commission-
jurisdictional transmission system and refuse to recognize that
other electric systems may be affected systems, under the pro forma
LGIP and pro forma LGIA, the Commission should provide that an
``Affected System'' means any affected ``electric system,'' not just
an affected ``Transmission System,'' and that an ``Affected System
Operator'' means any ``entity that operates an Affected System,''
not just a transmission owner or transmission provider. Id. at 36-
37, 39.
---------------------------------------------------------------------------
(2) Notification of Affected System Impacts
1050. Regarding the proposed triggering event at the close of (1)
the cluster request window, (2) the customer engagement window, (3) the
cluster study, or (4) the cluster restudy for a host transmission
provider to notify an affected system operator, PacifiCorp argues that
the 10-business day notification obligation begins with an ill-defined
standard in the NOPR--the ``close of first event giving rise to the
identification of an affected system
[[Page 61162]]
impact.'' \2037\ PacifiCorp requests that the Commission clarify this
standard and further clarify that transmission providers will not be
penalized if affected system issues are not discovered until later in
the interconnection process, as such impacts may not always be readily
apparent.
---------------------------------------------------------------------------
\2037\ PacifiCorp Initial Comments at 36.
---------------------------------------------------------------------------
1051. Some commenters oppose the proposed requirement in section
3.6.1 of the pro forma LGIP that a host transmission provider, within
10 business days of the triggering event that identifies a potential
affected system impact, notify an affected system operator of such
potential impact.\2038\ WAPA states that the initial notification
requirement could unnecessarily increase costs because the notification
could be received before the system impact study on the host
transmission provider's transmission system is complete and thus before
any potential network upgrades are identified. Duke Southeast Utilities
assert that the notification time frame should be 15 business days
because: (1) the host transmission provider may need additional time to
notify multiple affected system operators of a potential impact within
the same prescribed time frame; and (2) the host transmission provider
may need additional time to gather all necessary information and
compile adequate notification packages, due to the need to include a
technical basis for the affected system impact.\2039\ CAISO states that
the Commission should require transmission providers to begin the
notification process shortly after interconnection customers receive
their initial study results and face higher financial requirements to
proceed in the interconnection queue.\2040\ CAISO explains that this is
when the majority of interconnection customers withdraw their
interconnection requests because they do not wish to put more money at
risk. CAISO argues that using this smaller pool of interconnection
requests will enable faster affected system studies due to decreased
volume and more realistic study assumptions.
---------------------------------------------------------------------------
\2038\ Id.; CAISO Initial Comments at 27; Duke Southeast
Utilities Initial Comments at 12; PG&E Reply Comments at 5; WAPA
Initial Comments at 11.
\2039\ Duke Southeast Utilities Initial Comments at 12.
\2040\ CAISO Initial Comments at 29.
---------------------------------------------------------------------------
1052. A few commenters provide suggestions on the content of the
notice that the host transmission provider sends to the affected system
operator. Specifically, APPA-LPPC propose that pro forma LGIP section
3.6.1 be revised to include the following: ``Along with notification to
Interconnection Customer of the list of potential Affected Systems,
Transmission Provider will notify Interconnection Customer and such
Affected Systems whether a single set of studies (Feasibility, System
Impact and Facilities Studies) may be sufficient to manage all related
impacts. A single set of studies may be undertaken upon agreement of
all parties.'' \2041\ Duke Southeast Utilities suggest that, in
addition to such notification, the host transmission provider should
provide evidence of the potential impact, which they assert will assist
the affected system operator in: (1) understanding the host
transmission provider's engineering analysis and assumptions that led
it to identify the potential impact; and (2) determining whether to
conduct an affected system study.\2042\
---------------------------------------------------------------------------
\2041\ APPA-LPPC Initial Comments at 25-26.
\2042\ Duke Southeast Utilities Initial Comments at 13.
---------------------------------------------------------------------------
1053. Regarding to whom the host transmission provider should send
the notification, NRECA argues that the notification requirement should
extend to all potential affected systems and any affected system
operators to allow electric cooperative affected system transmission
providers to coordinate with the transmission provider and
interconnection customer to timely address any affected system
impacts.\2043\ Tri-State states that pro forma LGIP section 3.6.1 needs
clarification as to whom the notice is to be directed.\2044\
---------------------------------------------------------------------------
\2043\ NRECA Initial Comments at 38-39.
\2044\ Tri-State Initial Comments at 28.
---------------------------------------------------------------------------
1054. Other commenters oppose the proposed requirement in sections
3.6.2 and 9 of the pro forma LGIP that affected system transmission
providers must respond to the notification of affected system impacts
within 15 business days.\2045\ Bonneville advocates that the response
time be flexible and allow for reasonable extensions.\2046\ Bonneville
argues that, if affected system transmission providers only have 15
business days to respond, they will need to err on the side of caution,
which could lead to more affected system studies than necessary,
resulting in study delays. Duke Southeast Utilities assert that the
response time frame should be 20 business days, as the affected system
transmission provider may need additional time if: (1) it has received
multiple notifications within the same time frame; (2) it needs to
request additional data to determine if it intends to perform a study;
(3) its own staff is limited because of deadlines within its own
interconnection process; or (4) it wishes to perform a more detailed
review to ensure that performing a study does not become the default
approach.\2047\ Dominion asserts that a 15-business day requirement
could be reasonable if all affected system notifications were provided
at the same time.\2048\ Dominion contends that piecemeal notifications
make it difficult for an affected system transmission provider to know
if an affected system study is needed until all requests are received.
---------------------------------------------------------------------------
\2045\ Bonneville Initial Comments at 18; CAISO Initial Comments
at 27; PG&E Reply Comments at 5; WAPA Initial Comments at 11.
\2046\ Bonneville Initial Comments at 18.
\2047\ Duke Southeast Utilities Initial Comments at 13 (noting
that PJM often sends notice of multiple potential impacts from a
single cluster).
\2048\ Dominion Initial Comments at 37-38.
---------------------------------------------------------------------------
1055. Additionally, a few commenters contend that the NOPR proposal
was unclear what would happen if an affected system operator fails to
respond within 15 business days. Enel and ENGIE contend that it is
unclear what the consequence is for an affected system transmission
provider's failure to meet the response deadline.\2049\ Enel encourages
the Commission to add language to the pro forma LGIP to provide that
the affected system transmission provider will forfeit its right to
perform an affected system study if it fails to meet the response
deadline, as a lack of incentive (and relevant penalty) to respond
could result in delayed study results.\2050\ ENGIE suggests that the
affected system transmission provider bear any financial
consequences.\2051\ Pacific Northwest Utilities note that the non-
jurisdictional affected system operator is not required to respond to
the requirements under proposed pro forma LGIP section 3.6.1 and may
not have the mechanisms in place to respond within 15 business
days.\2052\
---------------------------------------------------------------------------
\2049\ Enel Initial Comments at 59-60; ENGIE Initial Comments at
8.
\2050\ Enel Initial Comments at 59-60; see also Invenergy
Initial Comments at 42-44.
\2051\ ENGIE Initial Comments at 8.
\2052\ Pacific Northwest Utilities Initial Comments at 17.
---------------------------------------------------------------------------
(3) Timing of Affected System Studies
1056. Several commenters argue that beginning affected system
studies too early may yield unreliable results that could lead to
restudies and late-stage withdrawals, among other problems.\2053\
NextEra asserts that it is unlikely that the host transmission provider
could provide useful information to the
[[Page 61163]]
affected system transmission provider at an earlier stage.\2054\ CAISO
and Idaho Power argue that the proposal to begin the affected system
study process as soon as potential impacts are identified will slow
affected system studies or result in unnecessary work for the affected
system transmission provider because the impacts will be assessed based
on transmission providers' entire interconnection queues, even though
many interconnection customers will withdraw early in the
interconnection process.\2055\
---------------------------------------------------------------------------
\2053\ CAISO Initial Comments at 28-29; Dominion Initial
Comments at 37; Enel Initial Comments at 59; Idaho Power Initial
Comments at 11; NextEra Initial Comments at 32-33; WAPA Initial
Comments at 11-12.
\2054\ NextEra Initial Comments at 32-33.
\2055\ CAISO Initial Comments at 28-29; Idaho Power Initial
Comments at 11.
---------------------------------------------------------------------------
1057. CAISO takes issue with the proposed deadlines for completing
affected system studies and claims that the size of modern
interconnection queues makes such quick deadlines impossible. According
to CAISO, such deadlines would result in all affected system
transmission providers exercising their rights to study every
interconnection customer because they have no time to determine whether
studies are necessary.\2056\
---------------------------------------------------------------------------
\2056\ CAISO Initial Comments at 27-28.
---------------------------------------------------------------------------
1058. Invenergy argues that affected system transmission providers
should be subject to a deadline for participation in the process.\2057\
---------------------------------------------------------------------------
\2057\ Invenergy Initial Comments at 41.
---------------------------------------------------------------------------
1059. Invenergy asserts that, although the NOPR clearly provides
that a host transmission provider is not required to pause its
interconnection process if an affected system transmission provider
does not timely complete its study, the reality is that this could
leave interconnection customers in the same position they are in now--
being forced under the host transmission provider's timeline to move
forward in the study process and to execute an LGIA (and put money at
risk) without the benefit of affected system study results. Invenergy
contends that the solution is to establish a clear deadline (e.g., LGIA
execution) by which time the affected system transmission provider must
have completed its studies and identified affected system network
upgrades; otherwise, it loses any right to assign affected system
network upgrades to an interconnection request in the future. Invenergy
states that, if the Commission does not impose such a deadline, it
should at least permit interconnection customers that have been forced
under host transmission provider's rules to execute LGIAs in the
absence of affected system study information to: (1) delay posting
security and funding network upgrades under that LGIA until the
affected system study results are received; and (2) have the
opportunity to withdraw without penalty after receiving affected system
study results if the interconnection customer's assigned costs
increased by more than 25% compared to costs allocated by the host
transmission provider.\2058\
---------------------------------------------------------------------------
\2058\ Id. at 25, 43-44.
---------------------------------------------------------------------------
1060. Several commenters argue that an affected system study
timeline should be consistent with the cluster study process on the
host transmission provider's transmission system because it can impact
the host transmission provider's study.\2059\ APS requests additional
clarification on how the proposed affected system study process
correlates to the host system studies and aligns with the host system's
requirements.\2060\ Enel acknowledges that the 90-calendar day affected
system study deadline may be problematic for transmission providers
that have 150 calendar days to run the same scope of studies for their
own interconnection requests.\2061\ AEP stresses the need for
coordination between these studies, which it argues would provide the
interconnection customer with a more meaningful cost estimate, with
coordination resulting in affected system and host system study results
being presented around the same time.\2062\ Enel contends that the
affected system transmission provider should be required to complete
any affected system impact studies no later than the host transmission
provider's deadline to complete the cluster restudy.\2063\ Enel asserts
that this initial affected system study should be completed before the
interconnection customer must satisfy requirements to enter the
facilities study, at which point the interconnection customer faces a
higher withdrawal penalty. Enel contends that the NOPR proposal could
result in an affected system transmission provider being notified that
an affected system study is needed after final results of the cluster
restudy are complete, meaning that an affected system study may not be
completed until or even after the execution of an LGIA. Enel argues
that, after affected system studies are complete, an interconnection
customer could have its costs double just before (or even after) an
LGIA is executed, and penalty-free withdrawal under proposed pro forma
LGIP section 3.7.1 would only apply if assigned interconnection costs
increase by more than 100%.
---------------------------------------------------------------------------
\2059\ APPA-LPPC Initial Comments at 26; AEP Initial Comments at
31; Bonneville Initial Comments at 21; NV Energy Initial Comments at
11.
\2060\ APS Initial Comments at 19-20.
\2061\ Enel Initial Comments at 65.
\2062\ AEP Initial Comments at 31-32.
\2063\ Enel Initial Comments at 58.
---------------------------------------------------------------------------
1061. Several commenters argue that the timing of affected system
studies should be structured to reduce potential burdens. Idaho Power
suggests that affected system studies be performed after the initial
cluster study to minimize unnecessary work and ensure that only
interconnection requests moving into the cluster restudy have their
affected system impacts studied.\2064\ Dominion notes that PJM recently
sought to address timing issues by incorporating affected system
studies into later phases of its cluster studies.\2065\
---------------------------------------------------------------------------
\2064\ Idaho Power Initial Comments at 11.
\2065\ Dominion Initial Comments at 37 (citing PJM
Interconnection, L.L.C., Tariff Revisions for Interconnection
Process Reform Transmittal Letter, Docket No. ER22-2110-000, at 55,
59-60 (filed June 14, 2022)).
---------------------------------------------------------------------------
(4) Affected System Scoping Meeting
1062. Several commenters express concern about the proposed
requirement in section 3.6.2 of the pro forma LGIP that the affected
system transmission provider (1) schedule an affected system scoping
meeting within seven business days after providing written notification
that it intends to conduct an affected system study and (2) hold that
meeting within seven business days after it is scheduled.\2066\
Bonneville and Dominion assert that holding the scoping meeting within
this time frame might not be realistic because these meetings are
contingent upon the availability of multiple attendees.\2067\ CAISO
contends that the proposal to schedule affected system scoping meetings
within seven business days is impossible and that affected system
transmission providers would simply hold scoping meetings to comply,
having had no time to prepare anything meaningful for the
meeting.\2068\ MISO argues that the Commission should allow each pair
of transmission providers to develop their own schedule for the scoping
process rather than mandating a one-size-fits-all schedule.\2069\ MISO
asserts that this is particularly true for RTOs/ISOs with joint
operating and/or planning agreements, which MISO claims should
[[Page 61164]]
be able to justify their existing procedures on compliance via the
independent entity variation standard. Bonneville emphasizes
flexibility and proposes that the phrase ``unless otherwise agreed to''
be added to this requirement.\2070\
---------------------------------------------------------------------------
\2066\ Id. at 38; Bonneville Initial Comments at 18-19; CAISO
Initial Comments at 28; MISO Initial Comments at 86. WAPA also
asserts that a meeting after the affected system study is completed
would be more beneficial than the proposed affected system scoping
meeting, as the proposed meeting would only provide speculative
impacts that might be caused by an interconnection request. WAPA
Initial Comments at 12.
\2067\ Bonneville Initial Comments at 18-19; Dominion Initial
Comments at 38.
\2068\ CAISO Initial Comments at 28.
\2069\ MISO Initial Comments at 86.
\2070\ Bonneville Initial Comments at 19.
---------------------------------------------------------------------------
1063. Pacific Northwest Utilities state that, provided that
regulated utilities properly invite the non-jurisdictional affected
system transmission provider to the affected system scoping meeting,
the Commission should clarify that such steps are sufficient to
demonstrate that the regulated transmission provider has met its
requirements under this section.\2071\ Further, Pacific Northwest
Utilities note that the non-jurisdictional affected system transmission
provider is not required to respond to the requirements under section
3.6.2 of the pro forma LGIP and may not be prepared to attend the
affected system scoping meeting.
---------------------------------------------------------------------------
\2071\ Pacific Northwest Utilities Initial Comments at 17.
---------------------------------------------------------------------------
(5) Affected System Study Process
1064. Multiple commenters advocate for changes to the proposed
requirement in section 3.6.3 of the pro forma LGIP that the
transmission provider provide data monthly, or more frequently as
needed, regarding the amount and location of generation in the
transmission provider's interconnection queue, as well as updated
information about the transmission provider's transmission system.
NRECA states that the proposed information sharing requirement is
essential but should not be limited to notifying or providing data to a
transmission provider acting as an affected system operator but should
extend to all potential affected systems and any affected system
operators to allow electric cooperative affected system operators to
perform studies and coordinate with the transmission provider and
interconnection customer to timely address any affected system
impact.\2072\ MISO argues that the Commission should not impose an
arbitrary time frame for data reports and suggests that such
information should be provided only at times when it changes.\2073\
MISO asserts that updates are not likely to be helpful to
interconnection customers until the next study stage has been
completed. NV Energy requests that the Commission move to quarterly
reporting because monthly updates would not be helpful and may provide
dramatic swings in study results, which could trigger the need for an
affected system study to start over.\2074\ NV Energy also requests that
assumptions for studies be coordinated between the host transmission
provider and affected system operator and that updates become quarterly
after the study has been issued.
---------------------------------------------------------------------------
\2072\ NRECA Initial Comments at 38-39.
\2073\ MISO Initial Comments at 86.
\2074\ NV Energy Initial Comments at 12.
---------------------------------------------------------------------------
1065. LADWP requests clarification as to what specific data
``updated information about the transmission provider's transmission
system'' refers.\2075\
---------------------------------------------------------------------------
\2075\ LADWP Initial Comments at 4 (citing NOPR, 179 FERC ]
61,194 at P 187).
---------------------------------------------------------------------------
1066. Bonneville and Dominion argue that the proposed information
sharing requirement is duplicative or unnecessary. Bonneville posits
that the requirement is duplicative of information that is already
available on OASIS.\2076\ Dominion argues that this requirement is
overly cumbersome given transmission providers' limited resources and
numerous obligations and may produce data that the affected system may
not even want or use.\2077\ Dominion asserts that it would be more
efficient to require the host transmission provider to provide such
information upon request.
---------------------------------------------------------------------------
\2076\ Bonneville Initial Comments at 19.
\2077\ Dominion Initial Comments at 38.
---------------------------------------------------------------------------
(6) Affected System Queue Position
1067. Several commenters support the NOPR proposal's first-ready,
first-served interconnection queue priority approach in proposed
section 9.2 of the pro forma LGIP.\2078\ OMS and MISO argue that MISO
and SPP's recently approved changes to their joint operating agreement
to modify the queue priority and coordination rules for affected system
studies conform to the NOPR's proposed approach and are an equitable
means for sharing costs for network upgrades amongst interconnection
customers in different regions and encourages timely processing of
affected system impacts.\2079\
---------------------------------------------------------------------------
\2078\ Alliant Energy Initial Comments at 7; EDF Renewables
Initial Comments at 11; Invenergy Initial Comments at 40; MISO
Initial Comments at 11-12; NextEra Reply Comments at 5; OMS Initial
Comments at 17.
\2079\ MISO Initial Comments at 88; OMS Initial Comments at 17
(citing Sw. Power Pool, Inc., 179 FERC ] 61,148 (2022)).
---------------------------------------------------------------------------
1068. However, Bonneville and NextEra assert that the NOPR does not
adequately address the important issue of queue priority
coordination.\2080\ NextEra argues that the notion of interconnection
customers racing to be the first (or perhaps the last) to sign an
affected system study agreement as a way of setting queue priority will
result in conflict.\2081\ NextEra contends that, instead, the goal
should be to ensure that transmission providers acting as affected
systems perform affected system studies on a timeline that is
consistent with the host transmission system's stated schedule so that
results are delivered in a timely manner and interconnection customers
can be well-informed in their decision making. NextEra recommends that
each pair of transmission providers whose interconnection customers
affect each other's system enter into agreements, to be filed with the
Commission, specifying how they will ensure appropriate queue priority
in affected system studies.
---------------------------------------------------------------------------
\2080\ Bonneville Initial Comments at 20; NextEra Reply Comments
at 5.
\2081\ NextEra Reply Comments at 5.
---------------------------------------------------------------------------
1069. Bonneville argues that the queue priority for affected system
interconnection requests should be determined by giving priority to an
interconnection request in an affected system study over any
interconnection request that has not yet started the cluster study on
the host transmission system.\2082\ Bonneville contends that if an
affected system interconnection request receives higher queue priority
relative to any interconnection requests for which the host
transmission provider has started the cluster study but has not yet
provided cluster study reports, then such a queue priority framework
would introduce uncertainty into the cluster study process, as an
affected system notification could be received during the cluster study
process and trigger a restudy, delays, and increased costs to the
participants of the cluster study.
---------------------------------------------------------------------------
\2082\ Bonneville Initial Comments at 20.
---------------------------------------------------------------------------
1070. Other commenters argue for different approaches to affected
system queue priority or allocation of affected system network upgrade
costs. ENGIE argues that, although assigning an affected system queue
position appears beneficial for assigning network upgrade costs, it
could also create delays for the interconnection customer because it
would be beholden to two separate interconnection queues.\2083\ ENGIE
recommends that the Commission allocate network upgrade costs outside
of the interconnection queue on an ex post basis to avoid the double-
queue situation.
---------------------------------------------------------------------------
\2083\ ENGIE Initial Comments at 9.
---------------------------------------------------------------------------
1071. Enel asserts that the NOPR's proposed queue priority
determination method will result in additional uncertainty about timing
of affected system studies, incomplete and inaccurate cluster study
results, and the
[[Page 61165]]
need for restudies.\2084\ Although Enel agrees that establishing queue
priority between host and affected system interconnection requests is
essential, Enel disagrees with the NOPR proposal to establish the
affected system interconnection request's queue priority according to
when the affected system interconnection customer executes an
``affected system study.'' \2085\ Enel states that this must be a typo
that should say ``affected system study agreement.'' Enel also notes
that proposed pro forma LGIP section 9.2 does not clearly state which
event establishes the date by which an affected system interconnection
request receives its queue priority relative to host system
interconnection requests and requests clarification on this
point.\2086\ Enel further states that, if affected system queue
priority is established based on an individual date, transmission
providers would need to process affected system interconnection
requests serially rather than by cluster and recommends that the
Commission adopt a queue priority framework in which affected system
interconnection requests would be studied in the same cluster grouping
that the host transmission provider uses.\2087\ Enel also recommends
that queue priority be assigned based on the deadline for entry into
the host transmission provider's interconnection queue.
---------------------------------------------------------------------------
\2084\ Enel Initial Comments at 62-63.
\2085\ Id. at 61.
\2086\ Id. at 61-62.
\2087\ Id. at 62-63.
---------------------------------------------------------------------------
1072. Several commenters request or propose specific clarifications
regarding proposed pro forma LGIP section 9.2, including how the
proposed first-ready, first-served interconnection queue priority
approach interacts with cluster studies.\2088\ EDF Renewables
recommends that, to better synchronize the host and affected system
study processes, the affected system operator should establish queue
priority between the host and affected system based on the
interconnection request achieving a certain stage in the host system's
study process, rather than the date the interconnection request was
submitted.\2089\ APPA-LPPC ask that the Commission clarify proposed pro
forma LGIP section 9.2 and the related obligations under pro forma LGIP
sections 9.8 and 4.2.3.\2090\ APPA-LPPC state that, as drafted,
proposed pro forma LGIP section 9.2 suggests a queue position for an
interconnection customer independent of ongoing and pending cluster
studies while pro forma LGIP section 9.8 and cross-referenced pro forma
LGIP section 4.2.3 contemplate the allocation of associated costs
incurred by affected systems in the context of a cluster study.
---------------------------------------------------------------------------
\2088\ APPA-LPPC Initial Comments at 26; Idaho Power Initial
Comments at 11; NextEra Initial Comments at 33.
\2089\ EDF Renewables Initial Comments at 11.
\2090\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------
1073. Additionally, MISO recommends that the final rule clarify an
enforcement mechanism, such as loss of relative queue priority used
under the MISO-SPP joint operating agreement, for the proposed first-
ready, first-served interconnection queue priority approach.\2091\
---------------------------------------------------------------------------
\2091\ MISO Initial Comments at 89.
---------------------------------------------------------------------------
(7) Affected System Study Agreement
1074. Dominion and Duke Southeast Utilities suggest doubling the
amount of time that transmission providers would have under proposed
pro forma LGIP section 9.3 to tender an affected system study agreement
after sharing the schedule for the affected system study.\2092\ Duke
Southeast Utilities assert that it usually takes more than five
business days to receive all needed interconnection request information
to draft an affected system study agreement (an often iterative
process).\2093\ Duke Southeast Utilities state that more time will help
affected system transmission providers that may need to draft numerous
affected system study agreements within the same time frame.
---------------------------------------------------------------------------
\2092\ Dominion Initial Comments at 38; Duke Southeast Utilities
Initial Comments at 14.
\2093\ Duke Southeast Utilities Initial Comments at 14.
---------------------------------------------------------------------------
1075. Bonneville requests clarification as to whether the failure
to execute the affected system study agreement, execute the affected
system facilities construction agreement, or provide the affected
system study deposit would be grounds for removal from the host
transmission provider's interconnection queue.\2094\
---------------------------------------------------------------------------
\2094\ Bonneville Initial Comments at 20-21.
---------------------------------------------------------------------------
(8) Affected System Study Scope and Timeline
1076. Many commenters, including transmission providers, argue that
the Commission should clarify the scope of required affected system
studies by addressing whether an affected system facilities study will
be required under section 9 of the pro forma LGIP.\2095\ For example,
Duke Southeast Utilities state that the NOPR proposal is unclear on
whether ``affected system study results'' is intended to reflect the
results of a system impact study, a facilities study, or a combination
thereof.\2096\
---------------------------------------------------------------------------
\2095\ APPA-LPPC Initial Comments at 26; Duke Southeast
Utilities Initial Comments at 15; Enel Initial Comments at 65;
Pattern Energy Initial Comments at 24.
\2096\ Duke Southeast Utilities Initial Comments at 15.
---------------------------------------------------------------------------
1077. Several commenters request that the Commission explicitly
include a facilities study in the affected system study process.\2097\
Duke Southeast Utilities, Enel, NV Energy, and SPP assert that
explicitly including a facilities study in the affected system study
process would provide both affected system transmission provider and
affected system interconnection customer with more refined estimated
costs and construction timelines.\2098\ Pattern Energy argues that a
facilities study is a useful tool for scoping and pricing network
upgrades and other facilities necessary to mitigate transmission-
related contingencies,\2099\ and LADWP argues that a facilities study
would improve the efficiency of the overall process by minimizing
discrepancies discovered after execution of a construction
agreement.\2100\ APPA-LPPC request that the Commission confirm that it
does not intend to foreclose the possibility of affected system
facilities studies being conducted, as a facilities study is needed to
ascertain the precise nature of any network upgrades that an
interconnection customer may cause.\2101\
---------------------------------------------------------------------------
\2097\ Id.; APPA-LPPC Initial Comments at 26; Enel Initial
Comments at 65; LADWP Initial Comments at 4; NV Energy Initial
Comments at 11; Pattern Energy Initial Comments at 25; SPP Initial
Comments at 16-17.
\2098\ Duke Southeast Utilities Initial Comments at 15; Enel
Initial Comments at 65; NV Energy Initial Comments at 11; SPP
Initial Comments at 16-17.
\2099\ LADWP Initial Comments at 4; Pattern Energy Initial
Comments at 24-25.
\2100\ LADWP Initial Comments at 4.
\2101\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------
1078. Shell argues for including further information regarding
local transmission planning from neighboring transmission providers in
affected system study results because early identification of all
transmission-related mitigation will ensure that interconnection
customers can anticipate affected system network upgrades as early as
possible.\2102\
---------------------------------------------------------------------------
\2102\ Shell Initial Comments at 31.
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1079. Several commenters, including transmission providers, argue
that the 90-calendar day time frame for completion of the affected
system study, from the date an affected system transmission provider
receives an executed affected system study agreement from the affected
system interconnection customer to the date the affected system
transmission provider presents the affected system study report to the
affected system
[[Page 61166]]
interconnection customer, as proposed in pro forma LGIP section 9.6,
does not provide affected system transmission providers sufficient time
to complete the study.\2103\ Bonneville requests that the Commission
clarify whether the schedule to complete the affected system study
could include a due date that is in excess of the 90-calendar day
timeline.\2104\ Tri-State requests the addition of ``and deposit'' to
proposed pro forma LGIP section 9.6, such that the 90-calendar day
period would begin after the receipt of the executed affected system
study agreement and deposit.\2105\ MISO requests that the Commission
clarify that the study clock would commence only after all necessary
data has been received.\2106\
---------------------------------------------------------------------------
\2103\ AEP Initial Comments at 31; WAPA Initial Comments at 13.
\2104\ Bonneville Initial Comments at 19.
\2105\ Tri-State Initial Comments at 19.
\2106\ MISO Initial Comments at 93.
---------------------------------------------------------------------------
1080. Other commenters support the NOPR proposal or argue that
affected system interconnection customers should be given the results
of affected system studies as early as possible. Interwest states that
it agrees with commenters that the proposed 90-calendar day time limit,
combined with monetary penalties, will help instill discipline and
support investments needed to meet the timelines.\2107\ Shell asserts
that affected system study results must be provided before or in
conjunction with system impact study results on the host transmission
system, or at the latest, before interconnection customers are required
to proceed to the facilities study on the host transmission system, as
interconnection customers typically pursue financing after receiving
system impact study results and before advancing to the facilities
study and doing so will avoid last minute network upgrade costs that
undermine project viability and cause interconnection queue
withdrawals.\2108\ Shell supports an option for interconnection
customers to pause the interconnection study process on the host
transmission system for an affected system study to ``catch-up'' if
such an option lowers the risk of receiving late affected system study
results. Similarly, Interwest asserts that affected system
interconnection customers should be permitted to delay posting security
and funding network upgrades, if there are delays in affected system
studies, which Interwest contends is a reasonable accommodation that
allows such affected system interconnection customers to reduce
risks.\2109\
---------------------------------------------------------------------------
\2107\ Interwest Reply Comments at 17.
\2108\ Shell Initial Comments at 30-31.
\2109\ Interwest Reply Comments at 18.
---------------------------------------------------------------------------
1081. Additionally, WAPA expresses concern about its ability to
tender an affected system facilities construction agreement to an
interconnection customer within 30 calendar days of providing the
affected system study report, as proposed in pro forma LGIP section
9.9.\2110\
---------------------------------------------------------------------------
\2110\ WAPA Initial Comments at 13.
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1082. Several commenters oppose, ask for clarification, or propose
alternatives regarding the scope and applicability of the financial
penalties that would apply if a transmission provider does not meet the
study completion deadlines set forth in proposed pro forma LGIP section
9.6. AECI asserts that, so long as affected system transmission
providers are using good utility practice and appropriate due diligence
to complete affected system studies, there is no benefit of imposing
additional penalties on affected system transmission providers.\2111\
ENGIE states that it is unclear who bears the financial penalties for
late affected system studies.\2112\
---------------------------------------------------------------------------
\2111\ AECI Initial Comments at 7.
\2112\ ENGIE Initial Comments at 9. Additionally, ENGIE states
that transmission owners typically have responsibilities for
affected system studies and, therefore, argues that the Commission
should consider language that distributes financial risk and
penalties to both transmission owners and transmission providers,
including an ability for transmission providers to recover costs
from transmission owners. Id.
---------------------------------------------------------------------------
1083. MISO, in contrast, interprets the NOPR proposal as applying
penalties only to the affected system transmission provider, and
recommends that the Commission recognize that some delays may be beyond
the control of the affected system transmission provider and not
penalize affected system transmission providers for third-party
delays.\2113\ Similarly, Duke Southeast Utilities express concern that
penalties could be levied against affected system transmission
providers for delays beyond their control, and further argue that the
Commission should consider imposing multilateral penalties on all
entities in accordance with their individual obligations set forth in
the proposed process.\2114\
---------------------------------------------------------------------------
\2113\ MISO Initial Comments at 92. WAPA also is generally
concerned about the imposition of monetary penalties for failure to
meet deadlines and questions whether Federal agencies like WAPA
should, or even can be, subject to monetary penalties. See WAPA
Initial Comments at 10, 14.
\2114\ Duke Southeast Utilities Initial Comments at 17-18.
---------------------------------------------------------------------------
1084. Several commenters state that the cost estimates provided in
affected system study results should be non-binding, or that certain
types of cost increases related to affected system study results should
allow interconnection customers to withdraw their interconnection
requests without penalty.\2115\ Similarly, Shell asserts that the
Commission should allow penalty-free withdrawals in the event of late
affected system network upgrade costs that surpass a certain threshold,
arguing that such circumstances are beyond the interconnection
customer's control.\2116\ PacifiCorp states that any cost estimates
identified by affected system operators should be non-binding, given
that they could be subject to change.\2117\
---------------------------------------------------------------------------
\2115\ Invenergy Initial Comments at 25; Shell Initial Comments
at 31; PacifiCorp Initial Comments at 36.
\2116\ Shell Initial Comments at 31.
\2117\ PacifiCorp Initial Comments at 36.
---------------------------------------------------------------------------
1085. Pattern Energy believes that the Commission should provide
incentives for transmission providers to provide more reasonable and
accurate cost estimates for network upgrades and related facilities,
even for affected system studies.\2118\ Pattern Energy claims that the
Commission should not adopt ``good faith'' to be the standard on which
cost estimates are provided in affected system studies, asserting that
reasonable cost estimates based on defined metrics should be the
standard.
---------------------------------------------------------------------------
\2118\ Pattern Energy Initial Comments at 25.
---------------------------------------------------------------------------
(9) Affected System Network Upgrade Cost Allocation
1086. SEIA supports the NOPR proposal to allocate affected system
network upgrade costs using a proportional impact method, arguing that
this method should help to reduce individual interconnection customer
network upgrade costs by allowing interconnection customers to share
the cost and, in doing so, reduce the likelihood of cascading
withdrawals.\2119\
---------------------------------------------------------------------------
\2119\ SEIA Initial Comments at 35.
---------------------------------------------------------------------------
1087. Other commenters stress the importance of certainty and
fairness in cost allocation rules. For example, National Grid contends
that cost allocation rules should provide certainty to interconnection
customers at a reasonable point in the interconnection process, while
also having appropriate rules to allocate changes in cost allocations
that arise after the date that network upgrade costs are
finalized.\2120\ National Grid suggests that this could be achieved by
finalizing network upgrade cost allocations at the facilities study
phase of the host transmission provider's interconnection study
process, subject to risk sharing cost allocation rules, whereby later
changes due to the identification of additional required facilities
could be
[[Page 61167]]
shared between the interconnection customer and load in a transmission
provider's footprint based on the principle of beneficiary pays,
through various particular methodologies, including those used for
transmission planning upgrades or those based on geography.\2121\
---------------------------------------------------------------------------
\2120\ National Grid Initial Comments at 35.
\2121\ Interwest Reply Comments at 17; National Grid Initial
Comments at 35-36.
---------------------------------------------------------------------------
1088. Finally, several commenters raise other issues regarding
affected system cost allocation. Enel seeks clarity regarding whether
shared network upgrades would apply between host system interconnection
requests and affected system interconnection requests.\2122\ NV Energy
asserts that, since the affected system interconnection request is
queued, if the affected system interconnection customer is allocated
affected system network upgrade costs based on the proportional impact
method and subsequentially withdraws, then a restudy could potentially
be required for a lower-queued cluster, which would result in a
misalignment with the timeline and withdrawal penalties in the
transmission provider's cluster study for native interconnection
requests.\2123\ ACE-NY argues that no project should be assigned
affected system network upgrade costs after it executes its LGIA and/or
after the interconnection customer has accepted its cost allocation in
the class year process in NYISO.\2124\
---------------------------------------------------------------------------
\2122\ Enel Initial Comments at 67 (citing proposed pro forma
LGIP sections 9.8 and 3.10).
\2123\ NV Energy Initial Comments at 11.
\2124\ ACE-NY Initial Comments at 9.
---------------------------------------------------------------------------
(10) Tender of Affected System Facilities Construction Agreement
1089. Several commenters argue that the proposed time frame for the
affected system transmission provider to tender an affected system
facilities construction agreement to the affected system
interconnection customer--within 30 calendar days of providing the
affected system study results to the interconnection customer, as
proposed in section 9.9 of the pro forma LGIP--should be extended or
modified. Duke Southeast Utilities argue that this deadline should be
60 calendar days for various administrative reasons.\2125\ Idaho Power
suggests that the affected system transmission provider tender the
affected system facilities construction agreement either within 60
calendar days after the interconnection customers executes a facilities
construction agreement with the host transmission provider or within 30
calendar days after providing the affected system study results to the
affected system interconnection customer, if the affected system study
is performed during the interconnection facilities study.\2126\ Idaho
Power explains that information required in the facilities construction
agreement is comparable to the information provided by the host
transmission provider in the interconnection facilities study report,
which, according to Idaho Power, provides a reasonably accurate timing
and cost estimate and requires considerable coordination to develop.
WAPA highlights other constraints, stating that it contracts out many
of its facilities study tasks, which can take significant time, that it
must work within the budgetary constraints of its annual appropriation,
and that it is impractical to have a construction agreement ready for
any interconnection customer within 30 calendar days.\2127\
---------------------------------------------------------------------------
\2125\ Duke Southeast Utilities Initial Comments at 15-16
(citing the possibility of multiple individual agreements, the need
to refine previously provided cost estimates and necessary
construction schedule, and the potential for more information and
updates from the host transmission provider).
\2126\ Idaho Power Initial Comments at 11.
\2127\ WAPA Initial Comments at 13.
---------------------------------------------------------------------------
1090. MISO cautions that providing detailed affected system network
upgrade cost estimates and construction timelines within 30 calendar
days of providing the affected system study results may not be feasible
given that MISO currently only gives high-level cost estimates after
its affected system study and construction timelines and detailed cost
estimates are provided in the affected system network upgrade
facilities study, which is performed by transmission owners.\2128\ MISO
further argues that it should not be responsible for actions that are
beyond its control, such as the transmission owner-prepared affected
system network upgrade facilities study, which it claims would not be
feasible to include in each affected system study report if it is
attempting to meet the 90-calendar day study timeline, and thus the
affected system study and the affected system facilities study should
be kept separate. MISO further argues that it is unlikely that
transmission owners could provide cost/schedule detail with +/-20%
accuracy within 30 calendar days of determination of affected system
network upgrade obligations, with 90 calendar days being a more
reasonable time frame.\2129\
---------------------------------------------------------------------------
\2128\ MISO Initial Comments at 90-91.
\2129\ Id. at 91-92.
---------------------------------------------------------------------------
(11) Restudy
1091. Bonneville expresses concern with the restudy timeline
proposed in pro forma LGIP section 9.10, which would require that a
restudy of the affected system study take no longer than 60 calendar
days from the date of notice. Bonneville argues that flexibility is
warranted due to the complexity of restudies.\2130\
---------------------------------------------------------------------------
\2130\ Bonneville Initial Comments at 22.
---------------------------------------------------------------------------
(d) Requests for Alternatives
(1) Clustering of Affected System Studies
1092. Several commenters argue that transmission providers should
process affected system studies using a clustering approach.\2131\
Several commenters argue that mandating use of serial studies for all
variously situated transmission providers would adversely impact the
efficiency of the study process and place a significant administrative
burden on transmission providers that is disproportionate to the
contemplated benefits.\2132\ NextEra urges the Commission to not
mandate serial affected system study processing when cluster studies of
affected system impacts will be more expeditious and efficient,
contending that this would particularly be the case when
interconnection requests in large cluster studies impact an adjacent
system.\2133\ North Carolina Commission and Staff claim that serial
studies come with substantial costs in the form of network upgrades
that may not be sufficient to meet future demand.\2134\
---------------------------------------------------------------------------
\2131\ AECI Initial Comments at 6; Indicated PJM TOs Initial
Comments at 47; NextEra Reply Comments at 4; North Carolina
Commission and Staff Initial Comments at 25; PPL Initial Comments at
19-20; SPP Initial Comments at 15; WAPA Initial Comments at 11.
\2132\ AECI Initial Comments at 6-7; Indicated PJM TOs Initial
Comments at 47; NextEra Reply Comments at 4; North Carolina
Commission and Staff Initial Comments at 24-25 (citing Gajda Aff. ]]
21-22, 27); SPP Initial Comments at 15-16.
\2133\ NextEra Reply Comments at 4-5.
\2134\ North Carolina Commission and Staff Initial Comments at
25 (noting that Duke Energy Progress, LLC constructed $711,805 in
affected system network upgrades in 2017 to accommodate a PJM
cluster and that a current, planned upgrade of the same transmission
line will eliminate the need for all or some of those affected
system network upgrades, which should have lasted at least 40 years
and were paid for by Duke Energy Progress, LLC's customers).
---------------------------------------------------------------------------
1093. Indicated PJM TOs argue that, for efficiency and consistency,
affected system studies should be integrated into the cluster study
process.\2135\ Indicated PJM TOs argue that PJM's proposed approach,
whereby an affected system study identified by one region would be
integrated into the cluster study of another region, would be more
efficient
[[Page 61168]]
and less disruptive than the approach identified in the NOPR.\2136\
---------------------------------------------------------------------------
\2135\ Indicated PJM TOs Initial Comments at 47-48; Indicated
PJM TOs Reply Comments at 41.
\2136\ Indicated PJM TOs Initial Comments at 47 (noting that the
2022 PJM filing provides that PJM will determine the need for an
affected system analysis in phase 1 of a study cycle, and when PJM
is identified by another region as needing to complete an affected
system analysis, it will place the affected system interconnection
request in phase 2 of an ongoing study cycle) (referencing PJM,
Filing, Docket No. ER22-2110-000, Sims Aff. ] 10 (filed June 14,
2022)).
---------------------------------------------------------------------------
1094. Some commenters also call for flexibility. AECI argues that
the Commission should not limit the flexibility yielded by its existing
process of studying each yearly cluster to determine impacts and
potential affected system network upgrades, when it is acting as the
affected system operator coordinating studies with a neighboring RTO/
ISO.\2137\ PPL argues that affected system transmission providers
should have the option to enter into a study agreement with either an
individual affected system interconnection customer, a group of
affected system interconnection customers from the same cluster (that
share cost and other responsibilities), or the ``direct connect
system.'' \2138\
---------------------------------------------------------------------------
\2137\ AECI Initial Comments at 6.
\2138\ PPL Initial Comments at 20.
---------------------------------------------------------------------------
(2) Coordination Between Host Transmission Provider and Affected System
Transmission Provider
1095. NextEra contends that the NOPR proposal gives too little
attention to complex issues, such as potential interconnection queue
coordination issues between transmission providers that could arise
after implementation of the proposed reforms.\2139\ Several commenters
argue that, for efficiency reasons, host transmission providers--and
not individual affected system interconnection customers--should be
required to coordinate affected system study activities with the
affected system transmission providers.\2140\ Some commenters recommend
that the Commission adopt the coordination approach used by MISO and
certain of its neighboring systems, whereby the host transmission
provider coordinates all technical data, study deposits, and studies
with the affected system transmission provider rather than the proposed
direct communication and coordination between interconnection customer
and affected system transmission provider.\2141\ Enel asserts that this
would reduce administrative burden, ensure timely compliance with the
tariff, reduce interconnection costs, and increase accountability. Enel
also argues that using the host transmission provider's study agreement
to require the interconnection customer to comply with the affected
system transmission provider's study process ensures that the
interconnection customer must meet tariff deadlines and cannot delay
the affected system transmission provider's studies. In addition, Shell
states that that the Commission should develop guidance for situations
in which neighboring transmission providers disagree on the scope and/
or timing of an affected system study.\2142\
---------------------------------------------------------------------------
\2139\ NextEra Reply Comments at 4.
\2140\ Enel Initial Comments at 60-61; North Carolina Commission
and Staff Initial Comments at 25-26; Shell Initial Comments at 30.
\2141\ Enel Initial Comments at 60-61. Enel further argues that
affected system studies should be invoiced to the host transmission
provider and paid out of the interconnection customer's study
deposits, subject to total study cost true-up, and that host
transmission providers should be required to share the
interconnection customer's technical data as needed. Enel reasons
that through direct connections, host and affected system
transmission providers would be better able to compare constraints
and proposed upgrades to coordinate where a single upgrade may
address constraints on both transmission systems. Id.
\2142\ Shell Initial Comments at 30.
---------------------------------------------------------------------------
1096. Several commenters argue that the NOPR proposal should be
reevaluated or modified regarding whether and when transmission
providers conducting cluster studies would be required to delay those
studies to wait for the results of affected system studies. Pattern
Energy contends that the Commission should consider an approach in
which host transmission providers are not required to wait for affected
system studies to be completed, if such delayed action would result in
a study milestone being missed.\2143\ Pattern Energy seeks to avoid an
unintentional ``delay loop,'' whereby the affected system is not
diligently processing an affected system study because the host
transmission provider is waiting for it.\2144\
---------------------------------------------------------------------------
\2143\ Pattern Energy Initial Comments at 25.
\2144\ Id. at 25-26.
---------------------------------------------------------------------------
1097. In contrast, PacifiCorp requests that the Commission clarify
that, although host transmission providers performing cluster studies
are not required to delay those studies by waiting for the results of
affected system studies, transmission providers will not be prohibited
from delaying the cluster study process to account for affected system
study issues if the host transmission provider determines that the
cluster study cannot progress without the results of the affected
system studies.\2145\ MISO raises similar concerns about a transmission
provider proceeding with its cluster studies without affected system
data, which it asserts is critical information for an interconnection
customer.\2146\ MISO further asserts that the NOPR proposal will not
provide useful information to the interconnection customer sooner and
will increase uncertainty, opportunities for late-stage withdrawals,
cost shifts, and unscheduled restudies and cascading withdrawals.\2147\
---------------------------------------------------------------------------
\2145\ PacifiCorp Initial Comments at 36-37.
\2146\ MISO Initial Comments at 93-94.
\2147\ Id. at 94-95.
---------------------------------------------------------------------------
1098. Xcel strongly supports improving affected system study
interactions, arguing that with common models and processes, in many
instances, host transmission provider study results can be used to
identify affected system network upgrades, leaving the affected system
transmission provider to only identify mitigation solutions.\2148\
Noting that many RTO/ISO regions have operating agreements that address
interface capacity rights and processes to relieve congestion near and
across seams, Xcel argues that host and affected system transmission
providers should take those operating agreements into account when
considering any interconnection-related requirements from the affected
system transmission provider.
---------------------------------------------------------------------------
\2148\ Xcel Initial Comments at 38-39.
---------------------------------------------------------------------------
1099. APPA-LPPC request that transmission providers be able to
forego a formal affected system study when studies by the host
transmission provider may be sufficient.\2149\ APPA-LPPC ask the
Commission to recognize in the pro forma LGIP that there may be
instances in which separate affected system studies may not be
necessary or useful because, in their members' experience, particularly
in the Western Interconnection, feasibility, system impact, and
facilities studies undertaken by a directly interconnecting
transmission provider may be adequate in scope to encompass impacts on
and any necessary upgrades to an affected system.\2150\ In such a case,
APPA-LPPC state, a unitary study would be less expensive for all
parties and avoid a complex administrative task of sequencing and
integrating separate system studies.\2151\
---------------------------------------------------------------------------
\2149\ APPA-LPPC Initial Comments at 25.
\2150\ Id. at 23-25.
\2151\ Id. at 25.
---------------------------------------------------------------------------
1100. Another alternative proposed by WAPA and Enel is the use of
an affected system screening process to identify instances where
affected system studies will be needed.\2152\ WAPA suggests that this
screening process could be a feasibility-level study, completed for an
entire cluster, to narrow down which interconnection requests within
the cluster potentially have impacts on an
[[Page 61169]]
affected system.\2153\ WAPA contends that, without a screening process,
transmission providers under the NOPR proposal will require affected
system studies by default. Enel suggests that the affected system
transmission provider should conduct the screening process during the
host transmission provider's cluster study so that the affected system
transmission provider is prepared to perform its affected system study
during the host transmission provider's initial cluster restudy.
---------------------------------------------------------------------------
\2152\ Enel Initial Comments at 57-58; WAPA Initial Comments at
12-13.
\2153\ WAPA Initial Comments at 12-13.
---------------------------------------------------------------------------
(3) Interregional Transmission Planning
1101. A few commenters urge the Commission to address affected
system impacts as a systematic phenomenon and a matter of interregional
transmission planning, rather than one-off events to be handled
serially.\2154\ EDF Renewables argues that better interregional
transmission planning should reduce the frequency and severity of
affected system impacts, asserting that a system-wide approach is more
efficient than a piecemeal one.\2155\ NextEra cautions that one issue
absent from the affected system proposals in the NOPR is that the costs
for alleviating an existing system condition should not rest with a new
generating facility interconnecting on an adjacent system that did not
create the problem.\2156\ NextEra argues that preexisting reliability
issues should instead be identified and solved through the transmission
planning processes.
---------------------------------------------------------------------------
\2154\ EDF Renewables Initial Comments at 11; NextEra Initial
Comments at 31; North Carolina Commission and Staff Initial Comments
at 3.
\2155\ EDF Renewables Initial Comments at 11.
\2156\ NextEra Initial Comments at 31.
---------------------------------------------------------------------------
(e) Requests for Clarification and Flexibility
1102. Idaho Power requests clarification regarding whether the
affected system study process would be required for entities that
already use the first-ready, first served cluster study process.\2157\
---------------------------------------------------------------------------
\2157\ Idaho Power Initial Comments at 11.
---------------------------------------------------------------------------
1103. Regarding timing, Invenergy argues that although many of the
NOPR's proposed requirements should apply prospectively to new
interconnection requests, immediate action from the Commission is
needed to resolve affected system issues. Invenergy requests that the
Commission clarify that the proposed reforms should apply to all
pending interconnection requests and active studies.\2158\
---------------------------------------------------------------------------
\2158\ Invenergy Initial Comments at 41.
---------------------------------------------------------------------------
1104. Several commenters request clarification regarding how the
proposed affected system reforms would affect RTO/ISO transmission
providers and transmission owners in their regions.\2159\ Eversource
requests that the Commission clarify that the proposed affected system
reforms are not applicable to intra-RTO/ISO system upgrades.\2160\
Similarly, NYTOs request that the Commission clarify that the proposed
affected system reforms would not apply to neighboring transmission
owners within a single RTO/ISO, or at least allow such transmission
owners to demonstrate on compliance that their existing processes
already address such intra-RTO/ISO issues.\2161\ AEP requests that the
Commission address what it terms the four primary types of affected
system scenarios: neighboring transmission owner systems within one
RTO/ISO; neighboring transmission owner systems in two separate RTOs/
ISOs; a transmission owner system in an RTO/ISO neighboring a non-RTO/
ISO transmission provider; and neighboring transmission providers both
outside of an RTO/ISO.\2162\ AEP contends that the Commission appears
to conflate all possible affected system scenarios in the NOPR, even
though the nature of any affected system study can be impacted by the
type of scenario.\2163\
---------------------------------------------------------------------------
\2159\ Eversource Initial Comments at 31-32; NYTOs Initial
Comments at 29.
\2160\ Eversource Initial Comments at 31-32.
\2161\ NYTOs Initial Comments at 29 (citing NYISO, NYISO
Tariffs, attach. X, section 30.3.5 (16.0.0)).
\2162\ AEP Initial Comments at 32-33; NextEra Reply Comments at
4.
\2163\ AEP Initial Comments at 33.
---------------------------------------------------------------------------
1105. CREA and NewSun seek clarification on whether the proposed
affected system reforms apply where QF interconnections under PURPA are
subject to state jurisdiction.\2164\ CREA and NewSun explain that,
under existing precedent, the Commission has allowed states to retain
their historic interconnection jurisdiction under PURPA where the QF
sells its entire net output to the interconnecting utility.\2165\ CREA
and NewSun argue, though, that where affected system issues are
involved, the state's jurisdiction over the sale of the QF's energy to
a utility regulated by that state would not extend to affected system
issues with a third-party transmission provider that is not purchasing
the QF's net output.\2166\ CREA and NewSun urge the Commission to
clarify that a QF interconnection customer has the option to opt into
use of the Commission's interconnection procedures, in cases where the
interconnection requires studies or network upgrades on an affected
system without loss of queue position. CREA and NewSun also argue that
the QF should retain the right to elect to proceed through the state
process in case the QF concludes that it would be less disruptive to do
so.
---------------------------------------------------------------------------
\2164\ CREA and NewSun Initial Comments at 86.
\2165\ Id. at 87 (citing Order No. 2003, 104 FERC ] 61,103 at PP
813-815; Prior Notice & Filing Requirements Under Part II of the
Fed. Power Act, 64 FERC ] 61,139, at 61,991-92, order on reh'g, 65
FERC ] 61,081 (1993)).
\2166\ Id. at 87-88.
---------------------------------------------------------------------------
1106. Several commenters request clarification on whether the
proposed affected system reforms apply to non-Commission-jurisdictional
transmission providers.\2167\ Invenergy and Interwest state that, if an
affected system is not a Commission-jurisdictional utility, the
Commission would be unable to enforce the process or any penalties
proposed in the NOPR, which would leave the interconnection customer in
the same bind that currently exists.\2168\ Invenergy, Interwest, Xcel,
and EEI assert that the Commission should prevent non-jurisdictional
entities from interfering with completion of jurisdictional
transmission providers' interconnection processes.\2169\
---------------------------------------------------------------------------
\2167\ Interwest Reply Comments at 18; Invenergy Initial
Comments at 42; Pacific Northwest Utilities Initial Comments at 17;
Puget Sound Initial Comments at 7; Tri-State Initial Comments at 20.
\2168\ Interwest Reply Comments at 18; Invenergy Initial
Comments at 42.
\2169\ EEI Initial Comments at 19; Interwest Reply Comments at
18; Invenergy Initial Comments at 43; Invenergy Reply Comments at 9;
Xcel Initial Comments at 39.
---------------------------------------------------------------------------
1107. Several commenters call for the Commission to explain how
jurisdictional transmission providers should respond to potential
delays or inaction by non-jurisdictional transmission providers not
subject to the affected system study process reforms.\2170\
---------------------------------------------------------------------------
\2170\ EEI Initial Comments at 19; NextEra Initial Comments at
34; Pacific Northwest Utilities Initial Comments at 15-16; Xcel
Initial Comments at 39.
---------------------------------------------------------------------------
1108. Other commenters argue that the Commission should hold
jurisdictional transmission providers harmless for delays induced by or
notifications not sent by non-jurisdictional affected system
transmission providers.\2171\ Pacific Northwest Utilities and Puget
Sound ask the Commission to clarify that transmission providers have
met their obligations in dealing with non-jurisdictional entities if
the host transmission provider notifies a non-jurisdictional affected
system transmission provider within 10 business days of identifying a
potential impact to the transmission system of the non-jurisdictional
entity, pursuant to pro forma LGIP section 3.6.1, and invites the non-
jurisdictional entity to an affected system scoping meeting,
[[Page 61170]]
pursuant to pro forma LGIP section 3.6.2.\2172\
---------------------------------------------------------------------------
\2171\ Pacific Northwest Utilities Initial Comments at 16-17;
Puget Sound Initial Comments at 7.
\2172\ Puget Sound Initial Comments at 8; Pacific Northwest
Utilities Initial Comments at 17.
---------------------------------------------------------------------------
1109. Many commenters emphasize the importance of flexibility for
transmission providers and argue in favor of granting transmission
providers compliance flexibility in implementing affected system study
process reforms.\2173\ Some commenters contend that the Commission
should allow transmission providers to demonstrate that their existing
affected system study processes or planned revisions to those processes
are adequate to address the Commission's concerns.\2174\
---------------------------------------------------------------------------
\2173\ AEP Initial Comments at 5; Dominion Initial Comments at
39; National Grid Initial Comments at 37-38; NYISO Initial Comments
at 44; PacifiCorp Initial Comments at 36; PJM Reply Comments at 10.
\2174\ AEP Initial Comments at 32; Alliant Energy Initial
Comments at 7; MISO Initial Comments at 7, 12-13, 83-85, 95; NYISO
Initial Comments at 44; Omaha Public Power Initial Comments at 12;
OMS Initial Comments at 17; SPP Initial Comments at 16-18.
---------------------------------------------------------------------------
iii. Commission Determination
1110. We adopt, with modifications, the NOPR proposal to establish
an affected system study process in, and add several related
definitions to, the pro forma LGIP. As explained in the NOPR, a
detailed affected system study process in the pro forma LGIP will
prevent the use of ad hoc approaches that may give rise to
interconnection customers being treated in an unjust, unreasonable, and
unduly discriminatory or preferential manner. We agree with commenters
that it will also provide interconnection customers greater certainty
regarding expectations throughout the interconnection process,
including greater cost certainty, which will lead to fewer late-stage
withdrawals and fewer delays. The firm affected system study deadlines
will also ensure that the affected system study process moves along
expediently, providing clarity, cost certainty, and increased
transparency throughout the study process, which will minimize
opportunities for undue discrimination. For these reasons, we find that
the affected system study process reforms adopted herein are just,
reasonable, and not unduly discriminatory or preferential and that they
remedy the unjust, unreasonable, and unduly discriminatory or
preferential rates resulting from the status quo with regard to
affected systems. We further find that such reforms will ensure that
interconnection customers are able to interconnect to the transmission
system in a reliable, efficient, transparent, and timely manner.
1111. We disagree with commenters' concerns that a broadly applied,
prescriptive affected system study process may not be helpful or may be
unworkable.\2175\ Instead, we agree with National Grid that the current
status quo is not working and will likely worsen absent
intervention.\2176\ Although some transmission providers may already
have working affected system study processes in place, many do not,
creating uncertainty and unreasonable delay in the interconnection
process. Further, as discussed below with regard to specific reforms,
we adopt several revisions to the NOPR proposal in response to comments
to ensure the affected system study process deadlines are reasonable
and support efficient processing of interconnection requests. We
disagree with commenters who argue that the NOPR proposal does not
increase efficiency and note that certain modifications will further
increase efficiency.\2177\ While certain required steps in the affected
system study process may increase the need for communication and
coordination between affected system transmission providers, affected
system interconnection customers, and/or host transmission providers,
we find that the potential burden of such discrete efforts are
outweighed by the efficiencies of a standardized and more predictable
affected system study process. We further find that defining an
affected system study process in the pro forma LGIP is necessary to
ensure that affected system interconnection customers are not being
treated in an unjust, unreasonable, and unduly discriminatory or
preferential manner, and to ensure that they can evaluate their costs
and make decisions regarding the viability of their generation
facilities in a timely manner during the interconnection study process.
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\2175\ Dominion Initial Comments at 37; Pacific Northwest
Utilities Initial Comments at 15; PJM Initial Comments at 63; SDG&E
Reply Comments at 3.
\2176\ National Grid Initial Comments at 35.
\2177\ Dominion Initial Comments at 36-37; SDG&E Reply Comments
at 3; SPP Initial Comments at 17; WAPA Initial Comments at 10.
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(a) Definitions and Applicability (Pro Forma LGIP Sections 1 and 9.1)
1112. We adopt the NOPR proposal, with modification, to include
several definitions in section 1 of the pro forma LGIP related to the
affected system reforms, specifically, ``affected system facilities
construction agreement,'' ``affected system interconnection customer,''
``affected system network upgrades,'' ``affected system study,''
``affected system study agreement,'' and ``affected system study
report.'' We find these terms to be necessary to enumerate the affected
system transmission provider's responsibilities in the affected system
study process.\2178\ We also add the terms ``multiparty affected system
study agreement'' and ``multiparty affected system facilities
construction agreement'' to section 1 of the pro forma LGIP in light of
our adoption of such agreements as part of this final rule, as
discussed below. We also add the term ``affected system queue
position'' to the pro forma LGIP because we find it helpful to
distinguish between an interconnection customer's queue position on the
host system versus its queue position on an affected system.
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\2178\ We note that, in the affected system context, there are
certain instances in which we intentionally use lowercase versions
of defined terms to deviate from their definitions in section 1 of
the pro forma LGIP. For example, ``generating facility'' is, in pro
forma LGIP section 1, part of the definition of ``affected system
interconnection customer.'' In the affected system context, we are
referring to a generating facility governed by another transmission
provider's LGIP rather than the affected system transmission
provider's generating facility as defined in its own LGIP.
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1113. We adopt, with modification, the NOPR proposal to add section
9.1 to the pro forma LGIP, titled ``Applicability.'' We find that pro
forma LGIP section 9.1 clarifies that the transmission provider's
obligations in section 9 apply when it is acting as an affected system
transmission provider, and we have added clarifying language to resolve
ambiguity therein.\2179\
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\2179\ We note that former pro forma LGIP section 9, titled
``Engineering and Procurement (`E&P') Agreement,'' is now pro forma
LGIP section 13.7 to accommodate the new affected system study
process section.
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1114. In response to PPL's argument that the term ``affected system
interconnection customer'' is confusing and that either another term
should be used or ``interconnection'' should be deleted from the term,
we reiterate that the pro forma LGIP is written to apply to all
transmission providers on a generic basis, meaning transmission
providers studying proposed interconnections to their transmission
systems (host transmission providers) as well as transmission providers
studying the impacts on their own transmission system of proposed
interconnections to other transmission providers' transmission systems
(affected system transmission providers). In other words, when a
transmission provider's transmission system is an affected system, the
interconnection customer creating the affected system impact is
different from that particular affected system transmission provider's
own interconnection customers (i.e., those
[[Page 61171]]
that propose to interconnect directly to the transmission provider's
transmission system) and must be distinguished accordingly in the pro
forma LGIP. The term ``affected system interconnection customer''
achieves this goal by distinguishing between the interconnection
customer's dual roles in the host transmission provider's study process
and the affected system transmission provider's study process.
1115. Further, we disagree with PPL's assertion that some
transmission providers combine interconnection and transmission
processes, making ``interconnection'' an unnecessary distinction.\2180\
This proceeding involves generic generator interconnection procedures,
pursuant to which transmission service request studies are performed
independently from interconnection studies.\2181\ However, we modify
the definition of ``affected system interconnection customer'' and use
other defined terms in the pro forma LGIP for additional clarity and
consistency.
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\2180\ PPL Initial Comments at 19-20.
\2181\ See Tenn. Power Co., 90 FERC ] at 61,761 (finding that
interconnection is an element of transmission service but that the
interconnection component of transmission service may be requested
separately from the delivery component (i.e., interconnection is
distinct from transmission service)).
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1116. As explained below, we do not adopt the NOPR proposal to
require an affected system scoping meeting and therefore also do not
adopt the proposed term ``affected system scoping meeting'' in section
1 of the pro forma LGIP.
1117. We clarify that the terms ``affected system'' and ``affected
system operator'' retain their existing definitions in pro forma LGIP
section 1.\2182\
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\2182\ An affected system is an electric system other than the
transmission provider's transmission system that may be affected by
the proposed interconnection. An affected system operator is the
entity that operates an affected system. Pro forma LGIP section 1.
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1118. In response to NRECA's request for clarification, we
reiterate that the final rule applies to transmission providers and, in
the affected system context, to transmission providers that are acting
as affected systems per the pro forma LGIP definition. Therefore, we
decline to expand the scope of several affected systems-related
definitions as requested by NRECA because we find NRECA's request to be
outside the scope of this proceeding.\2183\ In response to National
Grid's request for clarification regarding whether an affected system
solely includes transmission owners in each region or also includes
neighboring RTOs/ISOs or transmission providers in neighboring regions,
we reiterate that an affected system is defined in section 1 of the pro
forma LGIP as an electric system other than the transmission provider's
transmission system that may be affected by the proposed
interconnection.
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\2183\ See NRECA Initial Comments at 9, 36-39.
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(b) Identification and Notification of Affected Systems (Pro Forma LGIP
Sections 3.6.1, 9.2, and 11.2.1)
1119. We adopt, with modification, proposed section 3.6.1 of the
pro forma LGIP, which sets forth the trigger events for identification
of an affected system impact to begin the affected system study
process. We modify that section to retain as trigger events the
completion of the cluster study and cluster restudy but eliminate the
earlier trigger events--the close of the cluster request window and the
close of the customer engagement window. While we would expect
identification of potential affected system impacts to occur upon the
completion of the cluster study, we recognize that an affected system
impact may not be identified until a restudy occurs, and we adopt
language in pro forma LGIP section 3.6.1 to account for such a
scenario. Thus, as adopted in pro forma LGIP section 3.6.1, we require
the transmission provider to notify the affected system operator at the
first instance of an identified potential affected system impact, which
may occur at the completion of the (1) cluster study or (2) cluster
restudy. We also move the affected system transmission provider's
obligations to respond to the initial notification under proposed pro
forma LGIP section 3.6.1 to a new pro forma LGIP section 9.2. We find
this bifurcation of duties with respect to initial affected system
notification for the transmission provider, when acting as host
transmission provider and affected system transmission provider,
appropriately sets forth the responsibilities of the transmission
provider in the sections describing the conditions for each action.
1120. We also adopt the provision proposed in pro forma LGIP
section 3.6.1 that provides for the transmission provider to notify an
affected system operator of a potential affected system impact caused
by the interconnection request within 10 business days of the first
trigger event giving rise to the identification of the affected system
impact. We modify the provision in proposed pro forma LGIP section
3.6.1 for the affected system transmission provider to respond to such
notification in writing within 15 business days indicating whether it
intends to conduct an affected system study to 20 business days, which
we move to pro forma LGIP section 9.2, as noted above. We further move
to pro forma LGIP section 9.2 the requirement that, within 15 business
days of the affected system transmission provider's affirmative
response of its intent to conduct an affected system study, the
affected system transmission provider must share a non-binding good
faith estimate of the cost and schedule to complete the affected system
study.
1121. As adopted, the identification and notification process is
tied to the completion of the cluster study or the cluster restudy. At
that point, the host transmission provider will have a stronger basis
for deciding whether an interconnection request will potentially impact
an affected system. Further, the initiation of the affected system
study process after the initial study costs are received should lead to
affected system study results that provide greater cost certainty, as
the largest number of interconnection request withdrawals will most
likely occur after receipt of the initial cluster study results, a
point noted by commenters.\2184\ After receipt of the initial cluster
study results, those interconnection requests remaining in the host
system's interconnection queue are more likely to complete the
interconnection study process. We agree with CAISO that this smaller
pool of affected system interconnection customers will enable faster
affected system studies due to a decreased volume of affected system
interconnection customers and more realistic study assumptions.\2185\
Accordingly, we find that beginning the affected system study process
after the adopted trigger events provides greater certainty to
interconnection customers regarding affected system network upgrade
costs while ensuring a faster affected system study process. This is
because the affected system transmission provider will be using more
realistic study assumptions and studying a more realistic number of
affected system interconnection customers, reducing the need for
restudy.
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\2184\ CAISO Initial Comments at 28; Idaho Power Initial
Comments at 11; NextEra Initial Comments at 32.
\2185\ CAISO Initial Comments at 29.
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1122. We find that notification to an affected system operator of a
potential impact prior to receipt of cluster study results would be
administratively burdensome and inefficient and could potentially slow
the interconnection process because such notification would include
numerous interconnection
[[Page 61172]]
requests that ultimately do not reach commercial operation.\2186\
---------------------------------------------------------------------------
\2186\ Id. at 28-29; Enel Initial Comments at 59; Idaho Power
Initial Comments at 11; NextEra Initial Comments at 32.
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1123. In eliminating the first two notification triggers, we
recognize that the affected system study process will start later and,
as a result, the interconnection customer could be required to execute,
or request to be filed unexecuted, its LGIA before it has received its
affected system study results and cost estimates for any affected
system network upgrades. To avoid this result and in response to
commenters' requests that transmission providers should be given the
option to wait for affected system study results when conducting
cluster studies,\2187\ we modify the NOPR proposal and add a new
section 11.2.1 to the pro forma LGIP. Under this section, if the
interconnection customer does not receive its affected system study
results pursuant to pro forma LGIP section 9.7, discussed below, before
the deadline for LGIA execution, or the deadline to request that the
LGIA be filed unexecuted, in its host system, the host transmission
provider must, at the interconnection customer's request, delay the
deadline for the interconnection customer to finalize its LGIA.\2188\
The interconnection customer will have 30 calendar days after receipt
of the affected system study report to execute the LGIA, or request
that the LGIA be filed unexecuted.
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\2187\ PacifiCorp Initial Comments at 36-37; Pattern Energy
Initial Comments at 25; Shell Initial Comments at 30-31.
\2188\ Any interconnection customer that is not awaiting the
results of an affected system study must proceed under the timelines
set forth in pro forma LGIP section 11.1.
---------------------------------------------------------------------------
1124. As noted above, we find that by adopting pro forma LGIP
section 11.2.1, we ensure that interconnection customers have adequate
time to evaluate their costs prior to committing to the cost estimates
contained in an LGIA. Additionally, if the interconnection customer
prefers to proceed to the execution of its LGIA, or request that the
LGIA be filed unexecuted, before it has received its affected system
study results, it may notify the host transmission provider of its
intent to proceed with the execution of the LGIA, or request that the
LGIA be filed unexecuted. If the host transmission provider determines
that further delay to the LGIA execution date would cause a material
impact on the cost or timing of an equal- or lower-queued
interconnection customer, the transmission provider must notify the
interconnection customer whose deadline to execute the LGIA, or request
that the LGIA be filed unexecuted, is delayed of such impact and
establish that the new deadline is 30 calendar days after such notice
is provided.
1125. In response to ACE-NY's argument that no interconnection
customer should be assigned affected system network upgrade costs after
it executes its LGIA and/or after the interconnection customer has
accepted its cost allocation in the class year process in NYISO,\2189\
we decline to rule on specific transmission provider processes in this
final rule. We note, however, that, under new pro forma LGIP section
11.2.1, interconnection customers may negotiate LGIA execution to await
an affected system study report for greater certainty at the time of
LGIA execution, or requesting the LGIA to be filed unexecuted, if that
further delay to the LGIA execution date would not cause a material
impact on the cost or timing of an equal- or lower-queued
interconnection customer.
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\2189\ ACE-NY Initial Comments at 9.
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1126. We decline to require the affected system transmission
provider to provide affected system study results before the facilities
study phase, as asserted by Enel and Shell,\2190\ because such a
requirement would necessitate that the affected system transmission
provider would have to begin such studies before any interconnection
customers withdraw from the interconnection queue and would therefore
involve the study of numerous interconnection requests that do not
eventually proceed to commercial operation, resulting in additional
restudies and delays.
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\2190\ See Enel Initial Comments at 58; Shell Initial Comments
at 30-31.
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1127. In response to Tri-State's argument that proposed pro forma
LGIP section 3.6.1 needs to clarify to whom notice is to be
directed,\2191\ we note the language in pro forma LGIP section 3.6.1
beginning with ``Transmission Provider must notify Affected System
Operator of a potential Affected System impact.'' If Tri-State is
asking to whom the affected system transmission provider should respond
in writing regarding whether it intends to conduct an affected system
study, it should respond to the transmission provider who notified the
affected system operator of a potential affected system impact.
---------------------------------------------------------------------------
\2191\ Tri-State Initial Comments at 28.
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1128. We adopt Pacific Northwest Utilities' requested clarification
and agree with Puget Sound that, provided that transmission providers
properly notify a non-public utility affected system operator within 10
business days under proposed pro forma LGIP section 3.6.1, such steps
are sufficient to demonstrate that the transmission provider has met
its obligations under that section.\2192\
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\2192\ Pacific Northwest Utilities Initial Comments at 17; Puget
Sound Initial Comments at 8.
---------------------------------------------------------------------------
1129. We agree with Interwest and Invenergy that the
interconnection customer should be permitted to delay posting security
and funding for network upgrades under its LGIA until affected system
study results are received in certain situations.\2193\ Specifically,
an interconnection customer is not required to post security for and
fund network upgrades pursuant to an LGIA if the deadline for LGIA
execution, or to request that the LGIA be filed unexecuted, is delayed
under pro forma LGIP section 11.2.1. We agree with Interwest that this
would reduce an affected system interconnection customer's risk of
incurring affected system network upgrade costs after LGIA execution.
However, if the interconnection customer chooses to proceed to execute
an LGIA, or request that the LGIA be filed unexecuted, it will be
responsible for posting security and funding network upgrades as per
the schedule in its LGIA, regardless of whether it has received
affected system study results.
---------------------------------------------------------------------------
\2193\ Interwest Reply Comments at 18; Invenergy Initial
Comments at 43.
---------------------------------------------------------------------------
1130. We disagree with commenters that a transmission provider's
obligation to notify a potential affected system operator of an impact
in 10 business days is unrealistic or problematic.\2194\ As we are
eliminating two trigger events, the host transmission provider now has
the obligation to notify the affected system operator of a potential
impact to the affected system following the completion of the cluster
study or restudy, which we find provides a clear timeline contrary to
PacifiCorp's claims. Furthermore, we do not find any convincing
evidence that a host transmission provider will be unable to provide a
notification to an affected system operator of potential impacts within
10 business days and note that this timeline is supported by
commenters.\2195\
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\2194\ CAISO Initial Comments at 27; Duke Southeast Utilities
Initial Comments at 12; PacifiCorp Initial Comments at 36; PG&E
Reply Comments at 5.
\2195\ See AEP Initial Comments at 31; Pine Gate Initial
Comments at 42.
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1131. However, regarding comments that the affected system
operator's obligation to respond in 15 business days is
insufficient,\2196\ particularly
[[Page 61173]]
when numerous potential affected system impacts are identified in a
single cluster study, as stated above, we extend the affected system
operator's response obligation time period from 15 business days to 20
business days to provide the affected system operator with additional
time to consider whether to study these potential affected system
impacts on its transmission system, consistent with Duke Southeast
Utilities' suggestion.\2197\ We find these timelines necessary to
ensure timely processing of the affected system study process and to
provide certainty to the interconnection customer regarding the
processing of the affected system study.
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\2196\ Bonneville Initial Comments at 18; CAISO Initial Comments
at 27; Duke Southeast Utilities Initial Comments at 12; PG&E Reply
Comments at 5; WAPA Initial Comments at 11-12.
\2197\ See Duke Southeast Utilities Initial Comments at 12.
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(c) Affected System Scoping Meeting (Pro Forma LGIP Section 3.6.2) and
Affected System Study Procedures (Pro Forma LGIP Section 9.7)
1132. We decline to adopt the proposed requirement in pro forma
LGIP section 3.6.2 that affected system transmission providers must
hold an affected system scoping meeting within seven business days
after providing written notification that it intends to conduct an
affected system study. We agree with commenters' concerns that the
difficulties associated with holding an affected system scoping meeting
within the proposed time frame outweigh its potential benefits.\2198\
We also agree with WAPA that a meeting after the affected system study
is completed would be more beneficial than an affected system scoping
meeting.
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\2198\ Bonneville Initial Comments at 18-19; CAISO Initial
Comments at 28; Dominion Initial Comments at 38; MISO Initial
Comments at 86; WAPA Initial Comments at 12.
---------------------------------------------------------------------------
1133. We adopt, with modifications, the proposed affected system
study procedures set forth in pro forma LGIP section 9.6, now section
9.7. In particular, we modify the NOPR proposal to explicitly require
clustering of affected system interconnection customers for study
purposes where multiple interconnection requests that are part of a
single cluster in the host system's cluster study process cause the
need for an affected system study. We find that clustered affected
system studies will, consistent with the requirement to use a first-
ready, first-served cluster study process, improve administrative
efficiency in the affected system study process and reduce
administrative burden on the affected system transmission provider,
thereby promoting overall efficiency in the interconnection process. We
agree with commenters that serial affected system studies would place
an additional burden on transmission providers to study affected system
impacts and would further slow the interconnection process.\2199\ We,
therefore, believe that mandating clustering of affected system studies
will not place an additional unnecessary burden on transmission
providers, no matter their size; rather, it should reduce such burdens
as compared to multiple serial studies and restudies.
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\2199\ AECI Initial Comments at 6-7; Indicated PJM TOs Initial
Comments at 47; NextEra Reply Comments at 4; North Carolina
Commission and Staff Initial Comments at 24-25 (citing Gajda Aff. ]]
21-22, 27); SPP Initial Comments at 15-16.
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1134. We further modify proposed pro forma LGIP section 9.7, to
require the affected system transmission provider to complete the
affected system study and provide the affected system interconnection
customer with affected system study results within 150 calendar days
after receipt of the affected system study agreement, rather than the
proposed 90 calendar days. We agree with commenters that explain that
90 calendar days may not be adequate time to complete an affected
system study,\2200\ aligning with our discussion of the potential for
affected system transmission providers to conduct a facilities study
under proposed pro forma LGIP section 9.6 below. In recognition of
that, we extend the proposed maximum time frame to complete an affected
system study from the NOPR's proposed 90 calendar days to 150 calendar
days. This extension addresses Bonneville's concern that the proposed
schedule to complete an affected system study may have included a due
date in excess of the 90-calendar day timeline.
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\2200\ AEP Initial Comments at 31; Enel Initial Comments at 65;
WAPA Initial Comments at 13.
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1135. We also modify pro forma LGIP section 9.7, which, as
proposed, required the affected system transmission provider to notify
the affected system interconnection customer that an affected system
study will be late, to add a requirement for the affected system
transmission provider to notify the host transmission provider that the
affected system transmission provider will be unable to timely complete
the affected system study.
1136. We adopt Tri-State's request to add the phrase ``and
deposit'' to pro forma LGIP section 9.7, such that the affected system
transmission provider must provide the affected system study report to
the affected system interconnection customer within 150 calendar days
after the receipt of the affected system study agreement and deposit.
We find this addition is needed to clarify the affected system
interconnection customer's obligation to provide an affected system
study deposit, especially if an affected system interconnection
customer loses its affected system queue position, discussed below, for
failure to provide the required deposit under pro forma LGIP section
9.5. We also add to pro forma LGIP section 9.7 a requirement for the
affected system transmission provider to provide the affected system
study report to the host transmission provider at the same time it
provides the report to the affected system interconnection customer. We
find that this will enhance transparency in the interconnection study
process.
1137. In response to MISO's request for clarification that the
affected system study clock commences only after all necessary data has
been provided, we clarify that, because an affected system
interconnection customer has already submitted all required data to the
host transmission provider, and the host transmission provider has
verified that the data submitted is adequate and has conducted at least
one interconnection study, it is highly unlikely that there will be any
instances of requiring clarification or further data from
interconnection customers. Thus, under the modified affected system
study procedures, the data regarding interconnection requests given to
the affected system transmission provider should be complete, requiring
no delay or requests for further data. Nevertheless, we note that the
affected system interconnection customer is required, under pro forma
LGIP section 9.5, to provide all required technical data when it
delivers the affected system study agreement. As discussed below, the
clock for the affected system transmission provider to complete its
affected system study begins after the receipt of the executed affected
system study agreement and study deposit, which would include the
receipt of all required technical data from the affected system
interconnection customer.
(d) Affected System Queue Position (Pro Forma LGIP Section 9.3)
1138. We adopt, with modification, the NOPR proposal to add section
9.2, now section 9.3, titled ``Affected System Queue Position,'' to the
pro forma LGIP. Specifically, we adopt the first-ready, first-served
concept, as proposed in the NOPR,\2201\ along with the affected
[[Page 61174]]
system relative queue priority proposal. Consequently, the
interconnection requests of affected system interconnection customers
that have executed an affected system study agreement will be higher-
queued than the interconnection requests of those host system
interconnection customers that have not yet received their cluster
study results, and lower-queued than those interconnection customers
that have already received their cluster study results. We also add
clarifying language to pro forma LGIP section 9.3 to explain that,
although queue position is determined based on the date of affected
system study agreement execution, all affected system interconnection
requests studied within the same affected system cluster will be
equally queued.
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\2201\ We note that several commenters support the proposed
first-ready, first-served concept under proposed pro forma LGIP
section 9.2. See Alliant Energy Initial Comments at 7; MISO Initial
Comments at 11-12; NextEra Initial Comments at 33; OMS Initial
Comments at 17.
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1139. The affected system interconnection customer's affected
system queue position is for identification of affected system network
upgrades along with the affected system transmission provider's own
interconnection customers. Specifically, the affected system queue
position determines the order in which the affected system transmission
provider will study the affected system interconnection customers and
its own interconnection customers and thus impacts which network
upgrades may be identified as necessary and assigned to interconnection
customers, whether its own or affected system interconnection
customers.
1140. As an example, if a transmission provider has two cluster
studies of its own interconnection customers--cluster study 1 for which
the transmission provider is conducting the facilities studies and
cluster study 2 for which the transmission provider is conducting the
cluster study--cluster study 1 would be higher-queued than cluster
study 2. If that transmission provider receives notice from a
neighboring transmission provider of interconnection requests that may
impact its transmission system (i.e., affected system interconnection
customers), the transmission provider may decide to study those
affected system interconnection customers to determine if any network
upgrades are required to mitigate constraints caused by those affected
system interconnection customers. Once those affected system
interconnection customers have executed their affected system study
agreements, the transmission provider must assign them an affected
system queue position, which will be higher than any cluster study of
its own interconnection customers that have not received their cluster
study results. In this example, the cluster study 1 interconnection
customers would be higher-queued than the cluster of affected system
interconnection customers because the cluster study 1 interconnection
customers would have already received their cluster study results and
decided to proceed with their interconnection requests, and cluster
study 2 interconnection customers would be lower-queued than the
cluster of affected system interconnection customers because they would
not have received their cluster study results and thus are more likely
to withdraw.
1141. We find that establishing the affected system queue position
based on the execution of the affected system study agreement is
appropriate because, at that point, the affected system interconnection
customer has demonstrated its intent to proceed with its
interconnection request by executing the agreement and providing a
study deposit to the affected system transmission provider as well as
receiving its cluster study report on its host system and deciding to
proceed with its interconnection request. Furthermore, allowing these
affected system interconnection customers to be higher-queued than any
of its own interconnection customers that have not received their
cluster study results is appropriate because those interconnection
customers have not yet received any network upgrade estimates. Thus,
its own interconnection customers have not yet demonstrated their
intention to proceed to the facilities study.
1142. We agree with commenters that establishing queue priority in
an affected system transmission provider's interconnection queue based
on when an interconnection request is received by the host transmission
provider is problematic.\2202\ In part for this reason, we are adopting
the host system's cluster study results and execution of the affected
system study agreement as reference points for queue priority \2203\
because these points occur after the interconnection customer has made
demonstrations to indicate intent to progress through the
interconnection process.
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\2202\ EDF Renewables Initial Comments at 11; MISO Initial
Comments at 11, 87.
\2203\ See NOPR, 179 FERC ] 61,194 at P 189.
---------------------------------------------------------------------------
1143. We disagree with NextEra that the NOPR proposal's affected
system queue priority construct, which we adopt herein, will lead to a
race among interconnection customers to be first or last to sign an
affected system study agreement. NextEra's concern may occur under a
serial affected system study process, but, as explained above, we
require clustering of affected system studies. Studying affected system
interconnection requests in clusters mitigates the risk of a race to
execute affected system study agreements, as affected system
interconnection customers in the same affected system cluster will be
equally queued regardless of when they execute their affected system
study agreement, if it is within the appropriate window for affected
system study agreement execution. We find this to be a just and
reasonable queue priority construct for affected system studies.
1144. We decline to adopt EDF Renewables' suggestion that the
affected system transmission provider be required to establish queue
priority between the host and affected systems based on the
interconnection customer having achieved a certain stage in the host
system's study process, rather than the date the interconnection
customer submits an interconnection request. We clarify that we neither
propose to, nor do we adopt a proposal to, base relative affected
system queue priority on the date an interconnection customer submits
its interconnection request.\2204\
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\2204\ See NOPR, 179 FERC ] 61,194 at P 189 (providing that the
affected system transmission provider would assign the affected
system interconnection customer a queue position in its queue
according to when the affected system interconnection customer
executes an affected system study agreement rather than when the
affected system interconnection customer entered its host
transmission provider's queue).
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1145. We clarify, in response to Idaho Power's request, that the
affected system study process adopted in this final rule is required
for all transmission providers, regardless of preexisting use of the
first-ready, first-served cluster study process.
1146. We clarify, in response to APPA-LPPC, that establishing the
affected system queue priority is for identifying the affected system
network upgrades needed to mitigate constraints on the affected
system.\2205\ This process will proceed in parallel with the host
transmission provider's study process and should not result in delays
to the interconnection customer. As discussed above, we allow
interconnection customers to delay execution of their LGIAs, or request
that the LGIA be filed unexecuted, if they have not received their
affected system study results; however, based on the reforms we adopt
[[Page 61175]]
in this final rule, that should be the exception and not the rule.
Thus, we find that the affected system queue position is merely
intended to ensure that affected system interconnection customers are
assigned the appropriate network upgrade costs according to the
Commission's interconnection pricing policy, and not as an indicator
that interconnection customers become part of two separate
interconnection queues.
---------------------------------------------------------------------------
\2205\ APPA-LPPC Initial Comments at 26.
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1147. With respect to requests for clarification regarding proposed
pro forma LGIP section 9.2 and how the first-ready, first-served queue
priority approach interacts with cluster studies,\2206\ we clarify that
all affected system interconnection customers in the same cluster on
the affected system will have equal queue priority in the affected
system transmission provider's interconnection queue, which is
consistent with how the first-ready, first-served approach interacts
with cluster studies for interconnection customers on the transmission
provider's transmission system when it is acting as a host system. This
means that the affected system interconnection customers within a
cluster have equal queue priority and that queue priority will be
relative to the affected system transmission provider's own
interconnection customers. The affected system transmission provider's
own interconnection customers that already received their cluster study
results when an affected system interconnection customer or cluster of
affected system interconnection customers execute an affected system
study agreement will be higher-queued than that affected system
interconnection customer. Any of the affected system transmission
provider's own interconnection customers that receive their cluster
study results after the affected system interconnection customer or
cluster of affected system interconnection customers execute their
affected system study agreement will be lower-queued than that affected
system interconnection customer or cluster of affected system
interconnection customers. We clarify in response to APPA-LPPC that a
transmission provider will assign the costs of network upgrades
required on its transmission system to interconnection customers in its
host cluster study process and affected system interconnection
customers, also studied in their own cluster, based on their relative
queue priority and in accordance with the proportional impact method as
described in pro forma LGIP section 4.2.3, and as discussed further in
the next section.\2207\
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\2206\ Id.; Idaho Power Initial Comments at 11; NextEra Initial
Comments at 33.
\2207\ APPA-LPPC Initial Comments at 26.
---------------------------------------------------------------------------
1148. With respect to Bonneville's request for clarification, we
clarify that an affected system interconnection customer will lose its
affected system queue position if the affected system interconnection
customer fails to: (1) execute the affected system study agreement or
request it be filed unexecuted; (2) execute the affected system
facilities construction agreement or request it be filed unexecuted;
(3) provide the affected system study deposit; or (4) pay undisputed
affected system study true-up costs in a timely manner.
(e) Affected System Cost Allocation (Pro Forma LGIP Section 9.9)
1149. We also adopt the NOPR proposal in pro forma LGIP section
9.8, now pro forma LGIP section 9.9, titled ``Affected System Cost
Allocation,'' to allocate affected system network upgrade costs using a
proportional impact method, in accordance with pro forma LGIP section
4.2.1(1)(b).
1150. We agree with SEIA that using a proportional impact method
will reduce individual affected system network upgrade costs and reduce
the likelihood of cascading withdrawals, consistent with our discussion
above on the use of the proportional impact method for the allocation
of network upgrade costs in a cluster on the host system.
1151. We disagree with commenters that argue that the Commission
should provide for penalty-free withdrawal from the host system's
interconnection queue if affected system study results increase an
interconnection customer's costs by more than 25% or some other
threshold compared to costs allocated by the host transmission
provider.\2208\ First, we find that the final rule's requirement that
affected system transmission providers use ERIS modeling standard to
conduct affected system studies should reduce the number and total cost
of affected system network upgrades assigned to affected system
interconnection customers, which will reduce instances of ``sticker
shock'' from affected system network upgrades.\2209\ Second, as
discussed above, any interconnection customers in a cluster that are
not waiting for affected system study results must proceed with the
finalization of their LGIAs, pursuant to pro forma LGIP section 11.1.
Thus, we find that it would create sufficient uncertainty to allow an
interconnection customer to withdraw penalty-free when it receives its
affected system study results if there is a 25% increase in costs,
which may occur after other interconnection customers in the same
cluster have finalized their LGIAs. We note that interconnection
customers inherently assume some risk. Accordingly, we decline to
explicitly extend penalty-free withdrawal to include increases in
affected system network upgrade costs beyond a certain threshold.
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\2208\ Invenergy Initial Comments at 43-44; Shell Initial
Comments at 31.
\2209\ See infra section III.B.2.d.iii.
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1152. In response to NV Energy's assertion that use of the
proportional impact method may lead to restudies when a higher-queued
affected system interconnection customer withdraws its interconnection
request, we note that potential outcomes of withdrawal are restudy and
the reallocation of costs, regardless of the cost allocation
methodology used.\2210\ We also note that, as described above,
transmission providers may not need to perform a study if, in their
engineering judgment, the network upgrades assigned to the withdrawing
interconnection customer either are not needed or are easily reassigned
to a remaining interconnection customer. Thus, restudies under the new
interconnection process due to interconnection request withdrawals
should be relatively less frequent than under existing processes.
---------------------------------------------------------------------------
\2210\ NV Energy Initial Comments at 11-12.
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(f) Information Sharing Among Transmission Providers (Pro Forma LGIP
Section 3.6.3)
1153. We decline to adopt proposed section 3.6.3 of the pro forma
LGIP, which would have required a transmission provider to provide data
on a monthly basis, or more frequently as needed, to any affected
system operators regarding the amount and location of proposed
generation in the transmission provider's interconnection queue, as
well as updated information about the transmission provider's
transmission system.\2211\ We agree with commenters' arguments that the
information sharing requirement is duplicative of what is available on
OASIS and recognize that such a requirement may be overly
burdensome.\2212\ The OASIS postings provide transparency regarding the
host transmission provider's interconnection queue information.
Further, transmission providers are required to notify neighboring
transmission
[[Page 61176]]
providers of potential impacts on their systems per section 3.6.1 of
the pro forma LGIP, as described above.
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\2211\ Accordingly, we do not address comments on this section.
\2212\ Bonneville Initial Comments at 19; Dominion Initial
Comments at 38.
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(g) Affected System Study Agreement (Pro Forma LGIP Section 9.4) and
Execution Thereof (Pro Forma LGIP Section 9.5)
1154. With regard to tendering of the affected system study
agreement to the affected system interconnection customer, we modify
proposed pro forma LGIP section 9.3, now pro forma LGIP section 9.4, to
require that the transmission provider provide the affected system
study agreement within 10 business days of sharing the schedule for the
study with the affected system interconnection customer(s), per pro
forma LGIP section 9.2, rather than within five business days, as
proposed. We agree with commenters that five business days is not
enough time to prepare what could be numerous affected system study
agreements in the event a number of interconnection customers in a
large cluster on a neighboring transmission system impact the affected
system transmission provider's transmission system.
1155. Consistent with our decision--discussed above--to not adopt
the proposal to require affected system transmission providers to
convene a scoping meeting with affected system interconnection
customers, we remove references to such a meeting in pro forma LGIP
section 9.4. Accordingly, we modify the NOPR proposal requiring the
affected system operator to provide a non-binding good faith estimate
of the cost and time frame for completing an affected system study from
15 business days after the affected system scoping meeting to 20
business days from the date that the affected system operator responded
in writing to the host transmission provider that it intends to conduct
an affected system study, pursuant to section 3.6.1 of the pro forma
LGIP, and we also move this requirement to section 9.2 of the pro forma
LGIP. The time taken to tender an affected system study agreement will
also be measured from that date. We believe these changes will align
the study timeline to the lack of an affected system scoping meeting.
1156. Accordingly, we modify proposed pro forma LGIP section 9.4 so
that, after the affected system transmission provider responds with its
intent to conduct an affected system study, the affected system
transmission provider has 10 business days to tender an affected system
study agreement from the date of the affected system transmission
provider sharing the schedule for the study. Again, these changes align
the affected system study process timeline with the modification to
remove the affected system scoping meeting.
1157. We further modify proposed pro forma LGIP section 9.4 to
include a true-up of the affected system study deposit and actual cost
of the affected system study. The difference between these amounts must
be detailed in an invoice and paid by or refunded to the affected
system interconnection customer within 30 calendar days of the receipt
of such invoice. An affected system interconnection customer's failure
to pay the difference between these amounts will result in loss of that
affected system interconnection customer's affected system queue
position. We find these modifications necessary to effectuate actual
payment of affected system study costs and to outline the consequences
for failure to do so.
1158. With regard to execution of the affected system study
agreement, we adopt, with modification, the NOPR proposal to add
section 9.5 to the pro forma LGIP regarding the timing of the execution
of the affected system study agreement. As adopted, pro forma LGIP
section 9.5 states that the affected system interconnection customer
has 10 business days from the date of receipt of the affected system
study agreement to execute and deliver it to the affected system
transmission provider. Pro forma LGIP section 9.5 also provides that,
if the affected system interconnection customer does not provide all
required technical data when it delivers the affected system study
agreement, the affected system transmission provider shall notify the
affected system interconnection customer of the deficiency within five
business days of the receipt of the affected system study agreement,
and the affected system interconnection customer has 10 business days
to cure the deficiency after receipt of such notice, provided that the
deficiency does not include failure to deliver the executed affected
system study agreement or deposit.
1159. In the same vein, we modify proposed section 9.4 of the pro
forma LGIP to require the affected system transmission provider to
notify the host transmission provider of the affected system
interconnection customer's breach of its obligations under this
section, should such breach occur. We find that, absent such
notification, the host transmission provider may be unaware of such a
breach.
(h) Scope of Affected System Study (Pro Forma LGIP Section 9.6)
1160. We adopt, with modification, the NOPR proposal in pro forma
LGIP section 9.5, now pro forma LGIP section 9.6, regarding the scope
of the affected system study. The affected system study will consider
the base case as well as all higher-queued generating facilities on the
affected system transmission provider's transmission system and will
consist of a power flow, stability, and short circuit analysis. The
affected system study will provide a list of affected system network
upgrades that are required because of the affected system
interconnection customer's proposed interconnection, a non-binding good
faith estimate of cost responsibility, and a non-binding good faith
estimated time to construct. We find that these requirements will
ensure that the affected system study will identify affected system
network upgrades that are necessary to mitigate the impacts of the
affected system interconnection customer's proposed generating facility
on the affected system while providing the affected system
interconnection customer with estimated costs and a timeline to
construct necessary network upgrades.
1161. In response to APPA-LPPC, Duke Southeast Utilities, Enel, and
Pattern Energy, we modify the NOPR proposal and clarify that pro forma
LGIP section 9.6 does not preclude affected system transmission
providers from conducting facilities studies or other relevant studies
when conducting affected system studies. The affected system study may
consist of a system impact study, a facilities study, or a combination
of a system impact and facilities study.
1162. To address commenters' criticism that the NOPR proposal was
ambiguous with respect to whether a facilities study is specifically
contemplated as part of the affected system study process,\2213\ we
clarify that it is. We agree with commenters that an affected system
facilities study could provide more refined cost estimates and
construction timelines to better apprise the affected system
interconnection customer of expected affected system network upgrade
costs and timing, thereby improving interconnection process
efficiency.\2214\ We note that the study requirements for the affected
system study under pro forma LGIP section 9.6 that we proposed in the
[[Page 61177]]
NOPR, and adopt in this final rule, require the affected system
transmission provider to produce the same information that a facilities
study would produce; specifically, the affected system transmission
provider must provide a list of facilities that are required as a
result of an affected system interconnection customer's proposed
interconnection, a non-binding good faith estimate of cost
responsibility, and a non-binding good faith estimated time to
construct. Nevertheless, for further clarity, we modify proposed pro
forma LGIP section 9.6 to indicate that the affected system study may
consist of a system impact study, a facilities study, or some
combination thereof. We note that we have modified the proposal to
provide more time to the transmission provider to conduct such studies
that they deem necessary, as discussed above.
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\2213\ APPA-LPPC Initial Comments at 26; Duke Southeast
Utilities Initial Comments at 15.
\2214\ Enel Initial Comments at 65; LADWP Initial Comments at 4;
NV Energy Initial Comments at 11; Pattern Energy Initial Comments at
24-25.
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1163. In response to Duke Southeast Utilities' request for
clarification that affected system transmission providers conduct a
series of two affected system studies, we reiterate that nothing
precludes an affected system transmission provider from conducting an
affected system facilities study following an affected system impact
study, just as nothing precludes affected system transmission providers
from conducting a combined version of such studies, and we believe we
have provided adequate time for transmission providers to do so.
1164. We find out of scope Shell's request for inclusion of further
information on local transmission planning from neighboring public
utility transmission providers in the affected system study results.
(i) Meeting With Transmission Provider (Pro Forma LGIP Section 9.8) and
Affected System Facilities Construction Agreement (Pro Forma LGIP
Section 9.10)
1165. We adopt proposed section 9.9, now section 9.10, of the pro
forma LGIP, with modifications. Specifically, we adopt the requirement
for an affected system transmission provider to tender to the affected
system interconnection customer an affected system facilities
construction agreement within 30 calendar days of providing the
affected system study report. We modify this section to require the
affected system transmission provider to provide 10 business days--
rather than five business days, as proposed--after receipt of the
affected system facilities construction agreement for the affected
system interconnection customer to execute the agreement or have the
affected system transmission provider file it unexecuted with the
Commission. While no comments were filed in opposition to the five
business days to notify the affected system transmission provider of
the affected system interconnection customer's intent to execute the
agreement or request it to be filed unexecuted, as proposed in the
NOPR, we believe that 10 business days gives the affected system
interconnection customer a more appropriate length of time to review
the facilities construction agreement and the timelines and costs
contained therein to make a reasoned decision as to whether to execute
the agreement or request that it be filed unexecuted with the
Commission.
1166. Further, we find that it is appropriate to allow the
interconnection customer to request that the affected system facilities
construction agreement be filed unexecuted at the Commission. Similar
to an interconnection customer's ability pursuant to pro forma LGIP
section 11.3 to request the unexecuted filing of its LGIA, the ability
to request the affected system facilities construction agreement be
filed unexecuted allows an affected system interconnection customer to
dispute provisions of the affected system facilities construction
agreement before the Commission.\2215\ Because (1) the existing pro
forma LGIP section 11.3 permits the interconnection customer to request
the transmission provider to file the LGIA unexecuted, (2) we base the
affected system facilities construction agreement on the pro forma
LGIA, and (3) the affected system facilities construction agreement is
like a service agreement,\2216\ it is appropriate to include a similar
provision. We further find that an affected system interconnection
customer may be in a disadvantageous position to negotiate the terms of
an affected system facilities construction agreement, as this agreement
is between the affected system interconnection customer and a
transmission provider with which it does not directly connect.
Accordingly, to encourage good faith and fair dealings between the
parties and to avoid the addition of potentially discriminatory terms
or conditions to an affected system facilities construction agreement,
we allow an affected system interconnection customer to request that an
affected system facilities construction agreement be filed unexecuted
before the Commission.
---------------------------------------------------------------------------
\2215\ See Order No. 2003, 104 FERC ] 61,103 at P 233 (stating
that, if agreement negotiations are at an impasse, the
interconnection customer could either request termination of
negotiations and request submission of the unexecuted agreement to
the Commission or initiate dispute resolution procedures).
\2216\ See Revised Publ. Util. Filing Requirements, Order No.
2001, 99 FERC ] 61,107, at PP 196, 200, reh'g denied, Order No.
2001-A, 100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100 FERC
] 61,342, order directing filing, Order No. 2001-C, 101 FERC ]
61,314 (2002), order directing filing, Order No. 2001-D, 102 FERC ]
61,334, order refining filing requirements, Order No. 2001-E, 105
FERC ] 61,352 (2003), order on clarification, Order No. 2001-F, 106
FERC ] 61,060 (2004), order revising filing requirements, Order No.
2001-G, 120 FERC ] 61,270, order on reh'g and clarification, Order
No. 2001-H, 121 FERC ] 61,289 (2007), order revising filing
requirements, Order No. 2001-I, 125 FERC ] 61,103 (2008); see also
Order No. 2003, 104 FERC ] 61,103 at PP 913-915.
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1167. We disagree with commenters' assertions that 30 calendar days
may be an inadequate length of time to tender an affected system
facilities construction agreement or that considerable time is needed
to draft such an agreement.\2217\ This is the same period of time by
which the transmission provider must tender a draft LGIA to the
interconnection customer, the timeline of which is set forth in the
existing pro forma LGIP.\2218\ We believe these timelines should be
consistent because these agreements include similar provisions and
similar requirements and the record does not persuade us otherwise.
---------------------------------------------------------------------------
\2217\ See Duke Southeast Utilities Initial Comments at 15-16;
Idaho Power Initial Comments at 11; MISO Initial Comments at 91-92;
WAPA Initial Comments at 13.
\2218\ Pro forma LGIP section 11.1.
---------------------------------------------------------------------------
1168. We disagree with Idaho Power's suggestion that the affected
system transmission provider should tender an affected system
facilities construction agreement within 60 calendar days of the
interconnection customer executing a facilities study agreement with
the host transmission provider because, as the host system and affected
system study processes are separate, though overlapping and
interrelated, it is more administratively feasible to tie affected
system study process deadlines to affected system study process events.
In response to Idaho Power's suggestion that the affected system
transmission provider should tender an affected system facilities
construction agreement within 30 calendar days of providing the
affected system study results to the affected system interconnection
customer if the affected system study is performed during the
facilities study on the host transmission provider's system,\2219\ we
note that, as proposed in the NOPR, the affected system facilities
construction agreement tender deadline is within 30 calendar days of
the tendering of the affected system study report without any
additional caveats or conditions. This tender timeline is,
[[Page 61178]]
however, not directly linked to the host transmission provider's study
process.
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\2219\ Idaho Power Initial Comments at 11.
---------------------------------------------------------------------------
1169. We also adopt the NOPR proposal to add section 9.7, now
section 9.8, to the pro forma LGIP. Section 9.8 of the pro forma LGIP,
titled ``Meeting with Transmission Provider,'' requires the affected
system transmission provider and the affected system interconnection
customer to meet within 10 business days of the affected system
transmission provider tendering the affected system study report to the
affected system interconnection customer. We find that such a meeting
between the affected system transmission provider and affected system
interconnection customer will facilitate transparency and meaningful
communication in the affected system study process. We note that WAPA
stated that a meeting after the affected system study report is
tendered would be more beneficial than an affected system scoping
meeting. We agree with WAPA and find that no changes to this section
are necessary.
(j) Restudy Period (Pro Forma LGIP Section 9.11)
1170. We adopt the NOPR proposal in section 9.10, now section 9.11,
of the pro forma LGIP to include a maximum 60-calendar day restudy
period for any affected system restudies. We find that 60 calendar days
are adequate to complete an affected system restudy. We disagree that
affected system restudies are as complex as host system restudies, as
affected system studies will likely involve fewer interconnection
requests than cluster studies on the host system. Additionally, as
discussed further below, we find that standardization of affected
system study assumptions through ERIS modeling criteria will further
simplify both affected system studies and restudies. Thus, we find it
just and reasonable to adopt a 60-calendar day affected system restudy
period.
1171. In addition to the 60-calendar day restudy period, we adopt a
30-calendar day notification requirement for the affected system
transmission provider to notify the affected system interconnection
customer of the need for affected system restudy upon discovery of such
need in pro forma LGIP section 9.11. We find such a notification
requirement to be consistent with restudy notification on the host
system, and we find such notification necessary to continue a timely
affected system study process. Accordingly, we find such a notification
period to be just and reasonable.
(k) Coordination Between Host Transmission Provider and Affected System
Transmission Provider
1172. In response to multiple commenters' assertions that, for
efficiency reasons, host transmission providers should be required to
coordinate affected system study activities with affected system
transmission providers rather than individual interconnection
customers,\2220\ or that flexibility should be afforded in terms of the
parties to the affected system study agreement and the affected system
facilities construction agreement,\2221\ the Commission is not
persuaded that any potential efficiencies of such coordination outweigh
the burdens that may be placed on host transmission providers, and we
decline to require it in this final rule. We note that, in many cases,
the affected system operator may be a non-public utility transmission
provider, which would limit the usefulness of such a requirement.
However, we encourage any such voluntary coordination between
transmission providers who share transmission system seams and whose
interconnection customers frequently impact each other's systems. We
also note that, as NextEra suggests, such transmission providers may
file seams agreements under FPA section 205.\2222\
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\2220\ Enel Initial Comments at 60-61; Shell Initial Comments at
30.
\2221\ PPL Initial Comments at 20.
\2222\ NextEra Reply Comments at 5.
---------------------------------------------------------------------------
1173. In response to Indicated PJM TOs' argument that affected
system studies should be integrated into the cluster study process, we
do not have a record to support such a requirement in the final rule.
Integrating affected system interconnection customers into a cluster
that is already proceeding through the study process could meaningfully
change network upgrade cost estimates which could, in turn, create new
interconnection request withdrawals, leading to restudies and delays.
Maintaining the clusters as-is and placing the affected system
interconnection customers in a lower queue position than any
interconnection customers that have received cost estimates will ensure
this situation does not happen.
1174. In response to APS' request for clarification on how the
proposed affected system study process correlates to the host system's
studies and aligns with the host system's requirements,\2223\ we
explain that the affected system study is predicated on the completion
of a cluster study in the host transmission provider's interconnection
queue. Relative queue position for the affected system study is also
determined based on an interconnection customer's completion of the
host system cluster study. While the host transmission provider will
likely complete its facilities study prior to an affected system
transmission provider's completion of an affected system study, we add
a requirement for host transmission providers with interconnection
customers that have not yet received their affected system study
results to delay the LGIA execution (or unexecuted filing) deadline for
those interconnection customers. An interconnection customer's failure
to satisfy its obligations under the pro forma LGIP, including
coordination with the affected system transmission provider, where
applicable, will result in the loss of the interconnection customer's
affected system queue position.
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\2223\ APS Initial Comments at 19-20.
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(l) Non-Public Utility Requests
1175. We reject requests to impose firm deadlines and requirements
that prevent non-public utility transmission providers from interfering
with jurisdictional interconnection agreements because we do not have
the jurisdiction to do so.\2224\
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\2224\ Invenergy Initial Comments at 43; Invenergy Reply
Comments at 9; Interwest Reply Comments at 18.
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1176. In response to concerns regarding a transmission provider's
liability for delays or inaction by non-public utility transmission
providers,\2225\ we clarify that transmission providers will not face
consequences for the inaction of a non-public utility transmission
provider, as long as the transmission providers fulfill their
obligations as outlined in their LGIPs. For example, under the pro
forma LGIP affected system process, a transmission provider would
satisfy its obligation to a non-public utility affected system operator
by timely notifying it of an affected system impact per pro forma LGIP
section 3.6.1.
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\2225\ EEI Initial Comments at 19; NextEra Initial Comments at
34; Pacific Northwest Utilities Initial Comments at 15-16; Xcel
Initial Comments at 39.
---------------------------------------------------------------------------
(m) Miscellaneous
1177. We do not address the comments of North Carolina Commission
and Staff and EDF Renewables that interregional transmission planning
is a way to address affected system impacts because these comments are
beyond the scope of this proceeding, which is limited to generator
interconnection.
[[Page 61179]]
1178. In response to Eversource's and NYTOs' requests for
clarification that affected system study process reforms would not
apply to intra-RTO/ISO system upgrades or would not apply to
neighboring transmission owners within a single RTO/ISO,\2226\ we
clarify that, in RTO/ISO regions, the RTO/ISO serves as the
transmission provider for affected system study purposes, and the RTO/
ISO footprint as the affected system, and thus intra-RTO/ISO
considerations do not apply in this context and are beyond the scope of
this final rule.
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\2226\ See also AEP Initial Comments at 32-33 (highlighting four
different types of affected system scenarios and contending that the
Commission conflates them).
---------------------------------------------------------------------------
1179. We disagree with Invenergy's argument that affected system
study process reforms should apply to all pending interconnection
requests and active studies.\2227\ While we adopt a transition approach
for serial and cluster study processes in the final rule, as explained
above, we did not propose a similar transition approach with respect to
affected system studies in the NOPR. Without consistency between
transition processes as they pertain to neighboring transmission
providers and implicate the affected system study process, it would be
practically infeasible to apply the affected system study process
reforms to all pending interconnection requests and active studies as
Invenergy suggests. Accordingly, we decline to apply the affected
system study process reforms adopted in this final rule to any pending
interconnection requests and active studies.
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\2227\ Invenergy Initial Comments at 41.
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1180. In response to CREA and NewSun's request for clarification
that a QF interconnection customer has the option to opt into use of
the Commission's interconnection procedures in cases where the
interconnection requires studies or network upgrades on affected
systems,\2228\ we decline to implement a jurisdictional toggle option
for an interconnection customer. Longstanding Commission precedent
indicates when a QF's interconnection is subject to state jurisdiction
or Commission jurisdiction.\2229\ Nothing in this final rule is
intended to revise the Commission's approach under PURPA. Requiring
affected system studies does not change the sale of a QF's output,
which is the foundation of the Commission's interconnection analysis
under PURPA.\2230\ To the extent that affected system studies are
required due to a QF interconnection, the Commission will address such
filings upon their receipt.
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\2228\ CREA and NewSun Initial Comments at 86-88.
\2229\ Order No. 2003, 104 FERC ] 61,103 at PP 813-814 (finding
that, when an electric utility purchases a QF's total output, the
state exercises jurisdiction over the interconnection and allocation
of interconnection costs, while the presence of any output sold to a
third party yields Commission jurisdiction); Fla. Power & Light Co.,
133 FERC ] 61,121, at PP 19-23 (2010). See also 18 CFR 202.303,
202.306 (2022); Participation of Distributed Energy Res.
Aggregations in Mkts. Operated by Reg'l Transmission Orgs. & Indep.
Sys. Operators, Order No. 2222, 85 FR 67094 (Oct. 21, 2020), 172
FERC ] 61,247, at P 98 (2020), corrected, 85 FR 68540 (Oct. 29,
2020) (citing Order No. 2003, 104 FERC ] 61,103 at PP 813-815; Order
No. 2006, 111 FERC ] 61,220 at PP 516-518; Order No. 845, 163 FERC ]
61,043) (stating that nothing in the final rule revises the
Commission's jurisdictional approach to interconnections of QFs that
participate in distributed energy resource aggregations).
\2230\ Order No. 2003, 104 FERC ] 61,103 at PP 813-814.
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c. Affected System Pro Forma Agreements
i. Need for Reform
(a) NOPR Proposal
1181. In the NOPR, the Commission expressed concern that the lack
of pro forma agreements for affected system studies and the
construction of network upgrades on affected systems was hindering the
efficiency of the generator interconnection process through increased
litigation over such agreements and allowed for potential unduly
discriminatory behavior against interconnection customers whose
interconnection requests necessitate affected system network
upgrades.\2231\ Noting a recent increase in affected system-related
disputes, the Commission preliminarily found it unjust and unreasonable
to leave affected system agreements wholly up to individual
negotiations and proposed standardized pro forma affected system
agreements that minimize the likelihood for such disputes by (1)
stipulating how to study the impact of interconnecting generating
facilities on an affected system to identify network upgrades needed to
accommodate the interconnection request and (2) standardizing the
affected system facilities construction agreement to set the terms and
conditions for the construction of those network upgrades.\2232\
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\2231\ NOPR, 179 FERC ] 61,194 at P 194.
\2232\ Id. PP 194-195.
---------------------------------------------------------------------------
(b) Comments
1182. Many commenters generally support the proposal to develop
standardized pro forma affected system agreements.\2233\ Commenters
state that standardization and better synchronization of timelines and
processes for affected system studies between host and affected system
transmission providers will improve the efficiency of the
interconnection process and reduce opportunities for undue
discrimination.\2234\ ELCON suggests that standardization of affected
system study agreements, modeling, and assumptions furthers certainty
and accountability, resulting in a more transparent, efficient, and
cost-effective interconnection process.\2235\
---------------------------------------------------------------------------
\2233\ Alliant Energy Initial Comments at 7; APPA-LPPC Initial
Comments at 23; Clean Energy Associations Initial Comments at 48;
ELCON Initial Comments at 8; Interwest Reply Comments at 17;
Invenergy Initial Comments at 45; ISO-NE Initial Comments at 37-38;
NARUC Initial Comments at 23-24; NYISO Initial Comments at 44-45;
Pattern Energy Initial Comments at 26; Pine Gate Initial Comments at
42; SEIA Initial Comments at 34.
\2234\ Consumers Energy Initial Comments at 8; Invenergy Initial
Comments at 45; ISO-NE Initial Comments at 37-38.
\2235\ ELCON Initial Comments at 8.
---------------------------------------------------------------------------
(c) Commission Determination
1183. We find that the lack of affected system pro forma study and
facilities construction agreements hinders the efficiency of the
generator interconnection process through increased litigation over
such agreements and allows for potential unduly discriminatory behavior
against interconnection customers whose interconnection requests
necessitate affected system network upgrades. Our establishment of pro
forma affected system agreements is supported by the record.\2236\ We
agree with commenters that this standardization of timelines and
processes will improve the efficiency of the interconnection process
and reduce opportunities for undue discrimination.\2237\ For example,
in establishing such standardized agreements, affected system
transmission providers and affected system interconnection customers
will no longer need to negotiate individual non-standard agreements.
Also, in requiring affected system transmission providers to adhere to
a set of pro forma procedures in their tariffs common to all
jurisdictional transmission providers, we minimize the opportunities
for undue discrimination.\2238\ The
[[Page 61180]]
standardization of affected system agreements also furthers certainty
and accountability, resulting in a more transparent, efficient, and
cost-effective interconnection process by ensuring affected system
interconnection customers know the standard scope and terms of
agreements for the affected system interconnection process prior to
entering the interconnection queue.\2239\
---------------------------------------------------------------------------
\2236\ See id.; Alliant Energy Initial Comments at 7; APPA-LPPC
Initial Comments at 23; Clean Energy Associations Initial Comments
at 48; Invenergy Initial Comments at 45; ISO-NE Initial Comments at
37-38; NARUC Initial Comments at 23-24; NYISO Initial Comments at
44-45; Pattern Energy Initial Comments at 26; Pine Gate Initial
Comments at 42; SEIA Initial Comments at 34.
\2237\ See Consumers Energy Initial Comments at 8; Invenergy
Initial Comments at 45; ISO-NE Initial Comments at 37-38.
\2238\ See, e.g., Order No. 2003, 104 FERC ] 61,103 at P 11
(explaining that Commission precedent dating back to Order No. 888
establishes a need for standard procedures and agreements, in part
to minimize opportunities for undue discrimination).
\2239\ ELCON Initial Comments at 8.
---------------------------------------------------------------------------
ii. Pro Forma Affected System Study Agreement
(a) NOPR Proposal
1184. In the NOPR, the Commission proposed to establish a pro forma
affected system study agreement to improve the efficiency and
transparency of the interconnection customer's interaction with the
affected system transmission provider.\2240\ The Commission proposed to
model the pro forma affected system study agreement on the form of the
existing pro forma system impact study agreement, with necessary minor
revisions to the party names.\2241\ Specifically, the affected system
interconnection customer and affected system transmission provider
would be parties to the agreement.
---------------------------------------------------------------------------
\2240\ NOPR, 179 FERC ] 61,194 at P 197.
\2241\ Id. P 198.
---------------------------------------------------------------------------
1185. In articles 1, 2, 3, and 4, respectively, of the proposed pro
forma affected system study agreement, the agreement specifies (1) the
capitalization of defined terms in the pro forma LGIP, (2) that
coordination with the host transmission provider shall occur pursuant
to pro forma LGIP section 9, (3) that study assumptions shall be set
forth in attachment A to the agreement, and (4) that studies shall be
based on technical information provided by the affected system
interconnection customer. In article 5, with regard to the information
the affected system transmission provider will provide to the affected
system interconnection customer in a study report upon completion of
the affected system study, the Commission proposed to require the
following: identification of any circuit breaker short circuit
capability limits exceeded as a result of the interconnection;
identification of any thermal overload or voltage limit violations
resulting from the interconnection; identification of any instability
or inadequately damped response to system disturbances resulting from
the interconnection; a non-binding, good faith estimate of the cost of
facilities on the affected system required to accommodate the
interconnection of the affected system interconnection customer's
project to the host transmission system; and a description of how such
facilities will address the identified short circuit, instability, and
power flow issues identified in the affected system study.\2242\ The
Commission sought comment on whether the information required for the
study report would provide adequate information to the affected system
interconnection customer to understand the results of the affected
system study. Finally, in articles 6 and 7, the Commission specified
the provision of an affected system study deposit and that standard
miscellaneous terms would be used consistent with industry best
practice and with the pro forma LGIP and pro forma LGIA.
---------------------------------------------------------------------------
\2242\ Id. P 199.
---------------------------------------------------------------------------
(b) Comments
1186. Some commenters generally support the NOPR proposal to
develop a pro forma affected system study agreement.\2243\ Others
generally support the establishment of a pro forma affected system
study agreement but suggest general changes to the approach proposed in
the NOPR. For example, MISO states that the requirement to execute an
agreement with each affected system interconnection customer would
create a significant amount of work for transmission providers that is
likely to divert resources from performing studies and coordinating
with other transmission providers without any greater benefit than
provided by existing joint operating agreements and other seams
agreements with neighboring systems.\2244\ SPP adds that requiring
individualized invoicing for all affected system study requests from
another transmission provider's cluster study would present a
significant administrative burden for both transmission providers and
interconnection customers, which would be required to deal with
multiple transmission providers, instead of just the host transmission
provider.\2245\ SPP notes that, in its joint operating agreement with
MISO, the transmission providers coordinate affected system studies
following each transmission provider's system impact studies on their
own systems, and rather than invoicing each interconnection customer
individually, the transmission providers invoice each other for study
costs, which allows the host transmission provider to use existing
study deposits when available, and otherwise collect from its
interconnection customers as needed.\2246\
---------------------------------------------------------------------------
\2243\ Ameren Initial Comments at 23; Duke Southeast Utilities
Initial Comments at 18; North Carolina Commission and Staff Initial
Comments at 24; U.S. Chamber of Commerce Initial Comments at 10-11.
\2244\ MISO Initial Comments at 96.
\2245\ SPP Initial Comments at 19.
\2246\ Id. at 18-19.
---------------------------------------------------------------------------
1187. Other commenters suggest specific changes to the language
proposed in the NOPR. For instance, Tri-State proposes adding language
to article 9.4 of the pro forma LGIP specifying a protocol if
deficiencies are not cured, such as, ``shall be deemed withdrawn
pursuant to Section 3.7 of this LGIP.'' \2247\ PPL argues that the pro
forma affected system study agreement should: (1) have article 7
replaced entirely with actual contractual terms; (2) contain a clear
requirement for affected system interconnection customers to provide
data in a timely manner; (3) include data ownership and confidentiality
provisions; and (4) address restudies.\2248\
---------------------------------------------------------------------------
\2247\ Tri-State Initial Comments at 31-32.
\2248\ PPL Initial Comments at 20.
---------------------------------------------------------------------------
1188. Additionally, Tri-State includes an appendix containing a
redline version of the pro forma affected system study agreement that
specifies its requested revisions to the agreement. Of note, Tri-State
proposes changes to article 6, which would require the affected system
transmission provider to specify the affected system study deposit
value.\2249\
---------------------------------------------------------------------------
\2249\ Tri-State Initial Comments, app. B, at 122-124.
---------------------------------------------------------------------------
1189. In response to whether the information required in the
affected system study report would provide adequate information to the
affected system interconnection customer to understand the results of
the affected system study, Xcel states that the proposed information is
adequate.\2250\ Duke Southeast Utilities support the information
required by article 5 of the proposed agreement but suggest that any
other identified impacts outside of the prescribed information should
also be included.\2251\ LADWP believes that the study report should
also include whether modifications to remedial action schemes or other
special protection systems may be required.\2252\
---------------------------------------------------------------------------
\2250\ Xcel Initial Comments at 39.
\2251\ Duke Southeast Utilities Initial Comments at 18.
\2252\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------
1190. Enel seeks clarification on whether the affected system study
scope must include all of ``a short circuit analysis, thermal overload
or voltage limit identification, and stability analysis, and a power
flow analysis,'' as proposed in pro forma LGIP section 9.5,
[[Page 61181]]
and requests that transmission providers be allowed to waive portions
of the study scope if deemed unnecessary.\2253\
---------------------------------------------------------------------------
\2253\ Enel Initial Comments at 65.
---------------------------------------------------------------------------
1191. Several entities ask the Commission to allow regional
variations to avoid conflict with existing affected system coordination
processes.\2254\
---------------------------------------------------------------------------
\2254\ Ameren Initial Comments at 23; MISO Initial Comments at
95; SPP Initial Comments at 18-19.
---------------------------------------------------------------------------
(c) Commission Determination
1192. We adopt, with modifications, the proposed pro forma affected
system study agreement set forth in Appendix 9 of the pro forma
LGIP.\2255\ As discussed below, we make two modifications. First,
consistent with comments,\2256\ we establish a multiparty pro forma
affected system study agreement set forth in Appendix 10 of the pro
forma LGIP. Second, we modify article 6 of the proposed pro forma
affected system study agreement to make the language therein consistent
with similar language elsewhere in the pro forma LGIP.\2257\
---------------------------------------------------------------------------
\2255\ NOPR, 179 FERC ] 61,194 at P 197.
\2256\ MISO Initial Comments at 96; SPP Initial Comments at 18-
19.
\2257\ We also make minor consistency edits to article 5 of the
proposed pro forma affected system study agreement, to conform the
pro forma affected system study agreement with pro forma LGIP
section 9.6.
---------------------------------------------------------------------------
1193. Starting with the multiparty pro forma affected system study
agreement, as described above, we require affected system transmission
providers to study affected system interconnection requests in
clusters. To facilitate this change, we modify the NOPR proposal and
establish a pro forma multiparty affected system study agreement that
closely tracks the proposed two-party agreement. Such a pro forma
multiparty agreement will allow affected system transmission providers
to enter into the same affected system study agreement with each of the
affected system interconnection customers that it must study in a
cluster. We find that a pro forma multiparty affected system study
agreement will facilitate interactions with the affected system
transmission provider, making them more efficient and transparent. We
agree with SPP and MISO that a requirement for an affected system
transmission provider to sign affected system study agreements with
each affected system interconnection customer would be
burdensome.\2258\ In creating a pro forma multiparty affected system
study agreement, we reduce the administrative burden on transmission
providers that no longer need to manage several individual affected
system study agreements.
---------------------------------------------------------------------------
\2258\ MISO Initial Comments at 96; SPP Initial Comments at 18-
19.
---------------------------------------------------------------------------
1194. In response to SPP and MISO's suggestion to make the parties
to the pro forma affected system study agreement the affected system
transmission provider and the host transmission provider, we decline
this request. We believe that the interconnection customer, as the one
responsible for providing necessary information about the proposed
generating facility as well as funding the affected system study, is
the appropriate counterparty to the affected system study agreement. We
note, however, that any transmission providers may propose alternative
arrangements through joint operating agreements or otherwise pursuant
to FPA section 205.
1195. In response to comments from Tri-State and PPL's request
regarding affected system interconnection customers that fail to
provide required information,\2259\ we find that sufficient
requirements for data sharing exist in both the current and newly
adopted pro forma LGIP requirements. Specifically, as discussed above
and consistent with comments from Tri-State, we modify pro forma LGIP
section 9.5 to explicitly state that any affected system
interconnection customer failing to submit required information and
failing to cure that deficiency shall lose its affected system queue
position. We also add to pro forma LGIP section 9.5 a requirement that
the affected system transmission provider notify the host transmission
provider in a timely manner of such failure by the affected system
interconnection customer.
---------------------------------------------------------------------------
\2259\ PPL Initial Comments at 20; Tri-State Initial Comments at
18-19.
---------------------------------------------------------------------------
1196. In response to Tri-State's requested revisions to article 6
of the pro forma affected system study agreement, we modify the pro
forma affected system study agreement to add additional language to
explicitly require affected system interconnection customers to provide
a study deposit. The deposit will provide for the cost of the affected
system interconnection study. Moreover, we find that such revisions
will align the pro forma affected system study agreement with Appendix
2 (cluster study agreement), Appendix 3 (interconnection facilities
study agreement), and Appendix 4 (optional interconnection study
agreement) of the pro forma LGIP.
1197. In response to PPL's request that article 7, regarding
standard miscellaneous terms, should be replaced with actual
contractual terms, we decline to adopt PPL's proposed revisions. We
adopt article 7 of the pro forma affected system study agreement, with
modification to eliminate the reference to the LGIA. We note that this
article 7 is consistent with the existing pro forma interconnection
system impact study agreement (which the Commission is replacing with
new cluster study-based agreements adopted in this final rule),
interconnection facilities study agreement, and optional
interconnection study agreement, which also provide for standard
miscellaneous terms. In response to PPL's requests that the pro forma
affected system study agreement should address data ownership and
confidentiality requirements as well as restudies, we find such
revisions to the proposed pro forma affected system study agreement
unnecessary, as they would be duplicative of existing pro forma LGIP
provisions regarding confidentiality (section 13.1) and restudies
(former section 6.4, now contained in sections 7.5, 8.5, and 9.10).
Regarding the removal of the reference to the LGIA, we find that the
removal is appropriate as the parties to an interconnection customer's
LGIA would not be the same parties to an affected system study
agreement.
1198. In response to comments on the scope of the pro forma
affected system study, we agree with Xcel that the scope of the
affected system study is adequate.\2260\ Consequently, we decline to
modify the scope of the affected system study contained in article 5 of
the proposed pro forma affected system study agreement. We note that
the scope of the affected system studies identified in article 5 is
consistent with the scope of host system interconnection studies.\2261\
In response to comments from Duke Southeast Utilities that entities
should be able to include other, identified impacts in the affected
system study report, we clarify that the scope of affected system
studies must be consistent with the scope listed in article 5 of the
pro forma affected system study agreement. Affording affected system
transmission providers flexibility to expand the scope of affected
system studies on an ad hoc or individual basis creates the potential
for undue discrimination and a barrier to entry. With respect to
LADWP's request to include impacts to remedial action schemes and other
special protection systems within the scope of the affected system
studies,\2262\ we clarify that such impacts are already contemplated in
[[Page 61182]]
article 5 of the pro forma affected system study agreement.
---------------------------------------------------------------------------
\2260\ Xcel Initial Comments at 39.
\2261\ Pro forma LGIP, app. 2, art. 5; app. 3, art. 4.
\2262\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------
iii. Pro Forma Affected System Facilities Construction Agreement
(a) NOPR Proposal
1199. In the NOPR, the Commission proposed to revise the pro forma
LGIP to add a pro forma affected system facilities construction
agreement.\2263\ The proposed pro forma affected system facilities
construction agreement includes provisions on the following: terms of
the agreement; construction of network upgrades; taxes; force majeure;
information reporting; security, billing, and payments; assignment;
indemnity; breach, cure, and default; termination; contractors;
confidentiality; information access and audit rights; dispute
resolution; and notices.\2264\ Proposed Appendix A to the agreement
provides for details on identified network upgrades, cost estimates and
responsibility, the construction schedule for network upgrades, and a
payment schedule; proposed Appendix B addresses notification of
completed construction; and proposed Appendix C provides for a
transmission provider site map, a site plan, a plan and profile for
network upgrades, and the estimated cost of the network upgrades.
---------------------------------------------------------------------------
\2263\ NOPR, 179 FERC ] 61,194 at P 200.
\2264\ Id. P 201.
---------------------------------------------------------------------------
1200. The Commission proposed that the pro forma affected system
facilities construction agreement would be entered into by the affected
system transmission provider and the affected system interconnection
customer.\2265\ Under the NOPR proposal, the affected system
transmission provider would be responsible for the design, procurement,
construction, and installation of all network upgrades identified in
Appendix A using reasonable efforts to complete construction consistent
with the schedule identified in Appendix A. The affected system
interconnection customer would initially fund the cost of any assigned
network upgrades and be reimbursed by the affected system transmission
provider.\2266\ Rather, the Commission proposed to require that,
consistent with Order No. 2003, the affected system interconnection
customer must enter into an agreement with the affected system
transmission provider that must specify the terms governing payments to
be made by the affected system interconnection customer as well as
payment of refunds by the affected system transmission provider for the
full cost of network upgrades, plus interest.\2267\
---------------------------------------------------------------------------
\2265\ Id. P 202.
\2266\ Order No. 2003, 104 FERC ] 61,103 at P 738.
\2267\ Id. P 739.
---------------------------------------------------------------------------
1201. The Commission clarified that the term to be mutually agreed
upon for payment of refunds to affected system interconnection customer
funded network upgrades is not to exceed 20 years.\2268\ This term
mirrors the repayment term in the pro forma LGIA but allows for
flexibility for the parties to come to another arrangement if they
prefer. Under the NOPR proposal, within six months of completion of
construction of any required network upgrades, the affected system
transmission provider would invoice the affected system interconnection
customer for the final construction costs, including a true-up of
estimated and actual costs. The pro forma affected system facilities
construction agreement would terminate upon the affected system
transmission provider's final repayment to the affected system
interconnection customer. Alternatively, the affected system
interconnection customer could also terminate the affected system
facilities construction agreement with 60 calendar days' written notice
to the affected system transmission provider.
---------------------------------------------------------------------------
\2268\ Id.; see also Order No. 2003-B, 109 FERC ] 61,287 at PP
32-36 (extending the required repayment period from five years to 20
years).
---------------------------------------------------------------------------
1202. The Commission sought comment on the network upgrade funding
and repayment provisions in the proposed pro forma affected system
facilities construction agreement, specifically whether the repayment
time frame and the similarity of the proposal to the repayment terms in
the pro forma LGIA were appropriate.\2269\ The Commission also sought
comment on whether any articles or provisions should be added to the
proposed pro forma affected system facilities construction agreement or
whether the proposed provisions were sufficient.\2270\
---------------------------------------------------------------------------
\2269\ NOPR, 179 FERC ] 61,194 at P 203.
\2270\ Id. P 204.
---------------------------------------------------------------------------
(b) Comments
1203. Some commenters generally support the proposed pro forma
affected system facilities construction agreement because it will offer
uniformity across the country and increase administrative
efficiency.\2271\ Others argue that the agreement should be structured
as either an individual network upgrade agreement or a multiparty
network upgrade agreement.\2272\
---------------------------------------------------------------------------
\2271\ Ameren Initial Comments at 23; Duke Southeast Utilities
Initial Comments at 18; SPP Initial Comments at 19-20.
\2272\ PPL Initial Comments at 20; SPP Initial Comments at 20.
---------------------------------------------------------------------------
1204. Some commenters request that the Commission allow for
regional variations to avoid conflict with existing pro forma
facilities construction agreements.\2273\
---------------------------------------------------------------------------
\2273\ Ameren Initial Comments at 23; MISO Initial Comments at
97; NYISO Initial Comments at 45; PPL Initial Comments at 22.
---------------------------------------------------------------------------
(1) Comments on Specific Provisions and Related Proposals
1205. As a global change, Xcel recommends that the defined term
``affected system operator'' be used instead of ``transmission
provider'' when referencing the affected system transmission provider,
arguing that the use of the terms ``transmission provider'' and
``transmission provider acting as affected system'' are confusing and
may conflict with usage of those terms in the LGIP.\2274\
---------------------------------------------------------------------------
\2274\ Xcel Initial Comments at 40.
---------------------------------------------------------------------------
1206. With regard to article 2 (Term of Agreement), Tri-State
proposes the following addition: ``No Transmission Delivery Service.
The execution of this LGIA does not constitute a request for, nor the
provision of, any transmission delivery service under Transmission
Provider's Tariff, and does not convey any right to deliver electricity
to any specific customer or Point of Delivery.'' \2275\ Additionally,
Tri-State opposes the option in proposed article 2.2.1 that would allow
the affected system interconnection customer to terminate the affected
system facilities construction agreement with 60 calendar days' written
notice. Tri-State contends that allowing such termination could trigger
restudies for the affected system transmission provider.\2276\
---------------------------------------------------------------------------
\2275\ Tri-State Initial Comments at 32.
\2276\ Id. at 21.
---------------------------------------------------------------------------
1207. Southern states that the Commission should either reconsider
or clarify proposed article 2.2.2 (Termination Upon Default) and
proposed article 5.2 (Notice of Breach, Cure, and Default), which it
states appears to provide that if a default does not pose a threat to
the reliability of the affected system transmission provider's
transmission system, the affected system transmission provider may not
terminate the agreement if the affected system interconnection customer
has begun to cure and compensate the transmission provider for any
damage.\2277\ Southern argues that such provisions should be consistent
with pro forma LGIA provisions and that, if an affected system
interconnection customer defaults under the LGIA, the affected system
operator should not be required to build affected system network
upgrades. Southern argues that,
[[Page 61183]]
if the provisions are not consistent with the pro forma LGIA, affected
system transmission providers will build affected system network
upgrades that are not needed, and there will be different default and
termination rights applicable to these improvements. Similarly, Tri-
State submits suggested edits to proposed article 2.2.2, which remove
the provisions Southern comments on, explaining that a default should
only occur after a breach and failure to cure.\2278\
---------------------------------------------------------------------------
\2277\ Southern Initial Comments at 18.
\2278\ Tri-State Initial Comments at 33.
---------------------------------------------------------------------------
1208. Invenergy opposes proposed article 2.2.3, which provides
that, upon termination of the affected system facilities construction
agreement, the affected system interconnection customer would be
responsible for costs incurred by another affected system
interconnection customer due to the termination of: (1) its affected
system facilities construction agreement; (2) that interconnection
customer's LGIA; or (3) any of that interconnection customer's other
affected system facilities construction agreements.\2279\ Some
commenters argue that this requirement is unreasonable and must be
revised.\2280\ They claim that there is no basis for imposing on the
affected system interconnection customer broad and potentially
exorbitant liability for any potential impacts on any other
interconnection customer within the affected system, which they argue
exceeds potential liability imposed under the pro forma LGIA for the
host transmission provider's transmission system.\2281\ Invenergy
states that the provision appears to be based on a provision in MISO's
pro forma facilities construction agreement, which it argues does not
make sense for a generically applicable pro forma agreement.
---------------------------------------------------------------------------
\2279\ Invenergy Initial Comments at 45.
\2280\ Id. at 46; Interwest Reply Comments at 18-19; Tri-State
Initial Comments at 20.
\2281\ Interwest Reply Comments at 18-19; Invenergy Initial
Comments at 46; Tri-State Initial Comments at 20.
---------------------------------------------------------------------------
1209. As for proposed article 3 (Construction of Network Upgrades),
some commenters object to limiting the right to suspend for force
majeure events, contained in proposed article 3.1.2.1.\2282\ Southern
states that proposed article 3.1.2.1 appears to provide that the
affected system interconnection customer may only suspend its
interconnection request if there is a force majeure event and that no
such limitation on suspension rights exists under the pro forma LGIA,
meaning that an affected system interconnection customer could suspend
its interconnection request under the pro forma LGIA but still be
required to move forward with construction of affected system network
upgrades, if the reason for suspension under the pro forma LGIA is not
a force majeure event.\2283\ Enel asserts that the Commission has not
provided justification for limiting the affected system interconnection
customer's suspension rights to just force majeure events.\2284\ Enel,
Invenergy, and Southern argue that suspension rights under the pro
forma affected system facilities construction agreement should be
consistent with the suspension rights under the pro forma LGIA, with
Invenergy highlighting that the pro forma LGIA permits suspension for
up to three years.\2285\ Conversely, Tri-State argues that the same
force majeure language used in proposed article 3.1.2.1 should be added
to both the pro forma LGIA and pro forma LGIP.\2286\
---------------------------------------------------------------------------
\2282\ Enel Initial Comments at 83-84; Invenergy Initial
Comments at 47; Southern Initial Comments at 18; Tri-State Initial
Comments at 20.
\2283\ Southern Initial Comments at 18-19.
\2284\ Enel Initial Comments at 83-84.
\2285\ Id. at 83; Invenergy Initial Comments at 47; Southern
Initial Comments at 18-19.
\2286\ Tri-State Initial Comments at 33.
---------------------------------------------------------------------------
1210. MISO suggests that there should be a provision in the pro
forma affected system facilities construction agreement on cross-
defaults between the affected system facilities construction agreement
and the interconnection customer's LGIA.\2287\ MISO asserts that, as
proposed, if the affected system interconnection customer refuses to
make payments under an affected system facilities construction
agreement, it is unclear how it would affect the affected system
interconnection customer's LGIA.
---------------------------------------------------------------------------
\2287\ MISO Initial Comments at 97.
---------------------------------------------------------------------------
1211. In response to proposed article 3.2.2.1, which would require
affected system transmission providers to reimburse affected system
interconnection customers for their affected system network upgrade
costs, many commenters support the proposal,\2288\ while many others
oppose it.\2289\ In support, commenters contend that the reimbursement
policy is consistent with long-established Commission precedent and
cost causation, as it ensures that affected system network upgrade cost
reimbursement is rate-based, such that the transmission customers that
ultimately benefit from the network upgrades pay for those
upgrades.\2290\ In contrast, according to these commenters, allowing
transmission customers of the affected system to receive the benefits
of an affected system network upgrade, without paying for it, would
create a ``free-rider'' problem that is inconsistent with the
``beneficiary pays'' principle.\2291\
---------------------------------------------------------------------------
\2288\ ACE-NY Initial Comments 9; AES Initial Comments at 22;
Ameren Initial Comments at 23; APPA-LPPC Initial Comments at 23;
Enel Initial Comments at 66-67; Shell Initial Comments at 33-34.
\2289\ AECI Initial Comments at 9; Duke Southeast Utilities
Initial Comments at 19; EEI Initial Comments at 18-19; North
Carolina Commission and Staff Initial Comments at 6; PG&E Reply
Comments at 5-6; PPL Initial Comments at 20; Southern Reply Comments
at 7-8; Tri-State Initial Comments at 21-22; U.S. Chamber Commerce
Initial Comments at 11; WAPA Initial Comments at 13-14; Xcel Initial
Comments at 40.
\2290\ Enel Initial Comments at 66; Shell Initial Comments at
35.
\2291\ ACE-NY Initial Comments 9; Shell Initial Comments at 35-
36.
---------------------------------------------------------------------------
1212. Other commenters do not fully oppose the proposal but suggest
changes to proposed article 3.2.2.1. For instance, MISO and Southern
contend that the repayment provisions for affected system
interconnection customers should be consistent with how the
transmission provider repays its internal interconnection
customers.\2292\ MISO asserts that this will ensure comparability and
non-discriminatory treatment between affected system interconnection
customers and ``native'' interconnection customers interconnected to
the affected system.\2293\ APPA-LPPC argue that the NOPR proposal is
missing an express, contractual commitment ensuring that an
interconnection customer will fund network upgrades identified by the
affected system as a condition of interconnection.\2294\ APPA-LPPC
state that they believe this to be implicit in the proposal and that
the provision should specify that the identified affected system
transmission provider is an intended third-party beneficiary of the
LGIA. APPA-LPPC contend that the absence of such a contractual
obligation on the part of the interconnection customer is a particular
concern for non-public utilities, which have no standing under the FPA
to seek funding for network upgrades under Commission-jurisdictional
tariffs. However, according to Southern, in Order No. 2003, the
Commission declined to make a generic finding on the possibility of
network upgrade costs being passed onto native load and transmission
customers and instead allowed transmission providers to make a filing
if such entities were not being held harmless.\2295\ Southern states
that
[[Page 61184]]
the Commission should clarify that a transmission provider can make
such a filing, if warranted, in which it could propose that affected
system interconnection customers bear the cost responsibility of
identified affected system network upgrades.\2296\
---------------------------------------------------------------------------
\2292\ MISO Initial Comments at 97; Southern Initial Comments at
4.
\2293\ MISO Initial Comments at 97.
\2294\ APPA-LPPC Initial Comments at 24-25.
\2295\ Southern Initial Comments at 17-18; Southern Reply
Comments at 8 (citing Order No. 2003-A, 106 FERC ] 61,220 at P 586;
Order No. 2003-B, 109 FERC ] 61,287 at P 56).
\2296\ Southern Initial Comments at 17-18; Southern Reply
Comments at 9-10.
---------------------------------------------------------------------------
1213. Among issues raised by commenters that oppose the proposal,
one common concern is that the proposal would force affected system
transmission providers to subsidize interconnection to neighboring
transmission systems, despite potentially not receiving any energy from
such interconnection customers, causing increased costs to the affected
system due to the requirement to mitigate negative thermal, voltage,
and stability impacts without a corresponding increase in
benefits.\2297\ North Carolina Commission and Staff also contend that
the Commission has not provided evidence on this matter that would
allow the Commission to meet its burden under FPA section 206.\2298\
Some commenters assert that the affected system interconnection
customer should be responsible for the costs of affected system network
upgrades in exchange for use of the affected system (i.e., via
transmission service).\2299\ Xcel notes that, for loop flow impacts,
the affected system interconnection customer may not formally take
transmission service but may be granted the right to the transmission
capacity associated with the loop flows they cause, and some
transmission providers have charged unreserved use for such impacts or
otherwise required neighbors to pay for the transmission use.\2300\
---------------------------------------------------------------------------
\2297\ AECI Initial Comments at 9; Duke Southeast Utilities
Initial Comments at 21-22, 26; EEI Initial Comments at 18-19; North
Carolina Commission and Staff Initial Comments at 6; PPL Initial
Comments at 21; Tri-State Initial Comments at 21-22; U.S. Chamber of
Commerce Initial Comments at 11-12; Xcel Initial Comments at 40.
\2298\ North Carolina Commission and Staff Initial Comments at
16.
\2299\ Tri-State Initial Comments at 20; Xcel Initial Comments
at 40.
\2300\ Xcel Initial Comments at 40.
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1214. North Carolina Commission and Staff observe that, if the
Commission were to implement the NOPR proposal and allow RTOs/ISOs to
obtain independent entity variations from the proposed affected system
pricing scheme implementing a participant funding model, then North
Carolina retail and wholesale customers of Duke Energy Carolinas and
Duke Energy Progress would be paying for affected system network
upgrade costs when a generating facility interconnects with the PJM-
controlled transmission system in addition to paying for network
upgrade costs for native interconnection customers when generating
facilities interconnect with Duke Energy Progress or Duke Energy
Carolinas-owned transmission facilities, which they argue would be
patently unjust, unfair, and unduly preferential.\2301\
---------------------------------------------------------------------------
\2301\ North Carolina Commission and Staff Initial Comments at
23.
---------------------------------------------------------------------------
1215. Several commenters argue that the NOPR proposal is contrary
to important objectives articulated in Order No. 2003.\2302\ For
instance, Duke Southeast Utilities contend that, if transmission
providers are required to reimburse affected system interconnection
customers for costs advanced for affected system network upgrades, such
transmission providers will seek to obtain rate recovery of their
reimbursement cost from existing wholesale and retail transmission
customers, meaning those classes of customers will not be protected
from adverse rate implications because they will have to absorb all
affected system network upgrade costs.\2303\ According to Duke
Southeast Utilities, this is contrary to an important objective
articulated in Order No. 2003-B of the interconnection pricing policy
protecting existing transmission customers from adverse rate
implications associated with interconnection facilities and network
upgrades required to interconnect a new generating facility.\2304\
---------------------------------------------------------------------------
\2302\ Duke Southeast Utilities Initial Comments at 23; PPL
Initial Comments at 20-21.
\2303\ Duke Southeast Utilities Initial Comments at 23.
\2304\ Id. (citing Order No. 2003-B, 109 FERC ] 61,287 at P 56).
---------------------------------------------------------------------------
1216. According to PPL, the pricing policy established in Order No.
2003 was meant to promote competition in markets ``still dominated by
non-independent transmission providers.'' \2305\ PPL argues that non-
RTO/ISO transmission providers no longer dominate, and therefore this
policy is no longer necessary.\2306\ PPL asserts that, contrary to the
time of Order No. 2003's issuance, and as a result of the size and
nature of generating facilities being developed in RTO/ISO regions,
non-RTOs/ISOs might be required to build costly affected system network
upgrades to accommodate the interconnection of generating facilities in
adjacent markets. PPL contends that affected system network upgrade
costs can overwhelm the total network upgrade costs identified for
reliability or other planning purposes. PPL claims, however, that the
affected system network upgrade reimbursement proposal in the NOPR is
directly contrary to the Commission's interconnection pricing policy
meant to protect existing customers from the rate impacts of
interconnection-related network upgrades,\2307\ and allows affected
system interconnection customers to benefit from network upgrades
without paying for them.\2308\ Thus, PPL asserts that the Commission
should allow affected system transmission providers the flexibility to
directly assign affected system network upgrade costs. Duke Southeast
Utilities concur, asserting that there is ample precedent of the
Commission accepting, without modification, an affected system
operating agreement between affected system transmission providers and
affected system interconnection customers that directly assign network
upgrade costs to such interconnection customers without
reimbursement.\2309\
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\2305\ PPL Initial Comments at 20 (citing Order 2003-A, 106 FERC
] 61,220 at P 636).
\2306\ Id. at 20-21.
\2307\ Id. at 21 (citing Order 2003-A, 106 FERC ] 61,220 at P
586; Order 2003-B, 109 FERC ] 61,287 at P 56).
\2308\ Id. at 21-22.
\2309\ Duke Southeast Utilities Initial Comments at 24 (citing,
e.g., Docket No. ER21-1701-000 (involving acceptance of an affected
system upgrade agreement between Southern and Cooperative Energy)).
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1217. Invenergy asserts that the Commission should reject arguments
challenging the Commission's interconnection pricing policy established
in Order No. 2003.\2310\ Invenergy contends that this interconnection
pricing policy was fully litigated in the Order No. 2003 rulemaking
proceeding and that issues relating to cost causation were fully and
carefully considered at that time.\2311\ Invenergy also argues that
Duke Southeast Utilities' reference to Order No. 2003-B is misplaced,
as the Commission, in Order No. 2003-B, found that the interconnection
pricing policy fully protected native load customers and that
transmission providers could make and justify alternative proposals on
compliance.\2312\
---------------------------------------------------------------------------
\2310\ Invenergy Reply Comments at 10 (citing Order No. 2003,
104 FERC ] 61,103 at PP 693-696).
\2311\ Id. at 11-12 (citing Order No. 2003, 104 FERC ] 61,103 at
PP 684, 693-696).
\2312\ Id. at 10-11.
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1218. Duke Southeast Utilities and North Carolina Commission and
Staff assert that the affected system network upgrade reimbursement
proposal will stifle renewable generating facility
[[Page 61185]]
development.\2313\ For instance, Duke Southeast Utilities argue that
mandatory reimbursement has the likelihood of chilling development of
new, mainly renewable, generating facilities in states that consider
such costs as part of overall development costs when considering
whether to issue a certificate of public convenience and necessity to
permit these generating facilities.\2314\
---------------------------------------------------------------------------
\2313\ Duke Southeast Utilities Initial Comments at 24-25; North
Carolina Commission and Staff Initial Comments at 21.
\2314\ Duke Southeast Utilities Initial Comments at 24-25.
---------------------------------------------------------------------------
1219. Moreover, Duke Southeast Utilities argue that the mandatory
reimbursement by affected system transmission providers of affected
system network upgrade costs fails to encourage efficient siting
decisions by affected system interconnection customers.\2315\ Duke
Southeast Utilities assert that, if affected system interconnection
customers are reimbursed for 100% of the costs of network upgrades on
the affected system plus interest at the Commission-prescribed rate,
they actually profit financially from such reimbursement.\2316\
---------------------------------------------------------------------------
\2315\ Id. at 25; Duke Southeast Utilities Reply Comments at 23.
\2316\ Duke Southeast Utilities Initial Comments at 25.
---------------------------------------------------------------------------
1220. Invenergy argues that the possibility of certain states
considering affected system network upgrade costs in permitting
proceedings does not call the Commission's existing pricing policy into
question.\2317\ In response to arguments that the NOPR proposal could
foster inefficient siting, Invenergy asserts that this argument was
considered and settled in the Order No. 2003 rulemaking
proceeding.\2318\ Invenergy contends that such comments are speculative
and ignore other facts, such as that identification of affected system
network upgrades typically occurs after most siting decisions are made.
---------------------------------------------------------------------------
\2317\ Invenergy Reply Comments at 12.
\2318\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 695-
696).
---------------------------------------------------------------------------
1221. North Carolina Commission and Staff argue that affected
system costs are no longer incidental or rare and have been escalating
over time.\2319\ North Carolina Commission and Staff allege that the
proposed crediting policy will force North Carolina wholesale and
retail ratepayers to subsidize the policy choices of other states and
the corporate goals of businesses located in other states.
---------------------------------------------------------------------------
\2319\ North Carolina Commission and Staff Initial Comments at
21-22.
---------------------------------------------------------------------------
1222. Public Interest Organizations urge the Commission to
disregard North Carolina Commission and Staff's assertions on this
matter, arguing that the NOPR proposal is unrelated to state and
corporate policies.\2320\ Public Interest Organizations assert that the
proposal is meant to address existing gaps in the pro forma LGIP that
apply to all interconnection customers regardless of fuel type and
motivation for generating facility development.
---------------------------------------------------------------------------
\2320\ Public Interest Organizations Reply Comments at 18-19.
---------------------------------------------------------------------------
1223. WAPA expresses significant concerns with the NOPR proposal,
emphasizing that it requires the affected system transmission provider
to reimburse the affected system interconnection customer cash plus
interest over 20 years for the cost of affected system network
upgrades.\2321\ WAPA states that, as a Federal agency, it cannot
provide a cash payment with interest to an interconnection customer
that does not take transmission service from WAPA.\2322\ According to
WAPA, per its tariff, it only provides network credits, not cash
payments, for such customers, and it would need to work with the host
transmission provider to ensure a mechanism is developed to properly
credit the affected system interconnection customer.\2323\
---------------------------------------------------------------------------
\2321\ WAPA Initial Comments at 13.
\2322\ Id. Specifically, WAPA states that it must deposit all
revenues received into a reclamation fund and that it would need an
appropriation from Congress to use the money in the reclamation fund
to pay interconnection customers. Id. at 13 n.17 (citing 43
U.S.C.392a). WAPA also notes that its current tariff specifically
provides that WAPA cannot pay interest on any funds advanced by
interconnection customers. Id. (citing WAPA, WAPA Open Access
Transmission Tariff, section 17.3 (1.0.0)).
\2323\ Id. at 13-14.
---------------------------------------------------------------------------
1224. Also on proposed article 3 of the pro forma affected system
facilities construction agreement, Tri-State notes that proposed
article 3.2.2.1 (Repayment) does not contain a reference to determine
if affected system network upgrades are unnecessary.\2324\ Separately,
Tri-State also suggests revisions to state that the repayment period
should end no later than 20 years from the completion of the
construction of the affected system interconnection customer's
generating facility, rather than completion of the construction of the
affected system network upgrades.\2325\
---------------------------------------------------------------------------
\2324\ Tri-State Initial Comments at 33.
\2325\ Id., app. B at 133.
---------------------------------------------------------------------------
1225. With regard to proposed article 4 (Security, Billing, and
Payments), PacifiCorp offers suggested revisions to proposed article
4.1, which PacifiCorp asserts are intended to, among other things,
clarify that additional security will be required from the affected
system interconnection customer if the affected system transmission
provider determines that the costs of facilities may exceed the initial
estimate provided to the affected system interconnection
customer.\2326\ PPL also states that affected system interconnection
customers should be required to meet credit and security
requirements.\2327\
---------------------------------------------------------------------------
\2326\ PacifiCorp Initial Comments at 37.
\2327\ PPL Initial Comments at 20.
---------------------------------------------------------------------------
1226. As for proposed article 6 (Termination of Agreement), Tri-
State suggests consolidating proposed article 6.3.3 (Pre-construction
of Installation) with proposed article 2.2.3 and proposes removing some
language in proposed article 6.4 (Survival Rights) that it argues is
duplicative of proposed article 2.4.\2328\
---------------------------------------------------------------------------
\2328\ Tri-State Initial Comments at 33-34.
---------------------------------------------------------------------------
1227. Commenters also respond to the proposed confidentiality
provisions. Southern asserts that proposed article 8.1 in the pro forma
affected system facilities construction agreement, section 13.1 in the
pro forma LGIP, and article 22 in the pro forma LGIA should be revised
to reflect the use of backup servers and the obligations of
transmission providers to share information under NERC Reliability
Standards.\2329\ Southern asserts that it is administratively difficult
to meet the requirements in these provisions that specify that
confidential information be destroyed or returned, arguing that this
provision should allow information to be stored on backup servers.
Southern also notes that, under NERC Reliability Standards, which were
developed after the effective date of Order No. 2003, transmission
providers must disclose confidential information to neighboring
transmission providers, and therefore, this language should be updated
to reflect that the transmission provider must share this confidential
information.
---------------------------------------------------------------------------
\2329\ Southern Initial Comments at 19.
---------------------------------------------------------------------------
1228. Moving to proposed Appendix A, MISO contends that there is no
need for a commercial operation date to be listed for affected system
network upgrades in proposed Appendix A.\2330\ MISO argues that
commercial operation is something that occurs in the LGIA context,
where the affected system interconnection customer's injection of
energy onto the host transmission provider is memorialized.
---------------------------------------------------------------------------
\2330\ MISO Initial Comments at 97.
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[[Page 61186]]
(2) Requests for Clarification
1229. Southern explains that the pro forma LGIA and Commission
policy require that interconnection customers pay for the cost of
system protection facilities, and Southern requests that the Commission
clarify that it is not changing this policy.\2331\
---------------------------------------------------------------------------
\2331\ Southern Initial Comments at 17; Southern Reply Comments
at 8 (citing pro forma LGIA art. 9.7.4.1; Order No. 845, 163 FERC ]
61,043 at P 371).
---------------------------------------------------------------------------
(3) Miscellaneous
1230. Eversource states that the concerns of interconnection
customers and transmission providers with regard to ISO-NE's related
facilities agreement (RFA) \2332\ are not addressed by the NOPR
proposal, which address coordination between different tariffs and
system operators, and requests that the Commission clarify this
difference.\2333\
---------------------------------------------------------------------------
\2332\ ISO-NE's RFA is an intra-RTO/ISO agreement with a
specific transmission owner.
\2333\ Eversource Initial Comments at 32.
---------------------------------------------------------------------------
(c) Commission Determination
1231. We adopt, with modifications, the NOPR proposal to establish
a pro forma affected system facilities construction agreement in
Appendix 11 of the pro forma LGIP.\2334\ The pro forma affected system
facilities construction agreement, as adopted herein, closely tracks
the NOPR proposal: the affected system transmission provider and the
affected system interconnection customer(s) will enter into the
agreement; and the agreement will set forth the terms and conditions by
which the affected system transmission provider will be responsible for
the design, procurement, construction, and installation of all network
upgrades and terms and conditions by which the affected system
interconnection customer will initially fund, and be reimbursed for,
the cost of any assigned affected system network upgrades. As described
below, we modify the following proposed articles in the pro forma
affected system facilities construction agreement: (1) article 2.2.2
(Termination Upon Default); (2) article 2.2.3 (Consequences of
Termination); (3) article 3.1.1 (Transmission Provider Obligations);
(4) article 3.1.2.1 (Right to Suspend); (5) article 3.1.2.3 (Right to
Suspend Due to Default); (6) article 5.1 (Events of Breach); (7)
article 5.2 (Notice of Breach, Cure and Default); (8) article 5.2.1;
and (9) article 5.2.2.\2335\ Additionally, we establish a pro forma
multiparty affected system facilities construction agreement set forth
in Appendix 12 of the pro forma LGIP.
---------------------------------------------------------------------------
\2334\ NOPR, 179 FERC ] 61,194 at P 197.
\2335\ We further note that we streamline article 6.2
(Termination and Removal) of the pro forma affected system
facilities construction agreement with ministerial revisions, as
well as add article 5.2 to provide a definition of ``breaching
party,'' which changes the numbering for proposed article 5.2
(Notice of Breach, Cure, and Default) to article 5.3 and proposed
article 5.3 (Rights in the Event of Default) to article 5.4.
---------------------------------------------------------------------------
1232. We find that a pro forma affected system facilities
construction agreement will improve the efficiency of the
interconnection process by reducing delays through improved
coordination among relevant parties, consistent with the Commission's
preliminary findings in the NOPR and with record support.\2336\ As Duke
Southeast Utilities explains, the adoption of a pro forma affected
system facilities construction agreement will offer uniformity of these
types of agreements to be tendered by affected system transmission
providers across the country.\2337\ Such uniformity will help reduce
the potential for undue discrimination. As the Commission found in
Order No. 2003, a standard set of procedures as part of the tariff for
all jurisdictional transmission facilities will minimize opportunities
for undue discrimination.\2338\
---------------------------------------------------------------------------
\2336\ NOPR, 179 FERC ] 61,194 at P 200; see also Ameren Initial
Comments at 23; Duke Southeast Utilities Initial Comments at 18;
Pine Gate Initial Comments at 42; SPP Initial Comments at 19-20.
\2337\ Duke Southeast Utilities Initial Comments at 18.
\2338\ Order No. 2003, 104 FERC ] 61,103 at P 11.
---------------------------------------------------------------------------
1233. We also adopt a pro forma multiparty affected system
facilities construction agreement.\2339\ Similar to adopting the pro
forma multiparty affected system study agreement, as discussed earlier,
we find that the adoption of the pro forma multiparty affected system
facilities construction agreement will further improve coordination and
further minimize opportunities for undue discrimination, even relative
to a two-party agreement. Also, similar to the adoption of the pro
forma affected system study agreement, the establishment of the pro
forma multiparty affected system facilities construction agreement
aligns with the requirement to study affected system interconnection
requests in clusters. Specifically, such a multiparty agreement will
allow for a common agreement for the affected system transmission
provider to enter into with all affected system interconnection
customers for the construction of affected system network upgrades
identified by the cluster study that are assigned to more than one
affected system interconnection customer. Below, in discussing relevant
article-specific comments, we discuss noteworthy, additional changes
needed to convert the pro forma affected system facilities construction
agreement from a two-party agreement to a multiparty agreement.
---------------------------------------------------------------------------
\2339\ PPL Initial Comments at 20; SPP Initial Comments at 19-
20.
---------------------------------------------------------------------------
1234. As with the pro forma multiparty affected system study
agreement, discussed above, the pro forma multiparty affected system
facilities construction agreement that we adopt in this final rule
closely follows the two-party agreement, with changes needed to convert
to a multiparty agreement. In article 2.2.2 (Termination Upon Default),
we establish that the default by one affected system interconnection
customer does not allow the non-defaulting affected system
interconnection customer(s) the right to terminate the agreement and
that, instead, the defaulting party may be removed from the agreement
by the affected system transmission provider. In article 3.1.2.1 (Right
to Suspend), we maintain the affected system interconnection customer's
right to suspend but only upon the mutual agreement of all affected
system interconnection customers that are party to the multiparty
agreement. In article 5.3 (Notice of Breach, Cure, and Default), we
establish multiparty cure procedures whereby the non-breaching parties
may cure the other affected system interconnection customer's breach.
1235. We decline to make changes to the proposed pro forma affected
system facilities construction agreement and conforming changes to the
pro forma LGIP, aligning with Xcel's suggestion that the ``affected
system transmission provider'' should be renamed an ``affected system
operator.'' Instead, we clarify that the pro forma LGIP is written for
a specific transmission provider. When a transmission provider is
fulfilling its obligations as a host transmission provider, the pro
forma LGIP refers to the host transmission provider's interaction with
the ``affected system operator.'' However, when the pro forma LGIP
references a transmission provider and its obligations as the operator
of an affected system, we use the term ``transmission provider,'' as
the pro forma LGIP is setting the requirements of the transmission
provider, whether acting as the host or affected system transmission
provider, and that is a different perspective from a host transmission
provider's interaction with a separate ``affected system operator.''
1236. In response to Tri-State's suggestion to revise proposed
article 2 of the pro forma affected system facilities construction
agreement to
[[Page 61187]]
clarify that the execution of an LGIA does not convey transmission
service, we decline to adopt this request, as it is unnecessary.\2340\
However, we accept Tri-State's suggested revisions to article 3.1.1 of
the pro forma affected system facilities construction agreement to
clarify that the affected system transmission provider shall not
undertake any actions inconsistent with its safety practices, material
and equipment specifications, design criteria and construction
procedures, labor agreements, or any applicable laws and regulations.
---------------------------------------------------------------------------
\2340\ See Order No. 2003, 104 FERC ] 61,103 at P 118 (stating
that ``[t]he Commission continues to treat interconnection and
delivery as separate aspects of transmission service, and an
Interconnection Customer may request Interconnection Service
separately from transmission service (delivery of the Generating
Facility's power output)''); Order No. 2003-A, 106 FERC ] 61,220 at
P 113 (``reiterat[ing] that Interconnection Service is separate from
the delivery component of Transmission Service and that the mere
interconnection of the Generating Facility is unlikely to harm
reliability on Affected Systems'').
---------------------------------------------------------------------------
1237. We modify proposed articles 2.2.2 and 5.2 (now articles 2.2.2
and 5.3) of the pro forma affected system facilities construction
agreement in response to comments from Southern and Tri-State regarding
termination and cure. Proposed article 2.2.2 establishes that a non-
breaching party has the right to terminate the pro forma affected
system facilities construction agreement, provided that termination
does not pose a reliability threat and that the breaching party has not
undertaken efforts to cure the breach, pursuant to article 5.3 (Notice
of Breach, Cure and Default). However, consistent with comments from
Southern,\2341\ we agree that termination and default rights in the pro
forma affected system facilities construction agreement should be
consistent with the pro forma LGIA. Accordingly, as adopted, we modify
articles 2.2.2 and 5.2 (now articles 2.2.2 and 5.3) of the pro forma
affected system facilities construction agreement to make them
consistent with the existing default provisions in article 17 of the
pro forma LGIA (Default), which also establishes default and cure
provisions in the event of a breach.
---------------------------------------------------------------------------
\2341\ Southern Initial Comments at 18.
---------------------------------------------------------------------------
1238. We also modify proposed article 2.2.3 (Consequences of
Termination) of the pro forma affected system facilities construction
agreement in response to comments from Tri-State and Invenergy
suggesting that it would require affected system interconnection
customers to be responsible for the costs of additional facilities that
are caused by another interconnection customer terminating its affected
system facilities construction agreement or that interconnection
customer's LGIA.\2342\ Specifically, we remove the final sentence from
proposed article 2.2.3 that an ``affected system interconnection
customer is responsible for the cost of additional facilities that is
caused to another interconnection customer due to the termination of
this Agreement, affected system interconnection customer's LGIA, or any
affected system interconnection customer's other Affected System
Facilities Construction Agreement(s).'' We find that deletion of this
sentence is needed because the affected system interconnection customer
should not be responsible for any additional facilities that are
assigned to another interconnection customer under these circumstances.
As written, the provision implies that an affected system
interconnection customer could be responsible for any network upgrade
identified as a result of the agreement's termination, even if the
newly assigned network upgrade is on a different transmission
provider's transmission system than the transmission provider that is a
signatory to the terminated agreement. Additionally, we note that the
pro forma LGIA contains no similar requirement that upon termination of
an LGIA that the interconnection customer is responsible for any
additional costs assigned to another interconnection customer as a
result of the LGIA's termination and based on the comments received,
the record does not support including the provision.
---------------------------------------------------------------------------
\2342\ Invenergy Initial Comments at 45; Tri-State Initial
Comments at 20.
---------------------------------------------------------------------------
1239. MISO requests a cross-default provision between the pro forma
affected system facilities construction agreement and the pro forma
LGIA because MISO asserts that, if an affected system interconnection
customer does not meet its obligations under its affected system
facilities construction agreement, it is unclear how that would affect
that interconnection customer's LGIA on its host transmission
system.\2343\ In response, we clarify that a breach under the pro forma
affected system facilities construction agreement does not constitute a
breach under the pro forma LGIA. We are unpersuaded that cross-default
provisions between the pro forma affected system facilities
construction agreement and the pro forma LGIA are necessary because
both the pro forma affected system facilities construction agreement
and the pro forma LGIA individually already contain default provisions.
---------------------------------------------------------------------------
\2343\ MISO Initial Comments at 97.
---------------------------------------------------------------------------
1240. In addition, we are concerned that a cross-default provision,
which could result in the termination of an interconnection customer's
interconnection service based on actions under a separate agreement,
could raise contractual complications because the host transmission
provider will not be a party to the affected system facilities
construction agreement. We note, however, that any affected system
interconnection customer that defaults on its obligations under the pro
forma affected system facilities construction agreement may face
consequences, including, for example, curtailment. Additionally, we
find that article 4.1 of the pro forma affected system facilities
construction agreement already contains sufficient security provisions
to protect a transmission provider in the situation that the affected
system interconnection customer defaults on the agreement and which
discourages non-payment by the interconnection customer.
1241. We modify proposed article 3.1.2.1 (Right to Suspend for
Force Majeure Event) of the pro forma affected system facilities
construction agreement in response to comments that the proposed
suspension provision is too restrictive and inconsistent with the
suspension provision in the pro forma LGIA.\2344\ Specifically, we
revise article 3.1.2.1 to remove the limitation on the right to suspend
to force majeure events and modify the suspension provision to allow an
affected system interconnection customer to suspend work required under
the affected system facilities construction agreement for up to three
years.\2345\ We also modify article 3.1.2.1 to remove the requirement
for the affected system interconnection customer, prior to suspension,
to provide security to the affected system transmission provider of the
higher of $5 million or the total cost of all affected system network
upgrades listed in Appendix A of the agreement. We find the requirement
unnecessary because, under article 4.1 (Provision of Security) of the
pro forma affected system facilities construction agreement, the
affected system interconnection customer would have already been
required to provide security for the applicable portion of the affected
system network upgrades. With these changes to article 3.1.2.1, the
suspension provision in the pro forma affected
[[Page 61188]]
system facilities construction agreement will mirror the suspension
provision in the pro forma LGIA.\2346\
---------------------------------------------------------------------------
\2344\ Pro forma LGIA art. 5.16.
\2345\ We also make various conforming revisions throughout
proposed article 3.1.2.1 of the pro forma affected system facilities
construction agreement, consistent with this modification to the
suspension provision.
\2346\ Pro forma LGIA art. 5.16.
---------------------------------------------------------------------------
1242. Additionally, we revise proposed article 3.1.2.3 (Right to
Suspend Due to Default) of the pro forma affected system facilities
construction agreement, which provides for the right to suspend due to
default. The revisions we adopt to this provision clarify that if an
affected system interconnection customer defaults, the affected system
interconnection customer will be responsible for any additional
expenses incurred by the affected system transmission provider
associated with the construction and installation of the affected
system network upgrades, as set forth in article 2.2.3 (Consequences of
Termination). We find that the revisions will align the language in the
pro forma affected system facilities construction agreement with
similar language in the pro forma LGIP, as suggested by
PacifiCorp.\2347\ However, we reject the proposed revisions suggested
by Tri-State to article 3.1.2.3 because they would alter the right to
suspend to allow an affected system transmission provider the right to
suspend in the event of a breach, rather than in the event of a
default. Tri-State's suggested changes to article 3.1.2.3 would
contradict other provisions in the pro forma LGIA and the pro forma
affected system facilities construction agreement, which allow for the
breaching party to cure a breach as is appropriate.
---------------------------------------------------------------------------
\2347\ PacifiCorp Initial Comments, attach. A, at 54.
---------------------------------------------------------------------------
1243. We adopt article 3.2.2.1 (Repayment) of the pro forma
affected system facilities construction agreement as proposed, which is
consistent with existing Commission precedent.\2348\
---------------------------------------------------------------------------
\2348\ Order No. 2003, 104 FERC ] 61,103 at PP 693-696, 720-739;
Order No. 2003-A, 106 FERC ] 61,220 at PP 584-586 (stating that the
transmission system is a cohesive, integrated network that operates
as a single piece of equipment, and that network facilities benefit
all transmission customers; further, even if a customer can be said
to have caused the addition of a grid facility, such addition
represents a system expansion used by and benefiting all users due
to the integrated nature of the grid); Order No. 2003-C, 111 FERC ]
61,401 at P 13; NARUC v. FERC, 475 F.3d 1277, 1285 (D.C. Cir. 2007)
(affirming the Commission's conclusions); W. Mass. Elec. Co. v.
FERC, 165 F.3d 922, 927 (D.C. Cir. 1999).
---------------------------------------------------------------------------
1244. Some commenters are concerned that affected systems repayment
could force affected system transmission providers to subsidize
interconnection to neighboring systems, stifle renewable generating
facility development, or facilitate inefficient siting.\2349\ However,
in the NOPR, the Commission did not propose to change the Commission's
affected system repayment policy; instead, the Commission simply
proposed to memorialize the Commission's existing policy in a pro forma
agreement for affected systems.\2350\ As a result, we decline to
address arguments on the merits of the Commission's affected systems
repayment policy in this final rule.
---------------------------------------------------------------------------
\2349\ AECI Initial Comments at 9; Duke Southeast Utilities
Initial Comments at 21-22, 26; EEI Initial Comments at 18-19; North
Carolina Commission and Staff Initial Comments at 6; PPL Initial
Comments at 21; Tri-State Initial Comments at 21-22; U.S. Chamber of
Commerce Initial Comments at 11-12; Xcel Initial Comments at 40.
\2350\ See Order No. 2003, 104 FERC ] 61,103 at PP 738-739; see
also pro forma LGIA art. 11.4.
---------------------------------------------------------------------------
1245. With respect to the concerns raised by WAPA that it is unable
to repay affected system interconnection customers due to limitations
based on its Federal status, we decline to rule on the specifics of
individual transmission provider circumstances and instead find that
such concerns are better raised in a compliance proceeding, including
such a proceeding with a reciprocity tariff filing, if WAPA chooses to
file one.
1246. In response to requests for clarification from Southern, we
clarify that, consistent with the Commission's findings in Order No.
2003, we are not changing our policy requiring the interconnection
customer, at its expense, to install, operate, and maintain system
protection facilities as a part of its generating facility or its
interconnection facilities.\2351\ Also in response to Southern and
consistent with the Commission's findings in Order No. 2003,
transmission providers may make a filing to the Commission proposing an
incremental rate to the affected system interconnection customer, as
more fully described in Order Nos. 2003-A and 2003-B,\2352\ if native
load and existing transmission customers are not being held harmless,
though we reiterate that the transmission provider bears the full
burden of showing that any such proposal is just, reasonable, and not
unduly discriminatory or preferential and is appropriate under the
circumstances.\2353\
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\2351\ Pro forma LGIA art. 9.7.4.1; see also Order No. 845, 163
FERC ] 61,043 at P 371.
\2352\ Order No. 2003-A, 106 FERC ] 61,220 at P 586; Order No.
2003-B, 109 FERC ] 61,287 at P 56.
\2353\ Order No. 2003-B, 109 FERC ] 61,287 at P 56.
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1247. We adopt Tri-State's suggested revisions to proposed article
3.2.2.1 of the pro forma affected system facilities construction
agreement regarding the terms for repayment of affected system network
upgrades. Consistent with existing pro forma LGIA provisions,\2354\ the
parties may mutually agree to a repayment schedule for all applicable
costs associated with affected system network upgrades, with complete
repayment not to exceed 20 years from the commercial operation date of
the affected system interconnection customer's generating facility.
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\2354\ Pro forma LGIA art. 11.4.1.
---------------------------------------------------------------------------
1248. We decline to adopt additions to proposed article 4.1
(Provision of Security) of the pro forma affected system facilities
construction agreement suggested by PacifiCorp that would add
additional security posting requirements, to the extent that costs to
construct affected system network upgrades increase.\2355\ Proposed
article 4.1 is consistent with security provisions outlined in pro
forma LGIA article 11.5 (Provision of Security), and we find that such
provisions should be consistent across both the pro forma affected
system facilities construction agreement and the pro forma LGIA. We
also find that the security provision requirements are already
sufficiently clear in article 4.1 of the pro forma affected system
facilities construction agreement. Specifically, article 4.1 of the pro
forma affected system facilities construction agreement provides that
``security for payment shall be in an amount sufficient to cover the
costs for constructing, procuring and installing the applicable portion
of Affected System Network Upgrades.''
---------------------------------------------------------------------------
\2355\ PacifiCorp Initial Comments at 37.
---------------------------------------------------------------------------
1249. In response to comments from PPL asserting that affected
system interconnection customers should be responsible for meeting the
affected system transmission provider's creditworthiness
requirements,\2356\ because the pro forma affected system facilities
construction agreement is an agreement between the affected system
transmission provider and the affected system interconnection customer,
we clarify that affected system interconnection customers are obligated
to meet the affected system transmission provider's creditworthiness
and security requirements. We note that this is consistent with the
parallel requirement for interconnection customers to meet the
creditworthiness and security requirements of the host transmission
provider outlined in pro forma LGIA article 11.5.1.
---------------------------------------------------------------------------
\2356\ PPL Initial Comments at 20.
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1250. We revise proposed article 5.1(b) of the pro forma affected
system facilities construction agreement, consistent with PacifiCorp's
suggestion, to remove the requirement that a party will be in breach
for failure to comply with a material term or condition of the
agreement due to an inaccuracy in a representation, warranty, or
covenant
[[Page 61189]]
made in the agreement resulting in a breach under the agreement. We
find that there is no reason why an inaccuracy should lead to a
potential breach, or even a default, under the agreement. We note that
the pro forma LGIA contains no similar provision.
1251. We revise proposed article 5.2.1, now article 5.3.1, of the
pro forma affected system facilities construction agreement to extend
the cure period for a breach from 30 calendar days to 60 calendar days
and proposed article 5.2.2, now article 5.3.2, of the pro forma
affected system facilities construction agreement to remove the
additional cure period if the breach remains despite the occurrence of
good faith steps. We find that the revision will simplify the cure
requirements while providing breaching party with an extra 30 calendar
days at the onset to cure its breach. We also revise article 5.3.2 to
include a reference that if the breaching party defaults, then the non-
defaulting party may terminate the agreement in accordance with article
6.2 (Termination) of the agreement. We further clarify article 5 of
both the pro forma affected system facilities construction agreement
and the pro forma multiparty affected system facilities construction
agreement that a failure to cure a breach of either agreement will also
constitute a default.
1252. We decline to delete proposed article 6.4 (Survival of
Rights) of the pro forma affected system facilities construction
agreement, as suggested by Tri-State. Although Tri-State asserts that
proposed article 6.4 should be deleted because it is duplicative of
proposed article 2.4 (Survival),\2357\ we find that the contents are
sufficiently different to merit their separate inclusion. Specifically,
article 2.4 provides for the survival of the pro forma affected system
facilities construction agreement until all liabilities incurred prior
to termination are fulfilled, whereas article 6.4 clarifies the scope
of the rights of parties following termination to provide for final
billing, enforcement of liabilities and confidentiality obligations,
and for potential judicial or administrative action.
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\2357\ Tri-State Initial Comments at 34.
---------------------------------------------------------------------------
1253. In response to comments from Southern regarding updates to
the confidentiality provisions contained in proposed article 8
(Confidentiality) of the pro forma affected system facilities
construction agreement,\2358\ we find that, because we are not
proposing to revise the confidentiality provision set forth in the pro
forma LGIA--instead, we are merely adopting it into the pro forma
affected system facilities construction agreement--article 8, as
adopted, is just and reasonable. Contrary to Southern's comments, the
confidentiality provisions in article 8.1.7 of the pro forma affected
system facilities construction agreement allow for confidential
information to be destroyed, erased, deleted or, as applicable,
returned, not for such information to exclusively be ``destroyed or
returned.'' \2359\ Thus, such language reflects the fact that most
electronic information is stored in backup servers. Moreover, in
response to Southern's concern that deleting information stored on
backup servers is administratively difficult, we find that Southern has
not provided any evidence or explained why this might be so.
---------------------------------------------------------------------------
\2358\ Southern Initial Comments at 19.
\2359\ Id.
---------------------------------------------------------------------------
1254. In response to MISO's contention that there is no need to
list a commercial operation date for affected system network upgrades
in Appendix A of the pro forma affected system facilities construction
agreement,\2360\ we agree and modify Appendix A, now Attachment A, to
remove the commercial operation date from tables 1 and 3. However, we
note that parties may find it useful to memorialize the commercial
operation date for the affected system interconnection customer's
generating facility because, under article 2.2.1 of the pro forma
affected system facilities construction agreement, the parties to the
agreement may alter the affected system facilities construction
agreement by mutual consent if the in-service state date for the
affected system network upgrades or the commercial operation date for
the generating facility changes. To the extent MISO is concerned that
there could be different commercial operation dates listed for affected
system network upgrades in the LGIA and the affected system facilities
construction agreement, the host transmission provider must update the
commercial operation date for affected system network upgrades in the
affected system interconnection customer's LGIA with the host system,
to avoid discrepancies between the affected system facilities
construction agreement and the LGIA.
---------------------------------------------------------------------------
\2360\ MISO Initial Comments at 97.
---------------------------------------------------------------------------
1255. Finally, in response to comments from Eversource and ISO-
NE,\2361\ we clarify that these pro forma affected system agreements
are distinct from intra-RTO/ISO agreements, like ISO-NE's RFA, which
RTOs/ISOs may use to coordinate the construction of necessary network
upgrades within multiple transmission owner service territories within
the same RTO/ISO.\2362\
---------------------------------------------------------------------------
\2361\ Eversource Initial Comments at 32; ISO-NE Initial
Comments at 38.
\2362\ Eversource Initial Comments at 31-32.
---------------------------------------------------------------------------
d. Affected System Modeling and Study Assumptions
i. NOPR Proposal
1256. As the Commission explained in the NOPR, when an
interconnection customer submits an interconnection request, they must
choose to be studied as ERIS or NRIS, depending on the level of
deliverability they seek for the output of their generating facility.
For interconnection customers seeking to deliver their generating
facility's electric output using the existing firm or non-firm capacity
of the transmission provider's system on an as-available basis, the
interconnection customer will choose an ERIS study. An interconnection
customer will choose an NRIS study when seeking to integrate their
generating facility with the transmission provider's system (1) in a
manner comparable to that in which the transmission provider integrates
its generating facilities to serve native load customers or (2) in an
RTO/ISO with market-based congestion management, in the same manner as
network resources.\2363\ An NRIS study goes beyond the prerequisite
ERIS study and uses stricter modeling standards \2364\ to assess an
interconnection request to ensure that the interconnection customer's
electric output is deliverable to load in aggregate on the host
[[Page 61190]]
transmission provider's system.\2365\ Such a deliverability analysis
varies regionally but can analyze anything from various stressed
dispatch scenarios to an additional set of contingencies. As such, an
NRIS study will likely identify more network upgrades to accommodate
the interconnection of a generating facility than an ERIS study because
NRIS provides a higher level of interconnection service than ERIS.
---------------------------------------------------------------------------
\2363\ ``Network Resource shall mean any designated generating
resource owned, purchased, or leased by a Network Customer under the
Network Integration Transmission Service Tariff. Network Resources
do not include any resource, or any portion thereof, that is
committed for sale to third parties or otherwise cannot be called
upon to meet the Network Customer's Network Load on a non-
interruptible basis.'' Pro forma LGIP section 1; pro forma LGIA art.
1.
\2364\ NOPR, 179 FERC ] 61,194 at P 210. The term ``modeling
standard'' refers to the distribution factor threshold on a
transmission element used by transmission providers, such that
beyond this threshold an interconnection request will require
network upgrades. For example, in SPP, if a transmission element is
found to be overloaded in an interconnection study, and an NRIS
interconnection request has over a 3% distribution factor on that
element (3% being SPP's distribution factor threshold for NRIS
requests), the requesting entity will be assigned network upgrades.
SPP uses a 19.5% distribution factor threshold for ERIS requests.
See EDF Renewable Energy, Inc. v. Midcontinent Indep. Sys. Operator,
Inc., 168 FERC ] 61,173 at P 17. A lower threshold indicates a
stricter modeling standard because a smaller impact triggers network
upgrades. Additionally, when conducting an affected system analysis,
although some RTOs/ISOs (PJM and SPP, for example) use a modeling
standard associated with the same level of service as requested on
the host transmission provider's transmission system, the output of
proposed generating facilities is always sunk into the host
transmission provider's transmission system by reducing the output
of other generating facilities on that system. Id. P 85.
\2365\ See Order No. 2003, 104 FERC ] 61,103 at P 768; Order No.
2003-A, 106 FERC ] 61,220 at P 500. Specifically, a transmission
provider studying generating facility for NRIS would study the
transmission system at peak load, under a variety of severely
stressed conditions to determine whether, with the generating
facility operating at full output, the aggregate of generation in
the local area can be delivered to the aggregate of load, consistent
with reliability criteria and procedures.
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1257. As the Commission also explained in the NOPR, when a host
transmission provider notifies an affected system operator of a
possible impact on its system from an interconnection request in the
host's queue, it must specify whether the interconnection customer
requested ERIS or NRIS. Currently, there is no requirement for affected
system transmission providers to apply either ERIS or NRIS modeling
standards to study interconnection requests made on neighboring
systems. For example, MISO uses ERIS studies for all affected system
interconnection requests, while PJM and SPP use the modeling standard
associated with the level of service requested on the host system.
(They study ERIS requests as ERIS and NRIS requests as NRIS.) \2366\
---------------------------------------------------------------------------
\2366\ EDF Renewable Energy, Inc. v. Midcontinent Indep. Sys.
Operator, Inc., 168 FERC ] 61,173 at PP 75-76.
---------------------------------------------------------------------------
1258. In the NOPR, the Commission preliminarily found that it was
unjust and unreasonable for an affected system transmission provider to
study interconnection requests on other transmission systems using NRIS
modeling standards, regardless of the level of service requested on the
host transmission system. The Commission noted that, unlike the host
transmission provider with which the affected system interconnection
customer will directly interconnect, an affected system transmission
provider does not have a continuing obligation to operate its system so
that NRIS resources will remain deliverable on the host system. Without
such an obligation, the Commission stated that an affected system
interconnection customer may be required to construct significant
network upgrades on the transmission provider's affected system, but
not be fully deliverable due to curtailment or congestion on the
affected system. The Commission was concerned that this could result in
unjust and unreasonable rates by increasing the costs for the
interconnection customer without a commensurate increase in service.
1259. The Commission proposed to require, under new pro forma LGIP
section 9.6,\2367\ the affected system transmission provider to study
interconnection requests using ERIS modeling standards, regardless of
the requested level of service on the host transmission provider's
transmission system.\2368\
---------------------------------------------------------------------------
\2367\ We note that under the NOPR proposal, this reform was in
pro forma LGIP section 9.6; however, under the final rule, the
reform is in pro forma LGIP section 9.7.
\2368\ NOPR, 179 FERC ] 61,194 at P 211.
---------------------------------------------------------------------------
1260. The Commission also explained that if an affected system
transmission provider believed that it was necessary to study an
interconnection request that is requesting NRIS-level service using
NRIS modeling standards, such a transmission provider could make a
filing under FPA section 205. The Commission explained that it would
evaluate such case-by-case FPA section 205 filings to determine whether
they were just, reasonable, and not unduly discriminatory or
preferential.\2369\ The Commission noted that an affected system
transmission provider making this type of filing should provide
evidence indicating that using NRIS modeling standards in such a
scenario would not treat similarly situated customers differently or
afford similar treatment to dissimilar customers. In addition, this FPA
section 205 filing could contain, for example, such supporting
documentation as a reference to a NERC Reliability Standard violation,
an operational concern such as over-duty breakers, fault current
violations, impacts on transmission stability, increased loop flows, or
other concerns that implicate any other critical reliability
parameters.
---------------------------------------------------------------------------
\2369\ 16 U.S.C. 824d.
---------------------------------------------------------------------------
1261. The Commission stated that a modeling standard would create
consistency in the modeling standards used across all transmission
regions.\2370\ The Commission also stated that ERIS modeling standards
generally reduce the number and cost of network upgrades identified
and, by using ERIS modeling standards, interconnection customers would
be subject to fewer late-stage cost increases, which would reduce the
number of potential restudies and withdrawals thereby addressing the
concerns that the Commission has preliminarily found to result in
unjust, unreasonable, and unduly discriminatory or preferential
Commission-jurisdictional rates. The Commission acknowledged that using
a less stringent modeling standard may result in more frequent
redispatch or curtailment by not fully capturing all the potential
impacts of the interconnection generating facility(ies) on an affected
system.\2371\ Nevertheless, the Commission stated that it believed that
these risks were limited in nature and any significant impact would be
captured by an ERIS study, which would ensure that a proposed
generating facility can safely connect the affected system under the
expectation it will deliver its electric output using the existing firm
or non-firm capacity of the affected system transmission provider's
system on an as-available basis.
---------------------------------------------------------------------------
\2370\ The Commission noted that, while this proposal would
standardize the use of ERIS for affected system studies, individual
transmission providers use different specific thresholds for ERIS
studies. NOPR, 179 FERC ] 61,194 at P 212 n.292.
\2371\ Id. P 213.
---------------------------------------------------------------------------
1262. The Commission sought comment on: (1) how to align the
possibility for such case-by-case FPA section 205 filings with the
required timeline for the affected system study and other deadlines
proposed in the NOPR; (2) whether the proposed reform will adversely
affect reliability for the affected system transmission provider or the
host transmission provider; (3) the potential impact of requiring
affected system transmission providers to use ERIS modeling standards
when an interconnection customer seeks NRIS on the host transmission
provider's system; and (4) whether there are modifications to this
proposal that would reduce the likelihood of curtailment or redispatch
on the affected system transmission provider's system without requiring
the affected system interconnection customer to pay network upgrade
costs that are not commensurate with the level of service it
receives.\2372\
---------------------------------------------------------------------------
\2372\ Id. PP 211, 213, 215.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1263. Numerous commenters support the NOPR proposal.\2373\ ELCON
suggests that standardization of affected system modeling and
assumptions furthers certainty and accountability, resulting
[[Page 61191]]
in a more transparent, efficient, and cost-effective interconnection
process.\2374\ Some commenters argue that the NOPR proposal will reduce
the identification and assignment of unnecessary affected system
network upgrades under NRIS studies.\2375\ MISO and Shell contend that
ERIS modeling will adequately cover reliability for affected systems
and that they have no significant concerns regarding unnecessary
curtailment or redispatch on affected systems associated with ERIS
modeling.\2376\ Additionally, commenters contend that there is no need
to use NRIS modeling standards when the affected system interconnection
customer requests NRIS-level service on the host system because the
generating facility's output will not be delivered to the affected
system, and the NRIS standard serves the exclusive purpose of allowing
interconnection customers to be designated as a network resource on the
host system.\2377\ Some commenters claim that the NOPR proposal will
reduce the time required to conduct affected system study and
construction processes, as well as the likelihood of withdrawals once
the affected system necessary upgrades are identified.\2378\
---------------------------------------------------------------------------
\2373\ ACE-NY Initial Comments at 9; AES Initial Comments at 21;
Alliant Energy Initial Comments at 7; Clean Energy Associations
Initial Comments at 48; Clean Energy Associations Reply Comments at
12; ELCON Initial Comments at 8; Enel Initial Comments at 67-68;
Fervo Energy Initial Comments at 6; Invenergy Initial Comments at
44; MISO Initial Comments at 98; NextEra Initial Comments at 34; OMS
Initial Comments at 17; Pattern Energy Initial Comments at 26; Pine
Gate Initial Comments at 42; Shell Initial Comments at 31-32; UMPA
Initial Comments at 6.
\2374\ ELCON Initial Comments at 8.
\2375\ Fervo Energy Initial Comments at 6; UMPA Initial Comments
at 6.
\2376\ MISO Initial Comments at 98; Shell Initial Comments at
33.
\2377\ Fervo Energy Initial Comments at 6; Interwest Reply
Comments at 18; Invenergy Initial Comments at 44; NextEra Initial
Comments at 34; NextEra Reply Comments at 6; OMS Initial Comments at
17.
\2378\ OMS Initial Comments at 17; Pine Gate Initial Comments at
42; Public Interest Organizations Initial Comments at 51.
---------------------------------------------------------------------------
(b) Comments in Opposition
1264. Some commenters oppose the NOPR proposal.\2379\ AECI claims
that, without increasing the granularity of the redispatch and
curtailment process in real time to better understand the actual impact
an affected system interconnection customer has on the affected system
from a distribution factor standpoint, the NOPR proposal would produce
disproportionate burdens by reducing otherwise economical and reliable
generating facilities to accommodate resources that are outside an
affected system transmission provider's control.\2380\ Idaho Power
asserts that the NOPR proposal may not sufficiently capture network
upgrades that are jointly owned by multiple entities.\2381\
Specifically, Idaho Power states that the host transmission provider
``may not be the entity responsible for designing and constructing
network upgrades and interconnection facilities; therefore, the
affected party ERIS study may not provide sufficient details to be
meaningful.'' \2382\
---------------------------------------------------------------------------
\2379\ AECI Initial Comments at 7; AEP Initial Comments at 34;
Ameren Initial Comments at 23-24; Duke Southeast Utilities Initial
Comments at 28; EEI Initial Comments at 19; Illinois Commission
Initial Comments at 9; LADWP Initial Comments at 5; NRECA Initial
Comments at 39; Southern Initial Comments at 4, 16; SPP Initial
Comments at 20.
\2380\ AECI Initial Comments at 7.
\2381\ Idaho Power Initial Comments at 12.
\2382\ Id.
---------------------------------------------------------------------------
1265. Several commenters claim that the ERIS modeling requirement
for affected systems will negatively impact reliability.\2383\ AECI
argues that incentivizing ERIS-only studies would fundamentally affect
reliability by failing to address systemic de minimis issues that
become material in the aggregate.\2384\ Some commenters contend that,
under the NOPR proposal, reliability issues will not arise until the
operational time horizon, which could, as an example, result in an
increase in transmission loading relief events and redispatch of
network resources and native load.\2385\ LADWP asserts that the
dispatching assumptions of an interconnection request can make a
significant difference to flow patterns in the host system, and
parallel paths will inherently absorb the unscheduled flow intended for
the host system.\2386\ LADWP contends that, as the number of
interconnection requests continues to grow, these unscheduled flows
will continue to increase and begin to affect systems downstream of the
affected system, rather than just the local transmission system that
the ERIS modeling standard is designed to evaluate. LADWP claims that
the NOPR proposal would result in approval of generating facilities
without identification of sufficient network upgrades to accommodate
requested interconnection service, and affected system transmission
providers would be responsible for maintaining reliability by
developing operating procedures, capital projects, or performing
curtailments from the additional stress of energy that is not being
delivered to the affected system.
---------------------------------------------------------------------------
\2383\ AECI Initial Comments at 7; Illinois Commission Initial
Comments at 9; Southern Initial Comments at 16-17.
\2384\ AECI Initial Comments at 7.
\2385\ Ameren Initial Comments at 24; LADWP Initial Comments at
5; PJM Reply Comments at 10; Southern Initial Comments at 16-17.
\2386\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------
1266. AEP, SPP, and Xcel express concern that the proposed ERIS
modeling standard may harm firm transmission service on the affected
system.\2387\ AEP, NRECA, and Xcel argue that affected system
transmission providers should be able to use NRIS in affected system
studies if the affected system interconnection customer is requesting
NRIS-level service on the host transmission system to ensure the
required level of deliverability.\2388\ AEP states that, in the case
that the interconnection customer is requesting to interconnect to a
different RTO/ISO or is in a non-RTO/ISO, then an ERIS-only modeling
standard could result in the failure to construct affected system
network upgrades to mitigate congestion and/or loop flow once the new
generating facility commences operation, impacting loads that secured
and paid for firm transmission service and/or NRIS.\2389\
---------------------------------------------------------------------------
\2387\ AEP Initial Comments at 34; SPP Initial Comments at 20;
Xcel Initial Comments at 43.
\2388\ AEP Initial Comments at 34; NRECA Initial Comments at 39;
SPP Initial Comments at 20-21; Xcel Initial Comments at 43.
\2389\ AEP Initial Comments at 34.
---------------------------------------------------------------------------
1267. SPP is concerned that, if an affected system interconnection
customer requests NRIS-level service on the host transmission system
that grants deliverability rights without additional study procedures,
an affected system may be exposed to impacts that it has not had an
opportunity to evaluate under an ERIS modeling standard.\2390\ As an
example, SPP explains that SPP and MISO treat what constitutes firm
transmission service differently, but SPP's current ability to conduct
affected system studies under NRIS when the interconnection customer
has requested NRIS on the host system allows for that difference. In
response to SPP's concerns, NextEra argues that this issue appears to
be a problem of SPP's own making based on how SPP implemented ERIS and
NRIS on its own system and ignores that affected system interconnection
customers are not seeking deliverability or to be deemed firm on SPP's
transmission system through any sort of transmission service from
SPP.\2391\
---------------------------------------------------------------------------
\2390\ SPP Initial Comments at 20-21.
\2391\ NextEra Reply Comments at 6-7.
---------------------------------------------------------------------------
1268. Some commenters note that the proposal may not work in all
scenarios.\2392\ For instance, Clean Energy Associations state that
this proposal may not be appropriate for non-RTO/ISO regions, if these
impacts are not addressed through a coordinated transmission service
study.\2393\ Xcel believes that the use of ERIS modeling standards for
affected system studies
[[Page 61192]]
may be appropriate under a joint operating agreement or in areas where
the impact may be evaluated and mitigated in the transmission service
study process, but in other areas, if the impact will not be evaluated
in the transmission service study process, it is appropriate for an
affected system transmission provider to model the neighbor's NRIS
requests based on the expected delivery point.\2394\
---------------------------------------------------------------------------
\2392\ AEP Initial Comments at 34; Clean Energy Associations
Initial Comments at 48; SPP Initial Comments at 21-22; Xcel Initial
Comments at 43.
\2393\ Clean Energy Associations Initial Comments at 48.
\2394\ Xcel Initial Comments at 43-44.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
1269. Some commenters ask the Commission to make changes to the
NOPR proposal to mitigate the negative impacts they discuss in their
comments. For example, some commenters recommend that, in addition to
the ERIS modeling standard, the Commission should establish (or allow
affected system transmission providers to establish) a distribution
factor or impact threshold for affected system studies to ensure that
affected system interconnection customers are not assigned unnecessary
affected system network upgrades.\2395\ NextEra recommends that the use
of ERIS be included in the pro forma affected system study agreement to
require any affected system transmission provider proposing to use NRIS
rather than ERIS to file such agreement with the Commission on a non-
conforming basis.\2396\
---------------------------------------------------------------------------
\2395\ AES Initial Comments at 8, 21; Clean Energy Associations
Initial Comments at 48; Enel Initial Comments at 68; Pine Gate
Initial Comments at 42; SEIA Initial Comments at 35.
\2396\ NextEra Initial Comments at 34.
---------------------------------------------------------------------------
1270. Enel states that a critical interconnection issue not
addressed in the NOPR is the lack of clarification of ERIS and NRIS-
level service and how the different assumptions used by transmission
providers significantly alter results.\2397\ Enel explains that the
wide variety of views on what rights interconnection service grants to
an interconnection customer leads to confusion in the development of
study practices and requirements, as well as the services and products
a generating facility can provide. Enel requests that, in a final rule
or a supplemental notice, the Commission should provide concrete
direction regarding how these service types should be studied and what
outcome an interconnection customer should receive for making the
necessary transmission system improvements to obtain that
interconnection service. NV Energy requests that affected system
transmission providers and host transmission providers coordinate
assumptions for affected system studies and update those assumptions
quarterly after the affected system study has been issued to provide
meaningful changes.\2398\
---------------------------------------------------------------------------
\2397\ Enel Initial Comments at 26-27.
\2398\ NV Energy Initial Comments at 12.
---------------------------------------------------------------------------
1271. Some commenters note that a final rule should provide host
transmission providers with flexibility to work with their neighboring
regions to address modeling consistencies in transmission system
representations across regions.\2399\
---------------------------------------------------------------------------
\2399\ Duke Southeast Utilities Initial Comments at 27-28; NYISO
Initial Comments at 46.
---------------------------------------------------------------------------
1272. Some commenters specifically support allowing transmission
providers to use NRIS modeling standards for affected system studies
pursuant to separate FPA section 205 filings, as proposed in the
NOPR.\2400\ Duke Southeast Utilities assert that the Commission should
remove any negative repercussions, including any financial penalties or
liability for breaching deadlines of the study process, for affected
system transmission providers that seek to make such FPA section 205
filings.\2401\
---------------------------------------------------------------------------
\2400\ AES Initial Comments at 21; Clean Energy Associations
Initial Comments at 48; Fervo Energy Initial Comments at 6.
\2401\ Duke Southeast Utilities Initial Comments at 27-28.
---------------------------------------------------------------------------
1273. Several commenters argue that affected system transmission
providers should be able to use NRIS when conducting affected system
studies without requiring the NOPR's proposed FPA section 205
filing.\2402\ A few commenters argue that the requirement to make an
FPA section 205 filing to use NRIS modeling standards will create
delays and is overly burdensome on affected system transmission
providers.\2403\ SPP claims that, as proposed in the NOPR, an FPA
section 205 filing to use NRIS modeling assumptions would require
supporting documentation amounting to evidence that the affected system
transmission provider could only obtain if it conducted a study using
the standards of the heightened level of service, which it could not do
absent the Commission's grant of a waiver to require such a
study.\2404\ Invenergy argues that the option for an FPA section 205
request to conduct an affected system study using NRIS criteria invites
case-by-case disputes over modeling criteria, potentially delaying the
affected system study process. Therefore, Invenergy argues that the
Commission should clarify that any such filing must be limited to only
the facts of an individual interconnection request.\2405\
---------------------------------------------------------------------------
\2402\ Id. at 28; AECI Initial Comments at 7; AEP Initial
Comments at 34; Ameren Initial Comments at 23-24; EEI Initial
Comments at 19; Illinois Commission Initial Comments at 9; LADWP
Initial Comments at 5; NRECA Initial Comments at 39; Southern
Initial Comments at 4, 16; SPP Initial Comments at 20.
\2403\ AECI Initial Comments at 7; AEP Initial Comments at 34;
Duke Southeast Utilities Initial Comments at 27; EEI Initial
Comments at 19; LADWP Initial Comments at 5; MISO Initial Comments
at 98; Southern Initial Comments at 16; SPP Initial Comments at 20.
\2404\ SPP Initial Comments at 20.
\2405\ Invenergy Initial Comments at 44-45.
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1274. Xcel states that the Commission should: (1) remove the ERIS
option in RTO/ISO markets and require all generating facilities in such
markets to be deliverable; (2) curtail generating facilities that did
not pay for long-term firm transmission service; or (3) convene a
technical conference on this topic in this docket.\2406\ Xcel explains
that ERIS-only generating facilities in RTO/ISO markets may place a bid
to sell into the market, and the ERIS-only generating facilities will
be dispatched to the extent a bid clears, while in other areas, the
ERIS-only generating facilities must acquire transmission service to be
delivered.\2407\ Xcel concludes that ERIS service in RTO/ISO markets
results in unjust and unreasonable rates and discriminatory treatment
because ERIS-level generating facilities do not bear the costs
necessary to ensure that they are deliverable to load. Xcel claims
that: (1) the affected system transmission provider should not have to
assume it will redispatch its own network resources to accommodate an
affected system interconnection customer taking NRIS-level service; (2)
the affected system's network resources paid for and expect to receive
firm transmission service; and (3) there is no process for a host
transmission provider to require an affected system transmission
provider to redispatch its transmission system to accommodate a
generating facility on the host system under the pro forma
tariff.\2408\
---------------------------------------------------------------------------
\2406\ Xcel Initial Comments at 16, 41-42.
\2407\ Id. at 15.
\2408\ Id. at 43.
---------------------------------------------------------------------------
1275. NRECA asserts that the final rule should allow a
``transmission customer'' to propose a different standard through an
FPA section 206 complaint.\2409\ NextEra and MISO suggest that, to
avoid delays in the interconnection process, any affected system
transmission provider submitting an FPA section 205 filing to use NRIS
modeling in an affected system study should proceed with the affected
system study, using both the ERIS and NRIS standards, and then the
appropriate results could be used based on the outcome of the FPA
section 205
[[Page 61193]]
proceeding.\2410\ MISO also encourages the Commission to recognize that
this FPA section 205 filing process will add length and delay to the
affected system study process, which further compounds and demonstrates
the problems with the Commission's automatic penalty proposal.\2411\
---------------------------------------------------------------------------
\2409\ NRECA Initial Comments at 40.
\2410\ MISO Initial Comments at 98; NextEra Initial Comments at
34.
\2411\ MISO Initial Comments at 98.
---------------------------------------------------------------------------
iii. Commission Determination
1276. We adopt the NOPR proposal, with modification, to add section
9.7 to the pro forma LGIP to require affected system transmission
providers to study all affected system interconnection requests using
ERIS modeling standards.\2412\ We decline to adopt the NOPR proposal to
expressly acknowledge in pro forma LGIP section 9.7 that an affected
system transmission provider may submit an FPA section 205 filing to
request to study an affected system interconnection customer using NRIS
on a case-by-case basis.
---------------------------------------------------------------------------
\2412\ In relevant part, pro forma LGIP section 9.7 states:
``Transmission Provider must study an Affected System
Interconnection Customer using the Energy Resource Interconnection
Service modeling standard used for Interconnection Requests on its
own Transmission System, regardless of the level of interconnection
service that Affected System Interconnection Customer is seeking
from the host transmission provider with whom it seeks to
interconnect.''
---------------------------------------------------------------------------
1277. We find that the use of ERIS in affected system studies is
just and reasonable, given that the affected system transmission
provider has no obligation to continually ensure deliverability for an
affected system interconnection customer that has obtained NRIS on its
host system. An NRIS study goes beyond the prerequisite ERIS study and
uses stricter modeling standards to assess an interconnection request
to ensure that the interconnection customer's electric output is
deliverable to load in aggregate on the host transmission provider's
transmission system.\2413\ We find that the use of ERIS for affected
system studies is consistent with Order No. 2003 because
interconnection is separate from the deliverability component of
transmission service.\2414\
---------------------------------------------------------------------------
\2413\ See Order No. 2003, 104 FERC ] 61,103 at P 768; Order No.
2003-A, 106 FERC ] 61,220 at P 500. Specifically, a transmission
provider studying a generating facility for NRIS would study the
transmission system at peak load, under a variety of severely
stressed conditions to determine whether, with the generating
facility operating at full output, the aggregate of generation in
the local area can be delivered to the aggregate of load, consistent
with reliability criteria and procedures.
\2414\ Order No. 2003, 104 FERC ] 61,103 at P 118; Order No.
2003-A, 106 FERC ] 61,220 at P 113.
---------------------------------------------------------------------------
1278. We also find that this requirement is likely to prevent an
affected system interconnection customer from being required to
construct significant network upgrades on the transmission provider's
affected system, but not being deliverable due to curtailment or
congestion on the affected system. Without this reform, rates would
continue to be unjust and unreasonable because an affected system
interconnection customer would face increased costs without a
commensurate increase in service, as explained in the NOPR. This
mismatch between costs and services received would occur because the
affected system transmission provider has no obligation to ensure that
the output from the affected system interconnection customer's
generating facility is deliverable on the affected system and could
lead to curtailment of the generating facility, or there could be
congestion on the affected system preventing deliverability of the
generating facility's output.
1279. We also find that, if the affected system transmission
provider were able to study affected system interconnection customers
under an NRIS standard, it could require affected system
interconnection customers to pay significant upfront costs in order to
construct the required affected system network upgrades, which could
lead to late-stage interconnection request withdrawals as
interconnection customers will not receive affected system study
results until late in the interconnection process. An ERIS standard
ensures that the assigned affected system network upgrade costs will
likely be lower and that affected system interconnection customers
assigned affected system network upgrades will be less likely to
withdraw at a late stage. This standard will help prevent the cascading
restudies that commenters have observed \2415\ and will ensure that the
interconnection process operates more efficiently.
---------------------------------------------------------------------------
\2415\ OMS Initial Comments at 17; Pine Gate Initial Comments at
42.
---------------------------------------------------------------------------
1280. We also find that the use of ERIS in affected system study
processes across all transmission provider regions will create
consistency and provide transparency for affected system
interconnection customers. Currently, similarly situated
interconnection customers requesting NRIS on their host transmission
systems could have disparate impacts on affected systems that use
different modeling standards, and these interconnection customers could
be assigned dramatically different affected system network upgrade
costs due to those varying modeling standards, without any factual or
service differences to justify the discriminatory treatment. Thus, the
consistent application of ERIS in affected system studies across all
transmission providers' study processes will ensure that all affected
system interconnection customers are studied similarly.\2416\ As such,
we agree with commenters that the use of ERIS on all affected system
interconnection requests will increase certainty and
transparency.\2417\
---------------------------------------------------------------------------
\2416\ Order No. 2003, 104 FERC ] 61,103 at P 11 (stating that a
standard set of interconnection procedures will, among other things,
expedite the development of new generation, while protecting
reliability and ensuring that rates are just and reasonable).
\2417\ ELCON Initial Comments at 8; Fervo Energy Initial
Comments at 6; UMPA Initial Comments at 6.
---------------------------------------------------------------------------
1281. We find outside the scope of this final rule Xcel's request
that the Commission require all generating facilities in RTO/ISO
markets to be deliverable and its claim that ERIS-level generating
facilities do not bear the costs necessary to ensure that they are
deliverable to load.\2418\ We are not proposing in this final rule to
alter how an interconnection customer in an RTO/ISO requests its type
of interconnection service on the host system (i.e., ERIS or NRIS);
rather, we are standardizing how an affected system transmission
provider studies an affected system interconnection request.
---------------------------------------------------------------------------
\2418\ Xcel Initial Comments at 15-16, 41-42.
---------------------------------------------------------------------------
1282. Regarding AECI's claim that the NOPR proposal would produce
disproportionate burdens by necessitating curtailment from economical
and reliable generating facilities to accommodate generating facilities
on a different transmission system unless overall granularity of the
redispatch and curtailment process is increased in real time, we find
no evidence of this concern, from AECI or otherwise.\2419\ Rather, AECI
appears concerned that generating facilities on its transmission system
may be redispatched and curtailed, which we have acknowledged may
occur.\2420\ Additionally, we note the transmission loading relief
procedures set the priority for curtailing generating facilities as
necessary, and this final rule is not revising those procedures.
Finally, to the extent that the costs associated with increasing the
overall granularity of real-time models is less than any hypothetical
increase in curtailment and redispatch costs, a transmission provider
may increase the real-time granularity of its model.
---------------------------------------------------------------------------
\2419\ AECI Initial Comments at 7.
\2420\ NOPR, 179 FERC ] 61,194 at P 213.
---------------------------------------------------------------------------
1283. Further, we find that Idaho Power has not adequately
explained how this reform will result in
[[Page 61194]]
insufficiently identifying network upgrades that are jointly owned by
multiple entities.\2421\ Moreover, even if this were a valid concern,
we find that this concern would be equally present regardless of the
modeling standard (i.e., ERIS or NRIS) used to conduct the affected
system study.
---------------------------------------------------------------------------
\2421\ Idaho Power Initial Comments at 12.
---------------------------------------------------------------------------
1284. As discussed in the NOPR proposal, using a less stringent
modeling standard may result in more frequent redispatch or curtailment
by not fully capturing all the potential impacts of the affected system
interconnection customer's generating facility(ies) on an affected
system. Based on the record, we continue to find that these risks are
limited in nature, particularly in non-RTO/ISO regions where
interconnection service does not, by itself, allow a generating
facility's power to flow. In non-RTO/ISO regions, power can only flow
from a generating facility once transmission service has been requested
and granted. For example, once point-to-point transmission service has
been requested to enable a particular generating facility's power to
flow, either by the generating facility itself or its power sale
customer, pro forma open access transmission tariff section 21
(Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities) provides a process similar to the affected
system process in the pro forma LGIP. In summary, pro forma open access
transmission tariff section 21 makes the transmission customer
responsible for obtaining any necessary engineering, permitting, and
construction of transmission or distribution facilities on the
system(s) of utilities other than the directly connected transmission
provider, but requires that transmission provider to undertake
reasonable efforts to assist in that effort. This means that affected
systems will have another opportunity to study the impact of the
interconnection customer's generating facility in the context of this
transmission service request, whether a new point-to-point transmission
service request or designation as a new network resource under an
existing transmission customer's network integration transmission
service, before any power can flow from the generating facility.
1285. Moreover, we find that any significant impact would generally
be captured by an ERIS study, which would ensure that any reliability
impacts on the affected system are mitigated to accommodate the
interconnection of the affected system interconnection customer's
proposed generating facility to the host system. That ERIS adequately
studies an affected system interconnection customer's interconnection
request for its reliability impacts on the affected system is evidenced
by MISO's use of only ERIS in affected system studies without adverse
reliability impacts.\2422\
---------------------------------------------------------------------------
\2422\ MISO Initial Comments at 98.
---------------------------------------------------------------------------
1286. Regarding AECI's claim that using only ERIS in affected
system studies may result in increased de minimis impacts,\2423\ we are
not setting the implementation of the ERIS standard. Rather, each
transmission provider determines its own implementation of that
standard, which could include a de minimis threshold that is best for
its region. The Commission has found that, if consistently applied, it
is reasonable for interconnection customers to not bear cost
responsibility for de minimis impacts on transmission facilities based
on a threshold.\2424\ Additionally, we expect that any overloads in the
models due to the accumulation of de minimis impacts will ultimately be
assigned, pursuant to the transmission provider's tariff, when an
interconnection customer triggers the need for a network upgrade or
when the transmission provider's reliability transmission planning
process identifies the need for mitigation.
---------------------------------------------------------------------------
\2423\ AECI Initial Comments at 7.
\2424\ Tenaska Clear Creek Wind, LLC v. Sw. Power Pool, Inc.,
180 FERC ] 61,160, at P 99 (2022).
---------------------------------------------------------------------------
1287. We disagree with LADWP that the use of ERIS by an affected
system transmission provider will result in approval of generating
facilities with insufficient network upgrades identified.\2425\ As
discussed above, we find that, in general, the use of ERIS is
sufficient for affected system studies to prevent reliability issues
from occurring on the affected system. Moreover, as noted earlier, in
non-RTO/ISO regions, power can only flow from a generating facility
once transmission service has been requested and granted, meaning that
affected systems will have another opportunity to study the impact of
the interconnection customer's generating facility in the context of
the associated transmission service request before any power can flow
from that generating facility as explained above.
---------------------------------------------------------------------------
\2425\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------
1288. Similarly, we find that commenters' concerns about harm to
firm transmission service and cost shifting when using ERIS in affected
system studies are misplaced because those concerns do not arise until
the interconnection customer seeks to deliver power from its generating
facility to a customer, which outside of RTO/ISO regions can only
happen once transmission service is separately secured.\2426\ In Order
No. 2003, the Commission found that interconnection service is separate
from the delivery component of transmission service, and, in the
majority of circumstances, interconnection alone is unlikely to affect
the reliability of an affected system transmission provider's
transmission system.\2427\ Additionally, the Commission found that
holding new interconnection customers responsible for network upgrades
to all interconnected systems, including not only the transmission
system to which the generating facility interconnects, but other, more
distant transmission systems as well would create an unreasonable
obstacle to the construction of new generation.\2428\ As such, if an
affected system interconnection customer subsequently seeks
deliverability on either the host system or an affected system and
submits a transmission service request to either the host transmission
provider or the affected system transmission provider, the affected
system transmission provider will have the opportunity to study the
request and potentially require the construction of additional network
upgrades on the affected system to accommodate deliverability.
Therefore, we find that being assigned significant affected system
network upgrades under an NRIS study without the obligation for the
affected system transmission provider to ensure that the output from an
affected system interconnection customer's generating facility is
integrated on the affected system similar to generating facilities that
serve the affected system transmission provider's native load customers
or network resources results in unjust and unreasonable rates by
increasing the cost for affected system interconnection customers
without a commensurate increase in service.\2429\
---------------------------------------------------------------------------
\2426\ AEP Initial Comments at 34; NRECA Initial Comments at 39;
SPP Initial Comments at 20-21; Xcel Initial Comments at 43.
\2427\ Order No. 2003, 104 FERC ] 61,103 at P 118; Order No.
2003-A, 106 FERC ] 61,220 at P 113.
\2428\ Order No. 2003, 104 FERC ] 61,103 at P 120.
\2429\ As stated in section III.A.1, the pro forma LGIP defines
NRIS service as ``an Interconnection Service that allows the
Interconnection Customer to integrate its Large Generating Facility
with the Transmission Provider's Transmission System (1) in a manner
comparable to that in which the Transmission Provider integrates its
generating facilities to serve native load customers; or (2) in an
RTO or ISO with market based congestion management, in the same
manner as Network Resources. Network Resource Interconnection
Service in and of itself does not convey transmission service.'' Pro
forma LGIP section 1.
---------------------------------------------------------------------------
[[Page 61195]]
1289. Regarding claims that affected system transmission providers
would need to develop operating procedures or capital projects or
perform curtailments due to the additional stress on affected systems
caused by affected system interconnection requests being studied under
the ERIS modeling standard,\2430\ we find these claims to be
speculative and that affected system studies are designed to ensure
that an affected system interconnection customer's proposed generating
facility can reliably connect to the host system without adversely
impacting an affected system and are not meant to ensure deliverability
on either the host or affected system. As mentioned above, an affected
system transmission provider has no obligation to ensure that an
affected system interconnection request is fully deliverable.
---------------------------------------------------------------------------
\2430\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------
1290. We are unpersuaded by arguments that the NOPR proposal may
not work in all scenarios \2431\ and note that commenters did not
provide specific examples of how the proposal would not work under the
Commission's pro forma LGIP process. Several commenters raise concerns
that, although the use of ERIS may work in regions with joint operating
agreements or coordinated transmission service studies, the use of ERIS
for all affected system studies may not be appropriate if an affected
system transmission provider's transmission service studies do not
identify all impacts. Once again, in adopting the ERIS requirement for
affected system transmission providers, we find that ERIS is sufficient
to capture reliability impacts of affected system interconnection
requests on the affected system. We do not address whether individual
transmission providers have adequate transmission service studies. If a
transmission provider believes that changes are needed to better
consider the deliverability of transmission service on its transmission
system or with its neighboring transmission systems, nothing in this
final rule prevents transmission providers from addressing those
concerns.
---------------------------------------------------------------------------
\2431\ AEP Initial Comments at 34; Clean Energy Associations
Initial Comments at 48; SPP Initial Comments at 20-21; Xcel Initial
Comments at 43.
---------------------------------------------------------------------------
1291. We decline requests for the Commission to set modeling
standards, to require transmission providers to include their modeling
standards in their tariffs, or to provide direction on how ERIS and
NRIS should be studied and what service the interconnection customer
should receive, and to require neighboring transmission providers to
coordinate assumptions and update those assumptions quarterly.\2432\ We
find these requests to be outside the scope of the final rule.
---------------------------------------------------------------------------
\2432\ AES Initial Comments at 8, 21; Clean Energy Associations
Initial Comments at 48; Enel Initial Comments at 27, 68; NV Energy
Initial Comments at 12; Pine Gate Initial Comments at 42; SEIA
Initial Comments at 35.
---------------------------------------------------------------------------
1292. Although some commenters request flexibility on whether to
use ERIS or NRIS in conducting an affected system study,\2433\ we find
such a request is essentially a request to maintain the status quo,
which, as discussed above, results in Commission-jurisdictional rates
that are unjust, unreasonable, and unduly discriminatory or
preferential and prevents interconnection customers from
interconnecting in a reliable, efficient, transparent, and timely
manner.
---------------------------------------------------------------------------
\2433\ Duke Southeast Utilities Initial Comments at 27-28; NYISO
Initial Comments at 46.
---------------------------------------------------------------------------
1293. We decline to adopt the proposal stating that an affected
system transmission provider may make an FPA section 205 filing to
request use of an NRIS modeling standard in affected system studies. We
find that there is no need to expressly provide for the availability of
an FPA section 205 filing in pro forma LGIP section 9.7 because
transmission providers always have the right to submit an FPA section
205 filing.
3. Optional Resource Solicitation Study
a. NOPR Proposal
1294. In the NOPR, the Commission explained that resource
solicitation processes inspire a number of interconnection requests,
but in most cases, state agencies and LSEs implementing state mandates
do not have the opportunity to request dedicated studies
themselves.\2434\
---------------------------------------------------------------------------
\2434\ NOPR, 179 FERC ] 61,194 at P 211.
---------------------------------------------------------------------------
1295. The Commission proposed to revise the pro forma LGIP to
require transmission providers to allow resource planning entities,
i.e., any entity required to develop a resource plan or conduct a
resource solicitation process, including a state entity or LSE, to
initiate an optional resource solicitation study.\2435\
---------------------------------------------------------------------------
\2435\ Id. P 223.
---------------------------------------------------------------------------
1296. Under the NOPR proposal, the resource planning entity would
identify the valid interconnection requests associated with its
qualifying resource solicitation process or qualifying resource plan
and request that the transmission provider study several combinations
of those interconnection requests in a resource solicitation
study.\2436\
---------------------------------------------------------------------------
\2436\ Id. P 224.
---------------------------------------------------------------------------
1297. The Commission clarified that under this proposal, the
resource planning entity would not receive a queue position:
interconnection customers would maintain their queue position obtained
through the cluster request window and proceed through the regular
interconnection queue alongside all other customers.\2437\
---------------------------------------------------------------------------
\2437\ Id. P 226.
---------------------------------------------------------------------------
1298. The Commission proposed that the transmission provider must
evaluate each combination of interconnection requests submitted by the
resource planning entity as a group, in the same manner it will perform
cluster studies under the proposed pro forma LGIP.\2438\ The Commission
proposed a 135-calendar day time limit on the optional resource
solicitation study (compared to 150 calendar days for the cluster
study).
---------------------------------------------------------------------------
\2438\ Id. P 233.
---------------------------------------------------------------------------
1299. The Commission sought comment on: (1) the NOPR proposal to
explicitly include state agencies that are required to develop a
resource plan or conduct a resource solicitation process in the
definition of a resource planning entity; (2) whether other entities
should qualify as resource planning entities and therefore be able to
request initiation of an optional resource solicitation study, and, if
so, what impact, if any, their inclusion would have on the efficiency
of the interconnection process and whether their inclusion would raise
concerns of undue discrimination or preference; (3) whether the
proposed optional resource solicitation study raises any
confidentiality concerns, including whether the optional resource
solicitation study report could be posted on the transmission
provider's OASIS before the qualifying solicitation process has
concluded; and (4) what, if any, challenges multistate transmission
providers--in particular, those RTOs/ISOs that serve large, multi-state
areas--may face regarding study timing, multiple concurrent studies, or
other issues in offering an optional resource solicitation study
option, and any proposals to mitigate such challenges.\2439\
---------------------------------------------------------------------------
\2439\ Id. PP 236-237.
---------------------------------------------------------------------------
b. Comments
i. Comments in Support
1300. Many commenters support the NOPR proposal and note that the
ability to gather holistic information on a range of resource mix
scenarios from transmission providers would support efforts by states
and other resource planning entities to meet policy
[[Page 61196]]
objectives.\2440\ The North Dakota Commission notes that resource
solicitation studies could help improve coordination and make state-
level, bottom-up resource planning processes more efficient and cost-
effective.\2441\ Similarly, [Oslash]rsted argues that resource
solicitation studies have the potential to reduce the uncertainty
involving the interconnection cost portion of future state-sponsored
resource solicitations.\2442\
---------------------------------------------------------------------------
\2440\ Clean Energy States Initial Comments at 9; Colorado
Commission Reply Comments at 2; Consumers Energy Initial Comments at
8; EEI Initial Comments at 5-6; Illinois Commission Initial Comments
at 11; Iowa Commission Initial Comments at 6; NARUC Initial Comments
at 25; NESCOE Initial Comments at 17; New Jersey Commission Initial
Comments at 16-17; North Carolina Commission Initial Comments at 26;
Northwest and Intermountain Initial Comments at 15; [Oslash]rsted
Initial Comments at 15; OPSI Initial Comments at 7; Public Interest
Organizations Initial Comments at 37-38.
\2441\ North Dakota Commission Initial Comments at 7.
\2442\ [Oslash]rsted Initial Comments at 15.
---------------------------------------------------------------------------
ii. Comments in Opposition
1301. AES states that it does not believe reforms on this issue
should be part of the final rule but does not oppose transmission
providers submitting optional resource solicitation study proposals to
the Commission pursuant to separate FPA section 205 filings after
consultation with stakeholders.\2443\
---------------------------------------------------------------------------
\2443\ AES Initial Comments at 22.
---------------------------------------------------------------------------
1302. AEP disagrees with the Commission's conclusion that failure
to provide for a resource solicitation process leads to unjust and
unreasonable rates.\2444\ AEP argues that this reasoning only applies
to ``entities required to conduct a resource plan or resource
solicitation process'' and that, accordingly, there is no legal basis
to ``solve'' the problem through a nationwide mandate, as transmission
providers with no LSEs that are required to ``conduct a resource plan
or resource solicitation process'' do not need to amend their tariffs
to include the optional resource solicitation study proposal. AEP
asserts that there is no evidence that LSEs in RTOs/ISOs need the
optional resource solicitation study process to perform IRPs
efficiently and reach appropriate procurement decisions. AECI argues
that resource planning entities should maintain discretion over their
portfolios, and that the Commission lacks jurisdiction to mandate
deployment of any particular resource or to require transmission
providers to provide preferential treatment towards any specific
technology.\2445\
---------------------------------------------------------------------------
\2444\ AEP Initial Comments at 39-40.
\2445\ AECI Initial Comments at 8.
---------------------------------------------------------------------------
1303. Several commenters argue that the proposed optional resource
solicitation study is unnecessary, particularly in regions such as PJM
and MISO, which have existing or proposed processes for considering
state objectives.\2446\
---------------------------------------------------------------------------
\2446\ Dominion Initial Comments at 39; Dominion Reply Comments
at 24; Indicated PJM TOs Initial Comments at 51; MISO Initial
Comments at 9, 98-102; MISO Reply Comments at 11; National Grid
Initial Comments at 39; OMS Initial Comments at 18.
---------------------------------------------------------------------------
1304. CAISO and SPP argue that the proposed optional resource
solicitation study may create uncertainty regarding the cost and timing
of interconnecting to the transmission system.\2447\ CAISO asserts that
it is impossible to provide meaningful cost data to interconnection
customers until the transmission provider knows precisely the entire
make-up of the study cluster.\2448\
---------------------------------------------------------------------------
\2447\ CAISO Initial Comments at 30; SPP Initial Comments at 22.
\2448\ CAISO Initial Comments at 31.
---------------------------------------------------------------------------
1305. Several commenters question the efficacy of the resource
solicitation study proposal.\2449\ PJM argues that, because the study
would include only a subset of the clustered interconnection requests,
the results would not be indicative of the outcome when considering the
entire cluster, and would not provide information upon which resource
planning entities could act or base decisions.\2450\ Enel and Indicated
PJM TOs argue that the studies would not be expected to yield a
reliable estimate of the total costs of the portfolio of resources
being contemplated by the resource planner.\2451\ Similarly, Indicated
PJM TOs argue that optional studies will divert scarce resources away
from curing the fundamental problem, arguing that such studies may not
be valuable to resource planners because they would be conducted in a
vacuum, would not account for other interconnection requests, and would
not necessarily lead to the most efficient combination of
resources.\2452\
---------------------------------------------------------------------------
\2449\ AEE Initial Comments at 35; Enel Initial Comments at 71;
Indicated PJM TOs Initial Comments at 50.
\2450\ PJM Initial Comments at 50.
\2451\ Enel Initial Comments at 71; Indicated PJM TOs Initial
Comments at 50.
\2452\ Indicated PJM TOs Initial Comments at 50.
---------------------------------------------------------------------------
1306. Some commenters assert that prospective interconnection
customers will have an incentive to lodge speculative interconnection
requests antithetical to the desired streamlining of the pro forma LGIA
and pro forma LGIP process contemplated by the NOPR.\2453\ APPA-LPPC
comment that, to the extent that the generating facilities associated
with interconnection requests are competing in a resource solicitation
in which they may not be selected, such interconnection requests could
constitute the kind of speculative interconnection request that the
NOPR otherwise discourages.\2454\
---------------------------------------------------------------------------
\2453\ AECI Initial Comments at 8; Enel Initial Comments at 69.
\2454\ APPA-LPPC Initial Comments at 27.
---------------------------------------------------------------------------
1307. Several commenters argue that the optional resource
solicitation study will result in inefficiencies and delays that
degrade the quality of the main cluster study.\2455\ Several commenters
express concern that adding optional resource solicitation studies as a
pro forma LGIP requirement would hinder the Commission's goal of
increasing the speed of processing interconnection requests, arguing
that the additional study requirements are time consuming and would
require significant resources to complete.\2456\ Enel states that,
because a transmission provider would be required to evaluate six full
cluster studies (i.e., one standard plus five sensitivities) with
different combinations of generating facilities, the optional resource
solicitation study would inevitably lead to delays, restudies, late-
stage withdrawals, errors, and increased potential for inadequate
consideration of lower cost and alternative mitigations.\2457\ The
Colorado Commission argues that the NOPR proposal could materially
delay the clean energy transition in Colorado given interconnection
scarcity concerns if it required the elimination of resource
solicitation clusters as currently implemented by the Colorado
utilities.\2458\
---------------------------------------------------------------------------
\2455\ Id.; AECI Initial Comments at 8; Bonneville Initial
Comments at 22; CAISO Initial Comments 30-31; CREA and NewSun Reply
Comments at 55; Dominion Initial Comments at 39; Enel Initial
Comments at 69; Illinois Commission Initial Comments at 11; NARUC
Initial Comments at 31; NextEra Initial Comments at 35; NYISO
Initial Comments at 46; PJM Initial Comments at 5-6.
\2456\ Bonneville Initial Comments at 22; CAISO Initial Comments
30-31; CREA and NewSun Reply Comments at 55; Enel Initial Comments
at 69; Illinois Commission Initial Comments at 11; NARUC Initial
Comments at 31; NextEra Initial Comments at 35; NYISO Initial
Comments at 46; PJM Initial Comments at 6; SEIA Reply Comments at
18, 21; SPP Initial Comments at 22.
\2457\ Enel Initial Comments at 69-71.
\2458\ Colorado Commission Reply Comments at 3.
---------------------------------------------------------------------------
1308. Some commenters question whether transmission providers can
realistically manage interconnection cluster studies and perhaps
multiple optional resource solicitation studies at the same time.\2459\
Indicated PJM TOs
[[Page 61197]]
state that the ability for any resource planning entity to initiate the
resource solicitation study without warning at any time would be
especially burdensome.\2460\ MISO warns that multiple resource planning
entities could request an optional study with different combinations,
requiring MISO to perform numerous iterations of its system impact
studies.\2461\ Several commenters argue that instituting an additional
study will put further strain on transmission providers' limited staff
resources.\2462\ Bonneville, WAPA, and NRECA assert that most small
transmission providers are not staffed or organized to accomplish the
work discussed by the Commission.\2463\
---------------------------------------------------------------------------
\2459\ Indicated PJM TOs Initial Comments at 50; MISO Initial
Comments at 101-102; Northwest and Intermountain Initial Comments at
16-17; NRECA Initial Comments at 41-42; PJM Initial Comments at 6.
\2460\ Indicated PJM TOs Initial Comments at 50; Indicated PJM
TOs Reply Comments at 18.
\2461\ MISO Initial Comments at 102.
\2462\ Dominion Initial Comments at 39; Indicated PJM TOs
Initial Comments at 50; National Grid Initial Comments at 38-39;
NYISO Initial Comments at 46; PJM Initial Comments at 6; SEIA
Initial Comments at 36.
\2463\ Bonneville Initial Comments at 22; WAPA Initial Comments
at 14; NRECA Initial Comments at 41-42.
---------------------------------------------------------------------------
1309. Several commenters caution the Commission that the optional
resource solicitation studies could be costly.\2464\ MISO contends that
mandating a new study activity without a corresponding study deposit
may result in a situation where study deposit funds run out, halting
interconnection studies until more funds are provided and leading to
interconnection queue delays.\2465\ NRECA also argues that requiring
both the optional informational interconnection studies and the
optional resource solicitation studies increase costs for transmission
customers.\2466\ SEIA argues that imposing an optional resource
solicitation process in the early stages of the interconnection
process, before interconnection customers receive the cost estimates of
their network upgrades, means that the results from the study may not
accurately reflect the costs of the network upgrades for the resources
in the study.\2467\ Enel argues that, because the resource planning
entity selects generating facilities for scenarios without any
knowledge of interconnection results, it is possible that the selected
generating facilities will end up being built despite large upgrade
costs.\2468\
---------------------------------------------------------------------------
\2464\ Clean Energy Associations Initial Comments at 51;
Illinois Commission Initial Comments at 11; MISO Initial Comments at
103.
\2465\ MISO Initial Comments at 103.
\2466\ NRECA Initial Comments at 41-42.
\2467\ SEIA Reply Comments at 18-19.
\2468\ Enel Initial Comments at 72.
---------------------------------------------------------------------------
1310. Several commenters contend that the proposal is unjust,
unreasonable, and unduly discriminatory or preferential because it
gives special treatment to generating facilities selected to fulfill a
resource plan without full consideration of interconnection
upgrades.\2469\ Several commenters are concerned that this proposal
could allow vertically integrated transmission providers or LSEs to use
the process in a way that would inappropriately favor the
interconnection of company-owned resources.\2470\ NARUC and SEIA
explain that an LSE could have a transmission provider identify cost-
saving interconnection options through the optional resource
solicitation study for company-owned resources but exclude non-company-
owned resources from the analysis, thus tipping the cost evaluation in
favor of the company's resources.\2471\ Likewise, Interwest and EPSA
are concerned that priority in interconnection queue processing for
interconnection requests selected in a resource plan and under contract
with a utility may provide competitive advantages for vertically
integrated utilities because of their control over the selection of
projects and the identification and timing of the installation of
network upgrades.\2472\
---------------------------------------------------------------------------
\2469\ Id. at 68, 72; AEE Initial Comments at 35-36; EPSA
Initial Comments at 12; Interwest Initial Comments at 9; Interwest
Reply Comments at 8; MISO Initial Comments at 98; OMS Initial
Comments at 18; PJM Initial Comments at 50-51; SEIA Reply Comments
at 19-20.
\2470\ AEE Initial Comments at 36; CREA and NewSun Initial
Comments at 89; EPSA Initial Comments at 11-12; Interwest Initial
Comments at 9-10; NARUC Initial Comments at 26-27; Northwest and
Intermountain Initial Comments at 15-16; Public Interest
Organizations Initial Comments at 41; SEIA Initial Comments at 36.
\2471\ NARUC Initial Comments at 26-27; SEIA Initial Comments at
36; SEIA Reply Comments at 20.
\2472\ EPSA Initial Comments at 12; Interwest Initial Comments
at 9-10.
---------------------------------------------------------------------------
1311. SEIA also argues that an optional resource solicitation study
in situations where there is a commercial readiness requirement
presents numerous opportunities for a utility to discriminate against
independent power producers in favor of that utility's own
generation.\2473\ AEP argues that, in multi-state RTOs/ISOs, the
proposal facially discriminates against LSEs that are not eligible
resource planning entities or are located in states that are not
eligible resource planning entities themselves, and shifts key RTO/ISO
resources away from such entities.\2474\ In RTOs/ISOs that allow
bilateral capacity procurement, AEP argues that the proposal likewise
discriminates between LSEs with qualifying resource planning entities
(which may well be themselves) and those without.
---------------------------------------------------------------------------
\2473\ SEIA Initial Comments at 36.
\2474\ AEP Initial Comments at 37-38.
---------------------------------------------------------------------------
1312. Multiple commenters argue that the proposed requirement to
perform an optional resource solicitation study in multiple states
imposes a considerable burden on RTOs/ISOs without providing meaningful
benefits.\2475\ PJM argues that requiring it ``to serve as a de facto
consultant'' to resource planning entities in addition to its efforts
to expedite and process the country's largest interconnection queue
would require PJM to take on a role beyond its authority as a
transmission provider.\2476\ Similarly, Indicated PJM TOs argue that
there is no justification for requiring transmission providers to
provide resource solicitation studies when consultants could do
so.\2477\
---------------------------------------------------------------------------
\2475\ Id. at 36-37; AES Initial Comments at 22; CAISO Initial
Comments at 31; ClearPath Initial Comments at 9; Dominion Initial
Comments at 39; MISO Initial Comments at 105; NextEra Initial
Comments at 35; PJM Initial Comments at 51; SEIA Reply Comments at
21; WAPA Initial Comments at 15.
\2476\ PJM Initial Comments at 51.
\2477\ Indicated PJM TOs Reply Comments at 19.
---------------------------------------------------------------------------
1313. The North Dakota Commission suggests that the Commission
should consider whether the proposal potentially allows cost-shifting
from states or localities with significant resource build out mandates
to other states within the RTO/ISO and how to mitigate such unjust
cost-shifting.\2478\ Similarly, Interwest cautions that, in bilateral
and RTO/ISO markets, requiring a ranking in priority between
interconnection requests may result in setting up competition between
the utilities, with each vying for space on the constrained
system.\2479\
---------------------------------------------------------------------------
\2478\ North Dakota Commission Initial Comments at 7.
\2479\ Interwest Initial Comments at 10.
---------------------------------------------------------------------------
1314. Tri-State adds that there are ``timing issues'' regarding the
optional resource solicitation study, as it does not align with the
electric resource planning process within Colorado, and potentially
other states.\2480\ The Colorado Commission is also concerned that, to
the extent interconnection requests are permitted to be made into non-
resource solicitation cluster studies without strong requirements to
demonstrate that those requests are for viable generating facilities,
the cluster study results may render later resource solicitation study
results inaccurate.\2481\
---------------------------------------------------------------------------
\2480\ Tri-State Initial Comments at 29.
\2481\ Colorado Commission Reply Comments at 5 n.10.
---------------------------------------------------------------------------
[[Page 61198]]
iii. Requests for Alternatives and Regional Flexibility
1315. Public Interest Organizations argue that the Commission
should grant extra flexibility on the 135-calendar day study
timeline.\2482\ Several commenters support the implementation of
boundaries or guardrails to ensure that optional resource solicitation
studies do not delay the study of other interconnection requests by
diverting needed resources away from the general interconnection
queue.\2483\ Several commenters support the proposal so long as
protections are included to prevent undue discrimination and maintain a
competitive generation solicitation.\2484\
---------------------------------------------------------------------------
\2482\ Public Interest Organizations Initial Comments at 38.
\2483\ Illinois Commission Initial Comments at 11; NESCOE
Initial Comments at 18; OPSI Initial Comments at 7-8.
\2484\ CREA and NewSun Initial Comments at 89-90; CREA and
NewSun Reply Comments at 55; Interwest Initial Comments at 11;
Northwest and Intermountain Initial Comments at 16; Pine Gate
Initial Comments at 43; Public Interest Organizations Initial
Comments at 41; R Street Initial Comments at 15-16.
---------------------------------------------------------------------------
1316. NARUC asks the Commission to consider going farther than
requiring the optional resource solicitation study only for purposes of
transparency and cost estimation; it recommends making the results of
the studies available for interconnection customers to pursue and a
basis upon which interconnection customers could seek interconnection
on an expedited basis.\2485\
---------------------------------------------------------------------------
\2485\ NARUC Initial Comments at 31.
---------------------------------------------------------------------------
1317. Xcel, the Colorado Commission, and EEI argue that the
resource solicitation cluster should have its own queue position.\2486\
Enel recommends that the optional resource solicitation study be a
separate queue cycle with an intermediate queue priority between the
transmission provider's annual study clusters.\2487\ Several commenters
argue that resources selected as part of the resource solicitation
process should be given priority in the interconnection queue.\2488\
The Colorado Commission suggests that the Commission modify its
proposal to prioritize interconnection requests selected to serve
native and network load within the RTO/ISO.
---------------------------------------------------------------------------
\2486\ Colorado Commission Initial Comments at 29; Colorado
Commission Reply Comments at 6; EEI Initial Comments at 5-6; Xcel
Initial Comments at 11, 14.
\2487\ Enel Initial Comments at 72.
\2488\ Arizona Commission Initial Comments at 2; Colorado
Commission Reply Comments at 2; Public Interest Organizations
Initial Comments at 43; Xcel Initial Comments at 46.
---------------------------------------------------------------------------
1318. The Colorado Commission and Xcel encourage the Commission to
determine that any current resource solicitation cluster processes
already in place remain just and reasonable or are consistent with/
superior to the final rule.\2489\ SEIA disagrees, noting that PSCo's
existing resource solicitation study procedures were approved by the
Commission in 2004 only so long as PSCo did not ``disadvantage or delay
other Interconnection Requests not involved in the solicitation.''
\2490\ SEIA argues that the Colorado Commission's current proposal to
prioritize interconnection requests selected in the state process
conflicts with this 2004 order and the Commission's ``longstanding
prohibition against queue jumping.'' \2491\
---------------------------------------------------------------------------
\2489\ Colorado Commission Reply Comments at 1; Xcel Initial
Comments at 11.
\2490\ SEIA Reply Comments at 20 (citing NOPR, 179 FERC ] 61,194
at P 298; Xcel Energy Operating Cos., 109 FERC ] 61,072, at P 26
(2004)).
\2491\ Id. at 20-21 (citing Xcel Energy Operating Cos., 106 FERC
] 61,260, at P 22, order on reh'g, 109 FERC ] 61,072).
---------------------------------------------------------------------------
1319. Multiple commenters request clarification and changes to the
NOPR's proposal on resource solicitation in multistate transmission
areas,\2492\ but NARUC and Xcel suggest that facilitated coordination
of resource planning and interconnection as well as discussion across
states and LSEs may be the most helpful practice to reduce the burden
of differing state portfolio requirements on transmission providers in
multi-state areas.\2493\
---------------------------------------------------------------------------
\2492\ AEP Initial Comments at 36; CAISO Initial Comments at 31;
PacifiCorp Initial Comments at 39; PJM Initial Comments at 51; WAPA
Initial Comments at 15; Xcel Initial Comments at 45-46.
\2493\ NARUC Initial Comments at 30-31; Xcel Initial Comments at
45.
---------------------------------------------------------------------------
1320. Several commenters suggest that the proposed optional
resource solicitation study should occur outside the tariff
process.\2494\ NextEra argues that the absence of such a feature from
the pro forma LGIP is in no way unjust and unreasonable and that, if a
transmission provider feels the need to customize its LGIP in this way,
the transmission provider can do so on its own.\2495\ NRECA suggests
that the Commission require that base cases and support files are
available for LSEs so the LSE can run these studies outside of the
tariff process.\2496\ WAPA and Bonneville argue that resource
solicitation studies should occur at the reliability coordinator level
and not the transmission provider level.\2497\
---------------------------------------------------------------------------
\2494\ NextEra Initial Comments at 35; NRECA Initial Comments at
42.
\2495\ NextEra Initial Comments at 35.
\2496\ NRECA Initial Comments at 42.
\2497\ Bonneville Initial Comments at 22; WAPA Initial Comments
at 14.
---------------------------------------------------------------------------
1321. Several commenters argue that the Commission should allow
transmission providers flexibility in implementing resource
solicitations.\2498\ NYISO asserts that it has addressed the NOPR's
aims by permitting state agencies to act as a developer for purposes of
obtaining a generic interconnection request that they can put out for
solicitation.\2499\
---------------------------------------------------------------------------
\2498\ AECI Initial Comments at 8; Dominion Initial Comments at
39; Interwest Initial Comments at 12; ISO-NE Initial Comments at 38;
NESCOE Reply Comments at 15; NRECA Initial Comments at 10; NYISO
Initial Comments at 46; PacifiCorp Initial Comments at 39; PJM
Initial Comments at 51; Xcel Initial Comments at 14, 45; Xcel Reply
Comments at 3.
\2499\ NYISO Initial Comments at 47.
---------------------------------------------------------------------------
c. Commission Determination
1322. We decline to adopt the NOPR proposal to modify the pro forma
LGIP to require transmission providers to allow resource planning
entities to initiate an optional resource solicitation study.\2500\ We
find that there is insufficient evidence in the record to justify
establishing the optional resource solicitation study process proposed
in the NOPR as a generic solution across all regions for coordinating
state-level resource planning with the interconnection process. As
commenters explain, many transmission providers do not have LSEs that
conduct a resource solicitation process. We are also concerned that the
particular ``one size fits all'' approach proposed in the NOPR would
create uncertainty regarding the cost and timing of interconnecting to
the transmission system, because the proposed study would not result in
useful network upgrade cost estimates. Finally, we agree with
commenters that the proposal as set forth in the NOPR would divert
transmission provider resources and potentially lead to delays in the
processing of the interconnection queue.
---------------------------------------------------------------------------
\2500\ Because we are not adopting this proposal, we do not
address comments on specific aspects of the proposal.
---------------------------------------------------------------------------
1323. Notwithstanding our decision not to adopt the NOPR's resource
solicitation proposal, we agree with commenters who note that, in
certain regions, resource solicitation studies have the potential to
reduce uncertainty, improve coordination, and make resource planning
more efficient and cost effective. We acknowledge comments arguing that
a resource solicitation study may be most effective if paired with a
structure where the resources within the resource solicitation
structure are granted their own queue position, as this provides the
relevant resources and soliciting entity with actionable information
and avoids the uncertainty and delay that may occur if a study is
conducted only for informational purposes and the
[[Page 61199]]
associated resources do not have a queue position that corresponds to
the study assumptions.\2501\ We note that our decision not to adopt the
NOPR's proposal in this final rule in no way prejudges any future
resource solicitation study proposals that transmission providers may
choose to file pursuant to FPA section 205.
---------------------------------------------------------------------------
\2501\ See Colorado Commission Initial Comments at 29; Colorado
Commission Reply Comments at 6; EEI Initial Comments at 5-6; Xcel
Initial Comments at 11, 14.
---------------------------------------------------------------------------
C. Reforms To Incorporate Technological Advancements Into the
Interconnection Process
1. Increasing Flexibility in the Generator Interconnection Process
a. Co-Located Generating Facilities Behind One Point of Interconnection
With Shared Interconnection Requests
i. Need for Reform and NOPR Proposal
1324. In the NOPR, the Commission noted that the current pro forma
LGIP does not address interconnection requests made up of multiple
generating facilities seeking to co-locate and to share a single point
of interconnection.\2502\ The Commission preliminarily found that the
lack of such a process limits the interconnection of generating
facilities, hindering competition and rendering the Commission's
existing pro forma LGIP unjust, unreasonable, and unduly discriminatory
or preferential.\2503\
---------------------------------------------------------------------------
\2502\ NOPR, 179 FERC ] 61,194 at P 239.
\2503\ Id. P 240.
---------------------------------------------------------------------------
1325. The Commission therefore proposed to revise the pro forma
LGIP and pro forma LGIA to ``require 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.'' \2504\ The Commission explained that this proposed reform
would ``create a minimum standard that would remove barriers for co-
located resources by creating a standardized procedure for these types
of configurations to enable them to access the transmission system.''
\2505\
---------------------------------------------------------------------------
\2504\ Id. P 242.
\2505\ Id.
---------------------------------------------------------------------------
1326. The Commission proposed to revise the pro forma LGIP to:
``(1) define `Co-Located Resources' as `more than one resource located
behind the same point of interconnection'; (2) state that co-located
resources can share an interconnection request; (3) modify the
definition of site control such that it allows interconnection
customers to demonstrate shared land-use for co-located resources.''
\2506\ The Commission also proposed to modify the definition of
interconnection facilities to clarify that multiple generating
facilities located on the same site may share interconnection
facilities.\2507\
---------------------------------------------------------------------------
\2506\ Id. P 243.
\2507\ Id.; proposed pro forma LGIP section 1.
---------------------------------------------------------------------------
1327. The Commission also proposed revisions to the pro forma LGIP
to ``require generating facilities that are co-locating to have
technology to address differences in terminal voltage between the co-
located generating facilities to ensure that these generating
facilities have the same voltage levels.'' \2508\ The Commission noted
that many co-located generating facilities are co-located with electric
storage resources,\2509\ and proposed to define ``electric storage
resources'' in the pro forma LGIP as a resource capable of receiving
electric energy from the grid and storing it for later injection of
electric energy back to the grid.\2510\
---------------------------------------------------------------------------
\2508\ NOPR, 179 FERC ] 61,194 at P 245.
\2509\ Id. P 240.
\2510\ Id.; proposed pro forma LGIP section 1.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1328. Commenters overwhelmingly support the Commission's
proposal.\2511\ Eversource conditionally supports the proposal as a
solid step that will improve the interconnection process.\2512\
Avangrid is not opposed to the proposal but does not foresee the reform
as providing incremental efficiency to transmission providers.\2513\
---------------------------------------------------------------------------
\2511\ AEE Initial Comments at 38; AES Initial Comments at 23;
Ameren Initial Comments at 26; APPA-LPPC Initial Comments at 28;
CAISO Initial Comments at 32; Clean Energy Associations Initial
Comments at 59; Clean Energy Buyers Initial Comments at 4-5;
Consumers Energy Company Initial Comments at 8; CREA and NewSun
Initial Comments at 90; Environmental Defense Fund Initial Comments
at 5; Environmental Defense Fund Reply Comments at 8; ELCON Initial
Comments at 10; Enel Initial Comments at 78; Evergreen Action
Initial Comments at 3; ISO-NE Initial Comments at 39; MISO Initial
Comments at 107; NARUC Initial Comments at 33; National Grid Initial
Comments at 39; NextEra Initial Comments at 6; NRECA Initial
Comments at 44; NY Commission and NYSERDA Initial Comments at 9;
NYISO Initial Comments at 47; NYTOs Initial Comments at 31-32; OSPA
Reply Comments at 15; Ohio Commission Initial Comments at 14; Omaha
Public Power Initial Comments at 13; [Oslash]rsted Initial Comments
at 18; Pine Gate Initial Comments at 44-45; Public Interest
Organizations Initial Comments at 43; SEIA Initial Comments at 37;
SoCal Edison Initial Comments at 19; SPP Initial Comments at 23;
State Agencies Initial Comments at 14.
\2512\ Eversource Initial Comments at 32-33.
\2513\ Avangrid Initial Comments at 34.
---------------------------------------------------------------------------
1329. Evergreen Action avers that co-location is vital to
connecting more generation in the short term as transmission providers
begin to work through large interconnection queue backlogs,\2514\ and
Evergreen Action and NRECA state that co-locating two or more resources
will take advantage of technologies like battery storage to more
efficiently use the transmission system.\2515\ AEE and State Agencies
argue that, because existing interconnection procedures were designed
before battery storage and hybrid resource types came into common
usage, these types of technologies are often underserved under existing
interconnection procedures despite being well represented in current
interconnection queues, making this reform timely.\2516\ OSPA urges the
Commission to implement this proposal as soon as possible.\2517\
---------------------------------------------------------------------------
\2514\ Evergreen Action Initial Comments at 3.
\2515\ Id.; NRECA Initial Comments at 44.
\2516\ AEE Initial Comments at 38; State Agencies Initial
Comments at 14.
\2517\ OSPA Reply Comments at 15.
---------------------------------------------------------------------------
1330. Several commenters argue that the NOPR proposal will likely
improve the overall efficiency of interconnection processes, result in
more accurate interconnection queue positions, and help to ensure just
and reasonable rates.\2518\ Environmental Defense Fund argues that
combinations of generation and storage on a single site will create
several benefits, including reducing intermittency, shifting supply to
better meet demand, responding to grid events, and enabling provision
of ancillary services.\2519\
---------------------------------------------------------------------------
\2518\ AEE Initial Comments at 39; AES Initial Comments at 23;
NARUC Initial Comments at 33; Ohio Commission Initial Comments at
14.
\2519\ Environmental Defense Fund Initial Comments at 5.
---------------------------------------------------------------------------
1331. AEE argues that the greatest value of storage systems is
their ability to respond rapidly with a high degree of controllability,
and contends that hybrid resources smooth the output of variable
resources, allowing for increased land use efficiencies.\2520\ Several
commenters argue that the proposal will yield interconnection queue
efficiency because the shared nature of the co-located resources can be
fully accounted for in a single interconnection request: they contend
that requiring co-located resources to submit multiple interconnection
requests increases cost, timing, and complexity, while forgoing
reliability benefits.\2521\
---------------------------------------------------------------------------
\2520\ AEE Initial Comments at 39.
\2521\ Id.; AES Initial Comments at 39; Consumers Energy Company
Initial Comments at 8; Environmental Defense Fund Initial Comments
at 5-6; NARUC Initial Comments at 33; Ohio Commission Initial
Comments at 14; [Oslash]rsted Initial Comments at 19; Public
Interest Organizations Initial Comments at 44; SEIA Initial Comments
at 37-38; SoCal Edison Initial Comments at 19.
---------------------------------------------------------------------------
[[Page 61200]]
1332. In support of the proposal, AEE argues that several
transmission providers already allow co-located generating facilities
at the same point of interconnection to submit a single request (e.g.,
CAISO, ISO-NE, and MISO).\2522\ AES contends that the Commission's
proposed reforms are necessary to ensure parity across all RTOs/ISOs on
this issue, as some RTOs'/ISOs' practices erect unnecessary and
unreasonable barriers for generating facilities located behind a single
point of interconnection to interconnect.\2523\
---------------------------------------------------------------------------
\2522\ AEE Initial Comments at 39-40.
\2523\ AES Initial Comments at 23.
---------------------------------------------------------------------------
1333. Omaha Public Power supports the Commission's proposals to
facilitate new technologies, specifically the reforms related to co-
located resources, revisions to the modification process, and surplus
interconnection capacity.\2524\ Omaha Public Power observes, however,
that many transmission providers have already made progress in this
area and therefore recommends that the Commission allow existing
transmission provider processes that are facilitating new technologies
to continue.
---------------------------------------------------------------------------
\2524\ Omaha Public Power Initial Comments at 13.
---------------------------------------------------------------------------
(b) Comments on Specific Proposal
1334. Avangrid asserts that the Commission's proposal should not
change or supersede any regional metering requirements for market
participation and contends that co-located resources must have separate
meters even if they share a point of interconnection.\2525\
---------------------------------------------------------------------------
\2525\ Avangrid Initial Comments at 34.
---------------------------------------------------------------------------
1335. NARUC and MISO support the Commission's proposal that co-
located generating facilities must have technology to address
differences in terminal voltage between the co-located generating
facilities.\2526\ MISO states that having to study a single co-located
generating facility with two points of interconnection at different
voltages would be infeasible, and that co-located generating facilities
should be required to inject at a single point of interconnection, at a
single voltage.\2527\ SPP states that it is unclear what the Commission
intended in the NOPR by proposing to require that generating facilities
``address differences in terminal voltage between the co-located
generating facilities to ensure that these generating facilities have
the same voltage levels.'' \2528\ SPP contends that it would be simpler
to require that such generating facilities connect at the same point of
interconnection and leave the details as to how to do that to the
interconnection customer. Ameren argues that, so long as modeling is
available to the transmission provider for the types of resources that
are behind the point of interconnection, co-located resources with
differences in terminal voltage should not be an issue when performing
the interconnection studies.\2529\
---------------------------------------------------------------------------
\2526\ MISO Initial Comments at 107-108; NARUC Initial Comments
at 33.
\2527\ MISO Initial Comments at 107-108.
\2528\ SPP Initial Comments at 23 (citing NOPR, 179 FERC ]
61,194 at P 245).
\2529\ Ameren Initial Comments at 26.
---------------------------------------------------------------------------
1336. [Oslash]rsted supports the Commission's proposed changes to
the definition of ``interconnection facilities.'' \2530\ Enel states
that the proposed insertion of the phrase ``by interconnection
customer'' in the third sentence of the pro forma LGIA/LGIP definition
of ``interconnection facilities'' should be changed to the phrase ``by
interconnection customer(s).'' \2531\ Enel further states that the
proposed new fourth sentence to the definition of ``interconnection
facilities'' explains that multiple interconnection customers may use a
single set of interconnection facilities, and thus ``sole use
facilities'' may have multiple interconnection customer beneficiaries.
---------------------------------------------------------------------------
\2530\ [Oslash]rsted Initial Comments at 18.
\2531\ Enel Initial Comments at 81-82.
---------------------------------------------------------------------------
1337. Southern states that, under the NOPR proposal, co-located
resources can include different owners of different generating
facilities.\2532\ Pine Gate and Southern note that the proposal to
allow interconnection customers to demonstrate shared land-use may
require interconnection customers to provide transmission providers
more detailed site maps to demonstrate valid site control for each
generating facility.\2533\ Southern states that this is appropriate
because the transmission provider should not be responsible for
monitoring the legal relationship between the co-owners.\2534\ Southern
states that co-located resources must either be owned by the same
owner, or the different owners of the generating facilities must enter
into an agreement that addresses off-take rights and ownership, and
they must submit one interconnection request for the entire generating
facility. Tri-State suggests clarifying that a separate agreement is
not necessary when both co-located resources belong to the same
interconnection customer.\2535\
---------------------------------------------------------------------------
\2532\ Southern Initial Comments at 35.
\2533\ Id. at 36; Pine Gate Initial Comments at 46.
\2534\ Southern Initial Comments at 36.
\2535\ Tri-State Initial Comments at 25.
---------------------------------------------------------------------------
1338. Clean Energy Associations support allowing multiple
generating facilities that share a single point of interconnection to
submit a joint interconnection request as a hybrid or co-located
resource. Clean Energy Associations argue that interconnection
customers with proposed generating facilities where the electric
storage resource and generating facility are co-located, and have two
``resource IDs,'' should be allowed to choose to have each component
studied separately.\2536\ Clean Energy Associations also submit that
the generating equipment for the generating facilities should not be
required to be located on a shared site. Clean Energy Associations
further assert that such flexibility would allow, for example, a solar
facility to obtain a faster ERIS study while the co-located storage
could get a more detailed study for NRIS.
---------------------------------------------------------------------------
\2536\ Clean Energy Associations Initial Comments at 59-61.
---------------------------------------------------------------------------
1339. Southern contends that co-located resources that intend to be
qualifying facilities should be required to comply with PURPA
requirements.\2537\
---------------------------------------------------------------------------
\2537\ Southern Initial Comments at 36.
---------------------------------------------------------------------------
(c) Requests for Clarification and Flexibility
1340. Pine Gate agrees that co-located generating facilities must
have technology to address differences in terminal voltage between the
co-located generating facilities, arguing that such technology is
likely necessary in instances where a co-located resource is being
studied under a single interconnection request for a net injection at
the point of interconnection.\2538\ However, Pine Gate requests that
the Commission clarify that such technology is not necessary in
instances in which the interconnection customer elects to submit a co-
located resource using two separate interconnection requests.
---------------------------------------------------------------------------
\2538\ Pine Gate Initial Comments at 46.
---------------------------------------------------------------------------
1341. SPP notes that in the NOPR, the Commission proposed to define
``co-located resources'' as ``more than one resource located behind the
same point of interconnection,'' whereas the proposed definition in the
pro forma LGIP reads, ``Co-Located Resource shall mean multiple
Generating Facilities located on the same site.'' \2539\ SPP states
that two generating facilities can be located on the same site without
connecting behind the same point of interconnection. SPP asks the
Commission to clarify in the final rule which definition of co-located
resource is required. SPP states that it supports a definition that
explicitly states that the
[[Page 61201]]
generating facilities must connect at the same point of
interconnection.
---------------------------------------------------------------------------
\2539\ SPP Initial Comments at 23.
---------------------------------------------------------------------------
1342. MISO and Southern request that the Commission clarify that
co-located resources must be required to share an interconnection
request.\2540\ According to MISO, its tariff and Order No. 807 \2541\
allow for different interconnection requests to share a generator tie
line and thus share the same point of interconnection. MISO argues that
failing to amend the definition of co-located resource would conflate
the two scenarios under the same definition, such that two separate
noncontiguous generating facilities that share a generator tie line
would share the same point of interconnection, thus also falling under
the definition of co-located resources without the intent to do
so.\2542\ Southern argues that the Commission should clarify that the
interconnection tie line connecting the co-located resource to the
transmission system is a radial facility, not a network facility.\2543\
---------------------------------------------------------------------------
\2540\ MISO Initial Comments at 107; Southern Initial Comments
at 36.
\2541\ Open Access & Priority Rights on Interconnection
Customer's Interconnection Facilities, Order No. 807, 80 FR 17654
(Apr. 1, 2015), 150 FERC ] 61,211, order on reh'g, Order No. 807-A,
153 FERC ] 61,047 (2015).
\2542\ MISO Initial Comments at 107.
\2543\ Southern Initial Comments at 37.
---------------------------------------------------------------------------
1343. National Grid asks that the Commission clarify what is
included in the definition of ``co-located resources.'' \2544\ National
Grid understands that the term can apply to hybrid technologies owned
by a single interconnection customer interconnecting to a single point
of interconnection, such as a solar generating facility coupled with a
storage facility. National Grid suggests that, to the extent the term
also is intended to apply to multiple interconnection customers with
separate generating facilities interconnecting to a single point of
interconnection, that the proposal might create complexities not
discussed in the NOPR but may merit consideration.
---------------------------------------------------------------------------
\2544\ National Grid Initial Comments at 39-40.
---------------------------------------------------------------------------
1344. SEIA requests clarification on the terminology used in the
proposal.\2545\ SEIA states that in January 2021, in its order
directing reports on information related to hybrid resources, the
Commission used two distinct terms to identify hybrid resource market
participation.\2546\ SEIA states that ``co-located hybrid resources''
are defined as two separate resources sharing a single point of
interconnection that are modeled and dispatched separately. SEIA states
that ``integrated hybrid resources'' are defined as sets of resources
that share a single point of interconnection and are modeled and
dispatched as a single resource. Tri-State similarly states that the
``electric storage resource'' definition does not account for resources
designed to be charged apart from the transmission system, such as
solar or wind generating facilities that may charge an electric storage
resource.\2547\ SEIA requests that the Commission adopt the terms co-
located and integrated hybrid resources in the final rule and clarify
that interconnection customers retain the choice of how to structure
their interconnection requests to best suit their needs and the needs
of their customers.\2548\
---------------------------------------------------------------------------
\2545\ SEIA Initial Comments at 38.
\2546\ Id. (citing Hybrid Res., 174 FERC ] 61,034, at P 4
(2021)).
\2547\ Tri-State Initial Comments at 25.
\2548\ SEIA Initial Comments at 38.
---------------------------------------------------------------------------
1345. Some commenters ask that the Commission provide regional
flexibility as to the types of co-located resources permitted in each
RTO/ISO and existing processes that may already accomplish the goals of
the proposed reforms.\2549\ ISO-NE, NYISO, and MISO state that they are
already in compliance with the proposed reform.\2550\
---------------------------------------------------------------------------
\2549\ ISO-NE Initial Comments at 39; NY Commission and NYSERDA
Initial Comments at 9; NYTOs Initial Comments at 31-32.
\2550\ ISO-NE Initial Comments at 39; MISO Initial Comments at
107; NYISO Initial Comments at 47.
---------------------------------------------------------------------------
iii. Commission Determination
1346. We adopt, with modification, the NOPR proposal to revise pro
forma LGIP section 3.1.2 to require 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. We decline to adopt the proposed definitions of ``co-located
resource'' and ``electric storage resource,'' and we decline to adopt
the proposed modifications to the definitions of interconnection
facilities, and transmission provider's interconnection facilities in
pro forma LGIP section 1 and pro forma LGIA article 1.\2551\ We find
that including the definition of co-located resource in the pro forma
LGIP and pro forma LGIA is not necessary to effectuate the process
reforms detailed in the NOPR, and thus decline to adopt it here.\2552\
Given that Order No. 845 revised the definition of generating facility
to include electric storage resources,\2553\ we also find it
unnecessary to define the term electric storage resource in the pro
forma LGIP and LGIA. We note that declining to adopt the definition of
electric storage resource moots Tri-State's concern that the proposed
definition failed to account for electric storage resources that may be
charged apart from the transmission system.\2554\
---------------------------------------------------------------------------
\2551\ NOPR, 179 FERC ] 61,194 at P 243; proposed pro forma LGIA
section 1.
\2552\ Co-located generating facilities are more than one
generating facility that are located on the same site and that are
connected at the same point of interconnection that are operated and
dispatched as separate generating facilities.
\2553\ See Order No. 845, 163 FERC ] 61,043, at P 275 (modifying
the definition of ``Generating Facility'' in the pro forma LGIP and
pro forma LGIA to include ``and/or storage for later injection'').
\2554\ Tri-State Initial Comments at 25.
---------------------------------------------------------------------------
1347. We also decline to adopt the NOPR proposal to modify the
definitions of interconnection facilities and transmission provider's
interconnection facilities to specify that interconnection facilities
may be shared among interconnection customers. We find that such
specification in the pro forma LGIP and pro forma LGIA is not needed
because Commission policy does not prohibit interconnection customers
from sharing interconnection facilities.\2555\ We expect that there may
be benefits from interconnection customers being able to share
transmission provider's interconnection facilities and interconnection
customer's interconnection facilities, particularly in light of the
Commission's transition in this final rule to a cluster study approach.
Under a cluster study approach, in which multiple interconnection
requests are evaluated in a combined study, efficiencies may be gained
(in cost and time to construct) by allowing interconnection customers
to share use of, and payment for, interconnection facilities. We note
that such efficiencies from allowing the interconnection facilities to
be used by more than one interconnection customer do not exist under
the Commission's existing pro forma LGIP serial interconnection study
process because the serial study process does not consider the
interconnection facilities that would be necessary to accommodate the
interconnection of more than one interconnection customer. In response
to [Oslash]rsted and Enel's comments expressing support for the
revisions to the definitions of interconnection facilities and
transmission provider's interconnection facilities,\2556\ we state in
this final rule that the interconnection facilities also may be used by
more than one interconnection customer.
---------------------------------------------------------------------------
\2555\ See, e.g., Order No. 807, 150 FERC ] 61,211, at P 3
(discussing the ability of interconnection customer's
interconnection facilities owners to make excess capacity available
to third parties).
\2556\ [Oslash]rsted Initial Comments at 18; Enel Initial
Comments at 81-82.
---------------------------------------------------------------------------
[[Page 61202]]
1348. We also decline to adopt the NOPR proposal to revise the pro
forma LGIP to require generating facilities that are co-locating to
have technology to address differences in terminal voltage between the
co-located generating facilities to ensure that these generating
facilities have the same voltage levels.\2557\ We find that the
preexisting language in pro forma LGIP section 3.1 (section 3.1.2 as
revised by this final rule) is clear that ``[a]n Interconnection
Request to evaluate one site at two different voltage levels shall be
treated as two Interconnection Requests.'' This preexisting provision
makes clear that a set of co-located generating facilities must be at a
single terminal voltage in order to be treated as a single
interconnection request. The additional requirement proposed in the
NOPR is therefore unnecessary to adopt in the final rule. We note that
declining to adopt the NOPR proposal with respect to this issue
alleviates SPP's concern with the NOPR proposal.\2558\ In response to
Pine Gate, we reiterate that preexisting pro forma LGIP section 3.1
(section 3.1.2 as revised by this final rule) would require co-located
generating facilities with different terminal voltage levels to submit
separate interconnection requests.\2559\
---------------------------------------------------------------------------
\2557\ See NOPR, 179 FERC ] 61,194 at P 245.
\2558\ See SPP Initial Comments at 23.
\2559\ See Pine Gate Initial Comments at 46.
---------------------------------------------------------------------------
1349. As the Commission stated in the NOPR, recent studies
demonstrate that large numbers of generating facilities currently in
interconnection queues are seeking to co-locate on a shared site behind
one point of interconnection and share an interconnection request,
while operating separately, and that the pro forma LGIP currently lacks
provisions that explicitly allow them to do so.\2560\ We agree with
commenters that this type of generating facility configuration, in
spite of being prevalent in current interconnection queues, faces
barriers to interconnection under existing interconnection
procedures,\2561\ and that this reform will effectively remove such
barriers. We find that requiring transmission providers to allow
interconnection customers to submit a single interconnection request
that represents multiple generating facilities that are located behind
a single point of interconnection is required to ensure just and
reasonable rates. By doing so, this reform will improve efficiency for
transmission providers in the study process by reducing the number of
interconnection requests in the interconnection queue and will reduce
costs for interconnection customers because they will only submit a
single set of deposits to enter the interconnection queue.
---------------------------------------------------------------------------
\2560\ NOPR, 179 FERC ] 61,194 at P 238.
\2561\ AEE Initial Comments at 38; State Agencies Initial
Comments at 14.
---------------------------------------------------------------------------
1350. We also believe that this reform will improve interconnection
queue efficiency without imposing an adverse impact on the efficacy of
interconnection study results or other interconnection customers.
Because of the significant growth of generating facilities seeking to
interconnect jointly at a single point of interconnection,\2562\ we
find that allowing co-located generating facilities to submit one
interconnection request will lessen the delays experienced in many
interconnection queues. We agree with commenters that transmission
providers requiring co-located generating facilities to submit separate
interconnection requests increases the cost and complexity of the
interconnection process and creates undue delay to the interconnection
process.\2563\ Allowing co-located generating facilities to share
interconnection requests will ensure the interconnection queue moves
along expediently, providing clarity, cost certainty, and increased
transparency throughout the study process.
---------------------------------------------------------------------------
\2562\ Currently, 42% (285 GW) of solar and 8% (17 GW) of wind
projects in the queue are proposed as hybrid resources that would
include electric storage. Queued Up 2023 at 18.
\2563\ AEE Initial Comments at 39; Environmental Defense Fund
Initial Comments at 5-6.
---------------------------------------------------------------------------
1351. Some commenters suggest that co-located generating facilities
should always be required to share an interconnection request.\2564\
Others request that interconnection customers retain the choice whether
to share an interconnection request.\2565\ We clarify that
interconnection customers have the choice to structure their
interconnection requests according to their preference. We are not
requiring interconnection customers to share a single interconnection
request for multiple generating facilities located on the same site.
---------------------------------------------------------------------------
\2564\ MISO Initial Comments at 107; Southern Initial Comments
at 36.
\2565\ Clean Energy Associations Initial Comments at 59-61
(arguing against such a requirement to enable co-located generating
facilities to seek ERIS versus NRIS); SEIA Initial Comments at 38.
---------------------------------------------------------------------------
1352. However, we further clarify in response to Clean Energy
Associations \2566\ that interconnection customers may submit separate
interconnection requests to have each device studied separately. We
find that this clarification also addresses MISO's concern about any
potential conflict with Order No. 807.\2567\ Additionally, we clarify
that, where an interconnection customer chooses to submit a single
interconnection request for multiple generating facilities, the
generating facilities must be located on the same site in order to
reduce complexity for the transmission provider.
---------------------------------------------------------------------------
\2566\ Clean Energy Association Initial Comments at 59-61
(requesting that generating equipment not be required to be on the
same site).
\2567\ MISO Initial Comments at 107-108.
---------------------------------------------------------------------------
1353. In response to Southern's request that the Commission clarify
that the interconnection tie line connecting the co-located resource to
the transmission system is a radial facility, not a network facility,
we clarify that, as explained in Order No. 807, the Commission now
refers to tie lines as the interconnection customer's interconnection
facilities.\2568\ As the Commission stated in Order No. 807, the
interconnection customer's interconnection facilities ``are sole-use,
limited and discrete, radial in nature, and not part of an integrated
transmission network.'' \2569\ Radial facilities located between the
generating facility and point of interconnection are considered
interconnection facilities under the pro forma LGIP and pro forma
LGIA.\2570\
---------------------------------------------------------------------------
\2568\ The Commission stated that ``[t]he jurisdictional
interconnection facilities for which this Final rule grants a waiver
have sometimes in the past been referred to informally as `generator
tie lines,' but, in the Notice of Proposed Rulemaking, the
Commission used the term [Interconnection Customer's Interconnection
Facilities] as defined in the pro forma documents issued with Order
No. 2003.'' Order No. 807, 150 FERC ] 61,211, at n.1 (citing Order
No. 2003, 104 FERC ] 61,103).
\2569\ Order No. 807, 150 FERC ] 61,211 at P 114.
\2570\ Under the pro forma LGIP, ``Interconnection Facilities
shall mean Transmission Provider's Interconnection Facilities and
Interconnection Customer's Interconnection Facilities. Collectively,
Interconnection Facilities include all facilities and equipment
between the Generating Facility and the Point of Interconnection,
including any modification, additions or upgrades that are necessary
to physically and electrically interconnect the Generating Facility
to Transmission Provider's Transmission System. Interconnection
Facilities are sole use facilities and shall not include
Distribution Upgrades, Stand Alone Network Upgrades or Network
Upgrades.'' See pro forma LGIP section 1 and pro forma LGIA article
1.
---------------------------------------------------------------------------
1354. In response to Omaha Public Power's suggestion that the
Commission allow existing transmission provider processes that are
facilitating new technologies to continue unimpeded, we clarify that,
consistent with section IV of this final rule, to the extent
transmission providers believe that they already comply with the
adopted pro forma LGIP provisions, they may demonstrate this in their
compliance filings.
1355. In response to concerns about multiple interconnection
customers using the same interconnection
[[Page 61203]]
request,\2571\ we clarify that co-located generating facilities can be
owned by a single interconnection customer with multiple generating
facilities sharing a site, or by multiple interconnection customers
that have a contract or other agreement that allows for shared land
use.\2572\ In response to Tri-State,\2573\ we clarify that no such
agreement is necessary when the generating facilities in question
belong to the same interconnection customer. In response to
Southern,\2574\ we clarify that generating facilities that co-locate
still must adhere to all other applicable laws and regulations,
including PURPA.
---------------------------------------------------------------------------
\2571\ National Grid Initial Comments at 39-40; Southern Initial
Comments at 35-36.
\2572\ The revised definition of site control in the pro forma
LGIP adopted in this final rule requires that site control be
``demonstrated by a contract or other agreement that allows for
shared land use for all Generating Facilities that are co-located
and meet the provisions of the Site Control definition.'' Pro forma
LGIP section 3.4.2.
\2573\ Tri-State Initial Comments at 25.
\2574\ Southern Initial Comments at 36.
---------------------------------------------------------------------------
1356. We find that comments regarding the following issues are
outside the scope of this proceeding because they pertain to market
issues and other rules that were not addressed in the NOPR: (1)
permitting an interconnection customer to specify the co-located
generating facility's maximum injection level to the point of
interconnection; \2575\ and (2) metering requirements for co-located
generating facilities.\2576\
---------------------------------------------------------------------------
\2575\ Pine Gate Initial Comments at 45.
\2576\ Avangrid Initial Comments at 34.
---------------------------------------------------------------------------
1357. We decline SEIA's request that the Commission adopt a more
expansive definition of ``co-located resources,'' including how the
resources are modeled and dispatched. Modeling assumptions for electric
storage resources and co-located or hybrid generating facilities
containing electric storage resources are addressed elsewhere in this
final rule.\2577\
---------------------------------------------------------------------------
\2577\ See infra section III.C.1.d.
---------------------------------------------------------------------------
b. Revisions to the Modification Process To Require Consideration of
Generating Facility Additions
i. Need for Reform and NOPR Proposal
1358. In the NOPR, the Commission expressed concern that, because
certain requests to add a generating facility to an existing
interconnection request are often deemed material without an
evaluation, even if the injection amount remains the same, the material
modification process may result in unjust, unreasonable, and unduly
discriminatory or preferential outcomes.\2578\ The Commission pointed
out that, as explained in Order No. 2003, it is inadequate and
inefficient to solve interconnection issues on a case-by-case
basis.\2579\ The Commission explained that, in the case of processing
modification requests, without a standard set of procedures,
transmission providers have adopted varying strategies for processing
requests to add electric storage or other generating facilities that do
not change the requested interconnection service limit to existing
interconnection requests. The Commission preliminarily found that this
lack of uniformity leads to disparate outcomes across the country and
leaves open the potential for undue discrimination.
---------------------------------------------------------------------------
\2578\ NOPR, 179 FERC ] 61,194 at P 252.
\2579\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 9-
10).
---------------------------------------------------------------------------
1359. The Commission explained that the modification provisions in
the pro forma LGIP do not specify whether an interconnection customer
can modify its interconnection request to add another generating
facility at the same point of interconnection without increasing the
requested interconnection service level.\2580\ The Commission stated
that many transmission providers treat such a request automatically as
a material modification, such that the interconnection customer that
wishes to make this type of change faces a loss of interconnection
queue position regardless of the actual effect the addition of a
generating facility to an interconnection request may have on the
system. The Commission explained that this process is a significant
barrier to interconnection customers that wish to make this type of
change and preliminarily found that such a barrier hinders access to
the transmission system and may render existing interconnection
processes unjust, unreasonable, and unduly discriminatory or
preferential.\2581\
---------------------------------------------------------------------------
\2580\ Id. P 253.
\2581\ Id. P 254.
---------------------------------------------------------------------------
1360. In the NOPR, the Commission proposed to revise the pro forma
LGIP to require transmission providers to evaluate the proposed
addition of a generating facility to an interconnection request as long
as the interconnection customer does not request a change to the
originally requested interconnection service level.\2582\ Under this
proposed requirement, the transmission provider could not automatically
consider such a request to be a material modification. Specifically,
the Commission proposed to require that: (1) transmission providers
evaluate the proposed addition of a generating facility to an
interconnection request within 60 calendar days of receiving the
request for modification if such addition does not change the requested
interconnection service level; (2) the change cannot be considered an
automatic material modification and an evaluation (including studying
the configuration and necessary modeling) must occur prior to
determining whether the proposed change constitutes a material
modification of the interconnection request; and (3) if the proposed
addition does not have a material impact on the cost or timing of any
interconnection request that is lower or equally queued, and does not
cause any other reliability concerns, the addition will not be
considered a material modification.\2583\ The Commission noted that the
reliability concerns could include, for example, a material impact on
the transmission system with regard to short circuit capability limits,
steady-state thermal and voltage limits, or dynamic system stability
and response.
---------------------------------------------------------------------------
\2582\ Id. P 255.
\2583\ Id. P 255.
---------------------------------------------------------------------------
1361. The Commission sought comment on: (1) whether the addition of
a generating facility that does not alter an interconnection customer's
interconnection service limit could nonetheless require a full
interconnection service study; (2) how transmission providers should
perform studies required to confirm that there is no adverse impact
because of the addition of a generating facility to an interconnection
request, such as confirmation that the electrical characteristics of
the interconnection customer remain the same; (3) whether and how
interconnection customers in a later cluster, or interconnection
customers that are in the same cluster, could be adversely impacted by
such changes; (4) whether the addition of electric storage when in
charging mode (in terms of resistance, inductance, and capacitance) may
change the electrical characteristics of an interconnection request,
and whether those changes may affect the reliable operation of the
generating facility related to that interconnection request; and (5)
whether further specification is needed for the assessment of the
electrical characteristics due to the addition of a complex load.\2584\
---------------------------------------------------------------------------
\2584\ Id. PP 256-257.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1362. A diverse group of commenters indicate general support for
the NOPR proposal.\2585\ NARUC agrees that the
[[Page 61204]]
proposed reform will promote consistency for interconnection customers
throughout the country, in addition to promoting reliability, economic,
and administrative efficiency as the generation fleet continues to
evolve.\2586\ NARUC explains that the loss of interconnection queue
position as a result of adding a generating facility that does not
increase the requested service level or cause reliability issues, but
rather could improve the performance and capability of a generating
facility to manage reliability or lower the cost of energy to
customers, is an inefficient and discriminatory outcome the Commission
should seek to permanently remedy through this proceeding. AEE and
Public Interest Organizations assert that a restudy would be
automatically required for adding a generating facility such as
storage, and that if there were not a restudy related to the addition
of storage, they could provide numerous benefits, including firming up
variable renewable generation, avoided curtailment, congestion relief,
and, in the case of grid-forming inverters and batteries, fast
frequency response and other grid flexibility services.\2587\ AEE
contends that the loss of the benefits, primarily from adding storage,
will harm reliability and result in unjust and unreasonable
rates.\2588\ SEIA contends that adding an additional generating
facility (such as storage) that does not increase the interconnection
service level also should not increase the costs to later
interconnection requests because it generally would not require
additional network upgrades and should not delay lower-queued
interconnection requests.\2589\
---------------------------------------------------------------------------
\2585\ AEE Initial Comments at 40-41; AEE Reply Comments at 39-
41; AES Initial Comments at 23; Ameren Initial Comments at 27; APS
Initial Comments at 20; Avangrid Initial Comments at 34-35; CAISO
Initial Comments at 32; Clean Energy Associations Initial Comments
at 59-61; CREA and NewSun Initial Comments at 90-91; Cypress Creek
Initial Comments at 18-19; Environmental Defense Fund Initial
Comments at 6; Environmental Defense Fund Reply Comments at 8-9;
ENGIE Initial Comments at 10-11; EPSA Initial Comments at 13;
Equinor Wind Reply Comments at 5-6; Illinois Commission Initial
Comments at 13-14; NARUC Initial Comments at 33-35; National Grid
Initial Comments at 40 (noting qualifications); NRECA Initial
Comments at 44; NY Commission and NYSERDA Initial Comments at 9;
NYTOs Initial Comments at 31; Omaha Public Power Initial Comments at
13; [Oslash]rsted Initial Comments at 8; [Oslash]rsted Reply
Comments at 7; PacifiCorp Initial Comments at 39-40; Pine Gate
Initial Comments at 44, 47-49; OPSI Initial Comments at 9-10; Public
Interest Organizations Initial Comments at 45-47; SEIA Initial
Comments at 38-39; Shell Initial Comments, app. A at ii; SPP Initial
Comments at 24; UMPA Initial Comments at 7-9.
\2586\ NARUC Initial Comments at 33-35.
\2587\ AEE Initial Comments at 40-41; Public Interest
Organizations Initial Comments at 45.
\2588\ AEE Initial Comments at 40-41.
\2589\ SEIA Initial Comments at 38-39; see also ENGIE Initial
Comments at 10-11.
---------------------------------------------------------------------------
1363. Clean Energy Associations and Shell add that a generating
facility's addition of energy storage capability without increasing the
power capability upon which its interconnection service level is based
(e.g., increasing a two-hour battery to a four-hour battery) should not
automatically be considered a material modification.\2590\ Clean Energy
Associations also argue that the removal of a generating facility from
a hybrid or co-located resource interconnection request should not
automatically be considered a material modification if interconnection
service levels do not change.\2591\ Clean Energy Associations also
request that the material modification rules allow for an increase in
the underlying capability of the generating facility, rather than
simply an addition of a new resource.
---------------------------------------------------------------------------
\2590\ Clean Energy Associations Initial Comments at 59-61;
Shell Initial Comments, app. A at ii.
\2591\ Clean Energy Associations Initial Comments at 59-61.
---------------------------------------------------------------------------
1364. Ameren believes that when considering the addition of a
generating facility to an interconnection request, it is important to
protect reliability while avoiding unjustly limiting interconnection
customer changes by automatically deeming them material
modifications.\2592\ National Grid supports the proposal but asks the
Commission to acknowledge that there may be instances when a
determination that the requested generating facility addition is a
material modification is necessary, such as if: (1) changes in load
characteristics of the generating facility or in electrical
characteristics of a resource; or (2) impacts to other interconnection
customers in the interconnection queue.\2593\ SPP also generally
supports the proposal but similarly notes there may be instances when a
request that does not alter the interconnection service amount, it
could require a full interconnection study and result in additional
network upgrades (e.g., a request to change a generating facility from
one type to another where changes to electric characteristics impact
stability, fault current, or both).\2594\
---------------------------------------------------------------------------
\2592\ Ameren Initial Comments at 27.
\2593\ National Grid Initial Comments at 40.
\2594\ SPP Initial Comments at 24.
---------------------------------------------------------------------------
1365. AES supports the proposal because it adds flexibility to the
interconnection process, including the efficient addition of generating
facilities such as electric storage resources to previously submitted
interconnection requests.\2595\ UMPA supports the flexibility of a
generating facility's design if a more commercially viable option could
be pursued without changing the level of interconnection service or
causing reliability concerns, in particular when a prospective
interconnection customer intends to acquire a preexisting
interconnection queue position in accordance with pro forma LGIP
section 4.3.\2596\
---------------------------------------------------------------------------
\2595\ AES Initial Comments at 23.
\2596\ UMPA Initial Comments at 8.
---------------------------------------------------------------------------
1366. AEE suggests that the flexibility to adopt ``modest
modifications'' is important due to the current length of the
interconnection process, technology changes, price declines, and other
factors such as supply chain challenges.\2597\ AEE recognizes that some
modifications may be material and will require restudy but suggests
that disallowing modest changes like adding energy storage that may be
beneficial, will harm reliability, and could increase consumer costs by
limiting the ability to respond to changing opportunities and needs.
NRECA supports the reform if it results in better use of the
transmission system but argues that flexibility should not come at the
expense of the NOPR's overall goal of reducing speculative
interconnection requests, withdrawals, and restudies.\2598\
---------------------------------------------------------------------------
\2597\ AEE Initial Comments at 40-41.
\2598\ NRECA Initial Comments at 44.
---------------------------------------------------------------------------
1367. Some commenters point out that certain RTOs/ISOs use similar
approaches to those proposed.\2599\ NARUC highlights that certain
planning regions have demonstrated that they can reliably accommodate
generating facility additions that do not increase requested services
levels without treating the modification as a material change.\2600\
NARUC underscores CAISO's flexible process that allows interconnection
customers to modify the interconnection request and treats fewer
resource additions as a material modification, which results in more
consistent and predictable interconnection queue outcomes and
ultimately more optimized investments.
---------------------------------------------------------------------------
\2599\ CAISO Initial Comments at 32; NY Commission and NYSERDA
Initial Comments at 9; NYISO Initial Comments at 48-49; SPP Initial
Comments at 24.
\2600\ NARUC Initial Comments at 33-35.
---------------------------------------------------------------------------
(b) Comments in Opposition
1368. A number of commenters oppose the proposal.\2601\ ISO-NE and
[[Page 61205]]
Idaho Power argue that the Commission should require that
interconnection requests be fully conceived by the time a cluster
request window is closed and modifications be proposed in a subsequent
cluster so it does not delay the cluster.\2602\ ISO-NE contends that
the flexibility in the proposal is contrary to the NOPR's goal of
improving study completion timelines and readiness requirements because
adding a generating facility to an interconnection request could
introduce major changes to study scope, upgrade results, and delay
rather than increase study time speed.\2603\
---------------------------------------------------------------------------
\2601\ Ameren Initial Comments at 27; Cypress Creek Initial
Comments at 18-19; Eversource Initial Comments at 33-34; Idaho Power
Initial Comments at 13; Indicated PJM TOs Initial Comments at 52-54;
Indicated PJM TOs Reply Comments at 36-38, 52-54; ISO-NE Initial
Comments at 39-40; MISO Initial Comments at 10; NERC Initial
Comments at 19-20; PacifiCorp Initial Comments at 39-40; PJM Initial
Comments at 18-19, 51-53; Southern Initial Comments at 37-38; SPP
Initial Comments at 24.
\2602\ ISO-NE Initial Comments at 39-40; Idaho Power Initial
Comments at 13.
\2603\ ISO-NE Initial Comments at 39-40.
---------------------------------------------------------------------------
1369. MISO opposes the proposal because it believes that the
proposal will increase speculative interconnection requests, contrary
to the stated intention of NOPR, and that the balance is disrupted
between flexibility to make changes and promoting fairness and
certainty to other interconnection customers.\2604\ PJM, MISO, and
Indicated PJM TOs argue that the proposal will cause delays and divert
resources that would have been used toward processing the
interconnection queue,\2605\ and MISO states the proposal may enable an
end-run around its site control deadlines by giving interconnection
customers more time to obtain site control.\2606\
---------------------------------------------------------------------------
\2604\ MISO Initial Comments at 108-12 (citing Midcontinent
Indep. Sys. Operator, Inc., 177 FERC ] 61,234, at P 12 (2021)); see
also MISO Reply Comments at 9.
\2605\ Indicated PJM TOs Reply Comments at 38; Indicated PJM TOs
Initial Comments at 52-54; MISO Initial Comments at 108-12; PJM
Initial Comments at 6.
\2606\ MISO Initial Comments at 108-12.
---------------------------------------------------------------------------
1370. MISO states that, each time an interconnection customer
requests a fuel change (including the addition of storage), under the
proposal, MISO would have to determine if a material modification
exists within 60 days by doing the following: (1) stop processing the
interconnection queue, create an alternative model, and then run two
system impact studies based on the different models (original and
alternate) to determine if there were any changes between the two
studies; (2) rebuild the models of any lower-queued cycles and run
alternate system impact studies to determine if that would create any
impacts for those interconnection requests, which MISO would not be
able to complete within 60 days; and (3) correct the data that had been
sent to an affected system operator, noting it is unclear if the
affected system operator would be able to inform MISO if the change in
data created a material modification.\2607\ MISO notes that it uses
fuel-based dispatch in its interconnection modeling, which exacerbates
the above problems because it models individual fuel types in different
ways, and includes electric storage in its definition of a different
fuel type, so the addition of electric storage would result in a
different type of modeling.\2608\
---------------------------------------------------------------------------
\2607\ Id.
\2608\ Id. at 110.
---------------------------------------------------------------------------
1371. PJM argues that interconnection customers should only be able
to modify their interconnection requests in certain circumstances,
pointing to its proposal to allow interconnection customers to make
changes that meet pre-defined conditions at three decision points, with
the changes at each decision point restudied together.\2609\ PJM claims
that even if the maximum generating facility output or capacity
interconnection rights do not increase, adding a generating facility to
an interconnection request can affect other interconnection customers.
PJM and Avangrid assert that substituting battery storage facilities
for a portion of a solar generating facility or other generating
facility without changing the generating facility's maximum output or
capacity interconnection rights would likely be a material modification
because it would require a light load test or other testing that was
not performed for the original solar generating facility
interconnection request.\2610\ Ameren also states that such
interconnection request changes can present challenges (e.g., when an
interconnection customer's chosen technology changes due to the passage
of time) and can raise reliability issues if not properly addressed,
and therefore it is necessary to evaluate or conduct a restudy to make
sure that the studies reflect the technologies actually being
interconnected.\2611\ PacifiCorp similarly argues that requests to
incorporate grid-charging battery storage technology should be
processed separately because grid-charging capabilities can alter the
electrical characteristics of an interconnection request.\2612\
---------------------------------------------------------------------------
\2609\ PJM Initial Comments at 51-52 (citing PJM
Interconnection, L.L.C., Filing, Docket No. ER22-2110-000 (filed
June 14, 2022)); see also SEIA Reply Comments at 23 (supporting
PJM's suggestion).
\2610\ PJM Initial Comments at 51-52; Avangrid Initial Comments
at 34-35.
\2611\ Ameren Initial Comments at 27.
\2612\ PacifiCorp Initial Comments at 39-40.
---------------------------------------------------------------------------
NV Energy states that in these situations more detailed studies may
be required in areas of the transmission system where the fault duty is
already high.\2613\
---------------------------------------------------------------------------
\2613\ NV Energy Initial Comments at 18.
---------------------------------------------------------------------------
1372. Southern argues that the proposal should not accept
modifications to interconnection requests without review because these
requests could affect other interconnection customers in the same
cluster as well as lower-queued clusters, adding that it may be a
material modification that impacts the cost or timing of other
interconnection requests.\2614\
---------------------------------------------------------------------------
\2614\ Southern Initial Comments at 37-38.
---------------------------------------------------------------------------
1373. MISO asserts that it is unclear if the NOPR proposal will
require the interconnection customer to submit evidence of site control
before making the modification request or after the request is
granted.\2615\ Idaho Power notes that site control requirements
(primarily acreage) are based on the technology type used in the
interconnection request and would require modification if the
technology is changed.\2616\ Idaho Power therefore argues that changing
fuel type enables speculative interconnection requests that can affect
other interconnection customers both in later clusters and in the same
cluster.
---------------------------------------------------------------------------
\2615\ MISO Initial Comments at 108-12.
\2616\ Idaho Power Initial Comments at 13.
---------------------------------------------------------------------------
1374. Indicated PJM TOs also contend that not treating fuel type
changes as material modifications would provide gaming opportunities,
e.g., an interconnection customer could bypass the site control
demonstration required at the outset of the study process by entering
the interconnection queue with a proposed storage project with a small
site footprint and later, without changing the size of the
interconnection, adding a solar farm with a much larger site
footprint.\2617\ MISO also notes that the NOPR proposal is contrary to
a recent Commission-approved MISO tariff revision regarding changing
fuel types while it the interconnection queue, that went through a
lengthy stakeholder process.\2618\ MISO states that it uses fuel-based
dispatch assumptions for interconnection modeling and argues that there
is not a simple process to determine if changing fuel during the middle
of the interconnection process could cause harm to lower- or equally
queued interconnection requests without running a new study based on
the updated model. MISO explains that it studies storage generating
facilities differently than renewable generating
[[Page 61206]]
facilities, and this affects the interconnection modeling.\2619\
---------------------------------------------------------------------------
\2617\ Indicated PJM TOs Initial Comments at 52-54; Indicated
PJM TOs Reply Comments at 38.
\2618\ MISO Initial Comments at 112-13.
\2619\ Id. at 108-12.
---------------------------------------------------------------------------
1375. Indicated PJM TOs argue that determining the ``materiality''
of a particular type of generating facility modification needs to take
into account the cumulative impact on the cluster studies of all
similar requests.\2620\ Indicated PJM TOs explain that, even if a type
of modification sought by a single interconnection customer may have
modest system impacts and thus not be ``material'' in a particular
case, the cumulative impact of multiple similar requests in the same
area could be much larger.
---------------------------------------------------------------------------
\2620\ Indicated PJM TOs Reply Comments at 38.
---------------------------------------------------------------------------
1376. Indicated PJM TOs contend, however, that certain
modifications made behind the point of interconnection have reliability
impacts requiring restudy and thus amount to material modifications
(e.g., changing fuel type by adding storage to a generating
facility).\2621\ Indicated PJM TOs contend that such changes will
likely affect short circuit capability limits, steady-state thermal and
voltage limits, or dynamic system stability and response.\2622\
Indicated PJM TOs also ask that the Commission recognize that different
fuel types among resources have very different seasonal characteristics
and dynamic response, arguing that the overall reliability of the
transmission system could suffer if certain types of changes are
incorrectly identified as non-material.\2623\ However, Shell contends
that studies of the addition of a generating facility to an
interconnection request should be limited to determining increased
costs and/or study or construction delays of equal or lower-queued
interconnection requests.\2624\
---------------------------------------------------------------------------
\2621\ Id. at 37-38.
\2622\ Id. at 38 (citing PJM Interconnection, L.L.C., Answer,
Docket No. ER19-1958-002, at 5 n.16 (filed Apr. 29, 2020));
Indicated PJM TOs Initial Comments at 52-54.
\2623\ Indicated PJM TOs Initial Comments at 52-54; Indicated
PJM TOs Reply Comments at 38.
\2624\ Shell Initial Comments, app. A at ii.
---------------------------------------------------------------------------
1377. Indicated PJM TOs ask that, at a minimum, the Commission
allow transmission providers to determine the scope of ``material
modifications'' based on their practical experience on their own
systems and apply that knowledge as to the types of changes that
typically affect other customers and that trigger the need for
restudies.\2625\ Tri-State asserts that, when the performance of a new
proposed generating facility differs from the existing/incumbent
generating facility, transient stability analysis would be required but
steady state analysis (thermal/voltage) would not be required.\2626\
---------------------------------------------------------------------------
\2625\ Indicated PJM TOs Reply Comments at 39.
\2626\ Tri-State Initial Comments at 22.
---------------------------------------------------------------------------
1378. NERC argues that transmission providers should study the
potential impacts of any material change to the generating facility,
such as the addition of storage, even when the interconnection service
level does not change, because material modifications to the generating
facility could alter stability and the interaction of a resource with
the transmission system (e.g., adding inverters, which can increase
short circuit current, and charging batteries from the transmission
system, which can impact system power flow).\2627\
---------------------------------------------------------------------------
\2627\ NERC Initial Comments at 19-20.
---------------------------------------------------------------------------
1379. Eversource argues that transmission providers cannot be
expected to meet strict deadlines in an adversarial environment while
interconnection customers may compound these issues by suggesting
significant (even if not ``material'' by the definition of the revised
pro forma LGIP) changes to their generating facilities in the middle of
the interconnection process.\2628\
---------------------------------------------------------------------------
\2628\ Eversource Initial Comments at 34.
---------------------------------------------------------------------------
(c) Comments on Specific Matters
(1) Comments Seeking Materiality Guidelines
1380. Public Interest Organizations assert that the lack of a
standardized definition in the pro forma LGIP of what constitutes a
material modification, such as the addition of storage, leads to a lack
of uniformity among transmission providers and disparate outcomes that
could result in undue discrimination.\2629\ Similarly, Environmental
Defense Fund asks the Commission to clarify how much flexibility
transmission providers will be permitted in determining whether adding
co-located generating facilities changes the service level and becomes
a material modification, and it suggests that the Commission adopt firm
guidelines for transmission providers to determine when the addition of
a generating facility changes the service level to prevent
discrimination against generating facilities based on their inclusion
of hybrid resources.\2630\
---------------------------------------------------------------------------
\2629\ Public Interest Organizations Initial Comments at 45-47.
See also Clean Energy Associations Initial Comments at 59; ENGIE
Initial Comments at 10-11; SEIA Initial Comments at 38-39.
\2630\ Environmental Defense Fund Reply Comments at 8-9.
---------------------------------------------------------------------------
1381. Pine Gate asks the Commission to require transmission
providers to publish additional, consistent criteria regarding what
changes to an interconnection request will and will not be deemed a
material modification, and that transmission providers publish their
determinations about previous modification requests.\2631\ Pine Gate
contends that this information, which certain RTOs/ISOs already provide
to interconnection customers, will reduce the number of restudies,
shorten overall interconnection queue processing timelines, and reduce
costs. Pine Gate, SEIA, and Shell support establishing thresholds,
arguing that providing guidance of what constitutes a material
modification will provide certainty to both interconnection customers
and transmission owners.\2632\
---------------------------------------------------------------------------
\2631\ Pine Gate Initial Comments at 47-49.
\2632\ Id. at 48; SEIA Reply Comments at 23; Shell Initial
Comments, app. A at ii.
---------------------------------------------------------------------------
1382. OPSI asks the Commission to require transmission providers to
publish guidance on technologies and generating facility designs that
would qualify presumptively as minor system modifications.\2633\
Indicated PJM TOs ask for ``bright line'' criteria (based on technical
standards) for material modification to the extent possible, to narrow
the scope of changes in a service request that need to be
evaluated.\2634\ However, Indicated PJM TOs also argue that, in regions
with large interconnection queues, the Commission should give
transmission providers the flexibility to define ``material
modification,'' taking into account the cumulative impact of particular
categories of requested modifications based on the transmission
provider's past experience regarding the expected number of such
requests.\2635\
---------------------------------------------------------------------------
\2633\ OPSI Initial Comments at 9-10.
\2634\ Indicated PJM TOs Initial Comments at 52-54; Indicated
PJM TOs Reply Comments at 37.
\2635\ Indicated PJM TOs Reply Comments at 39.
---------------------------------------------------------------------------
1383. APS supports the proposal but requests guidelines regarding
different technology types (e.g., increasing the size of a battery
while also decreasing the size of a solar generating facility to keep
the interconnection amount the same).\2636\ APS recommends that each
technology type be treated independently in relation to requests to
increase or decrease the sizes in the original interconnection request
or otherwise be deemed a material modification (e.g., if the
characteristics of a storage component change, it should be considered
a different request that may be a material modification).
---------------------------------------------------------------------------
\2636\ APS Initial Comments at 20.
---------------------------------------------------------------------------
1384. R Street similarly asks the Commission to consider
standardized, non-discriminatory conditions that trigger a material
change to an interconnection request, even if the service limit does
not change, arguing
[[Page 61207]]
that hybrid resources should not be penalized for their technology
profile.\2637\ R Street notes, for example, that adding an inverter-
based generating facility to another such facility may not constitute a
material change, but adding a natural gas turbine to a solar site, even
with no increase to net output across the interconnection point, could
create a material shift in interconnection facilities.
---------------------------------------------------------------------------
\2637\ R Street Initial Comments at 16.
---------------------------------------------------------------------------
1385. NARUC asks the Commission to clarify the degree of
flexibility transmission providers have in determining what constitutes
a material reliability concern on the transmission system.\2638\
Cypress Creek asks the Commission to further modify the current
material modification definition to state that certain equipment
changes are not material (e.g., changing solar modules, changing
inverter models, adding storage capacity, or making minor adjustments
to inverter performance) if planned export and import capacity remains
the same and the technology changes comport with interconnection
agreement requirements.\2639\ ClearPath asks: (1) whether under the
proposed definition a change in equipment that necessitates submitting
new models and input data is a material modification; and (2) how
equipment changes for non-synchronous resources will be treated under
the proposed definition of material modification and the proposed
deadlines.\2640\
---------------------------------------------------------------------------
\2638\ NARUC Initial Comments at 33-35.
\2639\ Cypress Creek Initial Comments at 18-19.
\2640\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------
1386. [Oslash]rsted supports the proposed definition of ``material
modification'' but disagrees with imposing restrictions on when
material modifications can be submitted (e.g., after the initial
application).\2641\ [Oslash]rsted asks the Commission to recognize that
modifications may occur at various stages of the process to reflect the
use of evolving technology or to meet Federal or state
requirements.\2642\ [Oslash]rsted acknowledges transmission providers'
time and effort to conduct studies associated with proposed
modifications but states that there is also a need to balance the
interests of the interconnection customer, as there are a number of
reasons why changes to an interconnection request may be necessary and
development time for resources must also be considered. [Oslash]rsted
asserts that transmission providers' differing processes for assessing
material modifications create regulatory uncertainty for
interconnection customers seeking to develop generating facilities in
different regions, which can have significant economic impacts for the
generating facility.\2643\ [Oslash]rsted states that, if the Commission
chooses not to make the proposed change to the modification process,
then, at a minimum, the Commission should encourage development of best
practices that can be implemented by all the RTOs/ISOs with the goal of
increasing efficiency and regulatory certainty.
---------------------------------------------------------------------------
\2641\ [Oslash]rsted Reply Comments at 5 (citing PJM Initial
Comments at 17).
\2642\ Id. at 2.
\2643\ Id. at 6-7.
---------------------------------------------------------------------------
1387. Shell asks the Commission to define the differences between
``co-located additive,'' ``co-located non-additive,'' and ``hybrid''
resources, and explains that these categories will allow transmission
providers to develop proper criteria and business practices governing
additions and/or changes to pending interconnection requests.\2644\
Shell argues that, because transmission providers inconsistently apply
the methods they use to assess which issues qualify as being adverse
material impacts, the Commission should more clearly define the scope
of an ``adverse material impact'' to ensure that transmission providers
consistently determine whether an interconnection request impacts
equally or lower-queued interconnection customer(s) to a sufficient
level of harm.
---------------------------------------------------------------------------
\2644\ Shell Initial Comments, app. A at ii.
---------------------------------------------------------------------------
(2) Comments on Study Timeline
1388. With respect to the study timeline, while NARUC supports the
proposal to require transmission providers to evaluate proposed
generation additions within 60 calendar days because it is a reasonable
amount of time, it suggests that the Commission allow some flexibility
because planning regions and the industry may face challenges aligning
resources and expertise with increasingly aggressive schedules to
perform complex interconnection studies.\2645\ Public Interest
Organizations, on the other hand, argue that the 60-day timeline to
perform an evaluation is critically important for continuing to reduce
delays in interconnection queue processing.\2646\ Cypress Creek
supports the concept of expedited study if the request for a
modification does not change the level of service, there is no impact
on cost or timing of a request that is lower- or equally queued, and it
does not cause reliability concerns.\2647\ Tri-State asks how the 60-
day time frame would work with the cluster study process.\2648\ PJM
opposes the 60-day timeline.\2649\
---------------------------------------------------------------------------
\2645\ NARUC Initial Comments at 33-35.
\2646\ Public Interest Organizations Initial Comments at 45-47.
\2647\ Cypress Creek Initial Comments at 18-19.
\2648\ Tri-State Initial Comments at 30.
\2649\ PJM Initial Comments at 51-53.
---------------------------------------------------------------------------
(3) Comments on Control Technologies
1389. ENGIE suggests that including control technologies in the
evaluation of the addition of a generating facility to an existing
interconnection request should confirm the lack of impact on other
interconnection customers.\2650\ SEIA argues that transmission
providers should be transparent about requiring specific types of
control technologies to add an additional resource.\2651\ Clean Energy
Associations contend that hardware or software controls can also
address, reliably and cost-effectively, concerns about the impact of
the use or addition of energy storage on the reliable operation and
delivery of energy (such as PJM's concern regarding studies for light
load conditions).\2652\
---------------------------------------------------------------------------
\2650\ ENGIE Initial Comments at 11.
\2651\ SEIA Initial Comments at 38-39.
\2652\ Clean Energy Associations Reply Comments at 10-11.
---------------------------------------------------------------------------
(4) Comments on Impacts of Storage in Charging Mode
1390. Pine Gate states that the scope of the required studies for
the addition of storage will vary depending on the proposed
configuration of the resource, such as whether it charges from the
grid.\2653\ NV Energy states that any changes in the electrical
characteristics of the storage system in charging mode versus
generating mode are most likely negligible and unlikely to
significantly impact studies.\2654\
---------------------------------------------------------------------------
\2653\ Pine Gate Initial Comments at 48.
\2654\ NV Energy Initial Comments at 18.
---------------------------------------------------------------------------
1391. APS explains that, based on its experience, the introduction
of new load (not electrical characteristics), such as storage charging
from the grid in lieu of self-charging, which could require changes to
the system overall, could affect the results of the existing study and
other studies.\2655\
---------------------------------------------------------------------------
\2655\ APS Initial Comments at 21.
---------------------------------------------------------------------------
1392. Public Interest Organizations state that the transmission
provider should study whether a storage generating facility's charging
and discharging load profiles may impact the grid.\2656\ Public
Interest Organizations argue that the interconnection customer and
transmission provider should work together to ``identify the temporal
and
[[Page 61208]]
physical charging characteristics to be agreed upon,'' but that the
Commission does not need to further assess the details of the storage
generating facilities charging because those attributes will be tied to
the unique properties of the transmission system at that location and
assessed during the interconnection process to ensure that charging
load and operational profiles do not adversely impact the system.
---------------------------------------------------------------------------
\2656\ Public Interest Organizations Initial Comments at 45-47.
---------------------------------------------------------------------------
(5) Miscellaneous Comments
1393. PJM asks the Commission to restrict the ability to modify
interconnection requests after the initial application by allowing (1)
an interconnection customer to move its point of interconnection only
in certain limited instances and (2) other specified modifications only
at certain specified times to avoid restudies and study delays.\2657\
PJM contends that there is no need to study the materiality of a change
in an interconnection request's point of interconnection because each
such change requires analysis and the application of engineering
judgment, which takes time away from processing interconnection
requests and performing the cluster study. PJM claims that
interconnection customers making changes are really seeking to optimize
their generating facilities mid-process rather than performing due
diligence before entering the interconnection queue.
---------------------------------------------------------------------------
\2657\ PJM Initial Comments at 17-18.
---------------------------------------------------------------------------
1394. With respect to the need for system impact studies, Illinois
Commission argues that, although in some cases additional studies are
necessary in response to a request to add a generating facility to an
existing interconnection request to ensure reliability, transmission
providers should minimize repeating system impact studies to the extent
possible to avoid slowing down the interconnection queue.\2658\ In
response to the concern that evaluating modifications is time-
consuming, [Oslash]rsted asks the Commission to allow third-party
consultants engaged by the interconnection customers to help inform any
studies related to modifications to reduce the workload on RTO/ISO
staff.\2659\
---------------------------------------------------------------------------
\2658\ Illinois Commission Initial Comments at 13-14.
\2659\ [Oslash]rsted Reply Comments at 7.
---------------------------------------------------------------------------
1395. PPL suggests that the transmission provider should assign an
interconnection queue position to the proposed additional generating
facility.\2660\ PPL recommends the study of the original and additional
interconnection request together in the initial phase of the
interconnection process, and if they do not contribute to any network
upgrades or require any interconnection facilities, PPL suggests they
should be able to proceed directly to final agreements.
---------------------------------------------------------------------------
\2660\ PPL Initial Comments at 22.
---------------------------------------------------------------------------
1396. Pine Gate states that, if addition of a grid-charging storage
resource is deemed a material modification, the interconnection
customer should be permitted to propose the addition of a non-grid-
charging electric storage resource as an alternative.\2661\ In order to
reduce the burden on transmission providers, Pine Gate asks the
Commission to permit interconnection customers to provide to
transmission providers engineering analysis applying what Pine Gate
suggests would be published engineering criteria to the requested
modification and analyzing the impacts to other interconnection
customers or reliability, with the transmission provider then
validating the results and determining if the proposed modification is
material.
---------------------------------------------------------------------------
\2661\ Pine Gate Initial Comments at 47-49.
---------------------------------------------------------------------------
1397. Clean Energy Associations explain that if transmission
providers study each component of co-located generating facilities
separately, a wind or solar generating facility could obtain a faster
study for ERIS while the co-located storage could get a more detailed
study for NRIS.\2662\ Clean Energy Associations assert that this
flexibility would provide transmission providers more visibility during
interconnection processes, reduce requests to retrofit generating
facilities with additional co-located resources, and enable faster
interconnection processes for component resources that will accept
curtailment.
---------------------------------------------------------------------------
\2662\ Clean Energy Associations Initial Comments at 59-61.
---------------------------------------------------------------------------
(d) Requests for Clarification and Flexibility
1398. MISO asserts that, if the Commission adopts the proposal, the
Commission should modify the proposed requirement to allow the
``proposed addition of a generating facility to an interconnection
request as long as the interconnection customer does not request a
change to the originally requested interconnection service level and
the proposed addition to the generating facility is modeled the same
way as the original generating facility.'' \2663\
---------------------------------------------------------------------------
\2663\ MISO Initial Comments at 108-12.
---------------------------------------------------------------------------
1399. Clean Energy Associations ask the Commission to clarify
whether (1) generating facility size reductions, which could result in
upgrade costs being shifted to others in the same cluster, would be a
material modification and (2) there is a reduction threshold that would
trigger a material modification.\2664\
---------------------------------------------------------------------------
\2664\ Clean Energy Associations Initial Comments at 64.
---------------------------------------------------------------------------
1400. Invenergy asks the Commission to clarify that its proposed
requirement to evaluate requests to add a generating facility extends
to requests for surplus interconnection service and that those requests
cannot automatically be deemed a material modification.\2665\ Invenergy
argues that, when the surplus interconnection request is below the
total original LGIA interconnection rights and determined a material
modification, the interconnection customer should have the opportunity
to mitigate the identified issue so that it is no longer a material
modification.
---------------------------------------------------------------------------
\2665\ Invenergy Initial Comments at 51-52.
---------------------------------------------------------------------------
1401. Equinor Wind seeks clarification that the proposed definition
of material modification excludes changes that (1) occur on the
interconnection customer's side of the point of interconnection and (2)
do not alter the electrical output or electrical characteristics of a
generating facility, adding that such changes should not be subject to
the transmission provider's discretion or evaluation of whether they
amount to a material modification.\2666\ Equinor Wind argues that these
clarifications will reduce uncertainty for interconnection customers
and allow for some appropriate flexibility during generating facility
development, particularly for offshore wind. Equinor Wind asserts that
this clarification will not create reliability concerns because these
changes do not have transmission system impacts.
---------------------------------------------------------------------------
\2666\ Equinor Wind Reply Comments at 5-6.
---------------------------------------------------------------------------
1402. Indicated PJM TOs ask the Commission to clarify the
relationship between the use of the term ``material modification'' in
the pro forma LGIP and the term ``materially modify'' in NERC
Reliability Standards FAC-001-3 (Facility Interconnection Requirements)
and FAC-002-2 (Facility Interconnection Studies), asserting that the
lack of clarity and overlap between the two terms could cause confusion
and may result in additional delays to the interconnection
process.\2667\ UMPA asks the Commission to clarify that adding a
generating facility includes technology changes beyond electric storage
resources, such as changing from wind to solar.\2668\
---------------------------------------------------------------------------
\2667\ Indicated PJM TOs Initial Comments at 52-54 (noting
NERC's pending petition to change the term from ``materially
modify'' to ``qualified change'').
\2668\ UMPA Initial Comments at 8-9.
---------------------------------------------------------------------------
[[Page 61209]]
1403. With respect to who performs the study to determine the
impact of adding a generating facility to an existing interconnection
request, NARUC argues that, because the reliable operation of the bulk-
power system is at issue, the Commission should clarify that the
transmission providers determine whether (1) the addition of a
generating facility requires a full interconnection service study and
(2) the interconnection customers in the same cluster (or subsequent
clusters) could be adversely impacted.\2669\ NARUC adds that the
Commission should ensure that these processes are transparent, clearly
communicated to interconnection customers, and allow interconnection
customers to mitigate the impacts and revise their modifications
requests.
---------------------------------------------------------------------------
\2669\ NARUC Initial Comments at 33-35.
---------------------------------------------------------------------------
1404. National Grid urges the Commission to allow ISO-NE and NYISO
to maintain their processes that allow the transmission owner and RTO/
ISO to evaluate the proposed change and the RTO/ISO to make the final
determination as to whether the change constitutes a material
modification.\2670\ Indicated PJM TOs argue that the final rule should
have sufficient flexibility to allow PJM's proposed definition of
``material modification'' or permit PJM to obtain an independent entity
variation for its proposed definition.\2671\
---------------------------------------------------------------------------
\2670\ National Grid Initial Comments at 40.
\2671\ Indicated PJM TOs Initial Comments at 52-54.
---------------------------------------------------------------------------
1405. Omaha Public Power asks the Commission to allow transmission
providers to continue their existing processes of facilitating the use
of newer technologies such as storage to promote the stability of these
processes rather than using the proposed process on the NOPR.\2672\
---------------------------------------------------------------------------
\2672\ Omaha Public Power Initial Comments at 13.
---------------------------------------------------------------------------
iii. Commission Determination
1406. We adopt, with modifications, the NOPR proposal to revise
section 4.4.3 of the pro forma LGIP to require transmission providers
to evaluate the proposed addition of a generating facility at the same
point of interconnection prior to deeming such an addition a material
modification, if the addition does not change the originally requested
interconnection service level. We modify the NOPR proposal regarding
section 4.4.3 of the pro forma LGIP, as discussed in greater detail
below, to: (1) remove the 60-calendar day requirement for assessment of
material modification; (2) limit the requirement that the transmission
provider analyze a request to add a generating facility to an existing
interconnection request solely to requests received prior to the
interconnection customer's return of the executed facilities study
agreement to the transmission provider; and (3) create an exception for
transmission providers that employ fuel-based dispatch assumptions from
these requirements.
1407. We find that the record demonstrates that automatically
deeming a request to add a generating facility to an existing
interconnection request to be a material modification creates a
significant barrier to access to the transmission system \2673\ and
renders existing interconnection processes unjust and unreasonable.
Such default treatment deters interconnection customers from proceeding
with changes to a proposed generating facility that, after review, may
be found not to be material, thereby reducing the number of generating
facilities that can access the transmission system. This creates a
barrier to the addition of a generating facility to an existing
interconnection request that may improve the efficient use of the
transmission system.
---------------------------------------------------------------------------
\2673\ See, e.g., AEE Initial Comments at 40-41; Public Interest
Organizations Initial Comments at 45-47; SEIA Initial Comments at
38-39.
---------------------------------------------------------------------------
1408. We make several modifications to the NOPR proposal in
response to concerns reflected in the record. First, we recognize that
it may be difficult for some transmission providers to complete their
material modification evaluations within 60 calendar days, depending on
the details of their individual interconnection processes; therefore,
we decline to adopt a 60-calendar day requirement. This preserves
flexibility for transmission providers to address modification requests
as is most efficient with their overall interconnection queue
processing.
1409. Second, we modify the NOPR proposal to limit when an
interconnection customer may request to add a generating facility to an
existing interconnection request without such a request automatically
being deemed a material modification. We are persuaded by commenters'
arguments that allowing requests for evaluation to occur at any point
in the interconnection process could impede the ability of the
transmission provider to timely process its interconnection
queue.\2674\ Thus, we modify the NOPR proposal, and transmission
providers will only be required to evaluate whether a request to add a
generating facility to an existing interconnection request is material
if it is submitted before the interconnection customer returns the
executed facilities study agreement to the transmission provider. Once
the executed facilities study agreement is returned, the transmission
provider may decide to automatically treat requests to add a generating
facility to an existing interconnection request as material
modifications without review.
---------------------------------------------------------------------------
\2674\ See, e.g., Indicated PJM TOs Initial Comments at 52-54;
Indicated PJM TOs Reply Comments at 38; MISO Initial Comments at
108-112; PJM Initial Comments at 6.
---------------------------------------------------------------------------
1410. We clarify that interconnection customers may continue to
request changes to proposed generating facilities at any time in the
interconnection process. Transmission providers that choose to evaluate
modification requests later in the interconnection process than
required by this rule (i.e., after the interconnection customer returns
the executed facilities study agreement to the transmission provider)
may continue to do so. This final rule does not address how
transmission providers evaluate modification requests after the
facilities study agreement, and thus transmission providers are not
required to include their modification processes after the facilities
study agreement in their compliance filing with this final rule.
1411. We acknowledge that, as stated by commenters, transmission
providers that employ fuel-based dispatch assumptions, such as MISO,
may experience challenges with the proposal because the interconnection
study assumptions in a fuel-based dispatch model vary depending on the
fuel type; thus a request to add a generating facility of a different
fuel type to an existing interconnection request would always
constitute a modification that would require a study, thereby affecting
the interconnection costs or study timing for lower- or equally-queued
interconnection customers.\2675\ This type of request would most likely
represent a material modification and would result in the loss of
interconnection queue position under the tariff. Therefore, we modify
the proposal to include an exception for transmission providers that
use fuel-based dispatch assumptions in their interconnection studies.
---------------------------------------------------------------------------
\2675\ See, e.g., MISO Initial Comments at 108-12.
---------------------------------------------------------------------------
1412. In response to EPSA's and Equinor Wind's request to provide a
clearer standard definition of material modification,\2676\ we note
that we are not changing the definition of material modification in
this rule and do not believe a more prescriptive definition of material
modification is reasonable
[[Page 61210]]
given the nuances in transmission providers' processes for assessing
material modification, as described in the comments.\2677\ With respect
to NARUC's request to clarify the flexibility transmission providers
have in determining what constitutes a material reliability concern on
the transmission system,\2678\ we clarify that this reform only
requires transmission providers to evaluate interconnection
modification requests. As stated above, it does not alter the
definition of material modification.
---------------------------------------------------------------------------
\2676\ EPSA Initial Comments at 13; Equinor Wind Reply Comments
at 5-6.
\2677\ See, e.g., National Grid Initial Comments at 40.
\2678\ NARUC Initial Comments at 33-35.
---------------------------------------------------------------------------
Transmission providers may continue to find requests to be material
if they impact the cost or timing of an equally or lower-queued
interconnection customers.
1413. Commenters request clarification about the requirements for
demonstrating site control when submitting a modification
request.\2679\ In response, we clarify that, where a modification
request to add a generating facility to an existing interconnection
request requires the interconnection customer to adhere to a larger
footprint to support a modified facility design, the interconnection
customer must provide evidence of the required site control when
submitting the modification request to the transmission provider. The
requirements for site control that the interconnection customer must
adhere to may depend on the timing of the request for the modification
as well as the technology type of the requested additional generating
facility, as discussed in the site control portion of this rule.\2680\
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\2679\ See, e.g., Indicated PJM TOs Initial Comments at 52.
\2680\ See supra section III.A.6.b of this final rule.
---------------------------------------------------------------------------
1414. Indicated PJM TOs also request that the Commission clarify
the relationship between the term ``material modification'' in the pro
forma LGIP and the term ``materially modify'' in NERC Reliability
Standard FAC-001-3.\2681\ We find that this request to further define
the relationship between the terms is outside of the scope of this
rulemaking. As discussed above, this final rule does not alter the
preexisting definition of a material modification. Moreover, we note
that the Commission recently approved a change to the NERC FAC
Reliability Standards to change ``materially modify'' to ``qualifying
change.'' \2682\
---------------------------------------------------------------------------
\2681\ Indicated PJM TOs Initial Comments at 52.
\2682\ See N. Am. Elec. Reliability Corp., 181 FERC ] 61,126 at
P 9 (2022) (explaining that replacing materially modify with
qualified change ``removes the possibility of confusion with the
Commission's defined term `Material Modification' in its pro forma
interconnection procedures and agreements'').
---------------------------------------------------------------------------
1415. ClearPath seeks clarification regarding equipment changes,
specifically whether under the proposed definition of material
modification, a change in equipment that necessitates submitting new
models and input data is a material modification and how equipment
changes for non-synchronous resources will be treated under the
proposed definition of material modification and the proposed
deadlines.\2683\ We clarify that an equipment change, whether for
synchronous or non-synchronous resources, that does not change the
originally requested interconnection service level and does not qualify
for evaluation under the transmission provider's technological change
procedure must be evaluated by the transmission provider to determine
if it is a material modification.
---------------------------------------------------------------------------
\2683\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------
1416. Similarly, Equinor Wind seeks clarification that the proposed
definition of material modification excludes changes that do not alter
the electrical output or electrical characteristics of an
interconnection request, suggesting that such changes should not be
subject to the transmission provider's discretion or evaluation of
whether they amount to a material modification.\2684\ We note that the
definition of material modification is based on whether changes have a
material impact on the cost or timing of any interconnection request
with an equal or lower interconnection queue position, and thus we
decline to categorically exclude certain types of changes from the
definition.
---------------------------------------------------------------------------
\2684\ Equinor Wind Reply Comments at 5-6.
---------------------------------------------------------------------------
1417. Clean Energy Associations ask the Commission to clarify
whether: (1) generating facility size reductions, which could result in
upgrade costs being shifted to others in the same cluster, would be a
material modification; and (2) there is a reduction threshold that
would trigger a material modification.\2685\ We clarify that, as per
pro forma LGIP section 4.4.1, prior to the return of the cluster study
agreement from the transmission provider to the interconnection
customer, a decrease of up to 60% of electrical output (MW) must not be
considered a material modification. In addition, per pro forma LGIP
section 4.4.2, prior to the return of the executed interconnection
facilities study, an additional 15% decrease of electrical output of
the proposed project must not be considered a material modification if
the change occurred either through a decrease in plant size (MW) or a
decrease in interconnection service level accomplished by applying
transmission provider-approved injection-limiting equipment.
---------------------------------------------------------------------------
\2685\ Clean Energy Associations Initial Comments at 64.
---------------------------------------------------------------------------
1418. Invenergy, in discussing both surplus interconnection and
material modification, contends that in circumstances where a surplus
interconnection request is below the total LGIA interconnection rights
and determined to be a material modification, the interconnection
customer should have the opportunity to mitigate identified issues such
that there is no longer a material modification.\2686\ We find this
request to be outside the scope of this proceeding because the final
rule is not proposing a process whereby interconnection customers may
mitigate identified issues to avoid a material modification
determination. In response to Invenergy's request to clarify that the
proposed reforms to require evaluation of requests to add a generating
facility extend to requests for surplus interconnection service, the
Commission declines to make such a change. The surplus interconnection
service process is separate from the material modification process, and
the two processes should not be conflated.
---------------------------------------------------------------------------
\2686\ Invenergy Initial Comments at 51.
---------------------------------------------------------------------------
1419. We decline to adopt firm guidelines that transmission
providers will follow to determine what constitutes a material
modification when a request to add a generating facility to an existing
interconnection request involves adding co-located generating
facilities.\2687\ The varying configurations and varying electrical
characteristics that interconnection customers may propose through this
process may alter how they impact equally or lower-queued
interconnection customers, and therefore we find that transmission
providers must retain flexibility to evaluate these requests.
---------------------------------------------------------------------------
\2687\ We consider Shell's request for the Commission to define
the differences between ``co-located additive,'' ``co-located non-
additive,'' and ``hybrid'' resources, as well as Shell's request to
specify the approach to charging energy, to be included among the
requests for firm guidelines.
---------------------------------------------------------------------------
c. Availability of Surplus Interconnection Service
i. Need for Reform and NOPR Proposal
1420. In the NOPR, the Commission noted that Order No. 845
established a surplus interconnection service process to enable a new
interconnection customer to use the unused portion of an existing
interconnection customer's
[[Page 61211]]
approved interconnection service through the inclusion of an additional
generating facility behind a single point of interconnection.\2688\ The
Commission also noted that Order No. 845 did not specify when a
generating facility is considered to be ``existing,'' and preliminarily
found that limiting the use of surplus interconnection service to only
interconnection customers that have achieved commercial operation may
be unjust, unreasonable, and unduly discriminatory or
preferential.\2689\
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\2688\ NOPR, 179 FERC ] 61,194 at P 262.
\2689\ Id. P 263.
---------------------------------------------------------------------------
1421. The Commission proposed to revise the pro forma LGIP to
require 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.\2690\
---------------------------------------------------------------------------
\2690\ Id. P 264.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1422. The vast majority of commenters on this topic either support
or do not oppose the proposal regarding surplus interconnection
service, though some seek various clarifications.\2691\ MISO states
that surplus interconnection requests are the proper method for
interconnection customers to add storage or a different generating
facility fuel source to an interconnection request for an unbuilt
generating facility \2692\ and suggests that the Commission limit when
the transmission provider must tender a surplus interconnection
agreement to the interconnection customer to prevent a surplus
interconnection agreement from being tendered prior to the original
interconnection agreement becoming effective. MISO explains that its
generator interconnection procedures allow for a surplus
interconnection request to be made during the processing of the
interconnection queue and adds that MISO is not required to tender a
surplus interconnection agreement until the original interconnection
agreement has become effective because a surplus interconnection
agreement is a derivative of the original interconnection agreement.
According to MISO, under the proposed reform, the surplus
interconnection agreement could be tendered prior to the original
interconnection agreement becoming effective if the original
interconnection agreement is filed unexecuted and becomes the subject
of a disputed proceeding.
---------------------------------------------------------------------------
\2691\ AEE Initial Comments at 41; AEP Initial Comments at 5,
44-45; APS Initial Comments at 21; Clean Energy Associations Initial
Comments at 61; CREA and NewSun Initial Comments at 91; Elevate
Initial Comments at 11-12; Enel Initial Comments at 79; Eversource
Initial Comments at 34; Iowa Commission Initial Comments at 4; NARUC
Initial Comments at 36; National Grid Initial Comments at 41;
NextEra Initial Comments at 37; NRECA Initial Comments at 44; Omaha
Public Power Initial Comments at 13; PacifiCorp Initial Comments at
40; SEIA Initial Comments at 39; Shell Initial Comments at 36; SPP
Initial Comments at 24.
\2692\ MISO Initial Comments at 113-14.
---------------------------------------------------------------------------
(b) Comments in Opposition
1423. Some commenters either argue that the NOPR proposal is
inappropriate for their situation or oppose it outright, in some cases
arguing against the underlying concept of surplus interconnection
service. For instance, NYISO asserts that it does not provide for the
use of ``surplus'' interconnection service and the Commission has
previously granted NYISO an independent entity variation from the
surplus interconnection service requirement.\2693\ NYISO asserts that
this independent entity variation remains just and reasonable and
accomplishes the purposes of Order No. 845 and the instant NOPR to make
it easier for proposed generating facilities to interconnect without
costly upgrades.\2694\
---------------------------------------------------------------------------
\2693\ NYISO Initial Comments at 49 (citing N.Y. Indep. Sys.
Operator, Inc., 170 FERC ] 61,117, at P 98 (2020)).
\2694\ Id. at 50.
---------------------------------------------------------------------------
1424. ISO-NE states that allowing for co-location of generating
facilities meets the need of allowing surplus interconnection service
to be available after executing an LGIA, rendering the proposed reform
unnecessary.\2695\ ISO-NE explains that, unless the existing generating
facility is already commercial, there is no unused capability available
at the point of interconnection. ISO-NE asserts that, to the extent the
interconnection customer wants to co-locate generating facilities, it
should be required to propose that as part of the original
interconnection request.
---------------------------------------------------------------------------
\2695\ ISO-NE Initial Comments at 40.
---------------------------------------------------------------------------
1425. CAISO disagrees that allowing an interconnection customer to
request surplus interconnection service after the original
interconnection customer executes an LGIA would enable interconnection
customers with unused interconnection capacity to let other generating
facilities use that capacity earlier than allowed.\2696\ CAISO contends
that interconnection customers do not request to use surplus
interconnection service, and further reform is unlikely to have much
effect because surplus interconnection service is unavailable
independent of the Commission's definition. CAISO asserts that
interconnection customers do not oversize their interconnection
capacity; therefore, other interconnection customers cannot avail
themselves of any ``surplus'' because it is already subscribed.
---------------------------------------------------------------------------
\2696\ CAISO Initial Comments at 32-33.
---------------------------------------------------------------------------
1426. PJM asserts that the current surplus interconnection service
construct provides no value due to the challenges inherent in assessing
the dynamic response associated with adding a surplus generating
facility to the system while not infringing on the rights of the
interconnection customers in the interconnection queue or available
``headroom.'' \2697\ Therefore, PJM contends that it sees no benefit in
expanding its application and that PJM's current surplus
interconnection service is rarely used. PJM asserts that surplus
interconnection service imposes overhead costs without providing value
to interconnection customers wishing to interconnect.
---------------------------------------------------------------------------
\2697\ PJM Initial Comments at 65.
---------------------------------------------------------------------------
1427. In response to PJM and CAISO's comments, SEIA replies that
both PJM and CAISO take an overly narrow approach to surplus
interconnection service and that past use of surplus interconnection
service should not bar making the service available to future requests
to add storage to a generating facility.\2698\
---------------------------------------------------------------------------
\2698\ SEIA Reply Comments at 23-25.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
1428. Other commenters argue that, at least in some situations,
surplus interconnection service should be available even earlier than
proposed in the NOPR. For instance, Ameren asserts that there is no
need to restrict the request to an executed, or requested unexecuted,
LGIA.\2699\ Ameren contends that, under the Commission's proposal, MISO
and the interconnection customer would have finalized the network
upgrades and system impact study only to go back to assess what surplus
interconnection capacity would have been available. Therefore, Ameren
asks the Commission to allow for regional flexibility. Omaha Public
Power likewise recommends that the Commission allow existing
transmission provider processes that are facilitating new technologies
to continue.\2700\
---------------------------------------------------------------------------
\2699\ Ameren Initial Comments at 28.
\2700\ Omaha Public Power Initial Comments at 13.
---------------------------------------------------------------------------
1429. Pine Gate favorably cites MISO's process for surplus
interconnection service and asserts that the Commission should expand
its
[[Page 61212]]
current proposal to permit interconnection customers to access the
surplus interconnection service process upon completion of the cluster
restudy phase.\2701\ Invenergy states that the Commission should permit
requests for surplus interconnection service after an interconnection
request has an executed facilities study agreement.\2702\ Invenergy
contends that the Commission could further clarify that an LGIA must be
in place for the initial facility before any LGIA for the surplus
interconnection service can be tendered. Invenergy asserts that, if the
Commission does not modify the NOPR, it should clarify that
transmission providers like MISO that have existing practices under
which surplus interconnection service can be requested earlier in the
process may continue those existing practices in compliance filings
after any final rule may become effective. Invenergy also states that
the Commission should reinforce its commitment in Order No. 845 that
surplus interconnection service is available up to the maximum level
allowed under the original interconnection agreement.\2703\ According
to Invenergy, some transmission providers significantly limit an
interconnection customer's surplus interconnection rights by deeming an
otherwise permitted request a material modification except in the
limited situation of direct current (DC)-coupled behind-the-meter
storage, which effectively precludes surplus interconnection service in
all other circumstances under a standard that is not well-defined or
explained.
---------------------------------------------------------------------------
\2701\ Pine Gate Initial Comments at 49-50.
\2702\ Invenergy Initial Comments at 50.
\2703\ Id. at 50-51 (citing Order No. 845, 163 FERC ] 61,043 at
P 475).
---------------------------------------------------------------------------
1430. Elevate encourages the Commission to consider modifying the
duration of the period in which an interconnection customer taking
surplus interconnection service can continue to operate following the
original, host generating facility's retirement.\2704\ Elevate contends
that, although an interconnection customer taking surplus
interconnection service may operate for up to a year following the
original generating facility's retirement, a one-year period is too
short when it may take four years or more to navigate the
interconnection process. According to Elevate, a surplus
interconnection customer should be able to operate sufficiently long
following the original generating facility's retirement that it has the
ability to obtain permanent interconnection service through the
submission of a new interconnection request.\2705\ Elevate contends
that this will ensure that generation capacity that has been fully
constructed and is contributing to system reliability is not
unnecessarily forced offline due to interconnection queue backlogs
beyond their control.
---------------------------------------------------------------------------
\2704\ Elevate Initial Comments at 11-12.
\2705\ Id. at 12 (citing Order No. 845, 163 FERC ] 61,043 at P
506).
---------------------------------------------------------------------------
(d) Requests for Clarification
1431. Shell contends that the Commission should clarify that
transmission providers cannot deny surplus interconnection capacity
except where (1) the total amount of interconnection service, measured
in MW, at the point of interconnection has increased, or (2) there will
be a reliability risk to the relevant transmission system.\2706\
---------------------------------------------------------------------------
\2706\ Shell Initial Comments at 36.
---------------------------------------------------------------------------
1432. NARUC asks the Commission to clarify in the pro forma LGIP
that an interconnection customer that has been fully studied and has an
executed LGIA, or has filed an unexecuted LGIA, should be considered an
existing facility for purposes of surplus interconnection
service.\2707\ NARUC asserts that this clarification will increase
efficiency in interconnection queues throughout the planning regions
and ensure that available interconnection capacity can be used
efficiently.
---------------------------------------------------------------------------
\2707\ NARUC Initial Comments at 36.
---------------------------------------------------------------------------
1433. Enel requests that the Commission specify that parallel,
simultaneous operation and injection of two distinct, alternating
current (AC)-coupled generating facilities is an acceptable
configuration for surplus interconnection service so long as the total
injection of energy at the point of interconnection does not exceed the
interconnection service level.\2708\
---------------------------------------------------------------------------
\2708\ Enel Initial Comments at 79.
---------------------------------------------------------------------------
1434. APS and PacifiCorp ask the Commission to clarify that no
surplus can be provided if the LGIA of the original interconnection
request is suspended.\2709\ PacifiCorp explains that, if the underlying
LGIA is suspended, then there is no guarantee that the facilities
required for interconnection will be installed.\2710\ APS further
asserts that, if an interconnection customer requests to go into
suspension after a surplus request is granted, then that would also
require the surplus interconnection to be suspended.\2711\ PacifiCorp
asserts that any work the transmission provider were to undertake
relating to the surplus interconnection service may be wasted effort if
the LGIA never comes out of suspension.\2712\ PacifiCorp asks the
Commission to clarify that, if the original surplus interconnection
request exceeds its permitted suspension period, both the original LGIA
and any surplus interconnection service shall be terminated.
---------------------------------------------------------------------------
\2709\ APS Initial Comments at 21; PacifiCorp Initial Comments
at 40.
\2710\ PacifiCorp Initial Comments at 40.
\2711\ APS Initial Comments at 21.
\2712\ PacifiCorp Initial Comments at 40-41.
---------------------------------------------------------------------------
1435. Idaho Power requests clarification as to whether the
Commission intends for the surplus interconnection service process to
be used for an interconnection customer that owns a generating
facility, either in-service or with an executed interconnection
agreement, to add energy storage after the interconnection agreement is
executed, or if the Commission intends for these additions to be
evaluated under pro forma LGIA article 5.19 (Modification).\2713\
---------------------------------------------------------------------------
\2713\ Idaho Power Initial Comments at 14.
---------------------------------------------------------------------------
iii. Commission Determination
1436. We adopt the NOPR proposal to revise section 3.3.1 of the pro
forma LGIP to require 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.
1437. We find, based on the record, that this reform will enable
interconnection customers with unused interconnection service to let
other generating facilities use that interconnection service earlier
than is currently allowed and, therefore, increases overall efficiency
of the interconnection queue.\2714\ Because we find this reform to be
just and reasonable, to remedy the unjust and unreasonable rates caused
by the limited ability to use surplus interconnection service today and
ensure that interconnection customers are able to interconnect in a
reliable, efficient, transparent, and timely manner, we decline to
adopt alternative proposals suggested by commenters.
---------------------------------------------------------------------------
\2714\ See, e.g., AEE Initial Comments at 41.
---------------------------------------------------------------------------
1438. We find unpersuasive the comments from various RTOs/ISOs
opposing the NOPR proposal.\2715\ To the extent that they oppose the
surplus interconnection service process approved by the Commission in
Order No. 845, we find their arguments to be a collateral attack on the
Commission's findings in Order No. 845 and irrelevant for purposes of
determining whether the instant proposal is just and reasonable.
Further, consistent with the NOPR, we
[[Page 61213]]
continue to find that expanding the availability of surplus
interconnection service beyond those entities that have achieved
commercial operation will address the Commission's concerns regarding
undue restrictions on access to this surplus interconnection
service,\2716\ thereby making it available to a broader group of
potential interconnection customers and achieving the efficiencies
discussed above.
---------------------------------------------------------------------------
\2715\ CAISO Initial Comments at 32-33; ISO-NE Initial Comments
at 40; NYISO Initial Comments 49-50; PJM Initial Comments at 65.
\2716\ NOPR, 179 FERC ] 61,194 at P 263.
---------------------------------------------------------------------------
1439. We are also not persuaded by either Pine Gate's or Ameren's
arguments \2717\ to alter the NOPR proposal to require transmission
providers to allow interconnection customers to access the surplus
interconnection service process prior to the LGIA phase or Invenergy's
argument to allow requests for surplus interconnection service once
there is an executed facilities study agreement.\2718\ We find that
allowing interconnection customers to access the surplus
interconnection service process once the original interconnection
customer obtains an executed LGIA, or requests the filing of an
unexecuted LGIA, is appropriate because prior to that stage, the
network upgrades necessary to create the identified amount of surplus
interconnection service may not have been fully identified, let alone
begun the process of being placed into service.
---------------------------------------------------------------------------
\2717\ Ameren Initial Comments at 28; Pine Gate Initial Comments
at 50.
\2718\ Invenergy Initial Comments at 49.
---------------------------------------------------------------------------
1440. In response to APS's and PacifiCorp's requests for
clarification regarding suspensions,\2719\ we clarify that: (1) if the
LGIA of the original interconnection request is suspended, then any
submitted requests for surplus interconnection service are likewise
suspended, and new requests for surplus interconnection service may not
be submitted, until after the suspension is lifted; and (2) if the
original LGIA is terminated, including for exceeding the three-year
suspension period (pursuant to pro forma LGIA article 5.16), any
related surplus interconnection service allowed as a result of the
original LGIA will be terminated because surplus interconnection
service is dependent upon the underlying interconnection service used
by existing generating facilities.
---------------------------------------------------------------------------
\2719\ APS Initial Comments at 21; PacifiCorp Initial Comments
at 40-41.
---------------------------------------------------------------------------
1441. In response to NARUC's request to clarify that an
interconnection customer that has been fully studied and has an
executed LGIA, or that has requested the filing of an unexecuted LGIA,
should be considered an existing facility for purposes of surplus
interconnection service, we decline to make such clarification, but
reiterate that where an interconnection customer has executed the LGIA,
or requested that the LGIA be filed unexecuted, interconnection
customers may submit surplus interconnection service requests to the
transmission provider.
1442. We find that Enel's and Shell's respective requests \2720\
for clarification regarding establishing parameters on surplus
interconnection service are outside the scope of this proceeding
because this final rule is not proposing to modify eligibility for
surplus interconnection service as established in Order No. 845.
---------------------------------------------------------------------------
\2720\ Enel Initial Comments at 79; Shell Initial Comments at
36.
---------------------------------------------------------------------------
1443. We also find that Elevate's request \2721\ for the Commission
to modify the duration in which an interconnection customer taking
surplus interconnection service can continue to operate following the
original, host generating facility's retirement is outside the scope of
this proceeding because this final rule is not proposing to modify the
length of time for which surplus interconnection service may be
provided after the original generating facility retires.
---------------------------------------------------------------------------
\2721\ Elevate Initial Comments at 11-12.
---------------------------------------------------------------------------
1444. In response to Idaho Power's request for clarification
regarding whether the Commission intends for the surplus
interconnection service process to be used for an interconnection
customer that owns a generating facility with an executed or unexecuted
LGIA to later add energy storage,\2722\ the answer depends upon how the
energy storage facility will be used. If, for example, it is used only
to firm up the underlying generating facility (e.g., a wind or solar
power plant) without ever injecting in excess of the original
interconnection service level, then surplus interconnection service may
be used.\2723\ If, on the other hand, the new energy storage facility
and the existing generating facility will be configured to inject
together and exceed the original interconnection service limit, then
surplus interconnection service may not be used.
---------------------------------------------------------------------------
\2722\ Idaho Power Initial Comments at 14.
\2723\ See Order No. 845, 163 FERC ] 61,043 at P 472
(``[S]urplus interconnection service cannot exceed the total
interconnection service already provided by the original
interconnection customer's LGIA.'').
---------------------------------------------------------------------------
1445. In response to Invenergy's requests,\2724\ we clarify that
the original interconnection customer must have an LGIA in place,
either executed or requested to be filed unexecuted with the
Commission, prior to tendering any LGIA for surplus interconnection
service. With respect to Invenergy's request for flexibility for
transmission providers that currently allow requests for surplus
interconnection service before the LGIA phase, we note that
transmission providers can propose deviations from the requirements
adopted in this final rule and demonstrate how those deviations satisfy
the standards discussed in section IV of this final rule, which the
Commission will consider on a case-by-case basis.
---------------------------------------------------------------------------
\2724\ Invenergy Initial Comments at 50.
---------------------------------------------------------------------------
1446. In response to Invenergy's request to clarify that proposed
reforms to require evaluation of requests to add a generating facility
to an interconnection request extend to requests for surplus
interconnection service, we clarify that the revisions to the
modification process do not extend to the surplus interconnection
service process. We note that the modification process revisions would
be used by an interconnection customer while undergoing the
interconnection study process, whereas the surplus interconnection
process revisions would be used after the interconnection study process
is complete and the interconnection customer has an executed LGIA, or
an unexecuted and filed LGIA.
1447. Invenergy requests that the Commission reiterate and
reinforce its commitment in Order No. 845 that surplus interconnection
service is available up to the maximum level allowed under the original
interconnection agreement. Invenergy contends that, when the surplus
interconnection service request is below the total LGIA interconnection
rights and determined to be a material modification, the
interconnection customer should have the opportunity to mitigate
identified issues such that there is no longer a material modification.
We decline Invenergy's request because the final rule does not address
revisions to how the surplus interconnection service process is
conducted; rather, the final rule addresses when a request for surplus
interconnection service may be submitted.
d. Operating Assumptions for Interconnection Studies
i. Need for Reform and NOPR Proposal
1448. In the NOPR, the Commission stated that, as newer
technologies with operating parameters that differ from traditional
generation seek to interconnect, it is necessary for transmission
providers to use
[[Page 61214]]
assumptions that accurately reflect ``the operating parameters of
electric storage resources and co-located resources containing electric
storage resources (including hybrid resources) so that the unique
operating characteristics of such resources are taken into account
during the generator interconnection process.'' \2725\ The Commission
stated that, because the pro forma LGIP includes only general
requirements regarding the operating assumptions for generating
facilities in interconnection studies, it was concerned that ``electric
storage resources, and co-located resources containing electric storage
resources, may be studied under inappropriate operating assumptions
that result in assigning unnecessary network upgrades and increased
costs to interconnection customers.'' \2726\ The Commission therefore
preliminarily found that ``the lack of realistic operating assumptions
used in interconnection studies for electric storage resources and co-
located resources containing electric storage resources (including
hybrid resources) can result in excessive and unnecessary network
upgrades and may hinder the timely development of new generation,
thereby stifling competition in the wholesale markets, and resulting in
rates, terms, and conditions that are unjust and unreasonable.'' \2727\
Further, the Commission preliminarily found that ``the lack of
appropriate operating assumptions used in interconnection studies may
present an unduly discriminatory or preferential barrier to the
interconnection of electric storage resources and co-located resources
containing electric storage resources (including hybrid resources).''
\2728\
---------------------------------------------------------------------------
\2725\ NOPR, 179 FERC ] 61,194 at P 279.
\2726\ Id.
\2727\ Id.
\2728\ Id.
---------------------------------------------------------------------------
1449. The Commission proposed to revise the pro forma LGIP to
require transmission providers, at the request of the interconnection
customer, to use ``operating assumptions for interconnection studies
that reflect the proposed operation of an electric storage resource or
co-located resource containing an electric storage resource (including
hybrid resources)--i.e., whether the interconnecting resource will or
will not charge during peak load conditions, unless good utility
practice, including applicable reliability standards, otherwise require
the use of different operating assumptions.'' \2729\ The Commission
noted that, under this proposed reform, such operating assumptions
shall be proposed by the interconnection customer as part of its
initial interconnection request.
---------------------------------------------------------------------------
\2729\ Id. P 280.
---------------------------------------------------------------------------
1450. The Commission further proposed that such operating
assumptions must be ``reasonably representative of the likely behavior
of an electric storage resource or co-located resource containing an
electric storage resource (including hybrid resources) and, in cases
where available, consistent with the historical performance of such
resources in the relevant geographic area.'' \2730\ Further, to help
facilitate alignment between as-studied and real-world conditions, the
Commission proposed to allow transmission providers to hold
interconnection customers to the intended operation of their electric
storage resource or co-located resource containing an electric storage
resource (including hybrid resources) by: (1) memorializing these
operating restrictions in the interconnection customer's LGIA; and (2)
requiring control technologies (software and/or hardware) in cases
where appropriate, such as for electric storage that wishes to limit
its operations, with such protection devices included in Appendix C of
the LGIA.\2731\ The Commission noted that, ``if the interconnection
customer fails to operate its electric storage resource or co-located
resource containing an electric storage resource (including hybrid
resources) in accordance with these conditions as memorialized in the
LGIA, the interconnection customer may be considered in breach and the
transmission provider may pursue termination pursuant to article 17 of
the LGIA.'' \2732\ Additionally, the Commission proposed to ``require
that any transmission provider that requires electric storage resources
or co-located resources containing an electric storage resource
(including hybrid resources) to install control technologies to
publicly post a list of acceptable control technologies.'' \2733\
Furthermore, the Commission proposed revisions to the description of
the ERIS and NRIS studies in sections 3.2.1.2. and 3.2.2.2 of the pro
forma LGIP to accommodate this proposed reform.
---------------------------------------------------------------------------
\2730\ Id.
\2731\ Id.
\2732\ Id.
\2733\ Id.
---------------------------------------------------------------------------
1451. The Commission proposed to require that interconnection
customers clearly communicate to the transmission provider ``the
expected operating patterns of the electric storage resource, or co-
located resource containing an electric storage resource (including
hybrid resources).'' \2734\ In addition, for ``the electric storage
resource or co-located resource containing an electric storage resource
(including hybrid resources) to be studied, the Commission proposed to
require the interconnection customer to specify, as part of its initial
interconnection request, the ancillary services that it would or would
not provide so that the proper operating assumptions may be made in
interconnection studies.'' \2735\ Under the Commission's proposal,
regardless of any changes to operating assumptions, ``all electric
storage resources, or co-located resources containing an electric
storage resource (including hybrid resources) would be required to
continue to meet all requirements in the pro forma LGIP and pro forma
LGIA, as well as all applicable reliability standards.'' \2736\
---------------------------------------------------------------------------
\2734\ Id. P 281.
\2735\ Id.
\2736\ Id.
---------------------------------------------------------------------------
1452. The Commission noted that, under this proposed reform, each
transmission provider's operating assumptions used in their
interconnection studies must take into consideration the services that
the generating facility would provide and the timing of such services,
as applicable.\2737\ The Commission further noted that this could be
done in a variety of ways, and the transmission provider would have
flexibility to consider services as best fits its transmission system.
---------------------------------------------------------------------------
\2737\ Id. P 282.
---------------------------------------------------------------------------
1453. The Commission proposed to clarify that ``this proposed
reform to study electric storage resources, or co-located resources
containing an electric storage resource (including hybrid resources)
according to their planned operating assumptions at the request of the
interconnection customer as part of its initial interconnection request
is intended to mean the operating assumptions for withdrawals of energy
(e.g., the charging of an energy storage resource) in interconnection
studies.'' \2738\ The Commission proposed to require that the
interconnection customer include in its initial interconnection request
any operating assumptions for withdrawals of energy to be used by the
transmission provider in interconnection studies.
---------------------------------------------------------------------------
\2738\ Id. P 285.
---------------------------------------------------------------------------
1454. The Commission sought comment on whether the Commission
should expand this reform to address operating assumptions for
additional generating facility technologies that may currently be
inaccurately modeled, such as variable energy resources.\2739\ For
example, the Commission sought
[[Page 61215]]
comment on whether to expand this proposal to specify only that, at the
interconnection customer's request, a transmission provider must not
study generating facilities in ways that are not physically possible,
for example studying a solar resource as producing energy at night, or
a wind resource as producing maximum energy during low wind seasons, or
other circumstances wherein any resource is studied in ways that are
not physically possible, subject to the same proposed requirement that
the generating facility be equipped with sufficient control technology,
such as special protection systems, and/or subject to penalties for
deviating from dispatch. The Commission sought comment on whether other
operating assumptions, in addition to the assumption that electric
storage resources withdraw energy during peak load periods, should be
considered as part of this proposed reform.
---------------------------------------------------------------------------
\2739\ Id. P 286.
---------------------------------------------------------------------------
1455. The Commission sought comment on how to define the study
parameters (e.g., should the Commission define the peak load period
and/or net peak load during which transmission providers must not study
a generating facility as withdrawing energy, and if so how).\2740\
---------------------------------------------------------------------------
\2740\ Id. P 287.
---------------------------------------------------------------------------
1456. The Commission also sought comment on ``whether, and if so
how, to define firm and non-firm charging for electric storage
resources and require transmission providers to define study criteria
and possible ways to interconnect related to both firm and non-firm
charging.'' \2741\ The Commission sought comment on whether providing
such options would improve the effectiveness of this proposed reform
and whether there would be other consequences of implementing such an
approach. With respect to the definition of firm and non-firm charging,
the Commission sought comment on whether to: (1) define firm charging
service as interconnection service that allows the interconnection
customer to be eligible to receive electric energy in a manner
comparable to a transmission provider's load; and (2) define non-firm
charging service as interconnection service that allows the
interconnection customer to be eligible to receive electric energy
using the existing firm or non-firm capacity of the transmission system
on an ``as available'' basis, noting that in an RTO/ISO with market-
based congestion management, a generating facility with non-firm
charging service must respond to the RTO's/ISO's dispatch instructions,
including curtailment to manage congestion.\2742\
---------------------------------------------------------------------------
\2741\ Id. P 288.
\2742\ Id.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1457. Many commenters support the Commission's proposal to revise
the pro forma LGIP to require transmission providers, at the request of
the interconnection customer, to use operating assumptions for
interconnection studies that reflect the proposed operation of an
electric storage resource or co-located resource containing an electric
storage resource (including hybrid resources)--i.e., whether the
interconnecting generating facility will or will not charge during peak
load conditions, unless good utility practice, including applicable
reliability standards, otherwise require the use of different operating
assumptions.\2743\
---------------------------------------------------------------------------
\2743\ ACE-NY Initial Comments at 14-15; AEE Initial Comments at
41-42; AES Clean Energy Initial Comments at 24; Alliant Energy
Initial Comments at 8; Bonneville Initial Comments at 22-23; CESA
Initial Comments at 14-15; Clean Energy Associations Initial
Comments at 52; Clean Energy Associations Reply Comments at 10; CREA
and NewSun Initial Comments at 91-92; Cypress Creek Initial Comments
at 9; Environmental Defense Fund Initial Comments at 6;
Environmental Defense Fund Reply Comments at 8-9; ELCON Initial
Comments at 10; Elevate Initial Comments at 13; Interwest Reply
Comments at 15; Longroad Reply Comments at 10-12; Microgrid
Resources Initial Comments at 6; NARUC Initial Comments at 37;
NextEra Initial Comments at 36; NESCOE Reply Comments at 18; NRECA
Initial Comments at 10, 44; NY Commission and NYSERDA Initial
Comments at 10; Pine Gate Initial Comments at 51; Public Interest
Organizations Initial Comments at 47; R Street Initial Comments at
16; SEIA Initial Comments at 40; Shell Initial Comments, app. A at
iii; Union of Concerned Scientists Reply Comments at 9-10.
---------------------------------------------------------------------------
1458. Many commenters agree with the Commission that the lack of
realistic operating assumptions used in interconnection studies for
electric storage resources and co-located resources containing electric
storage resources (including hybrid resources) can result in excessive
and unnecessary network upgrades and hinder the timely development of
new generation, thereby stifling competition in the wholesale markets,
and resulting in rates, terms, and conditions that are unjust and
unreasonable.\2744\ These commenters also agree that using unrealistic
operating assumptions in interconnection studies creates an unduly
discriminatory or preferential barrier to the interconnection of
electric storage resources and co-located resources containing electric
storage resources (including hybrid resources).
---------------------------------------------------------------------------
\2744\ AEE Initial Comments at 42; Alliant Energy Initial
Comments at 8; Clean Energy Associations Initial Comments at 52-53;
Hydropower Commenters Initial Comments at 21-22; Longroad Reply
Comments at 10-12; NARUC Initial Comments at 36-37; NESCOE Reply
Comments at 18; Pine Gate Initial Comments at 51, 54; Public
Interest Organizations Initial Comments at 47; rPlus Initial
Comments at 6; SEIA Initial Comments at 40; SEIA Reply Comments at
27.
---------------------------------------------------------------------------
1459. Many commenters agree with the Commission that the
assumptions used in interconnection studies for the charging of
electric storage resources should closely resemble the expected ``real-
world'' operation of such resources.\2745\ For example, NextEra asserts
that operating assumptions should reflect the rational economic
dispatch of electric storage and co-located resources and that
interconnection customers with electric storage resources should be
allowed to request a lower maximum allowed charging rate in place of
being assigned network upgrade cost allocations.\2746\ Shell asserts
that parameters used to study storage should consider market
conditions.\2747\
---------------------------------------------------------------------------
\2745\ Alliant Energy Initial Comments at 8; APPA-LPPC Initial
Comments at 29; NextEra Initial Comments at 36-37; NY Commission and
NYSERDA Initial Comments at 10; Pine Gate Initial Comments at 51;
Shell Initial Comments, app. A at iii.
\2746\ NextEra Initial Comments at 37.
\2747\ Shell Initial Comments, app. A at iii.
---------------------------------------------------------------------------
1460. Many commenters argue that assuming in an interconnection
study that an electric storage resource will withdraw energy during
peak demand similar to firm end-use customer demand fails to recognize
the real-time attributes of electric storage resources, such as the
ability to respond within seconds to prices and dispatch signals from
the transmission provider.\2748\ For example, NARUC and NESCOE argue
that studying electric storage resources using worst-case operating
assumptions, such as withdrawing energy during peak demand, ignores the
real-time attributes and benefits of these technologies, such as their
ability to respond within seconds to prices and dispatch signals from
transmission providers and inject electricity during peak demand
conditions.\2749\ Further, Union of Concerned Scientists asserts that
modeling storage as charging during times of peak demand penalizes
interconnection customers for trying to locate electric storage
resources in places where they are most needed (e.g., load pockets)
because the study inappropriately models electric storage resources as
contributing to the problem
[[Page 61216]]
of transmission congestion rather than relieving it.\2750\ AEP argues
that some electric storage resources do occasionally charge during peak
demand; however, AEP has no objection to electric storage resources
being studied under a certain set of operating conditions as long as
operating restrictions are imposed through interconnection agreements
and the resource owner/operator recognizes that it must abide by
dispatch orders and bear the consequences of any limitations on its
operation that result in penalties.\2751\
---------------------------------------------------------------------------
\2748\ Clean Energy Alliance Initial Comments at 14-15; NARUC
Initial Comments at 37; PacifiCorp Initial Comments at 41; Pattern
Energy Initial Comments at 12; Pine Gate Initial Comments at 51;
SEIA Initial Comments at 40; Union of Concerned Scientists Reply
Comments at 10-11.
\2749\ NESCOE Reply Comments at 18 (citing NARUC Initial
Comments at 36-37).
\2750\ Union of Concerned Scientists Reply Comments at 10-11.
\2751\ AEP Initial Comments at 46-47.
---------------------------------------------------------------------------
(b) Comments in Opposition
1461. Some commenters argue that the proposed reform is overly
burdensome on transmission providers and could add time and complexity
to the interconnection process.\2752\ For example, NYISO opposes the
proposed reform, arguing that it would not streamline the
interconnection study process and instead would add significantly more
complexity to the process and increase the time required to complete
studies.\2753\
---------------------------------------------------------------------------
\2752\ Avangrid Initial Comments at 35; Enel Initial Comments at
74; ISO-NE Initial Comments at 40; NYISO Initial Comments at 51;
PacifiCorp Initial Comments at 41-42; PJM Initial Comments at 67;
Southern Initial Comments at 33.
\2753\ NYISO Initial Comments at 51.
---------------------------------------------------------------------------
1462. Some commenters oppose the proposed reform due to reliability
concerns.\2754\ PJM argues that the proposal would be extremely
difficult to police and enforce and would not guarantee that units will
operate within their studied parameters, putting PJM at operational
risk.\2755\ Southern opposes the proposed reform, stating that
transmission providers are ultimately responsible for planning for the
safety and reliable operation of their transmission systems, which
includes standard assumptions for interconnection studies.\2756\
Southern contends that it may be viable to provide an information-only
scenario using the assumptions provided by the interconnection
customer, but it would not be just and reasonable to allow
interconnection customers to dictate the study assumptions for their
electric storage, hybrid, or co-located resources. NYISO asserts that
its interconnection studies are designed to capture extreme system
scenarios to best maintain the reliability of the system and to be
prepared for rare extreme conditions and without such planning, the
interconnection studies could fail to identify essential non-local
network upgrades.\2757\ SDG&E argues that the reform may introduce
undue risk into the interconnection study process and could lead to the
transmission system being operated in an unstudied/unplanned
state.\2758\
---------------------------------------------------------------------------
\2754\ Id. at 67; SDG&E Initial Comments at 8; Southern Initial
Comments at 33.
\2755\ PJM Initial Comments at 67.
\2756\ Southern Initial Comments at 33.
\2757\ NYISO Initial Comments at 51.
\2758\ SDG&E Initial Comments at 7.
---------------------------------------------------------------------------
1463. However, several commenters disagree that the proposed reform
will introduce undue risk into the interconnection study process and
real-time operations.\2759\ CESA asserts that many transmission
providers continue to use historical planning standards that do not
consider the capability of advanced firmware and software controls to
dispatch resources in accordance with operating assumptions that can
provide much needed additional capacity to the transmission system,
which may result in continued delays and inefficiencies in the
interconnection process.\2760\
---------------------------------------------------------------------------
\2759\ AEE Initial Comments at 41-42; CESA Reply Comments at 10
(citing SDG&E Initial Comments at 7); Clean Energy Associations
Initial Comments at 58; R Street Initial Comments at 16.
\2760\ CESA Reply Comments at 10.
---------------------------------------------------------------------------
1464. NARUC suggests that, in RTO/ISO regions, independent market
monitors may be well-positioned to track deviations from proposed
operational limits in real-time operations.\2761\ For non-RTO/ISO
regions, NARUC contends that it may be appropriate for an independent
transmission monitor or NERC regional reliability entity to serve in
such a role.
---------------------------------------------------------------------------
\2761\ NARUC Initial Comments at 38.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
1465. Some commenters support the flexibility that the proposed
reform provides on the basis that it would allow for better use of the
transmission system or help facilitate the interconnection process
while still allowing for adequate controls.\2762\ NRECA cautions,
however, that such flexibility should not come at the expense of the
NOPR's overall goal of reducing speculative interconnection requests,
withdrawals, and restudies.\2763\ APS also believes that operating
assumptions used in interconnection studies should be limited to
factors that can be automatically controlled by the interconnection
customer; otherwise, system issues may occur when interconnection
facilities are operating outside of the assumptions used in the
studies.\2764\ Although AEP generally supports the proposed reform
because interconnection studies should be as accurate as possible, AEP
notes that using operating assumptions provided by the interconnection
customer may complicate studies and thus realistic study time frames
must be adopted.\2765\
---------------------------------------------------------------------------
\2762\ APS Initial Comments at 22; Cypress Creek Initial
Comments at 9; NRECA Initial Comments at 10, 44; rPlus Initial
Comments at 6.
\2763\ NRECA Initial Comments at 44.
\2764\ APS Initial Comments at 22.
\2765\ AEP Initial Comments at 45.
---------------------------------------------------------------------------
1466. Many commenters support the proposal to allow transmission
providers to require the use of controls to ensure compliance with
planned operation.\2766\ Clean Energy Associations argue that electric
storage resources are controllable with a level of precision and speed
unparalleled by conventional generating facilities, which provides
transmission owners and providers and interconnection customers with
new opportunities to accommodate transmission system reliability needs
and efficiently use scarce transmission interconnection capacity.\2767\
Clean Energy Associations assert that the proposed reform would
acknowledge the fact that electric storage resources are highly
controllable through hardware and software controls.\2768\ SEIA asserts
that power control systems, which electronically limit or control
steady state currents to a programmable limit, can ensure that electric
storage resources follow operating assumptions, and that their use is
growing.\2769\
---------------------------------------------------------------------------
\2766\ AEE Initial Comments at 41-42; APS Initial Comments at
22; Bonneville Initial Comments at 23; Clean Energy Associations
Initial Comments at 52-58; ELCON Initial Comments at 10; Eversource
Initial Comments at 36; NARUC Initial Comments at 38; PPL Initial
Comments at 23; Public Interest Organizations Initial Comments at
49-50; SEIA Initial Comments at 40.
\2767\ Clean Energy Associations Initial Comments at 52.
\2768\ Clean Energy Associations Reply Comments at 10.
\2769\ SEIA Reply Comments at 26-27 (citing IREC Initial
Comments, app. A at 43-48, 56, 159).
---------------------------------------------------------------------------
1467. Idaho Power states that it currently has a generator control
and monitoring technology that can be leveraged for monitoring and
controlling electric storage charging.\2770\ However, Idaho Power
asserts that it will need to implement a control scheme for operators
to view and control interconnection facilities in order to
intermittently interrupt discharge and charging due to system
conditions and related outages, which would likely require upfront and
ongoing costs for both Idaho Power and interconnection customers. Idaho
Power requests that the Commission consider including additional
language to ensure that the
[[Page 61217]]
transmission provider can disconnect, or take other action, including
seeking damages, in the event that the charging electric storage
resource does not follow its schedule.
---------------------------------------------------------------------------
\2770\ Idaho Power Initial Comments at 15-16.
---------------------------------------------------------------------------
1468. Eversource states that it is essential for system operators
and transmission planners to have sufficient visibility and controls in
place to ensure that the transmission system is not placed in unstudied
and potentially insecure N-1 contingency states.\2771\ Eversource
suggests that this issue, as well as other issues of grid dispatch,
should be the subject of its own proceeding. Alternatively, Eversource
requests that the Commission require that interconnection customers
with proposed operational study assumptions have technological controls
in place that automatically limit the electric storage facility's
operation to the proposed operational parameters. Eversource further
requests that the Commission reflect these requirements in the body of
the pro forma LGIA, and not only the appendices.
---------------------------------------------------------------------------
\2771\ Eversource Initial Comments at 35-36.
---------------------------------------------------------------------------
1469. NARUC and Public Interest Organizations support the proposed
requirement to consider resources to be in breach of their LGIA if they
fail to operate as intended.\2772\ NARUC asserts that such a
consequence, in combination with technology and software that can limit
the operations of an electric storage resource, should sufficiently
mitigate behavior that deviates from planned.\2773\ Public Interest
Organizations contend that installing control technologies would allow
the transmission provider and interconnection customer to engage in an
interactive dialogue to develop a set of operating assumptions that
both satisfy the interconnection customer's operational desires and
align with ``good utility practice.'' \2774\
---------------------------------------------------------------------------
\2772\ NARUC Initial Comments at 37; Public Interest
Organizations Initial Comments at 48-50.
\2773\ NARUC Initial Comments at 37-38.
\2774\ Public Interest Organizations Initial Comments at 48.
---------------------------------------------------------------------------
1470. rPlus generally supports the proposal but argues that the
proposed termination requirements for the interconnection customer
should the operational characteristics not be met are too stringent and
restrictive.\2775\ rPlus agrees that it is important to memorialize the
studied operational assumptions in the interconnection agreement but
asserts that it would benefit from the inclusion of additional language
should deviation from the originally defined operational assumptions be
beneficial.
---------------------------------------------------------------------------
\2775\ rPlus Initial Comments at 6.
---------------------------------------------------------------------------
Therefore, rPlus suggests that the Commission remove any explicit
or implied requirement for electric storage resources not to charge
during peak load periods and add language to retain the possibility of
altering the operational characteristics when these changes would
benefit the reliable and efficient operation of the transmission system
or benefit ratepayers.
1471. Invenergy supports the proposed reform to accommodate study
assumptions that more reasonably approximate anticipated actual
operations, but opposes requiring the studied operating conditions to
be memorialized in the interconnection agreement.\2776\ Invenergy
states that, if there are concerns that an unexpected event may require
a facility to occasionally operate outside those conditions, those
concerns should be addressed through the regional transmission planning
process, rather than forcing interconnection customers to fund upgrades
that are rarely if ever needed.\2777\
---------------------------------------------------------------------------
\2776\ Invenergy Initial Comments at 59-61.
\2777\ Id. at 61-62.
---------------------------------------------------------------------------
1472. Several commenters suggest modifications to the proposal to
better achieve the Commission's goal. For example, Pine Gate suggests
that the Commission require transmission providers to use a uniform set
of minimum interconnection study requirements (e.g., by eliminating the
use of extreme contingency scenarios and overly conservative
operational characteristics and strategies) to facilitate effective,
efficient interconnection queue processing, which is an essential
prerequisite of consumer protection.\2778\ With respect to the
provision of ancillary services, Pine Gate requests that the
interconnection customer not be required to definitively indicate the
specific ancillary services that it would or would not provide in the
initial interconnection request because it is not possible for the
interconnection customer to know with certainty which ancillary
services it may be eligible to provide when it is ultimately placed in
service.\2779\ For this reason, Pine Gate requests that the Commission
require the interconnection customer to list in the original
interconnection request only whether it intends to provide ancillary
services generally.\2780\
---------------------------------------------------------------------------
\2778\ Pine Gate Initial Comments at 55.
\2779\ Id. at 52.
\2780\ Id. at 53.
---------------------------------------------------------------------------
1473. Union of Concerned Scientists urges the Commission to direct
in the final rule that technical capabilities offered by an
interconnection customer be appropriately recognized and used in the
modeling of transmission impacts and their mitigation, including the
ability to respond to contingencies and provide dynamic real or
reactive power, which if omitted could lead to millions of dollars of
costs to customers to provide such capability by other means.\2781\
---------------------------------------------------------------------------
\2781\ Union of Concerned Scientists Reply Comments at 13-14.
---------------------------------------------------------------------------
1474. Interwest supports allowing interconnection customers to
request that transmission providers apply certain study assumptions to
better approximate realistic operations and requiring transmission
providers to apply congestion management practices to unusual events,
developed through regional transmission planning processes, rather than
building in assumptions assuming worst-case operations scenarios.\2782\
---------------------------------------------------------------------------
\2782\ Interwest Reply Comments at 15.
---------------------------------------------------------------------------
1475. Public Interest Organizations recommend that, if a
transmission provider finds an interconnection customer's proposed
operating assumptions to be in conflict with ``good utility practice,''
the transmission provider should be required to provide the
interconnection customer with a clear explanation of why the submitted
operating assumptions are insufficient or inappropriate, and allow the
interconnection customer to revise and resubmit the proposed operating
assumptions as necessary, within a reasonable time period.\2783\
---------------------------------------------------------------------------
\2783\ Public Interest Organizations Initial Comments at 47-48,
49.
---------------------------------------------------------------------------
1476. Clean Energy Associations urge the Commission to define study
parameters such as ``peak load'' and ``net peak load.'' \2784\ Clean
Energy Associations request that the Commission define ``net peak
load'' as the period during which transmission providers must not study
a facility as withdrawing energy. Clean Energy Associations note that
in regions with high solar penetration, the net peak load hour diverges
from the peak load hour and migrates to later in the day and, under
these conditions, low prices during the peak load hour may create
incentives for storage to charge, whereas prices would be high during
the net peak load hour creating incentives to discharge. Therefore,
Clean Energy Associations contend that using the net peak load as the
period of study will ensure that studies continue to accurately reflect
expected economic price response of storage as system conditions
evolve.
---------------------------------------------------------------------------
\2784\ Clean Energy Associations Initial Comments at 53-54.
---------------------------------------------------------------------------
[[Page 61218]]
1477. NextEra and Clean Energy Associations urge the Commission to
require transmission providers to use additional study assumptions
beyond just whether electric storage and co-located resources
(including hybrid resources) should charge during peak load periods.
Both NextEra and Clean Energy Associations argue that transmission
providers should not study electric storage resources as injecting
energy during low load and shoulder periods because that does not
reasonably reflect the rational economic behavior and typical
operations of such resources.\2785\
---------------------------------------------------------------------------
\2785\ NextEra Initial Comments at 37; Clean Energy Associations
Initial Comments at 53.
---------------------------------------------------------------------------
1478. In contrast, MISO argues against requiring additional study
assumptions for electric storage resources.\2786\ MISO notes that there
may be times in the future when renewable resources are constrained or
unavailable due to the lack of fuel (e.g., no wind or sun) such that
the MISO transmission system will need to call upon electric storage
resources for injection: but, if these resources are not permitted to
discharge due to their operational assumptions, then the transmission
system's reliance on those resources could lead to reliability risks.
---------------------------------------------------------------------------
\2786\ MISO Initial Comments at 116.
---------------------------------------------------------------------------
1479. Several other commenters urge the Commission not to define
study parameters, such as ``peak load'' or ``net peak load,'' and
instead allow for regional flexibility.\2787\ For example, rather than
define peak load, Microgrid Resources states that the Commission should
require individual evaluation of the expected operating assumptions for
the resource(s) being studied.\2788\ Enel asserts that it does not
believe clear and transparent criteria regarding the peak load period
could be developed such that the limitations on a generating facility
could appropriately be modeled with only a few power flow model
``snapshots in time'' serving as the basis for the restriction.\2789\
---------------------------------------------------------------------------
\2787\ Ameren Initial Comments at 29; Enel Initial Comments at
74; Idaho Power Initial Comments at 16; Microgrid Resources Initial
Comments at 8; Shell Initial Comments, app. A at iii.
\2788\ Microgrid Resources Initial Comments at 8.
\2789\ Enel Initial Comments at 74.
---------------------------------------------------------------------------
1480. Several commenters support eliminating unrealistic
interconnection study assumptions for resource types other than
electric storage resources, such as assuming that a solar facility will
operate a night, or that a wind resource will produce maximum output
during low-wind seasons.\2790\ Ameren, Cypress Creek, Microgrid
Resources, NARUC, Pine Gate, and rPlus all request that the Commission
extend this reform to allow any resource type, not just electric
storage or co-located resources, to request that interconnection
studies be based on their particular operating assumptions and
characteristics.\2791\ NARUC further asserts that it is reasonable to
allow interconnection customers to request that transmission providers
not study interconnecting generating facilities in ways that are not
physically possible, subject to the same proposed requirement that the
generating facility be equipped with sufficient control technologies
and penalties for deviations.\2792\ Microgrid Resources urges the
Commission to define microgrid in the tariff, noting particularly the
inclusion of load, and to make clear that interconnection studies must
be based on operating assumptions for the microgrid as a whole.\2793\
---------------------------------------------------------------------------
\2790\ Id.; AES Clean Energy Initial Comments at 24-25; Ameren
Initial Comments at 29; CREA and NewSun Initial Comments at 92;
Cypress Creek Initial Comments at 9-10; Invenergy Initial Comments
at 59-61; Microgrid Resources Initial Comments at 7-8; Pine Gate
Initial Comments at 54; Public Interest Organizations Initial
Comments at 48-49; R Street Initial Comments at 16; rPlus Initial
Comments at 6.
\2791\ Ameren Initial Comments at 29; Cypress Creek Initial
Comments at 9-10; Microgrid Resources Initial Comments at 7; NARUC
Initial Comments at 38; Pine Gate Initial Comments at 54; rPlus
Initial Comments at 6.
\2792\ NARUC Initial Comments at 38.
\2793\ Microgrid Resources Initial Comments at 7.
---------------------------------------------------------------------------
1481. Pattern Energy asserts that transmission providers should be
required to update their operating assumptions annually, after
stakeholder input.\2794\ Pattern Energy asserts that some transmission
providers require light-load reliability analysis for wind resources
but not for natural gas plants, which is unduly discriminatory.\2795\
---------------------------------------------------------------------------
\2794\ Pattern Energy Initial Comments at 13.
\2795\ Id. (referencing PJM Manual 14B at 47, section 2.3.1.1).
---------------------------------------------------------------------------
1482. Some commenters support expanding the proposed reforms to the
entire facility of hybrid or co-located resources. For instance, ENGIE
recommends that interconnection customers submitting hybrid or co-
located resources should be able to specify operating parameters across
the entire generating facility, including variable energy resources,
within their interconnection request to allow interconnection customers
to reflect parameters such as solar-based charging of the electric
storage resource more accurately.\2796\ Pine Gate states that co-
located resources are typically studied independently, which requires
studying the combined maximum injection of the two generating
facilities that are co-located, despite the fact that studying in this
manner overestimates the impact on the transmission system and could
trigger unnecessary network upgrades.\2797\ Pine Gate asserts that,
consistent with the NOPR's proposals regarding operating assumptions
for electric storage resources and co-located resources, the Commission
should permit an interconnection customer to specify the proposed
operation of all components of a co-located resource in its
interconnection request.
---------------------------------------------------------------------------
\2796\ ENGIE Initial Comments at 11.
\2797\ Pine Gate Initial Comments at 45.
---------------------------------------------------------------------------
SEIA contends that studying two, co-located resources as a single
resource would be more accurate, as this would reflect the actual
electrical impact to the transmission system.\2798\
---------------------------------------------------------------------------
\2798\ SEIA Initial Comments at 38.
---------------------------------------------------------------------------
1483. Although not entirely opposed to the proposed reform,
PacifiCorp asserts that this proposed reform should not be extended to
co-located and hybrid resources because monitoring and enforcing
operational limitations could be complex, and incorporating operational
limitations could complicate the cluster study process.\2799\
Nevertheless, PacifiCorp encourages the Commission to permit
transmission providers to opt-in to extending this type of reform to
hybrid resources if appropriate for their systems.
---------------------------------------------------------------------------
\2799\ PacifiCorp Initial Comments at 41-42.
---------------------------------------------------------------------------
1484. Several other commenters urge the Commission to go further
and require transmission providers to use more realistic operating
assumptions without requiring the interconnection customer to request
that transmission provider do so.\2800\ Public Interest Organizations
argue that extending the reforms to all generation technologies would
help prevent unduly discriminatory treatment.\2801\ Therefore, Public
Interest Organizations recommend that the Commission require
transmission providers to work with interconnection customers to ensure
operating assumptions reflect physical, operational, and market
realities, ``good utility practice,'' and applicable reliability
standards. AES Clean Energy argues that the Commission should require
transmission providers to establish a process to revisit and update
operating assumptions of different resource types in consultation with
stakeholders to ensure that these operating assumptions are realistic
and approximately reflect
[[Page 61219]]
the expected actual operation of these resources.\2802\
---------------------------------------------------------------------------
\2800\ AES Clean Energy Initial Comments at 24-25; CREA and
NewSun Initial Comments at 92; R Street Initial Comments at 16.
\2801\ Public Interest Organizations Initial Comments at 49.
\2802\ AES Clean Energy Initial Comments at 24-25.
---------------------------------------------------------------------------
1485. Shell supports the use of accurate modeling assumptions,
including for variable energy resources, but argues that electric
storage and renewable resources should not be treated in the same way
because electric storage is dispatchable and renewable resources
generally are not dispatchable.\2803\ Further, Shell asserts that the
Commission should not assume all wind and solar resources are the same
(and not dispatchable).
---------------------------------------------------------------------------
\2803\ Shell Initial Comments, app. A at iii.
---------------------------------------------------------------------------
1486. AECI and NextEra oppose extending the proposed reform to
other resources types.\2804\ NextEra opposes extending customized
operating assumptions to wind and solar energy resources because doing
so could unduly complicate subsequent operational decisions for the
system operator and possibly restrict the system operator's ability to
call on resources when needed.\2805\ AECI proposes to continue studying
wind and solar resources as NRIS facilities that are dispatched at 100%
to avoid potential reliability issues at the worst times.\2806\ MISO
explains that it currently requires interconnection customers to be
responsible for limiting and controlling their own dispatch in some
conditions, but that it has no ability to monitor in real time if an
interconnection customer violates its operating limits.\2807\ MISO
states that it is unaware of any plant side control device or
operational tool that MISO could use to prevent a generating facility's
injection to enforce an electric storage resource's operating
assumptions regarding discharging. Idaho Power states that it is
unclear how a cluster study with multiple interconnection requests
could be performed when accounting for numerous and potentially
conflicting study parameters, such as ``low wind season'' for one
interconnection customer but not for another.\2808\ Idaho Power seeks
clarification of the definition of study parameters such as ``low wind
season.''
---------------------------------------------------------------------------
\2804\ AECI Initial Comments at 8; NextEra Initial Comments at
37.
\2805\ NextEra Initial Comments at 37.
\2806\ AECI Initial Comments at 8.
\2807\ MISO Initial Comments at 116.
\2808\ Idaho Power Initial Comments at 16.
---------------------------------------------------------------------------
1487. Some commenters support the Commission defining the terms
firm and non-firm charging service for electric storage resources and
requiring transmission providers to define study criteria to
interconnect related to both firm and non-firm charging.\2809\ For
example, Clean Energy Associations support enabling interconnection
customers with electric storage resources and hybrid resources to
request non-firm transmission service for their charging energy,
provided that transmission providers update study criteria and
interconnection processes for such service accordingly and provide
definitions of firm and non-firm charging service for electric storage
resources.\2810\ CESA argues that electric storage resources should not
be forced to use one type of charging service over another since some
resources may find it sufficient to take advantage of charging capacity
as it is available whereas others may want or need greater assurances
of charging capacity and are willing to pay for the requisite network
upgrades.\2811\ CESA urges the Commission to set requirements as to how
partial or full firm charging services should be offered on a flexible,
as-requested basis, such that an interconnection customer can seek firm
charging service for specific time windows or for a portion of the
electric storage resource's nameplate or interconnection capacity. CESA
asserts that, as discussed in the NOPR, accommodating firm and as-
available charging service options should reflect the operating
capabilities of the storage resource (i.e., price responsive,
dispatchable), achieve efficient market outcomes, and avoid expensive
and unnecessary upgrades.\2812\
---------------------------------------------------------------------------
\2809\ CESA Initial Comments at 12-13; Clean Energy Associations
Initial Comments at 54-56; ENGIE Initial Comments at 12.
\2810\ Clean Energy Associations Initial Comments at 54.
\2811\ CESA Initial Comments at 12-13.
\2812\ Id. at 12.
---------------------------------------------------------------------------
1488. Clean Energy Associations assert that the Commission should
direct transmission providers to use the following criteria for
studying interconnection requests that opt for non-firm charging
service: (1) the electric storage resource should have the option to
receive electric energy using the existing firm or non-firm capacity of
the transmission system on an ``as available'' basis; (2) any study of
an electric storage resource charging should allow the interconnection
customer to elect to use a lower charging level or a control technology
to mitigate any identified constraints in lieu of being assigned
network upgrades to address such constraints; and (3) the electric
storage resource should receive information relative to any network
upgrades, charging restrictions, or control requirements in advance of
signing an interconnection agreement.\2813\ Clean Energy Associations
urge the Commission to direct transmission owners to indicate
conditions under which charging energy could be curtailed in
interconnection agreements that include non-firm service for charging
energy. Clean Energy Associations also caution that the Commission
should avoid recategorizing charging energy of electric storage
resources as a wholesale load, which would be contrary to the
Commission's findings in Order No. 841.
---------------------------------------------------------------------------
\2813\ Clean Energy Associations Initial Comments at 55-56.
---------------------------------------------------------------------------
1489. AEP suggests that clarifications would be needed for the
proposed definitions of firm and non-firm charging to be effective. For
example, AEP asserts that the proposed definitions for firm and non-
firm charging service conflate different products and services required
to charge an electric storage resource.\2814\ AEP argues that charging
service is not a form of interconnection service, nor is
interconnection service referred to in the industry as firm or non-
firm. According to AEP, it is the delivery service (i.e., transmission
and wholesale distribution service) that can be firm or non-firm and
therefore the relevant question is whether, in the interconnection
process, an electric storage resource can or needs to request to be
studied as a ``firm'' or ``non-firm'' load for delivery purposes. AEP
asserts that the Commission should recognize that, for electric storage
resources, the interconnection cluster study process should include an
analysis of transmission service. AEP notes that the Commission has
permitted the California utilities to study the need for wholesale
distribution upgrades required for charging on a firm basis as part of
the interconnection study process. AEP argues that, if it is
technically possible to distinguish loads, a load that affects human
safety, health, and welfare directly should have priority over the
charging of an electric storage resource, unless for example, if the
electric storage resource will be used for blackstart after an outage,
adding that the final rule does not need to interfere with emergency
load shedding protocols.
---------------------------------------------------------------------------
\2814\ AEP Initial Comments at 48-50.
---------------------------------------------------------------------------
1490. Shell asserts that the need for firm or non-firm transmission
service will vary by generating facility, as well as by the usage
pattern of the electric storage resource (e.g., whether the electric
storage resource is standalone or part of a hybrid resource that is AC-
coupled, DC-coupled, or DC-tight-
[[Page 61220]]
coupled).\2815\ Shell states that, if an electric storage resource is
charging from the transmission system as non-firm load, and the
resource owner is required to comply with the transmission provider's
real-time dispatch orders to cease charging from the transmission
system due to reliability concerns, then there is no need for long-term
firm transmission service reservations to serve the electric storage
resource. Shell contends that non-firm electric storage load should not
be required to acquire transmission service prior to charging from the
transmission system, as such charging will be captured by the revenue
meter and can be billed at the transmission provider's non-firm point-
to-point transmission rate at the end of the billing period.
---------------------------------------------------------------------------
\2815\ Shell Initial Comments, app. A at iii.
---------------------------------------------------------------------------
1491. Xcel suggests that the evaluation of non-firm charging must
assume a price and then the electric storage resource should be bound
to that price.\2816\ Xcel contends that, if an electric storage
resource is studied as non-firm load but ends up offering to buy energy
in the market above average market prices, the study will not represent
the resulting dispatch. Therefore, Xcel recommends that electric
storage resources and other non-firm load should be required to have a
maximum bid price that is included in Attachment C of the pro forma
LGIA.
---------------------------------------------------------------------------
\2816\ Xcel Initial Comments at 46.
---------------------------------------------------------------------------
1492. Some commenters oppose the Commission defining firm and non-
firm charging or requiring transmission providers to define study
criteria as part of this rulemaking.\2817\ For example, PPL asserts
that the Commission should leave defining such study parameters to the
transmission providers.\2818\
---------------------------------------------------------------------------
\2817\ Ameren Initial Comments at 29; Idaho Power Initial
Comments at 16; PPL Initial Comments at 23.
\2818\ PPL Initial Comments at 23.
---------------------------------------------------------------------------
1493. Several commenters suggest clarifications to the proposed
reform regarding the timing of submitting operating assumptions.\2819\
Clean Energy Associations and ENGIE recommend that the Commission
define a clear decision point in the interconnection study process
before which interconnection customers may adjust operating assumptions
and after which inputs remain constant.\2820\ APS suggests that the
Commission modify the proposal to specify that any changes to the
operating assumptions initially provided by the interconnection
customer would be considered a material modification.\2821\
---------------------------------------------------------------------------
\2819\ AES Clean Energy Initial Comments at 24; APS Initial
Comments at 22; Clean Energy Associations Initial Comments at 56-57;
ENGIE Initial Comments at 11.
\2820\ Clean Energy Associations Initial Comments at 56-57;
ENGIE Initial Comments at 11.
\2821\ APS Initial Comments at 22.
---------------------------------------------------------------------------
(d) Alternative Proposals and Requests for Further Process
1494. Enel argues that using power flow studies and assuming
extreme transmission system conditions matches the concept of a firmer
product well (e.g., for NRIS or transmission service studies), but
applied to ERIS studies it implies that an ERIS resource cannot or will
not curtail, absorb congestion costs, or be redispatched to mitigate
transmission system disturbances, which goes beyond ``as available''
service and does not allow for lower-cost mitigation options.\2822\ For
these reasons, Enel recommends that the Commission direct transmission
providers to replace power flow studies with Security Constrained
Economic Dispatch analysis for ERIS service studies instead of the
Commission's proposed reform,\2823\ or in the alternative, require
appropriately supported fuel-based dispatch assumptions in ERIS and,
where appropriate, NRIS study models.\2824\
---------------------------------------------------------------------------
\2822\ Enel Initial Comments at 75.
\2823\ Id. at 73, 75.
\2824\ Id. at 77-78.
---------------------------------------------------------------------------
1495. Several other commenters support requiring transmission
providers to apply realistic fuel-based dispatch assumptions to all
resource types.\2825\ Additionally, Invenergy notes that both MISO and
SPP already use realistic fuel-based dispatch assumptions in their
interconnection study processes.\2826\ Although MISO believes that a
fuel-based dispatch methodology would address the concerns stated in
the NOPR about unrealistic operating assumptions, MISO also believes
that study methods should be flexible to the unique needs of a region's
stakeholders and that the Commission should allow flexibility regarding
how a transmission provider conducts its studies.\2827\ MISO asserts
that fuel-based dispatch enables more efficient generator
interconnection because it recognizes that not all generating
facilities will be dispatched up to their requested interconnection
service at all times of the year and that some fuels will not be
dispatched when other fuels are being dispatched.\2828\ MISO explains
that its current fuel dispatch method also addresses withdrawal for
electric storage resources and was informed by operational data.\2829\
---------------------------------------------------------------------------
\2825\ Enel Initial Comments at 77-78; Interwest Reply Comment
at 15; Invenergy Initial Comments at 60-61.
\2826\ Invenergy Initial Comments at 60-61.
\2827\ MISO Initial Comments at 119.
\2828\ Id. at 117, 119.
\2829\ Id. at 117-118 (citing MISO, Business Practice Manual-15,
tbl. 6-1).
---------------------------------------------------------------------------
1496. Public Interest Organizations encourage the Commission to
consider a requirement that would ensure operational and market
realities are appropriately reflected in operating assumptions for the
purposes of interconnection studies.\2830\ Public Interest
Organizations state that this could include both operational practices
and procedures as well as market-based price signals for curtailment
and congestion management. Furthermore, Public Interest Organizations
contend that fossil generating facilities should not be expected to
generate at or near peak output during times when market prices are
depressed, such as during periods of high renewable generation.\2831\
---------------------------------------------------------------------------
\2830\ Public Interest Organizations Initial Comments at 48.
\2831\ Id. at 48-49 (citing Joe Daniel & Sam Gomberg, Union of
Concerned Scientists, Why Does Wind Energy Get Wasted? (Nov. 16,
2021), https://www.ucsusa.org/resources/wind-oversupply-myths).
---------------------------------------------------------------------------
1497. IREC asserts that interconnection application forms for small
generating facilities should be updated to include information about
electric storage resources and, where export controls are used, the
type of export control and the equipment type and settings that will be
used.\2832\ IREC asserts that, in order for the interconnection process
to fully recognize the ways electric storage resources can be designed
and controlled to avoid transmission system constraints, utilities
should consider operating profiles (which can include operating
schedules) in their feasibility studies and system impact
studies.\2833\
---------------------------------------------------------------------------
\2832\ IREC Initial Comments at 15, attach. A.
\2833\ Id. at 16, attach. A.
---------------------------------------------------------------------------
1498. Several commenters urge the Commission to hold a technical
conference and/or open a new proceeding to sort out the complex details
of this proposed reform.\2834\ For example, Clean Energy Associations
note that the Commission could build a further evidentiary record
regarding parameters for evaluating electric storage and other
resources via a technical conference, with the aim of developing
reasonable and consistent assumptions across regions.\2835\ SEIA urges
the Commission to convene a technical conference in this proceeding
[[Page 61221]]
to increase transmission provider certainty and confidence in the
capabilities and testing of power control systems.\2836\ ISO-NE
suggests that its concerns with the proposed reform may be better
addressed through the establishment of a new category of
interconnection service for the charging mode of electric storage
devices as part of a separate proceeding.\2837\
---------------------------------------------------------------------------
\2834\ Clean Energy Associations Initial Comments at 53;
Eversource Initial Comments at 35; ISO-NE Initial Comments at 40;
Puget Sound Initial Comments at 13.
\2835\ Clean Energy Associations Initial Comments at 53.
\2836\ SEIA Initial Comments at 27.
\2837\ ISO-NE Initial Comments at 40.
---------------------------------------------------------------------------
(e) Comments Regarding Transmission Service Request Studies
1499. Clean Energy Associations note that some RTOs/ISOs determine
the network upgrades needed to accommodate the charging of electric
storage resources as part of the interconnection process, whereas other
transmission providers do so in the transmission service request
process.\2838\ Similarly, Xcel states that charging from the
transmission system can be evaluated and approved through the
designation of a new delivery point as part of a transmission service
request.\2839\ Xcel further notes that it is unaware of a transmission
service study process defined in the pro forma tariff that specifically
evaluates non-firm load. Puget Sound states that it currently studies
charging outside of the interconnection process and recognizes that
charging could be considered a retail or a transmission product once
the load piece is interconnected.\2840\ However, Puget Sound asserts
that charging should be studied in the interconnection process, and the
transmission provider should be granted more time to study this
additional element. Puget Sound seeks clarity as to whether the
proposed reform means that charging should now be considered part of
the interconnection process, or if it can be part of the process should
the transmission provider wish to include it. Further, Puget Sound
argues that the Commission should standardize the pro forma LGIA to
include specific operating assumptions to avoid interconnection request
delays due to needing to file a non-conforming LGIA with the Commission
and/or interconnection customer hesitancy.
---------------------------------------------------------------------------
\2838\ Clean Energy Associations Initial Comments at 54-55
(referencing, e.g., ISO-NE Planning Procedure No. 5-6, at 18 (2022);
MISO, Business Practice Manual 15-r24, at 53.
\2839\ Xcel Initial Comments at 46-47.
\2840\ Puget Sound Initial Comments at 11-12.
---------------------------------------------------------------------------
1500. In contrast, Tri-State argues that it is inappropriate to
study charging of electric storage resources within a generator
interconnection study, and instead asserts that this type of analysis
is best performed as a part of a transmission service study, which
covers delivery of energy to load or charging of an electric storage
resource.\2841\ Similarly, SPP argues that evaluating the impact of an
electric storage resource's charging on the transmission system is
better suited to other existing processes designed to assess load
impact, such as the long-term transmission service study process, the
short-term transmission service evaluation process, or market
processes.\2842\
---------------------------------------------------------------------------
\2841\ Tri-State Initial Comments at 22.
\2842\ SPP Initial Comments at 25.
---------------------------------------------------------------------------
(f) Requests for Clarification and Flexibility
1501. Pine Gate requests that the Commission provide additional
guidance regarding how transmission owners should perform studies and
what network upgrade costs will be allocated to interconnection
customers as a result.\2843\ Pine Gate states that transmission
providers may need to study electric storage or co-located resources
based on worst-case operating assumptions to understand the potential
impact these resources would have on the transmission system absent
operating restrictions being implemented. However, Pine Gate requests
that the Commission clarify that network upgrade costs will not be
assigned to the interconnection customer based on the unrealistic
worst-case scenarios where there is agreement to implement operating
restrictions.
---------------------------------------------------------------------------
\2843\ Pine Gate Initial Comments at 52.
---------------------------------------------------------------------------
1502. Elevate requests that the Commission clarify that the
proposed reform applies to all study processes related to the
interconnection of electric storage resources, including generator
replacement, surplus interconnection, and requests to modify an
existing generation resource, arguing that there is no reason for the
Commission to require that transmission providers use realistic study
parameters only in the context of requests for new interconnection
service while allowing unrealistic study assumptions in other study
processes.\2844\
---------------------------------------------------------------------------
\2844\ Elevate Initial Comments at 13-14.
---------------------------------------------------------------------------
1503. CAISO is concerned that, if not modified, the proposed reform
would require transmission providers to provide firm charging options,
whereas CAISO asserts that it does not currently provide firm charging
service and stakeholders have never requested such service.\2845\ CAISO
argues that requiring firm charging service would have a profound
impact on organized electricity markets and asserts that if the
Commission proposes to allow electric storage resources to bypass
economic dispatch and charge whenever they desire--even during stressed
peak conditions--it should do so expressly and not in the context of a
rulemaking addressing interconnection. CAISO asserts that the
Commission should consider a simple clarification and avoid requiring
transmission providers to offer firm charging, but instead require
transmission providers that offer firm charging to allow
interconnection customers to request it at the outset of their
interconnection request.
---------------------------------------------------------------------------
\2845\ CAISO Initial Comments at 34-35.
---------------------------------------------------------------------------
1504. Environmental Defense Fund urges the Commission to clarify
that an apparent failure to operate in accordance with agreed-upon
conditions should be treated as a normal alleged default or breach as
governed by article 17 of the pro forma LGIA, which would not result in
immediate termination.\2846\ Environmental Defense Fund asserts that
the requirements of article 17.1 of the pro forma LGIA state that a
breaching party be given an opportunity to cure the breach and that
termination is only available if the breaching party fails to cure or
the breach is not capable of being cured. Similarly, Hydropower
Commenters generally support the proposal, but believe that the
proposed requirement that if an interconnection customer fails to
operate its electric storage resource in accordance with the operating
assumptions memorialized in the interconnection agreement, the
interconnection customer may be considered in breach and the
transmission provider may pursue termination of the interconnection
agreement, is overly restrictive, will discourage the development of
pumped storage projects, and should be modified.\2847\ Instead,
Hydropower Commenters urge the Commission to provide for a standard
cure period to address deviations, and penalties in the event of
failure to cure.
---------------------------------------------------------------------------
\2846\ Environmental Defense Fund Initial Comments at 6-7.
\2847\ Hydropower Commenters Initial Comments at 23-24.
---------------------------------------------------------------------------
1505. MISO states that the proposed reform is unclear because the
text of the NOPR states that the Commission intends operating
instructions to only apply to an electric storage resource's ability to
describe how it will withdraw energy from the transmission system
(i.e., charge a battery), whereas the proposed pro forma LGIP revisions
state that the operating assumptions can also apply to the manner the
interconnection request states that the electric storage
[[Page 61222]]
resource will discharge.\2848\ MISO asks that the Commission clarify
that the text of the NOPR is correct, and that the Commission did not
intend to propose to allow electric storage resources to define the
operating assumptions for how they will inject into the transmission
system because, according to MISO, allowing interconnection requests to
define operating assumptions regarding discharge would result in
operational problems and would be discriminatory to other generating
facilities.
---------------------------------------------------------------------------
\2848\ MISO Initial Comments at 115.
---------------------------------------------------------------------------
1506. Hydropower Commenters suggest that the proposed reform be
modified to include a simplified procedure for amending an
interconnection customer's interconnection agreement to optimize the
operating parameters of a pumped storage plant to the extent the
transmission system is available.\2849\
---------------------------------------------------------------------------
\2849\ Hydropower Commenters Initial Comments at 24.
---------------------------------------------------------------------------
1507. Some commenters note that several transmission providers
already study electric storage resources using more realistic operating
assumptions and assert that transmission providers should have the
flexibility to determine the assumptions used when studying generating
facilities interconnecting to the transmission system, including
operating assumptions for electric storage resources, while also
factoring in input from the interconnection customer.\2850\ NESCOE
argues that the final rule should require transmission providers to
work with the relevant states, transmission owners, electric storage
resource interconnection customers, and stakeholders in their region to
develop modeling assumptions for electric storage resources that are
reasonable, realistic, and ensure the ability to interconnect is
offered on a non-discriminatory basis.\2851\
---------------------------------------------------------------------------
\2850\ APPA-LPPC Initial Comments at 29-30; Bonneville Initial
Comments at 23; MISO Initial Comments at 117; National Grid Initial
Comments at 41; NESCOE Reply Comments at 19.
\2851\ NESCOE Reply Comments at 18.
---------------------------------------------------------------------------
1508. National Grid recommends that the Commission provide regional
flexibility to adopt or decline this proposed reform after transmission
providers receive input from their stakeholders to determine if ad hoc
proposed operating assumptions for interconnection requests are
reasonable and appropriate or if certain pre-determined acceptable
ranges of assumptions are consistent with reliability.\2852\ APPA-LPPC
argues that the proposal could entail creating entirely new models for
off-peak scenarios, not just running sensitivity analyses from an
existing model, and therefore urges the Commission to give transmission
providers the autonomy to determine whether additional transmission
studies are needed.\2853\
---------------------------------------------------------------------------
\2852\ National Grid Initial Comments at 41.
\2853\ APPA-LPPC Initial Comments at 29-30.
---------------------------------------------------------------------------
iii. Commission Determination
1509. We adopt the NOPR proposal, subject to modification, to
revise sections 3.1.2, 3.2.1.2, 3.2.2.2, 3.3.1, 3.4.2, 4.4.3, 7.3, 8.2,
and Appendix 1 of the pro forma LGIP and article 17.2 and Appendix H of
the pro forma LGIA to require 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 \2854\ (whether standalone, co-located
generating facilities,\2855\ or part of a hybrid generating facility
\2856\)--i.e., whether the interconnecting generating facility will or
will not charge during peak load conditions--unless good utility
practice, including applicable reliability standards,\2857\ otherwise
requires the use of different operating assumptions.\2858\ We clarify
that studying electric storage resources, at the request of the
interconnection customer, according to their planned operating
assumptions means only the operating assumptions for withdrawals of
energy (e.g., the charging of an electric storage resource) in
interconnection studies.
---------------------------------------------------------------------------
\2854\ An electric storage resource is a generating facility
capable of receiving electric energy from the grid and storing it
for later injection of electricity.
\2855\ As noted above, co-located generating facilities are more
than one generating facility that are located on the same site and
that are connected at the same point of interconnection that are
operated and dispatched as separate generating facilities. See supra
section III.C.1.a.iii.
\2856\ As noted above, a hybrid generating facility is a
generating facility composed of more than one device of different
technology types for the production and/or storage for later
injection of electricity that are located on the same site and are
operated and dispatched as a single integrated generating facility.
See supra section III.A.6.b.iii.
\2857\ Applicable reliability standards means ``the requirements
and guidelines of the Electric Reliability Organization and the
Balancing Authority Area of the Transmission System to which the
Generating Facility is directly interconnected.'' See pro forma LGIP
section 1 (Definitions).
\2858\ For clarity, we note that the reforms described in this
determination section and the related sections of the pro forma LGIP
apply to all interconnecting electric storage resources, whether
they are standalone, co-located generating facilities, or part of a
hybrid generating facility.
---------------------------------------------------------------------------
1510. We find that by more accurately reflecting the technical
capabilities of electric storage resources in interconnection studies
through the use of appropriate operating assumptions, this reform
ensures the reliable interconnection of new electric storage resources
without overestimating their impact on the transmission system, thereby
ensuring just and reasonable rates by avoiding excessive and
unnecessary network upgrades that may hinder the timely development of
new generating facilities that stifles competition in the wholesale
market. We also find that reflecting the technical capabilities of
electric storage resources through the use of appropriate operating
assumptions in interconnection studies reduces unduly discriminatory or
preferential barriers to the interconnection of electric storage
resources.
1511. We adopt the proposed revisions, subject to modification, to
section 3.1.2 of the pro forma LGIP to require transmission providers,
at the request of the interconnection customer, to use operating
assumptions that reflect the proposed charging behavior of an electric
storage resource, allow interconnection customers to resubmit their
operating assumptions if the transmission provider finds the originally
proposed operating assumptions are in conflict with good utility
practice, and allow the transmission provider to require the
interconnection customer to install additional control technologies. We
agree with Public Interest Organizations that transparency is necessary
when a transmission provider finds that an interconnection customer's
operating assumptions conflict with good utility practice.\2859\
Therefore, we modify the proposed revisions to section 3.1.2 of the pro
forma LGIP to require that, if a transmission provider finds an
interconnection customer's proposed operating assumptions to be in
conflict with good utility practice, the transmission provider must
provide the interconnection customer with a clear explanation in
writing of why the submitted operating assumptions are insufficient or
inappropriate by no later than 30 calendar days before the end of the
customer engagement window and allow the interconnection customer to
revise and resubmit the proposed operating assumptions one time at
least 10 calendar days before the end of the customer engagement
window.
---------------------------------------------------------------------------
\2859\ Public Interest Organizations Initial Comments at 47-49.
---------------------------------------------------------------------------
1512. We adopt the proposed revisions to section 3.2.1.2 of the pro
forma LGIP to require transmission providers to study electric storage
resources that request ERIS service according to the interconnection
customer's proposed operating
[[Page 61223]]
assumptions. We adopt the proposed revisions to section 3.2.2.2 of the
pro forma LGIP to require transmission providers to study electric
storage resources that request NRIS service according to the
interconnection customer's proposed operating assumptions.
1513. We agree with Elevate and clarify that the reform to use
operating assumptions in interconnection studies, at the request of the
interconnection customer, that reflect the proposed charging behavior
of an electric storage resource applies to the operating assumptions
used in all study processes related to the interconnection of electric
storage resources. Accordingly, we modify the NOPR proposal to require
transmission providers, at the request of the interconnection customer,
to use operating assumptions that reflect the proposed charging
behavior of an electric storage resource in additional study processes,
as described below.
1514. With respect to surplus interconnection service, we modify
the NOPR proposal to revise section 3.3.1 of the pro forma LGIP to
require transmission providers, at the request of the interconnection
customer, to use operating assumptions that reflect the proposed
charging behavior of an electric storage resource in the surplus
interconnection service process.
1515. We adopt the proposed revisions to section 3.4.2 of the pro
forma LGIP to require interconnection customers to include in their
interconnection request the proposed operating assumptions that reflect
the proposed charging behavior of the electric storage resource and a
description of any control technologies that will limit the operation
of the electric storage resource to its intended operation.
1516. To the extent an interconnection customer requests to modify
a generating facility already in the interconnection queue by adding an
electric storage resource to the interconnection request, the
transmission provider shall study such a modification in accordance
with section 4.4.3 of the pro forma LGIP using operating assumptions
that reflect the proposed charging behavior of an electric storage
resource, at the request of the interconnection customer. Accordingly,
we modify the NOPR proposal to revise section 4.4.3 of the pro forma
LGIP to require transmission providers, at the request of the
interconnection customer, to use operating assumptions that reflect the
proposed charging behavior of an electric storage resource in the
material modification process.
1517. We adopt the proposed revisions to section 7.3 of the pro
forma LGIP to require transmission providers, at the request of the
interconnection customer, to use operating assumptions that reflect the
proposed charging behavior of an electric storage resource in the
cluster study process and to allow, but not require, transmission
providers to: (1) memorialize the generating facility's operating
assumptions in Appendix H of the interconnection customer's LGIA; and/
or (2) require control technologies (software and/or hardware) for an
electric storage resource that wishes to limit its operations during
peak load conditions, with such protection devices included in Appendix
C of the interconnection customer's LGIA.
1518. We adopt the proposed revisions to section 8.2 of the pro
forma LGIP to require transmission providers, at the request of the
interconnection customer, to use operating assumptions that reflect the
proposed charging behavior of an electric storage resource in the
interconnection facilities study process.
1519. We adopt the NOPR proposal to revise Appendix 1 of the pro
forma LGIP to require interconnection customers to provide to the
transmission provider as part of the initial interconnection request:
(1) the requested operating assumptions for the interconnecting
electric storage resource; and (2) a description of any applicable
control technologies. However, we agree with MISO and Pine Gate that it
is not necessary, and may not be possible, to specify the specific
ancillary services that an electric storage resource will provide
before entering the interconnection queue, particularly because the
market rules addressing the provision of ancillary services from
electric storage resources, whether they are standalone, part of co-
located generating facilities, or part of a hybrid generating facility,
are still being developed in multiple markets and such rules will
likely change over the coming years.\2860\ Therefore, we decline to
adopt the proposed revision to require interconnection customers to
list the specific ancillary services they intend to provide as part of
the initial interconnection request.\2861\ In addition, we agree with
MISO and CAISO that control technologies frequently evolve, and
interconnection customers that choose to specify operating assumptions
should be responsible for including appropriate control technologies
with their requests to use such operating assumptions. Therefore, we
also decline to adopt the proposed revision to require transmission
providers to publicly post a list of acceptable control technologies.
---------------------------------------------------------------------------
\2860\ MISO Initial Comments at 118; Pine Gate Initial Comments
at 52.
\2861\ NOPR, 179 FERC ] 61,194 at P 281.
---------------------------------------------------------------------------
1520. We adopt the NOPR proposal to revise Appendix 1 of the pro
forma LGIP to require interconnection customers to provide to the
transmission provider any proposed operating assumptions for the
interconnecting electric storage resource as part of the initial
interconnection request. This timing ensures that the flexibility
provided by this reform does not delay the cluster study process by
ensuring the transmission provider has all necessary information at the
time interconnection studies commence. In response to commenters that
request that the Commission define a clear decision point after which
changes to operating assumptions may be considered a material
modification,\2862\ we reiterate that the operating assumptions must be
submitted as part of the initial interconnection request. Further, we
clarify that such operating assumptions only pertain to the proposed
charging behavior of an electric storage resource, i.e., whether the
interconnecting resource will or will not charge during peak load
conditions.
---------------------------------------------------------------------------
\2862\ AES Clean Energy Initial Comments at 24; APS Initial
Comments at 22; Clean Energy Associations Initial Comments at 56-57;
ENGIE Initial Comments at 11.
---------------------------------------------------------------------------
1521. We modify the NOPR proposal to add article 17.2 to the pro
forma LGIA to describe a violation of operating assumptions for
generating facilities, including for an electric storage resource. We
also add Appendix H to the pro forma LGIA as the location for the
interconnection customer to memorialize its operating assumptions. If
the owner of the generating facility fails to operate the generating
facility in accordance with its operating assumptions, as memorialized
in Appendix H of the pro forma LGIA, the transmission provider may
pursue termination of the LGIA through the breach and cure provisions
found in article 17 of the pro forma LGIA. As already provided for in
article 17 of the pro forma LGIA, we agree with Environmental Defense
Fund that interconnection customers should be given the opportunity to
cure a breach of the LGIA if possible.\2863\ We clarify that, if an
interconnection customer fails to operate its electric storage resource
in accordance with the operating assumptions memorialized in the
interconnection customer's LGIA, the
[[Page 61224]]
procedure for termination pursuant to articles 17.1.1 and 17.1.2 of the
pro forma LGIA is appropriate. We believe that repeat violations of the
operating assumptions memorialized in the LGIA are likely not
consistent with good utility practice.\2864\ Additionally, we agree
with rPlus and Idaho Power that there may be unique instances in real-
time operations during which a transmission provider would want an
electric storage resource to charge during peak load conditions (e.g.,
because the electric storage resource is located in a generation
pocket). Therefore, we clarify that, if done so at the direction of the
transmission provider to maintain the reliable and efficient operation
of the transmission system, an electric storage resource that operates
contrary to the operating assumptions specified in its LGIA in this
instance must not be considered in breach of its LGIA by the
transmission provider.
---------------------------------------------------------------------------
\2863\ Environmental Defense Fund Initial Comments at 6-7.
\2864\ The pro forma LGIA states that ``Each Party shall perform
all of its obligations under this LGIA in accordance with Applicable
Laws and Regulations, Applicable Reliability Standards, and Good
Utility Practice, and to the extent a Party is required or prevented
or limited in taking any action by such regulations and standards,
such Party shall not be deemed to be in Breach of this LGIA for its
compliance therewith.'' Pro forma LGIA art. 4.3 (Performance
Standards).
---------------------------------------------------------------------------
1522. We believe that, taken together, the revisions to the pro
forma LGIP and pro forma LGIA will ensure that interconnection
customers adhere to the operating assumptions used to study their
electric storage resource and ameliorate concerns about possible
reliability problems expressed by commenters. We agree with commenters
that: (1) control devices can prevent electric storage resources from
charging during peak load conditions; (2) modern electric storage
resources can respond to signals from the transmission provider within
seconds; (3) electric storage resources generally do not have an
economic incentive to charge during peak load conditions; and (4) the
consequence of being considered in breach of the LGIA provides an
additional incentive for electric storage resources to follow the
agreed-upon operating assumptions memorialized in their LGIA. Further,
we note that some transmission providers already assume in their
interconnection studies that electric storage resources will not charge
during peak load conditions.\2865\ We emphasize that, irrespective of
these changes to operating assumptions, all electric storage resources
must continue to meet all requirements in the pro forma LGIP and pro
forma LGIA, as well as all applicable reliability standards.
---------------------------------------------------------------------------
\2865\ Bonneville Initial Comments at 23; MISO Comments at 117;
see also PacifiCorp, 182 FERC ] 61,131 (2023) (accepting, subject to
condition, revisions to PacifiCorp's LGIP and LGIA to allow
PacifiCorp to study electric storage resources in its
interconnection study process using operating assumptions that more
accurately reflect their expected operation).
---------------------------------------------------------------------------
1523. We agree with commenters that the speed and control with
which electric storage resources can respond to signals from
transmission providers sufficiently distinguishes the charging behavior
of electric storage resources from that of firm customer end-use load.
Therefore, for purposes of determining any network upgrades necessary
to accommodate the reliable interconnection of electric storage
resources, we find that the charging of electric storage resources
should not be modeled equivalently to firm customer end-use load in
interconnection studies if the interconnection customer memorializes
its operating assumptions in the LGIA and installs control
technologies, if required, to limit its operations as specified.
1524. For clarity and in response to MISO's concern about
conflicting descriptions of the reform in the NOPR preamble and the
proposed revisions to the pro forma LGIP, we modify the proposed
revisions to the pro forma LGIP to clarify that these requirements
apply only to the operating assumptions for withdrawals of energy
(e.g., proposed charging behavior of electric storage resources,
whether standalone, co-located generating facilities, or part of a
hybrid generating facility), not to discharging.
1525. In response to Pine Gate's request for clarification about
what network upgrade costs will be allocated to interconnection
customers as a result of the adoption of the revisions related to
operating assumptions, we clarify that the transmission provider must
not assign network upgrade costs to the interconnection customer based
on those worst-case operating assumptions (e.g., charging at maximum
capacity during peak load conditions) where there is agreement from the
interconnection customer to, if required, implement operating
restrictions including installing or demonstrating that the generating
facility already has control technologies (software and/or hardware) to
limit its operations during peak load conditions. As addressed above,
we believe that these conditions sufficiently address any reliability
concerns associated with the unexpected operation of an electric
storage resource and thus believe it is appropriate for the
transmission provider to only assign costs for network upgrades based
on the proposed charging behavior of the electric storage
resource.\2866\
---------------------------------------------------------------------------
\2866\ See, e.g., AEE Initial Comments at 41-42; AEP Initial
Comments at 46-47; CESA Reply Comments at 10; Clean Energy
Associations Initial Comments at 52, 56-58; NARUC Initial Comments
at 37; NESCOE Reply Comments at 18; Public Interest Organizations
Initial Comments at 48-50; R Street Initial Comments at 16; SEIA
Reply Comments at 26-27.
---------------------------------------------------------------------------
1526. Several commenters point out that not all transmission
providers use the same process to study the charging of electric
storage resources. Some transmission providers determine the network
upgrades needed to accommodate the charging of an electric storage
resource in the interconnection process, whereas other transmission
providers do so exclusively as part of a transmission service
request.\2867\ In response to these commenters, we clarify that the
requirement for transmission providers to use operating assumptions, at
the request of the interconnection customer, in interconnection studies
that reflect the proposed charging behavior of an electric storage
resource applies only to the operating assumptions that transmission
providers use in the interconnection process. This requirement does not
apply to transmission service requests and this final rule does not
propose to modify the process for requesting transmission service. In
response to Puget Sound,\2868\ we further clarify that this reform does
not require transmission providers to study charging as part of the
interconnection process if they do not already do so. If a transmission
provider does not determine the network upgrades needed to accommodate
the charging of an electric storage resource through the
interconnection process, then on compliance the transmission provider
must demonstrate why this reform does not apply to that particular
transmission provider.
---------------------------------------------------------------------------
\2867\ See, e.g., Clean Energy Associations Initial Comments at
55; Puget Sound Initial Comments at 11-12; SPP Initial Comments at
25; Tri-State Initial Comments at 22; Xcel Initial Comments at 46-
47.
\2868\ Puget Sound Initial Comments at 11-12.
---------------------------------------------------------------------------
1527. In the NOPR, the Commission sought comment on whether to
define ``peak load period'' and/or ``net peak load'' period.\2869\
Given the variation in the scenarios that transmission providers study
in the interconnection process (e.g., summer peak load, winter peak
load, shoulder peak load, light load conditions, etc.), we agree with
commenters that regional flexibility is warranted.\2870\ Therefore, we
decline to adopt standardized definitions of ``peak
[[Page 61225]]
load period'' and/or ``net peak load'' period.
---------------------------------------------------------------------------
\2869\ NOPR, 179 FERC ] 61,194 at P 287.
\2870\ See, e.g., Ameren Initial Comments at 29; Microgrid
Resources Initial Comments at 8.
---------------------------------------------------------------------------
1528. In the NOPR, the Commission also sought comment on whether to
define firm and non-firm charging for electric storage resources and
require transmission providers to define study criteria and possible
ways to interconnect related to both firm and non-firm charging.\2871\
Further, the Commission sought comment on proposed definitions of firm
and non-firm charging service. Several commenters express concerns
about defining firm and non-firm charging service, including whether
the proposed definitions conflate interconnection and transmission
service. We believe that, given the other reforms adopted herein
regarding operating assumptions, the proposed definitions of firm and
non-firm charging service are not necessary to ensure that transmission
providers, at the request of the interconnection customer, use more
realistic operating assumptions to study electric storage resources in
the interconnection process and to avoid excessive and unnecessary
network upgrades that may otherwise hinder the timely development of
new electric storage resources. Therefore, we decline to adopt any
definitions of firm and non-firm charging service. As a result, we also
clarify that this final rule does not require transmission providers to
define conditions under which electric storage resources will be
curtailed. In response to CAISO's concern that a proposed definition of
firm charging service would require transmission providers that do not
currently provide firm charging service to do so, we clarify that this
final rule does not require transmission providers to provide firm
charging service.
---------------------------------------------------------------------------
\2871\ NOPR, 179 FERC ] 61,194 at P 288.
---------------------------------------------------------------------------
1529. In the NOPR, the Commission sought comment on whether to
expand this reform to address operating assumptions for additional
generating facility technologies that may currently be inaccurately
modeled, such as variable energy resources.\2872\ The Commission also
sought comment on whether other operating assumptions, in addition to
the assumption that electric storage resources withdraw energy during
peak load periods, should be addressed as part of this proposed reform.
In response to several commenters' concerns about potential reliability
impacts and the administrative burden of extending the NOPR proposal to
also address injections of power from electric storage resources or
other resource types, we decline in this final rule to extend the
reform to apply to additional generating facility technologies or to
other operating assumptions. We clarify that this reform does not apply
to the operating assumptions used to study the injection of power from
electric storage resources or the injection of power from other
resource types (e.g., natural gas, solar, wind, etc.). We encourage
transmission providers to examine on an individual basis what operating
assumptions used to study the injection of power may be appropriate to
render the study process more accurate. Similarly, we decline to
require transmission providers to use fuel-based dispatch assumptions
to study the injection of power from all resource types in
interconnection studies at this time, as suggested by some commenters.
We acknowledge that fuel-based dispatch assumptions may be able to
address some of the identified challenges associated with inaccurate
modeling assumptions for all resource types and encourage transmission
providers to evaluate the merits of adopting it, but we do not believe
that adopting such a requirement on a generic basis is supported by the
record.
---------------------------------------------------------------------------
\2872\ Id. P 286.
---------------------------------------------------------------------------
1530. We decline to address the potential implications of this
reform for transmission providers with Commission-approved
interconnection processes that vary from the pro forma requirements
adopted in Order Nos. 2003 and 845. As explained in the section IV of
this final rule, transmission providers with such variations from the
pro forma LGIP and pro forma LGIA may seek approval as part of the
compliance process to maintain those variations, which the Commission
will consider on a case-by-case basis. What we adopt in this final rule
are requirements that are part of the pro forma LGIP and pro forma
LGIA, and we therefore only address the interaction of the requirements
adopted herein with existing requirements that are part of the pro
forma process and not variations thereto.
1531. We also decline to require transmission providers to use
standardized operating assumptions, as some commenters suggest.\2873\
In the NOPR, the Commission did not propose to require transmission
providers to use standardized operating assumptions, and we decline to
do so here.
---------------------------------------------------------------------------
\2873\ Puget Sound Initial Comments at 12; Pine Gate Initial
Comments at 54.
---------------------------------------------------------------------------
1532. In response to comments from Hydropower Commenters'
suggestion that the final rule include a simplified procedure for
amending an executed interconnection agreement to optimize the
operating parameters of a pumped storage plant already in
operation,\2874\ we find that such a request is outside the scope of
this proceeding. In the NOPR, the Commission did not propose a new
study process for resources already in operation to amend operating
assumptions memorialized in their interconnection agreements.
---------------------------------------------------------------------------
\2874\ Hydropower Commenters Initial Comments at 24.
---------------------------------------------------------------------------
1533. In response to Microgrid Resources' request that the
Commission explicitly include microgrids in the provisions of this
rulemaking applied to hybrid resources,\2875\ we find such a request to
be outside the scope of this proceeding. The Commission did not propose
to define microgrids or apply specific reforms to microgrids in the
NOPR, and we decline to do so now. Further, in response to Microgrid
Resources' and IREC's requests that the Commission extend the proposed
reforms for hybrid resources to the pro forma SGIP,\2876\ we note that
the NOPR did not propose to revise the pro forma SGIP to require
transmission providers to use operating assumptions in interconnection
studies that reflect the proposed charging behavior of an electric
storage resource, and we decline to do so here.
---------------------------------------------------------------------------
\2875\ Microgrid Resources Initial Comments at 7.
\2876\ Id.; IREC Initial Comments at 15, attach. A.
---------------------------------------------------------------------------
2. Incorporating the Enumerated Alternative Transmission Technologies
Into the Generator Interconnection Process
a. Consideration of the Enumerated Alternative Transmission
Technologies in Interconnection Studies Upon Request of the
Interconnection Customer
i. Need for Reform and NOPR Proposal
1534. In the NOPR, the Commission stated that alternative
transmission technologies can provide substantial benefits to optimize
the transmission system in specific scenarios because they often can be
deployed both more quickly and at lower costs than other network
upgrades.\2877\ The Commission stated that, despite these potential
benefits, alternative transmission technologies often do not receive
the same consideration during generator interconnection processes as
other network upgrades.\2878\ The Commission preliminarily found that
failing to consider alternative transmission technologies that can be
deployed both more quickly and at lower costs than network upgrades may
render
[[Page 61226]]
Commission-jurisdictional rates unjust and unreasonable.
---------------------------------------------------------------------------
\2877\ NOPR, 179 FERC ] 61,194 at P 294.
\2878\ Id. P 296.
---------------------------------------------------------------------------
1535. The Commission proposed to revise the pro forma LGIP and pro
forma SGIP to require transmission providers, upon request of the
interconnection customer, to evaluate the requested alternative
transmission solution(s) during the pro forma LGIP cluster study and
the pro forma SGIP system impact study and facilities study within the
generator interconnection process.\2879\
---------------------------------------------------------------------------
\2879\ Id. P 297.
---------------------------------------------------------------------------
1536. To provide more certainty for evaluation purposes, and focus
on technologies that serve a transmission function and thus are subject
to Commission jurisdiction, the Commission proposed to specify the
technologies that the interconnection customer may request to be
evaluated.\2880\ Specifically, the Commission proposed revisions to the
pro forma LGIP and pro forma SGIP to require transmission providers to
consider the following technologies within the cluster study of the pro
forma LGIP and within the system impact study and facilities study of
the pro forma SGIP upon request of the interconnection customer:
advanced power flow control, transmission switching, dynamic line
ratings, static synchronous compensators, and static VAR compensators.
The Commission stated that it believes that the deployment of these
transmission technologies may reduce interconnection costs by providing
lower cost network upgrades to interconnect new generating
facilities.\2881\
---------------------------------------------------------------------------
\2880\ Id. P 298.
\2881\ Id.; see also id. PP 294-95, 298.
---------------------------------------------------------------------------
1537. The Commission explained that, under this proposal, the
interconnection customer may request, at the relevant scoping meeting,
that the transmission provider consider a single, multiple, or all
technologies on this list.\2882\ The Commission proposed that the
transmission provider would be required to evaluate the transmission
technologies identified above for feasibility, cost, and time savings
within the cluster study for the pro forma LGIP and the system impact
study and facilities study for the pro forma SGIP, upon request of the
interconnection customer. The Commission explained that the
transmission provider, upon this request, must evaluate the identified
transmission technology and, if feasible, determine whether it should
be used, consistent with good utility practice and other applicable
regulatory standards. Transmission providers would continue to retain
discretion regarding whether to use the transmission technology.
---------------------------------------------------------------------------
\2882\ Id. P 299.
---------------------------------------------------------------------------
1538. The Commission sought comment on whether the list of
alternative transmission technologies is sufficient.\2883\ In
particular, the Commission sought comment on whether storage that
performs a transmission function, synchronous condensers, and voltage
source converters should be included in the list of alternative
transmission technologies. The Commission also sought comment on: (1)
whether there are software, operational, or other barriers to the use
of these transmission technologies as proposed; (2) whether the use of
alternative transmission technologies as supplements for, or in the
place of, traditional network upgrades is sufficient to guarantee a
level of service to accommodate an interconnection customer seeking
NRIS, or whether such a network upgrade can only be used if the
interconnection customer requested ERIS; (3) whether the existing study
processes and models in the generator interconnection process remain
suitable for considering alternative transmission technologies, whether
additional processes or models are needed, and if so, which entity
should be responsible for developing them; (4) how costs incurred for
evaluating alternative transmission technology study requests would be
allocated among interconnection customers in the cluster; (5) what
reasonable number of transmission technology study requests from each
interconnection customer would be workable, the burden (in terms of
both time and resources) on transmission providers required to evaluate
such requests, and whether interconnection study deadlines may need to
be extended to account for time needed to evaluate the alternative
transmission technology study requests; and (6) whether provisional
interconnection service consideration for transmission technologies
should be mandatory.\2884\
---------------------------------------------------------------------------
\2883\ Id. P 300.
\2884\ Id. P 301.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1539. Numerous commenters support the Commission's proposal because
they believe that it could reduce interconnection costs, increase
flexibility, increase the speed of interconnections, and improve
reliability.\2885\ Commenters assert that the proposed alternative
transmission technologies in the NOPR can reduce costs.\2886\ With
respect to reducing interconnection costs, SEIA contends that, by
decreasing the costs of network upgrades, the proposal will reduce the
number of withdrawals from the interconnection queue, creating a more
stable and efficient interconnection process.\2887\ SEIA also claims
that decreasing these costs will reduce the interconnection costs for
interconnection customers, who may then reflect those savings in power
purchase agreements or integrated resource plan submissions.\2888\
Commenters contend that, if the Commission were to not adopt this
proposal, the failure to lower interconnection costs by evaluating
alternative transmission technologies would impose unjust and
unreasonable costs on interconnection customers.\2889\
---------------------------------------------------------------------------
\2885\ ACORE Reply Comments at 3-4; AEE Initial Comments at 42;
AEE Reply Comments at 41; AES Initial Comments at 25; Amazon Initial
Comments at 5-6; Clean Energy Associations Initial Comments at 61-
62; Clean Energy Associations Reply Comments at 9; Clean Energy
Buyers Initial Comments at 5; Consumer Protection Coalition Reply
Comments at 2; CREA and NewSun Initial Comments at 92; EDF
Renewables Initial Comments at 14; ENGIE Initial Comments at 12;
EPRI Initial Comments at 20-21; Fervo Energy Reply Comments at 8-9;
Illinois Commission Initial Comments at 14; Invenergy Initial
Comments at 52; NARUC Initial Comments at 38-39; OSPA Reply Comments
at 14; Ohio Commission Consumer Advocate Initial Comments at 15; OMS
Initial Comments at 19; [Oslash]rsted Initial Comments at 3;
[Oslash]rsted Reply Comments at 8; R Street Initial Comments at 9;
SEIA Initial Comments at 41; Tesla Initial Comments at 8; WATT
Coalition Initial Comments at 2; WATT Coalition Reply Comments at 1;
Joint Fed.-State Task Force on Elec. Transmission, Technical
Conference, Docket No. AD21-15-000, recording at 1:16:18-1:24:02
(approx.) (Commissioner Darcie Houck) (July 16, 2023).
\2886\ Cyprus Creek Initial Comments at 26; SEIA Initial
Comments at 40; Shell Initial Comments, app. A at v-vi.
\2887\ SEIA Initial Comments at 40; see also AEE Initial
Comments at 42; EDF Renewables Initial Comments at 14; ENGIE Initial
Comments at 12; [Oslash]rsted Initial Comments at 37; OMS Initial
Comments at 19.
\2888\ SEIA Initial Comments at 40-41.
\2889\ Clean Energy Associations Reply Comments at 9-10;
Environmental Defense Fund Initial Comments at 7; Fervo Energy Reply
Comments at 9; NARUC Initial Comments at 38.
---------------------------------------------------------------------------
1540. With respect to reducing interconnection delays, Illinois
Commission asserts, for example, that alternative transmission
technologies allow resources to come online more quickly and allow for
better use of the existing transmission system, requiring fewer
transmission buildouts.\2890\ OMS contends that failing to consider
alternative transmission technologies risks requiring longer lead-time
network upgrades.\2891\ WATT Coalition argues that use of the
appropriate technologies will result in fewer withdrawals from
[[Page 61227]]
the interconnection queue and a reduction in restudies and
delays.\2892\ WATT Coalition points out that, when interconnection
customers withdraw, grid enhancing technologies offer additional value
because they are scalable and modular to address evolving needs and can
be redeployed as those needs continue to change.\2893\
---------------------------------------------------------------------------
\2890\ Illinois Commission Initial Comments at 14.
\2891\ OMS Initial Comments at 19.
\2892\ WATT Coalition Initial Comments at 2.
\2893\ Id. at 2-3; WATT Coalition Reply Comments at 5-6.
---------------------------------------------------------------------------
1541. With respect to reliability, Ohio Commission Consumer
Advocate contends that some alternative transmission technologies could
provide substantial benefits by resolving thermal overloads and
avoiding voltage collapse.\2894\
---------------------------------------------------------------------------
\2894\ Ohio Commission Consumer Advocate Initial Comments at 15.
---------------------------------------------------------------------------
1542. Some commenters argue that a requirement to study alternative
transmission technologies would not slow down interconnection studies
overall.\2895\ For example, AEE states that, if a technology is not
proven or commercially viable, it will be quickly ruled out of further
evaluation under prevailing study approaches.\2896\ ACORE claims that
an evaluation of alternative transmission technologies would not be a
burden but rather an integral part of interconnection studies because
such an evaluation will likely reduce the number of withdrawals and
restudies.\2897\ WATT Coalition argues that, because transmission
providers currently use an iterative process when conducting
interconnection studies, adding the proposed list of alternative
transmission technologies to an iterative solution set should not
significantly change the time frame or complexity of studies.\2898\
---------------------------------------------------------------------------
\2895\ ACORE Reply Comments at 3-4; AEE Initial Comments at 44;
ENGIE Initial Comments at 13; Fervo Energy Initial Comments at 7.
\2896\ AEE Initial Comments at 44.
\2897\ ACORE Reply Comments at 3-4.
\2898\ WATT Coalition Reply Comments at 2.
---------------------------------------------------------------------------
(b) Comments in Opposition
1543. Some commenters argue that the proposal is unnecessary
because transmission providers already consider alternative
transmission technologies in interconnection studies.\2899\ For
example, Southern states that transmission providers already include
the assessment of alternative transmission technologies such as static
VAR compensators as needed in interconnection studies.\2900\ AEE
responds that, if alternative transmission technologies are already
being evaluated, then the proposal will not place an additional burden
on interconnection queues.\2901\
---------------------------------------------------------------------------
\2899\ Bonneville Initial Comments at 23-24; MISO Initial
Comments at 120; MISO Reply Comments at 12; Southern Initial
Comments at 29.
\2900\ Southern Initial Comments at 29.
\2901\ AEE Reply Comments at 42-43.
---------------------------------------------------------------------------
1544. Several commenters oppose the proposal because they believe
it conflates the use of alternative transmission technologies in
operations with their use in planning.\2902\ For instance, MISO argues
that alternative transmission technologies are not necessarily the
solution needed for any particular interconnection because these are
often operational solutions that are inappropriate for wide-scale
deployment in a planning process, which reviews an entire cycle of
proposed interconnections and identifies solutions to support those
interconnections for the expected lifetime of their
interconnection.\2903\ MISO claims that using alternative transmission
technologies in planning for interconnection rather than in operations
may be inconsistent with ``good utility practice'' and ``applicable
regulatory standards'', and MISO expresses concerns about the impact or
effectiveness of using alternative transmission technologies in place
of network upgrades.\2904\ NYTOs assert that alternative transmission
technologies should generally not be used in interconnection studies
unless they are effective in the planning context.\2905\ PJM argues
that alternative transmission technologies should not be incorporated
into the generator interconnection process because they do not
represent long-term solutions that can serve as blanket substitutes for
the need for transmission expansion.\2906\ In response, AEE and WATT
Coalition argue that the primary purpose of alternative transmission
technologies is to serve as a complementary bridge technology while
more robust transmission is built.\2907\
---------------------------------------------------------------------------
\2902\ MISO Initial Comments at 120; NRECA Initial Comments at
45-46; NYTOs Initial Comments at 32: PJM Initial Comments at 68.
\2903\ MISO Initial Comments at 120; see also NRECA Initial
Comments at 45-46.
\2904\ MISO Initial Comments at 122-123.
\2905\ NYTOs Initial Comments at 32; see also Puget Sound
Initial Comments at 13-14.
\2906\ PJM Initial Comments at 68.
\2907\ AEE Reply Comments at 43-44; WATT Coalition Reply
Comments at 3-4.
---------------------------------------------------------------------------
1545. Some commenters express concern that alternative transmission
technologies are not always appropriate for addressing long-term,
interconnection-related reliability issues.\2908\ Southern adds that,
because transmission providers already consider these technologies and
are subject to mandatory reliability standards, interconnection
customers should not be able to request certain reliability fixes
because their overall focus may be to minimize cost instead of
maximizing reliability.\2909\ EEI asserts that building firm
transmission capacity or replacing or upgrading limiting equipment
provides a more reliable long-term solution than the use of alternative
transmission technologies because they are not dependable for reducing
congestion or providing more capacity in the long-term or during
extreme system conditions.\2910\
---------------------------------------------------------------------------
\2908\ AECI Initial Comments at 9; AEP Initial Comments at 51;
Avangrid Initial Comments at 36; Southern Initial Comments at 29;
U.S. Chamber of Commerce Initial Comments at 12.
\2909\ Southern Initial Comments at 29.
\2910\ EEI Initial Comments at 20.
---------------------------------------------------------------------------
1546. Ameren and EEI oppose the proposal because they assert it
overlaps with pending proposals in other proceedings.\2911\ EEI argues
the Commission should not promulgate requirements related to
alternative transmission technologies in this proceeding while other
Commission proceedings meant to address the use of these same
technologies are pending.\2912\ ACORE responds that, given the benefits
of incorporating alternative transmission technologies in
interconnection studies, there is no justification for delaying this
requirement pending action in the other Commission proceedings.\2913\
---------------------------------------------------------------------------
\2911\ Ameren Initial Comments at 30; EEI Initial Comments at
20.
\2912\ EEI Initial Comments at 21 (citing Electric Transmission
Incentives Policy Under Section 219 of the Federal Power Act, Notice
of Proposed Rulemaking, Docket No. RM20-10-000; Grid-Enhancing
Technologies, Notice of Workshop, Docket No. AD19-19-000;
Implementation of Dynamic Line Ratings, Notice of Inquiry, Docket
No. AD22-5-000; Building for the Future Through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, Notice of Proposed Rulemaking, Docket No. RM21-17-
000).
\2913\ ACORE Reply Comments at 4.
---------------------------------------------------------------------------
1547. Other commenters argue that requiring interconnection studies
to consider alternative transmission technologies will increase
interconnection study timelines and therefore slow interconnection
request processing speeds, contrary to the NOPR's objective.\2914\
Puget Sound asserts that ``the time is not ripe'' to enforce new
standards concerning alternative transmission technologies, given the
sweeping changes proposed in the NOPR, adding that advanced
transmission technologies requirements
[[Page 61228]]
may not be possible in the short term and could negate the Commission's
goals to streamline the interconnection process.\2915\
---------------------------------------------------------------------------
\2914\ AECI Initial Comments at 9; AEP Initial Comments at 53;
Avangrid Initial Comments at 35; Dominion Initial Comments at 41;
EEI Initial Comments at 21; Eversource Initial Comments at 36-37;
Indicated PJM TOs Initial Comments at 55; Indicated PJM TOs Reply
Comments at 18; ISO-NE Initial Comments at 41; MISO Initial Comments
at 11, 123; National Grid Initial Comments at 42-43; Puget Sound
Initial Comments at 13.
\2915\ Puget Sound Initial Comments at 13.
---------------------------------------------------------------------------
1548. MISO contends that some alternative transmission
technologies, e.g., technologies that can control line impedances, may
shift the burden of system impacts to other parties by causing
additional new constraints.\2916\ Indicated PJM TOs are concerned that,
if one interconnection customer request changes power flows, such as
through the use of phase angle regulators, it will impact other
interconnection customers and effectively require a whole additional
set of studies for large areas of the transmission system.\2917\ AECI
argues that the appropriate balance of the burden to justify the use of
a particular technology should rest with the interconnection customer
so that ``capricious study requests'' are avoided.\2918\
---------------------------------------------------------------------------
\2916\ MISO Initial Comments at 122, 124.
\2917\ Indicated PJM TOs Initial Comments at 55.
\2918\ AECI Initial Comments at 9.
---------------------------------------------------------------------------
1549. Several commenters argue that the NOPR proposal is overly
burdensome for transmission providers.\2919\ For instance, MISO TOs
note the competing interests (i.e., accelerating the interconnection
process and layering numerous additional requirements and significantly
increasing the number of studies an RTO/ISO and its transmission owners
must perform).\2920\ MISO argues that the Commission's proposal would
require MISO to conduct 4,780 evaluations in the first phase of its
interconnection study process.\2921\ MISO contends that, when
evaluating how these technologies can be incorporated, the effects on
the rest of the interconnection queue and system can generate debate
that could slow down the interconnection process. Similarly, National
Grid claims that new alternative transmission technologies can present
modeling uncertainties (e.g., operating parameters and cost
uncertainties) and potential software limitations that transmission
owners would need an unforeseeable amount of time to evaluate and could
lead to possible penalties if study deadlines are not met.\2922\
---------------------------------------------------------------------------
\2919\ Dominion Initial Comments at 41; EEI Initial Comments at
21; Eversource Initial Comments at 36-37; MISO TOs Initial Comments
at 30; NextEra Initial Comments at 6.
\2920\ MISO TOs Initial Comments at 30.
\2921\ MISO Initial Comments at 11.
\2922\ National Grid Initial Comments at 42-43.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
(1) List of Alternative Transmission Technologies
1550. Some commenters broadly support the list of proposed
alternative transmission technologies,\2923\ with others supporting
particular technologies (e.g., dynamic line ratings \2924\ and advanced
power flow control \2925\).
---------------------------------------------------------------------------
\2923\ NARUC Initial Comments at 39; OMS Initial Comments at 19;
[Oslash]rsted Initial Comments at 16; WATT Coalition Initial
Comments at 3; Xcel Initial Comments at 47.
\2924\ Illinois Commission Initial Comments at 14; OMS Initial
Comments at 19; WATT Coalition Initial Comments at 2; Joint Fed.-
State Task Force on Elec. Transmission, Technical Conference, Docket
No. AD21-15-000, recording at 1:16:18-1:24:02 (approx.)
(Commissioner Darcie Houck) (July 16, 2023).
\2925\ WATT Coalition Initial Comments at 2; Joint Fed.-State
Task Force on Elec. Transmission, Technical Conference, Docket No.
AD21-15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner
Darcie Houck) (July 16, 2023).
---------------------------------------------------------------------------
1551. MISO and SoCal Edison oppose the proposed list of
technologies because they contend that it includes technologies that
are not appropriate for interconnection.\2926\ MISO asserts that,
although the deployment of devices such as static series synchronous
compensators could solve some problems, they could create other issues
(e.g., a change to the impedance of any one transmission facility could
cause problems or impact operations elsewhere), requiring the holistic
management of their operation and deployment.\2927\ SoCal Edison claims
that certain technologies that the interconnection customer may request
to be evaluated, such as dynamic line ratings, have not been fully
tested by certain RTOs/ISOs and thus should be excluded from the
permissible list of options requested by an interconnection
customer.\2928\
---------------------------------------------------------------------------
\2926\ MISO Initial Comments at 122; SoCal Edison Initial
Comments at 20.
\2927\ MISO Initial Comments at 122.
\2928\ SoCal Edison Initial Comments at 20.
---------------------------------------------------------------------------
1552. Some commenters assert that, although dynamic line ratings
may be beneficial during operations, they may not be appropriate for
interconnection or transmission planning.\2929\ Others note several
operational challenges of using dynamic line ratings in
interconnection, such as: (1) there is currently no Commission or NERC
guidance on how to use dynamic line ratings absent thorough data on
wind conditions, temperature, and other future system conditions;
\2930\ and (2) interconnection study software is not capable of
incorporating dynamic line ratings, and it is not clear what
assumptions should be used on affected systems.\2931\ ISO-NE argues
that the Commission should continue to consider the use and
implementation of this technology in Docket No. AD22-5, rather than
here.\2932\ In response, WATT Coalition argues that there is
significant value in considering dynamic line ratings in planning,
adding that dynamic line ratings and other grid enhancing technologies
are not more difficult to study than legacy devices and traditional
solutions.\2933\
---------------------------------------------------------------------------
\2929\ Indicated PJM TOs Initial Comments at 56; ISO-NE Initial
Comments at 41; NYTOs Initial Comments at 32-33; PacifiCorp Initial
Comments at 44; Tri-State Initial Comments at 23; U.S. Chamber of
Commerce Initial Comments at 12-13.
\2930\ PacifiCorp Initial Comments at 44.
\2931\ Tri-State Initial Comments at 23.
\2932\ ISO-NE Initial Comments at 41.
\2933\ WATT Coalition Reply Comments at 4-6.
---------------------------------------------------------------------------
1553. While acknowledging the benefits that advanced power flow
control devices provide for real-time operations, Indicated PJM TOs
contend that they are inappropriate in the context of implementing
solutions to facilitate interconnection.\2934\ Tri-State claims that
advanced power flow control devices may push power onto other affected
systems, which is a more significant challenge in non-RTO/ISO
scenarios.\2935\ MISO asserts that the widespread use of advanced flow
control devices can have widespread impacts due to sizeable adjustments
to line impedances and that using these devices could result in a
cascade of issues across the system, pushing the problem and the costs
of remedying it to other customers.\2936\ WATT Coalition asserts that
automatic power factor controllers are just as effective at mitigating
overloads as reconductoring but that automatic power factor controllers
are the only flexible AC transmission system devices that suffer from
the ``perverse incentive'' identified by stakeholders because
installation costs are much lower than the upgrades they compete
with.\2937\ PacifiCorp states that in the course of the interconnection
study process it often considers the use of advanced power flow control
devices as potential alternatives to standard system
infrastructure.\2938\
---------------------------------------------------------------------------
\2934\ Indicated PJM TOs Initial Comments at 56.
\2935\ Tri-State Initial Comments at 23.
\2936\ MISO Initial Comments at 122.
\2937\ WATT Coalition Initial Comments at 3.
\2938\ PacifiCorp Initial Comments at 43.
---------------------------------------------------------------------------
1554. Some commenters raise concerns about using transmission
switching for interconnection. For instance, Tri-State questions
whether transmission switching is meant to be a remedial action scheme
or to create permanent open points on the system, which it argues may
be problematic in non-RTOs/ISOs and may result in
[[Page 61229]]
reduced reliability on the transmission system.\2939\ MISO argues that
applying automatic topology changes would be remedial action schemes,
noting that MISO and its transmission owners have attempted to reduce
the number of remedial action schemes employed on the system as a
matter of good utility practice.\2940\ PacifiCorp contends that
transmission switching is a complex process that can be implemented
only under particular factual scenarios and system conditions, adding
that it is unlikely that system congestion could be reliably reduced by
requiring the analysis of transmission switching in the study
process.\2941\
---------------------------------------------------------------------------
\2939\ Tri-State Initial Comments at 23.
\2940\ MISO Initial Comments at 122.
\2941\ PacifiCorp Initial Comments at 44.
---------------------------------------------------------------------------
1555. Other commenters argue that the Commission should not limit
the alternative transmission technologies to a pre-approved list.\2942\
Some commenters contend that the Commission's proposal could limit
future grid enhancing technologies that might be the best solution
because the list includes only five technologies and would not require
transmission providers to consider new grid enhancing technologies
until the list is expanded.\2943\ AEE and ENGIE ask the Commission to
provide a non-exhaustive list of alternative transmission technologies
and allow any alternative transmission technologies or grid enhancing
technologies that are proven and commercially viable to qualify for
evaluation, consistent with the Commission's statutory obligation to
``encourage, as appropriate, the deployment of advanced transmission
technologies'' and the list of alternative transmission technologies
included in that statute.\2944\
---------------------------------------------------------------------------
\2942\ Amazon Initial Comments at 6-7; CTC Global Initial
Comments at 17; ENGIE Initial Comments at 13; Environmental Defense
Fund Initial Comments at 7; Invenergy Initial Comments at 52;
Microgrid Resources Initial Comments at 8; NRECA Initial Comments at
46; Public Interest Organizations Initial Comments at 53-55; Xcel
Initial Comments at 47.
\2943\ Ameren Initial Comments at 31-32; MISO Reply Comments at
13-14; Shell Initial Comments, app. A at v.
\2944\ AEE Initial Comments at 44-45 (citing 42 U.S.C. 16422);
ENGIE Initial Comments at 13.
---------------------------------------------------------------------------
1556. Commenters suggest adding the following technologies to the
list: (1) synchronous condensers and voltage source converters; \2945\
(2) IBR technology solutions for advanced control capabilities and
control parameter tuning; \2946\ (3) microgrid control technologies;
\2947\ and (4) remedial action schemes, which they contend are an
effective and inexpensive way to mitigate local transmission
constraints the use of which is not allowed in many transmission
providers' policies.\2948\
---------------------------------------------------------------------------
\2945\ NARUC Initial Comments at 39; Xcel Initial Comments at
47.
\2946\ EPRI Initial Comments at 21.
\2947\ Microgrid Resources Initial Comments at 8.
\2948\ Enel Initial Comments at 80.
---------------------------------------------------------------------------
1557. Several commenters also suggest adding advanced conductors to
the required list of alternative transmission technologies.\2949\ VEIR
and ACORE argue that advanced conductors may be a beneficial
alternative to network upgrades because: (1) advanced conductors meet
the same criteria of quick deployment and low cost and have advantages
over other network upgrades, especially the elimination of additional
siting and permitting requirements; \2950\ and (2) a recent Grid
Strategies LLC report finds ``short lead time to reconductor existing
lines can help manage risk and uncertainties and significantly increase
system capacity to mitigate overloads identified in interconnection
studies.'' \2951\ NARUC asks the Commission to consider requiring an
evaluation of the accuracy of transmission line ratings on surrounding
or impacted transmission facilities if requested by an interconnection
customer.\2952\ Additionally, Ampjack proposes tower lifting to
increase transmission line ratings due to the time savings, lack of
outages, and use of existing structures.\2953\
---------------------------------------------------------------------------
\2949\ ACORE Initial Comments at 6-7; CTC Global Initial
Comments at 6-9; VEIR Initial Comments at 5-7.
\2950\ VEIR Initial Comments at 5-7.
\2951\ ACORE Initial Comments at 7 (citing Jay Caspary and Jesse
Schneider, Grid Strategies, LLC, Opportunities to Use Advanced
Conductors to Accelerate Grid Decarbonization, at 9 (Feb. 2022),
https://acore.org/wp-content/uploads/2022/03/Advanced_Conductors_to_Accelerate_Grid_Decarbonization.pdf).
\2952\ NARUC Initial Comments at 39-40.
\2953\ Ampjack Initial Comments at 1-4.
---------------------------------------------------------------------------
1558. Many commenters recommend that the Commission add storage
that performs a transmission function to the list.\2954\ Illinois
Commission contends that storage that performs a transmission function
can relieve congestion, maintain reliability, and be placed on the
transmission system more quickly and cheaply than building new
transmission lines.\2955\ Tesla suggests expanding the list to include
batteries as virtual transmission, arguing that it provides several
benefits (e.g., providing emergency capacity for congested transmission
lines and surplus generation and surplus load capacity to allow
operation of transmission lines closer to thermal capacity without risk
of outage and averting the need for load shed by providing grid
stability service).\2956\ Clean Energy Associations note that the
Commission has approved tariffs for storage that performs a
transmission function. Clean Energy Associations assert that it would
be inconsistent to prohibit an interconnection customer from adding
electric storage to an interconnection request specifically to address
transmission reliability impacts in lieu of conventional upgrades,
while at the same time allowing an interconnection customer to add such
storage to an interconnection request for purposes unrelated to
transmission reliability or allowing an interconnection customer to
limit electric storage operations as a means to avoid network
upgrades.\2957\
---------------------------------------------------------------------------
\2954\ AES Initial Comments at 25; Clean Energy Associations
Initial Comments at 62; Clean Energy Associations Reply Comments at
9; ENGIE Initial Comments at 13; Illinois Commission Initial
Comments at 14-15; Illinois CUB Reply Comments at 1; NARUC Initial
Comments at 39; NESCOE Reply Comments at 19; NY Commission and
NYSERDA Initial Comments at 10; Ohio Commission Consumer Advocate
Initial Comments at 17; OMS Initial Comments at 19; [Oslash]rsted
Initial Comments at 16; Tesla Initial Comments at 8-9; Union of
Concerned Scientists Reply Comments at 14-15; Xcel Initial Comments
at 47; Joint Fed.-State Task Force on Elec. Transmission, Technical
Conference, Docket No. AD21-15-000, recording at 1:16:18-1:24:02
(approx.) (Commissioner Darcie Houck) (July 16, 2023).
\2955\ Illinois Commission Initial Comments at 14-15.
\2956\ Tesla Initial Comments at 8-9.
\2957\ Clean Energy Associations Initial Comments at 62-63.
---------------------------------------------------------------------------
1559. Other commenters do not agree with adding storage that
performs a transmission function to the list.\2958\ MISO notes that,
although it already evaluates storage that performs a transmission
function in its generator interconnection process, it was a subject of
considerable debate.\2959\ Shell states that, while storage that
performs a transmission function may provide system benefits, it has
concerns regarding the ability of storage that performs a transmission
function to ``queue jump'' interconnection customers, thus putting
those customers at a competitive disadvantage.\2960\
---------------------------------------------------------------------------
\2958\ Ameren Initial Comments at 31; MISO Initial Comments at
121; Shell Initial Comments, app. A at v.
\2959\ MISO Initial Comments at 121.
\2960\ Shell Initial Comments, app. A at v.
---------------------------------------------------------------------------
(2) Whether To Mandate the Consideration of Alternative Transmission
Technologies
1560. Several commenters argue that these technologies should be
studied by default, rather than at the request of the interconnection
customer, with some suggesting an ``opt-out'' that the
[[Page 61230]]
interconnection customer could elect.\2961\ Fervo Energy argues that
mandating the consideration of grid enhancing technologies could be
more efficient and facilitate more and faster interconnection, although
there may be delays initially as transmission providers adjust.\2962\
Clean Energy Associations ask that transmission providers automatically
evaluate grid enhancing technologies, unless all interconnection
customers in a cluster opt out.\2963\ [Oslash]rsted recommends that the
Commission consider requiring that advanced transmission technologies
be studied and implemented when network upgrades are needed but cannot
be completed within three years of being identified.\2964\
---------------------------------------------------------------------------
\2961\ ACORE Initial Comments at 6; AEE Initial Comments at 42,
44; AEE Reply Comments at 41-42; Amazon Initial Comments at 6; Clean
Energy Associations Initial Comments at 63-64; Environmental Defense
Fund Initial Comments at 7; ELCON Initial Comments at 11; ENGIE
Initial Comments at 13; Fervo Energy Reply Comments at 9; Hannon
Armstrong Initial Comments at 2; Invenergy Initial Comments at 52-
53; R Street Initial Comments at 16; WATT Coalition Initial Comments
at 2; WATT Coalition Reply Comments at 1; Joint Fed.-State Task
Force on Elec. Transmission, Technical Conference, Docket No. AD21-
15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner Darcie
Houck) (July 16, 2023).
\2962\ Fervo Energy Reply Comments at 9.
\2963\ Clean Energy Associations Initial Comments at 63.
\2964\ [Oslash]rsted Reply Comments at 8.
---------------------------------------------------------------------------
1561. CAISO contends that the Commission should simply require
transmission providers to include a statement in their tariffs that
they will consider alternative transmission technologies for every
interconnection and incorporate them when they are the cost-effective
solution.\2965\ CAISO states that this would allow the interconnection
customer to request an unexecuted interconnection agreement and to
raise with the Commission any transmission provider refusal to consider
a technology.\2966\ Ohio Commission Consumer Advocate suggests that
transmission providers and interconnection customers mutually determine
an appropriate number of evaluations for grid enhancing
technologies.\2967\
---------------------------------------------------------------------------
\2965\ CAISO Initial Comments at 38.
\2966\ Id.; see also MISO Reply Comments at 13.
\2967\ Ohio Commission Consumer Advocate Initial Comments at 16.
---------------------------------------------------------------------------
(3) Alternative Transmission Technologies in Provisional
Interconnection Service
1562. Some commenters argue that alternative transmission
technologies could assist with provisional interconnection service. For
instance, R Street and Hannon Armstrong assert that these technologies
can be used as a temporary measure until other network upgrades are
completed, thus reducing the cost and delays of generator
interconnection, even if they only serve as a bridge to a permanent
solution set, such as cluster network upgrades.\2968\ NextEra contends
that, when an alternative transmission technology may serve as a
temporary solution, the transmission provider should reasonably
cooperate with requests from an interconnection customer willing to
fund installation of that technology as an interim solution.\2969\
Fervo Energy asks the Commission to require transmission providers to
consider alternative transmission technologies when responding to a
provisional interconnection request if these technologies allow for
earlier in-service dates.\2970\
---------------------------------------------------------------------------
\2968\ R Street Initial Comments at 16; Hannon Armstrong Initial
Comments at 2.
\2969\ NextEra Initial Comments at 38-39.
\2970\ Fervo Energy Reply Comments at 10.
---------------------------------------------------------------------------
1563. Others oppose requiring evaluation of alternative
transmission technologies for provisional interconnection
service.\2971\ For instance, MISO argues that the consideration of
advanced transmission technologies for provisional interconnection
service should not be mandatory because it may result in delays that
are contrary to the goals of this proceeding.\2972\
---------------------------------------------------------------------------
\2971\ Ameren Initial Comments at 32; MISO Initial Comments at
124.
\2972\ MISO Initial Comments at 124.
---------------------------------------------------------------------------
(4) Alternative Transmission Technologies for NRIS or ERIS
1564. Some commenters responded to whether the use of alternative
transmission technologies can support an interconnection customer's
request for NRIS, or whether the use of such technologies can only be
used if the interconnection customer requested ERIS. Hannon Armstrong
asserts that one or more of these alternative transmission technologies
may be able to delay or eliminate the needed network upgrades
identified in interconnection studies under both ERIS and NRIS.\2973\
MISO argues that technologies that merely curtail generation would not
be suitable for interconnection requests seeking NRIS as they could not
pass the deliverability test, while technologies that can control
transmission line impedances, such as phase shifters, are acceptable
for NRIS.\2974\ Invenergy contends that a given alternative
transmission technology may only facilitate ERIS service in certain
circumstances but that there is no reason to limit the scope of
alternative transmission technologies at the outset without having
performed any relevant analysis.\2975\ Clean Energy Associations ask
the Commission to require transmission providers to publicly post any
service differences (e.g., if use of a given technology would enable
ERIS but not necessarily NRIS).\2976\
---------------------------------------------------------------------------
\2973\ Hannon Armstrong Initial Comments at 2.
\2974\ MISO Initial Comments at 124.
\2975\ Invenergy Initial Comments at 53.
\2976\ Clean Energy Associations Initial Comments at 62.
---------------------------------------------------------------------------
(5) Study and Network Upgrade Cost Allocation for Alternative
Transmission Technologies
1565. Commenters address the Commission's question about how costs
incurred for evaluating alternative transmission technology study
requests would be allocated among interconnection customers in the
cluster. WATT Coalition argues that any marginal increase of study
costs to accommodate the evaluation of grid enhancing technologies
should be allocated evenly across interconnection customer cluster
study participants.\2977\ However, NARUC and Indicated PJM TOs
disagree, asserting that additional costs incurred for evaluating
alternative transmission technologies should be allocated to the
requesting interconnection customer(s) to maintain cost certainty and
equity.\2978\ Fervo Energy proposes that, if the requested alternative
transmission technology would benefit more than one interconnection
customer in the cluster, a pro rata allocation of study cost among
those interconnection customers would be appropriate; however, if the
requested technology only serves one interconnection customer, Fervo
Energy argues that direct cost allocation for that study cost is
appropriate.\2979\ Fervo Energy adds that it would support pro rata
allocation of costs even if the Commission mandates consideration of
alternative transmission technologies.\2980\
---------------------------------------------------------------------------
\2977\ WATT Coalition Initial Comments at 4.
\2978\ NARUC Initial Comments at 40; Indicated PJM TOs Reply
Comments at 17-18.
\2979\ Fervo Energy Initial Comments at 7.
\2980\ Fervo Energy Reply Comments at 10.
---------------------------------------------------------------------------
1566. NextEra argues that, under the ``but for'' principle of cost
allocation, the interconnection customer's cost responsibility should
be limited to the cost of the alternative transmission technology that
would have sufficed as a long-term solution for a given network
upgrade, especially when transmission providers choose instead to
construct more costly upgrades beyond what is
[[Page 61231]]
required for the interconnection customer's proposed generating
facility.\2981\ Tri-State instead argues that the Commission's proposal
does not consider the likely outcome of an interconnection request
advancing with a new technology, which will force the subsequent
interconnection customer to fund costly network upgrades when it would
be more equitable for the interconnection customers to share the cost
of a single network upgrade.\2982\
---------------------------------------------------------------------------
\2981\ NextEra Initial Comments at 38.
\2982\ Tri-State Initial Comments at 23.
---------------------------------------------------------------------------
(6) Timing of Alternative Transmission Technology Evaluation Requests
1567. Some commenters discuss limiting the request to include
alternative transmission technologies to the initial stages of the
interconnection process. ISO-NE and NESCOE argue that any alternatives
that are proposed should be included in the initial interconnection
request with specific assumptions that can be studied.\2983\
---------------------------------------------------------------------------
\2983\ ISO-NE Initial Comments at 41; NESCOE Reply Comments at
21.
---------------------------------------------------------------------------
1568. Other commenters argue that interconnection customers should
be able to request the study of alternative transmission technologies
later in the interconnection process or when more information is
available.\2984\ Clean Energy Associations contend that transmission
providers should be required to post the costs of requested
technologies and give interconnection customers the flexibility to
adopt appropriate solutions, subject to system conditions and any
limitations in the area.\2985\ [Oslash]rsted suggests that once cluster
studies are done, and if the required upgrades are outside of the
cluster area, then alternate transmission technologies, with the
addition of energy storage, should be evaluated by the transmission
provider during its system impact study phase.\2986\
---------------------------------------------------------------------------
\2984\ EDF Renewables Initial Comments at 14-15; Enel Initial
Comments at 79; Fervo Energy Reply Comments at 9; Invenergy Initial
Comments at 55; [Oslash]rsted Initial Comments at 9.
\2985\ Clean Energy Associations Initial Comments at 62.
\2986\ [Oslash]rsted Initial Comments at 9 (referencing
definition of ``alternative transmission technologies,'' NOPR, 179
FERC ] 61,194 at P 294 n.406).
---------------------------------------------------------------------------
1569. NARUC asks the Commission to ensure that there is an
opportunity for information exchange between the transmission provider
and interconnection customer to design alternative transmission
technology solutions and supports implementation of a time frame to
facilitate that information exchange.\2987\ Ohio Commission Consumer
Advocate contends that some changes would be required to address unique
attributes of grid enhancing technologies that may be overlooked by
existing frameworks and that the cost and duration of modeling and
evaluations would be best addressed by transmission providers in
concert with interconnection customers.\2988\
---------------------------------------------------------------------------
\2987\ NARUC Initial Comments at 40-41.
\2988\ Ohio Commission Consumer Advocate Initial Comments at 16.
---------------------------------------------------------------------------
(d) Requests for Clarification and Flexibility
1570. Ameren asks how software or operational barriers (such as
whether the MISO software can model the technology) will be
addressed.\2989\ Ameren asks for clarification as to who pays for the
software necessary to model the alternative transmission technology and
whether that gets assigned to the interconnection customer requesting
the use of the advanced transmission technology or to the cluster of
interconnection customers, some of which may prefer a different
solution that does not involve use of an advanced transmission
technology. Ameren claims that it is unclear what happens if
interconnection customers within the same cluster disagree about using
an alternative transmission technology in place of a network upgrade
and whether consensus is required.
---------------------------------------------------------------------------
\2989\ Ameren Initial Comments at 32.
---------------------------------------------------------------------------
1571. NARUC suggests that the Commission clarify that transmission
providers need not perform a separate study for each requested
alternative transmission technology.\2990\ NARUC also asks the
Commission to clarify that interconnection customers bear the burden of
designing the alternative transmission technology solutions, preparing
necessary technical data, and determining whether it is temporary or
permanent.
---------------------------------------------------------------------------
\2990\ NARUC Initial Comments at 40.
---------------------------------------------------------------------------
1572. NEPOOL urges the Commission to receive input from each RTO/
ISO to consider how much flexibility to provide with respect to the
list of alternative transmission technologies because they are the most
informed with respect to which alternative transmission technologies
are feasible.\2991\ Similarly, NYTOs ask the Commission to allow
regions to determine which alternative transmission technologies would
be appropriate and beneficial in performing interconnection studies
instead of mandating their use.\2992\
---------------------------------------------------------------------------
\2991\ NEPOOL Initial Comments at 17.
\2992\ NYTOs Initial Comments at 32-33.
---------------------------------------------------------------------------
1573. Some commenters underscore the importance of transmission
providers retaining the discretion to decline to adopt an alternative
transmission technology in the place of a network upgrade.\2993\
National Grid argues that, to the extent an interconnection customer
requests evaluation of a new alternative transmission technology beyond
the list proposed in the NOPR and provides studies in support of its
proposed use, the transmission owner should be permitted to determine
whether the evaluation of such a new technology will be
beneficial.\2994\ Indicated PJM TOs request that, if the final rule
requires transmission providers to consider alternative transmission
technologies, the transmission provider and transmission owners have
the ability to reject the request without a study when they have
knowledge or experience that the request will not work.\2995\
---------------------------------------------------------------------------
\2993\ Ameren Initial Comments at 31; APS Initial Comments at
23; Indicated PJM TOs Initial Comments at 57; National Grid Initial
Comments at 42; PacifiCorp Initial Comments at 43; Xcel Initial
Comments at 47.
\2994\ National Grid Initial Comments at 42.
\2995\ Indicated PJM TOs Reply Comments at 17.
---------------------------------------------------------------------------
(e) Miscellaneous
1574. Invenergy argues that, if an alternative transmission
technology is not selected, the transmission providers should provide
detailed reports, including a cost-benefit analysis, behind the
decision and there should be a process to resolve disagreements over
the decision with the interconnection customer.\2996\ R Street requests
that the Commission require transmission providers to describe the
benefits, or lack thereof, of the set of technologies listed in the
NOPR.\2997\ WATT Coalition and California Public Utilities Commissioner
Darcie Houck request that transmission providers abide by strict
standards when studying grid enhancing technologies.\2998\
---------------------------------------------------------------------------
\2996\ Invenergy Initial Comments at 54.
\2997\ R Street Initial Comments at 16.
\2998\ WATT Coalition Initial Comments at 3-4; Joint Fed.-State
Task Force on Elec. Transmission, Technical Conference, Docket No.
AD21-15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner
Darcie Houck) (July 16, 2023).
---------------------------------------------------------------------------
1575. In addition to the study of alternative transmission
technologies that the Commission envisions, [Oslash]rsted recommends
requiring the deployment of these alternative transmission technologies
as a medium-term or long-term alternative to transmission build
out.\2999\
---------------------------------------------------------------------------
\2999\ [Oslash]rsted Initial Comments at 16.
---------------------------------------------------------------------------
1576. EDF Renewables suggests that the Commission require the
consideration of alternative transmission technologies not only in
[[Page 61232]]
interconnection and transmission planning but also in market operations
upon an interconnection customer's request.\3000\
---------------------------------------------------------------------------
\3000\ EDF Renewables Initial Comments at 14-15.
---------------------------------------------------------------------------
1577. Enel claims that interconnection customer interconnection
facilities are underutilized and could be networked into the
transmission system to mitigate transmission constraints and to
increase system reliability.\3001\ Enel suggests that the Commission
add language to the pro forma LGIA that allows interconnection
facilities to convert to distribution facilities or regional
transmission facilities.
---------------------------------------------------------------------------
\3001\ Enel Initial Comments at 80-81.
---------------------------------------------------------------------------
iii. Commission Determination
1578. We adopt, with modifications, the proposed revisions to
section 7.3 of the pro forma LGIP, and sections 3.3.6 and 3.4.10 of the
pro forma SGIP. We modify the NOPR proposal to require transmission
providers to evaluate the following enumerated list of alternative
transmission technologies: static synchronous compensators, static VAR
compensators, advanced power flow control devices, transmission
switching, synchronous condensers, voltage source converters, advanced
conductors, and tower lifting. We modify proposed pro forma LGIP
section 7.3 to require transmission providers to evaluate the list of
alternative transmission technologies enumerated in this final rule
during the cluster study, including any restudies, of the generator
interconnection process in all instances (i.e., for all interconnection
customers in a cluster), without the need for a request from an
interconnection customer. We require transmission providers to evaluate
each alternative transmission technology listed in pro forma LGIP
section 7.3 and to determine, in the transmission provider's sole
discretion, whether it should be used, consistent with good utility
practice, applicable reliability standards, and other applicable
regulatory requirements. Finally, we require transmission providers to
include, in the pro forma LGIP cluster study report, an explanation of
the results of the evaluation of the enumerated alternative
transmission technologies for feasibility, cost, and time savings as an
alternative to a traditional network upgrade.
1579. We modify the enumerated list of alternative transmission
technologies from the NOPR proposal to: (1) retain synchronous, static
VAR compensators, advanced power flower control, and transmission
switching in the list; (2) add synchronous condensers, voltage source
converters, advanced conductors, and tower lifting to the list; and (3)
remove dynamic line ratings from the list. Generally, we find that
these enumerated alternative transmission technologies are those with
the most potential to be useful to reduce interconnection costs by
providing lower cost network upgrades to interconnect new generating
facilities and, thus, we require transmission providers to evaluate
these technologies in the interconnection process for their
feasibility, cost, and time savings potential.
1580. We also adopt, with modifications, the proposed revisions to
sections 3.3.6 and 3.4.10 of the pro forma SGIP. Consistent with the
pro forma LGIP requirement, we require transmission providers to
evaluate the enumerated alternative transmission technologies in all
instances, without the need for a request from an interconnection
customer. We modify the proposal to require such evaluations to occur
during the pro forma SGIP feasibility study and system impact study of
the generator interconnection process, as opposed to in the pro forma
SGIP system impact study and facilities study. We find that it is
appropriate to modify the proposal so that these evaluations occur
during the relevant pro forma SGIP studies where network upgrades are
identified, consistent with the pro forma LGIP requirement. We require
transmission providers to evaluate each alternative transmission
technology listed in pro forma SGIP sections 3.3.6 and 3.4.10 and
determine, in the transmission provider's sole discretion, whether it
should be used, consistent with good utility practice, applicable
reliability standards, and other applicable regulatory requirements.
1581. Finally, we require transmission providers to include, in the
feasibility study report and system impact study report, an explanation
of the results of the evaluation of the enumerated alternative
transmission technologies for feasibility, cost, and time savings as an
alternative to a traditional network upgrade. We note that this reform
is one of the few reforms in this final rule that applies to small
generating facilities, in addition to large generating facilities. As
described below, we find that the enumerated alternative transmission
technologies that we are requiring transmission providers to evaluate
in their interconnection studies are appropriate for evaluation in the
pro forma SGIP context because they are scalable, and we find that the
enumerated alternative transmission technologies have the potential to
provide similar benefits in the context of both small and large
generating facilities, including cost and time savings. As such, we
adopt, with modifications, the proposed revisions to require
transmission providers to evaluate the enumerated alternative
transmission technologies in all instances in both the pro forma LGIP
and pro forma SGIP.
1582. This final rule does not create a presumption in favor of
substituting alternative transmission technologies for necessary
traditional network upgrades, either categorically or in specific
cases.\3002\ This final rule is agnostic as to whether, in a specific
case, an alternative transmission technology is an acceptable
alternative to a traditional network upgrade,\3003\ ``that would allow
the interconnection customer to flow the output of its generating
facility onto the transmission provider's transmission system in a safe
and reliable manner.'' \3004\ The determination in each specific case
whether to require a traditional network upgrade or an alternative
transmission
[[Page 61233]]
technology is to be made by the transmission provider, and the
determination should be consistent with good utility practice,
applicable reliability standards, and other applicable regulatory
requirements.\3005\ This rule mandates a process of evaluation of
alternatives to traditional network upgrades, not outcomes in specific
cases.
---------------------------------------------------------------------------
\3002\ See PJM Initial Comments at 68 (``PJM therefore cautions
the Commission not to conflate the operational benefits of
alternative transmission technologies . . . with the need to address
significant capacity enhancement needs (short and long-term) or
long-range transmission needs under rapid growth or changing
resource mix scenarios.''); MISO Initial Comments at 120 (``However,
the Commission fails to recognize that these technologies may be
evaluated in the generator interconnection process already but may
nonetheless not be adopted as they are not the appropriate solution
to a Transmission Issue related to an interconnection.'').
\3003\ See MISO Initial Comments at 121-22 (``Further, although
these technologies may be evaluated, the technologies identified by
the Commission still may not provide the appropriate solution from a
planning perspective.[ ] Many of the technologies identified are
appropriately considered as operational tools or short-term
solutions but are not necessarily appropriate for planning to
support a particular generator interconnection.'').
\3004\ See Order No. 2003, 104 FERC ] 61,103 at P 767 (``Both
Energy Resource Interconnection Service and Network Resource
Interconnection Service provide for the construction of Network
Upgrades that would allow the Interconnection Customer to flow the
output of its Generating Facility onto the Transmission Provider's
Transmission System in a safe and reliable manner''); Order No.
2003-A, 106 FERC ] 61,220 at P 404; pro forma LGIA art. 9.3
(``Transmission Provider shall cause the Transmission System and the
Transmission Provider's Interconnection Facilities to be operated,
maintained and controlled in a safe and reliable manner and in
accordance with this LGIA''); Midwest Indep. Transmission Sys.
Operator, Inc., 138 FERC ] 61,233, at P 190 (2012), reh'g denied,
139 FERC ] 61,253 (2012), partial reh'g granted on other grounds,
150 FERC ] 61,035 (2015). See also pro forma LGIA art. 9.4
(``Interconnection Customer shall at its own expense operate,
maintain and control the Large Generating Facility and
Interconnection Customer's Interconnection Facilities in a safe and
reliable manner and in accordance with this LGIA'').
\3005\ See MISO Initial Comments at 123 (``Additionally, as
noted by the Commission in the proposed reform, although alternative
transmission technologies may be useful tools for operations,
relying on these tools for planning for interconnection may not be
consistent with `good utility practice' and `applicable regulatory
standards.' '').
---------------------------------------------------------------------------
1583. Based on the record, we affirm the Commission's preliminary
finding in the NOPR that alternative transmission technologies have the
potential to provide benefits to optimize the transmission system in
specific scenarios.\3006\ Specifically, a number of commenters argue
that selecting alternative transmission technologies as network
upgrades may reduce interconnection costs by providing lower cost
transmission solutions to interconnecting new generating facilities
\3007\ and may allow for a faster interconnection by providing
solutions that can be implemented more quickly.\3008\ Commenters also
point out that alternative transmission technologies allow for better
use of the existing transmission system,\3009\ can enhance
reliability,\3010\ and may reduce withdrawals, restudies, and overall
interconnection delays.\3011\ In addition, several commenters argue
that decreasing the costs of network upgrades will reduce the number of
withdrawals from interconnection queues, which will ultimately create a
more efficient interconnection process by reducing the number of
restudies triggered by withdrawals.\3012\ Furthermore, commenters argue
that alternative transmission technologies offer additional value
because they are scalable and modular to address evolving needs and can
be redeployed as those needs continue to change.\3013\ We find that
failing to evaluate the enumerated alternative transmission
technologies renders Commission-jurisdictional rates unjust and
unreasonable and fails to ensure that interconnection customers are
able to interconnect in a reliable, efficient, transparent, and timely
manner.\3014\
---------------------------------------------------------------------------
\3006\ NOPR, 179 FERC ] 61,194 at PP 294-295.
\3007\ AEE Initial Comments at 42; EDF Renewables Initial
Comments at 14; ENGIE Initial Comments at 12; OMS Initial Comments
at 19; [Oslash]rsted Initial Comments at 3; SEIA Initial Comments at
40.
\3008\ AEE Initial Comments at 42; OMS Initial Comments at 19;
[Oslash]rsted Initial Comments at 3; SEIA Initial Comments at 40.
\3009\ Illinois Commission Initial Comments at 14; Joint Fed.-
State Task Force on Elec. Transmission, Technical Conference, Docket
No. AD21-15-000, recording at 1:16:18-1:24:02 (approx.)
(Commissioner Darcie Houck) (July 16, 2023).
\3010\ AEE Initial Comments at 42; Ohio Commission Consumer
Advocate Initial Comments at 15; Joint Fed.-State Task Force on
Elec. Transmission, Technical Conference, Docket No. AD21-15-000,
recording at 1:16:18-1:24:02 (approx.) (Commissioner Darcie Houck)
(July 16, 2023).
\3011\ [Oslash]rsted Initial Comments at 3, 15-16; R Street
Initial Comments at 16; SEIA Initial Comments at 40; WATT Coalition
Initial Comments at 2.
\3012\ SEIA Initial Comments at 41; WATT Coalition Initial
Comments at 2.
\3013\ WATT Coalition Initial Comments at 2-3; WATT Coalition
Reply Comments at 5-6.
\3014\ NOPR, 179 FERC ] 61,194 at P 296; see Clean Energy
Associations Reply Comments at 9-10; Environmental Defense Fund
Initial Comments at 7; Fervo Reply Comments at 9; NARUC Initial
Comments at 38.
---------------------------------------------------------------------------
1584. However, as stated above,\3015\ this final rule mandates a
process of evaluation of alternative transmission technologies, not
outcomes in specific cases, and does not create a presumption in favor
of using an alternative transmission technology as a substitute for a
traditional network upgrade deemed necessary in a specific case.
Rather, under the approach adopted here, in all cases, the transmission
provider is required only to evaluate the use of alternative
transmission technologies as network upgrades consistent with good
utility practice, applicable reliability standards, and other
applicable regulatory requirements.\3016\ We recognize that, after the
transmission provider evaluates the enumerated alternative transmission
technologies, the transmission provider, in its sole discretion, may
still decide to remedy an identified reliability problem with a
traditional network upgrade.
---------------------------------------------------------------------------
\3015\ See supra P 1582.
\3016\ See MISO Initial Comments at 122-123.
---------------------------------------------------------------------------
1585. We modify the proposed requirement that transmission
providers evaluate the enumerated alternative transmission technologies
only at the request of the interconnection customer. Instead, we
require transmission providers to evaluate the enumerated alternative
transmission technologies in all instances, without a request from an
interconnection customer. We find that this approach both ensures that
the enumerated alternative transmission technologies are considered in
the interconnection process and avoids introducing additional
procedural complexity to the interconnection process. This approach,
which was suggested by many commenters,\3017\ will provide the benefits
of an evaluation of the enumerated alternative transmission
technologies more broadly and consistently and in a more efficient
manner. We believe that modifying the proposal addresses concerns
raised by commenters about the NOPR proposal.\3018\ More specifically,
evaluating alternative transmission technologies only by request, as
proposed in the NOPR, would create an overly complicated and time-
consuming process under which transmission providers evaluate each
alternative transmission technology for each interconnection request
individually. Commenters also raise concerns about the impact on costs
and timing for the entire cluster if only a portion of the cluster
requests evaluation of alternative transmission technologies or if
interconnection customers within the same cluster disagree about using
an alternative transmission technology.\3019\ Given these concerns, and
the potential for benefits to be gained by the evaluation and use, at
the transmission provider's sole discretion, of the enumerated
alternative transmission technologies, we find that it would be overly
burdensome and complex to require transmission providers to track and
process interconnection customer-specific study requests and to resolve
conflicts between interconnection customers' different study requests,
at the expense of those benefits.
---------------------------------------------------------------------------
\3017\ ACORE Initial Comments at 6; AEE Initial Comments at 42;
CAISO Initial Comments at 38; Amazon Initial Comments at 6; ELCON
Initial Comments at 11; Fervo Energy Reply Comments at 9; Hannon
Armstrong Initial Comments at 2; Invenergy Initial Comments at 52-
53; R Street Initial Comments at 16; Joint Fed.-State Task Force on
Elec. Transmission, Technical Conference, Docket No. AD21-15-000,
recording at 1:16:18-1:24:02 (approx.) (Commissioner Darcie Houck)
(July 16, 2023).
\3018\ Indicated PJM TOs Initial Comments at 55; MISO Initial
Comments at 11, 121; MISO TOs Initial Comments at 30; National Grid
Initial Comments at 42-43.
\3019\ CAISO Initial Comments at 38; Puget Sound Initial
Comments at 13; Ameren Initial Comments at 32.
---------------------------------------------------------------------------
1586. The record before us demonstrates that the requirements we
adopt today will not overly burden transmission providers.\3020\ We
find that requiring transmission providers to evaluate the enumerated
alternative transmission technologies in each interconnection study
will not be a significant additional burden on interconnection queues
for those transmission providers that already consider alternative
transmission technologies in their interconnection process.
Furthermore, we find that the benefits of evaluating and implementing
the enumerated alternative transmission technologies outweigh the
potential
[[Page 61234]]
burden or the potential of increased study times. As recognized by
commenters and explained above, the evaluation and use, at the
transmission provider's sole discretion, of the enumerated alternative
transmission technologies could decrease network upgrade costs,
withdrawals, and restudies, thereby increasing the efficiency of the
interconnection process overall. For these reasons, we disagree with
commenters that argue that requiring transmission providers to evaluate
the enumerated alternative transmission technologies is contrary to the
NOPR's goal of increasing the speed of interconnection queue
processing.
---------------------------------------------------------------------------
\3020\ AEE Initial Comments at 44; ENGIE Initial Comments at 13;
ACORE Reply Comments at 3-4.
---------------------------------------------------------------------------
1587. We find that, in conducting an evaluation of the enumerated
alternative transmission technologies, it is appropriate for
transmission providers to continue to retain discretion regarding
whether to use each enumerated alternative transmission technology,
consistent with the NOPR.\3021\ The requirement is to evaluate the
enumerated alternative transmission technologies in the interconnection
process for feasibility, cost, and time savings and to determine
whether, in the transmission provider's sole discretion, an alternative
transmission technology should be used as a solution--consistent with
good utility practice, applicable reliability standards, and other
applicable regulatory requirements.\3022\ The transmission provider
must determine whether using any of the enumerated alternative
transmission technologies is an appropriate and reliable network
upgrade ``that would allow the interconnection customer to flow the
output of its generating facility onto the transmission provider's
transmission system in a safe and reliable manner.'' \3023\ The
requirement to make such a determination before allowing for the use of
the enumerated alternative transmission technologies addresses concerns
that their use may impinge on reliability, delay network upgrades
instead of reducing the need for them or obviating the need for them
altogether, or fail to address all transmission system issues that a
traditional network upgrade would address. We recognize the need to
avoid time-consuming delays and costly disputes or litigation over
interconnection costs that could arise as a result of this
reform.\3024\ Therefore, we find that, if a transmission provider
evaluates the enumerated alternative transmission technologies as
required herein and, in its sole discretion, determines not to use any
enumerated alternative transmission technologies as an alternative to a
traditional network upgrade, the transmission provider has complied
with this final rule, including tariffs filed pursuant to this final
rule.
---------------------------------------------------------------------------
\3021\ NOPR, 179 FERC ] 61,194 at P 299.
\3022\ See MISO Initial Comments at 122-123 (``Additionally, as
noted by the Commission in the proposed reform, although alternative
transmission technologies may be useful tools for operations,
relying on these tools for planning for interconnection may not be
consistent with `good utility practice' and `applicable regulatory
standards.' '').
\3023\ See Order No. 2003, 104 FERC ] 61,103 at P 767 (``Both
Energy Resource Interconnection Service and Network Resource
Interconnection Service provide for the construction of Network
Upgrades that would allow the Interconnection Customer to flow the
output of its Generating Facility onto the Transmission Provider's
Transmission System in a safe and reliable manner''); Order No.
2003-A, 106 FERC ] 61,220 at P 404; pro forma LGIA art. 9.3
(``Transmission Provider shall cause the Transmission System and the
Transmission Provider's Interconnection Facilities to be operated,
maintained and controlled in a safe and reliable manner and in
accordance with this LGIA''); Midwest Indep. Transmission Sys.
Operator, Inc., 138 FERC ] 61,233, at P 190 (2012), reh'g denied,
139 FERC ] 61,253 (2012), partial reh'g granted on other grounds,
150 FERC ] 61,035 (2015). See also pro forma LGIA art. 9.4
(``Interconnection Customer shall at its own expense operate,
maintain and control the Large Generating Facility and
Interconnection Customer's Interconnection Facilities in a safe and
reliable manner and in accordance with this LGIA'').
\3024\ See SPP Initial Comments at 26 (``Even though the
Commission has stated that transmission providers retain the
discretion regarding whether to use such technologies, the very fact
that the transmission provider is required to evaluate them will
lead to disputes if the transmission provider then exercises that
discretion.'').
---------------------------------------------------------------------------
1588. Because we modify the NOPR proposal and require transmission
providers to evaluate the enumerated alternative transmission
technologies in all instances, we find that the final rule will not
``effectively require a whole additional set of studies for large areas
of the transmission system'' or exponentially increase the number of
studies needed to consider the various combinations, as Indicated PJM
TOs argue could occur under the NOPR proposal.\3025\ This is because
transmission providers will not be evaluating the enumerated
alternative transmission technologies for a subset of interconnection
customers within a cluster--but rather for the entire cluster.
---------------------------------------------------------------------------
\3025\ Indicated PJM TOs Initial Comments at 55.
---------------------------------------------------------------------------
1589. Regarding WATT Coalition and California Public Utility
Commissioner Darcie Houck's request that transmission providers abide
by strict standards when studying alternative transmission
technologies,\3026\ we decline to adopt any such standards in the pro
forma LGIP and pro forma SGIP governing the evaluation of alternative
transmission technologies. We find that it is appropriate to continue
to rely on transmission providers to use good utility practice,
applicable reliability standards, and other applicable regulatory
requirements, in their evaluations of alternative transmission
technologies, including the enumerated list, because the specific
evaluation may depend on the transmission provider's individual
transmission system, cluster makeup, and other factors. Similarly,
regarding National Grid's concern that studying every potential
alternative transmission technology for every interconnection request
could cause transmission providers to be penalized for not meeting
study deadlines,\3027\ the final rule does not require the study of all
technologies considered alternative transmission technologies but
rather the evaluation of the enumerated alternative transmission
technologies. Further, we find that the transmission provider--
consistent with good utility practice, applicable reliability
standards, and other applicable regulatory requirements--retains the
sole discretion to determine whether a particular technology in the
enumerated list of alternative transmission technologies is appropriate
and reliable as a network upgrade, or not, for a given cluster.
---------------------------------------------------------------------------
\3026\ WATT Coalition Initial Comments at 3-4; Joint Fed.-State
Task Force on Elec. Transmission, Technical Conference, Docket No.
AD21-15-000, recording at 1:16:18-1:24:02 (approx.) (Commissioner
Darcie Houck) (July 16, 2023).
\3027\ National Grid Initial Comments at 42-43.
---------------------------------------------------------------------------
1590. We also believe that the requirement that transmission
providers evaluate the enumerated alternative transmission technologies
for an entire cluster--rather than on an individual interconnection
customer-request basis--and the modifications to the enumerated list of
alternative transmission technologies (as discussed below) will ease
the burden on transmission providers, thereby lessening the risk that
they are unable to complete studies by the required deadlines. We note
that we are not dictating how a transmission provider must evaluate
each enumerated alternative transmission technology on the list in each
instance; we recognize that in some cases transmission providers may be
able to rapidly determine if a certain enumerated alternative
transmission technology is inappropriate for further study. In response
to Invenergy's request that transmission providers should provide
detailed evaluation reports on why an alternative transmission
technology was not selected, transmission providers are required to
include an explanation of the results of the evaluation of the required
alternative transmission
[[Page 61235]]
technologies for feasibility, cost, and time savings as an alternative
to a traditional network upgrade in the applicable study report.
However, we do not direct any additional detailed requirements related
to this reporting requirement because we find they are not needed or
appropriate. We find the required explanation of the results of the
transmission provider's evaluation included in the applicable study
report provides sufficient transparency without placing a further
burden on transmission providers that would delay the processing of
interconnection requests.
1591. Because we modify the NOPR proposal to require transmission
providers to evaluate all the enumerated alternative transmission
technologies in all instances, i.e., regardless of an interconnection
customer requesting such an evaluation, we decline to adopt commenters'
request to require transmission providers to evaluate the required
alternative transmission technologies by default with an ``opt-out''
option for interconnection customers. We are not persuaded that there
are benefits to including an ``opt-out'' option in the requirement, and
we find it would be overly burdensome and complex to require
transmission providers to track and process interconnection customers'
requests to ``opt-out'' of the evaluation of certain alternative
transmission technologies. Further, an ``opt-out'' would run contrary
to our goal to have transmission providers evaluate the enumerated
technologies in order to achieve beneficial outcomes like decreasing
network upgrade costs, withdrawals, and restudies, thereby increasing
the efficiency of the interconnection process overall.
1592. As discussed above, the enumerated alternative transmission
technologies that transmission providers must evaluate in
interconnection studies are: static synchronous compensators, static
VAR compensators, synchronous condensers, advanced power flow control,
transmission switching, voltage source converters, advanced conductors,
and tower lifting. We discuss each technology in turn.
1593. Regarding synchronous and static VAR compensators, we find
that, in providing reactive power to the transmission system, such
devices could reduce interconnection costs by providing the voltage
support where needed for the new generation facility being
interconnected to operate reliably, rather than building a traditional
network upgrade to resolve the voltage support issues. This potentially
results in lower cost network upgrades to interconnect new generating
facilities. ISO-NE states that it already evaluates static synchronous
compensators when evaluating interconnection requests.\3028\ Similarly,
as Indicated PJM TOs attest, PJM already considers static synchronous
compensators in its interconnection and transmission planning
processes.\3029\ Accordingly, we find that synchronous and static VAR
compensators are appropriately included in the list of alternative
transmission technologies enumerated in this final rule that
transmission providers must evaluate in the interconnection process.
---------------------------------------------------------------------------
\3028\ ISO-NE Initial Comments at 41.
\3029\ Indicated PJM TOs Initial Comments at 57.
---------------------------------------------------------------------------
1594. Regarding advanced power flow controls, we find that these
devices allow power to be pushed and pulled to alternate lines with
spare capacity leading to maximum utilization of transmission capacity
and mitigation of overloads. Advanced power flow control devices can be
scaled back as needed, providing an advantage over new lines or
reconductors.\3030\ PacifiCorp attests that it often considers the use
of advanced power flow control devices as potential alternatives to
standard system infrastructure, and Indicated PJM TOs note that PJM and
PJM transmission owners already consider the appropriateness of power
flow control devices when conducting interconnection studies.\3031\ As
discussed above, our decision to modify the NOPR proposal and require
transmission providers to evaluate the enumerated alternative
transmission technologies in all instances addresses Indicated PJM TOs'
statement that evaluation of advanced power flow control devices in the
interconnection process would significantly increase the complexity of
interconnection studies and thus could cause delays in their
completion.\3032\ We acknowledge the possibility that use of advanced
power flow control devices can have impacts on line impedance which may
result in issues in other parts of the system, as suggested by MISO.
However, the requirement of this Final rule is merely that the
transmission provider evaluate each alternative transmission
technology, not that they deploy them in all circumstances. We
appreciate, and expect, that if a transmission provider's evaluation
demonstrates that deployment of advanced power flow control devices
would create issues on the transmission provider's system as described
by MISO, it will not select that advanced power flow control as the
network upgrade.\3033\
---------------------------------------------------------------------------
\3030\ AEE Initial Comments at 42.
\3031\ PacifiCorp Initial Comments at 43; Indicated PJM TOs at
57.
\3032\ Supra P 1585.
\3033\ See also infra P 1602.
---------------------------------------------------------------------------
1595. We also retain transmission switching on the enumerated list
of alternative technologies in this final rule. Transmission switching
can be used to route energy around areas with high congestion and
improve the overall transfer capability of the system, potentially
resulting in lower network upgrade costs. In regard to PacifiCorp's
argument that transmission switching is a complex process that can be
implemented only under very particular factual scenarios and system
conditions, transmission providers are already required to evaluate the
impact of the proposed interconnection on the reliability of the
transmission system \3034\ and thus should understand whether the
factual scenarios and system conditions exist that would make a
transmission switching solution appropriate. In response to Tri-State's
question about whether transmission switching is meant to be a remedial
action scheme or to create permanent normally open points on the
system, this final rule does not prescribe how transmission providers
deploy any of the enumerated alternative transmission technologies on
their systems if they determine to use them. To Tri-State's concern
that transmission switching solutions may be ``problematic in highly
interconnected systems not operating in an RTO/ISO,'' we reiterate that
transmission providers retain the discretion to determine whether to
deploy any of the enumerated alternative transmission technologies,
including transmission switching solutions.
---------------------------------------------------------------------------
\3034\ See pro forma LGIP section 7.3; pro forma SGIP sections
3.3.1, 3.4.1.
---------------------------------------------------------------------------
1596. We find that the record supports including synchronous
condensers and voltage source converters to the list because these
technologies similarly may reduce interconnection costs in situations
where voltage support is a constraint and where a new or modified
transmission line with these technologies may provide a lower cost
network upgrade option to interconnect new generating facilities.
Specifically, ISO-NE states that it already evaluates synchronous
condensers when evaluating interconnection requests,\3035\ and NARUC
and Xcel urge the Commission to include evaluation of synchronous
condensers and voltage
[[Page 61236]]
source converters in the interconnection process.\3036\
---------------------------------------------------------------------------
\3035\ ISO-NE Initial Comments at 41.
\3036\ NARUC Initial Comments at 39; Xcel Initial Comments at
47.
---------------------------------------------------------------------------
1597. We also add advanced conductors and tower lifting to the list
of alternative transmission technologies enumerated in this final rule.
We note the comments arguing that advanced conductors may be beneficial
as network upgrades.\3037\ ACORE explains that deploying advanced
conductors can significantly increase transmission capacity and allow
for the interconnection of new generating facilities without the
construction of new network upgrades.\3038\ Similarly, we find that
tower lifting has the potential to increase transmission line ratings
by providing additional clearance from the ground.\3039\ By increasing
transmission line ratings, there will be more ``headroom'' on the
system to address normal and contingency conditions identified in
interconnection studies, and likely a reduced need for network
upgrades.\3040\ Given these potential benefits to interconnection
customers, we require transmission providers to evaluate advanced
conductors and tower lifting in the interconnection process.
---------------------------------------------------------------------------
\3037\ ACORE Initial Comments at 6-7; CTC Global Initial
Comments at 6-9; VEIR Initial Comments at 5-6.
\3038\ ACORE Initial Comments at 7 (citing Jay Caspary and Jesse
Schneider, Grid Strategies, LLC, Opportunities to Use Advanced
Conductors to Accelerate Grid Decarbonization, at 2 (Feb. 2022),
https://acore.org/wp-content/uploads/2022/03/AdvancedConductorstoAccelerateGridDecarbonization.pdf).
\3039\ See Ampjack Initial Comments at 4. As with other network
upgrades, we note that tower lifting may require a modification to a
certificate of public convenience and necessity (CPCN) or similar
permit issued by a state utility regulator, which may include tower
height limits or other physical restrictions. To the extent the
transmission provider considers potential delays or the possibility
of not receiving such a state CPCN modification when evaluating
potential network upgrades, it should include a similar
consideration in its evaluation of alternative transmission
technologies.
\3040\ See id. at 1, 4.
---------------------------------------------------------------------------
1598. We remove dynamic line ratings from the list of enumerated
alternative transmission technologies proposed in the NOPR. We agree
with commenters that the technology may be less beneficial in the
interconnection context than in the transmission operations and
planning context because, for example, dynamic line ratings' ability to
increase the available interconnection service depends on favorable
weather and congestion parameters.\3041\ That is, while dynamic line
ratings may relieve congestion to increase available interconnection
service temporarily or in the short-term, they may not be an adequate
substitute for building interconnection facilities and/or traditional
network upgrades identified through the interconnection study process
that are needed to reliably interconnect a generating facility to the
transmission system during all hours.
---------------------------------------------------------------------------
\3041\ Indicated PJM TOs Initial Comments at 56; ISO-NE Initial
Comments at 41; NYTOs Initial Comments at 32-33; PacifiCorp Initial
Comments at 44; Tri-State Initial Comments at 23; U.S. Chamber of
Commerce Initial Comments at 12-13.
---------------------------------------------------------------------------
1599. We decline to add storage that performs a transmission
function to the list of alternative transmission technologies
enumerated in this final rule. The Commission has determined that the
evaluation of whether a storage resource performs a transmission
function requires a case-by-case analysis of either how a particular
storage resource would be operated or the requirements set forth in a
tariff governing selection of such storage resources. For example, in
approving SPP's proposal to establish a framework under which an
electric storage resource may be considered a transmission asset
(thereby making the selected storage resources eligible for cost-based
rate recovery through transmission rates), the Commission identified
five considerations that, together, ensure that a selected storage
resource will serve a transmission function.\3042\
---------------------------------------------------------------------------
\3042\ Sw. Power Pool, Inc., 183 FERC ] 61,153, at P 29 (2023).
---------------------------------------------------------------------------
1600. We clarify that transmission providers are not precluded from
studying a technology that is not included in the enumerated list of
alternative transmission technologies. Under the modified requirement,
transmission providers must evaluate the enumerated alternative
transmission technologies in all instances, but we are not precluding a
transmission provider from studying or evaluating any other technology,
including those such as dynamic line ratings that we have determined
not to add to the list of technologies enumerated in this final rule.
We acknowledge that certain transmission providers already evaluate in
certain studies transmission technologies not included in the final
rule list.\3043\ In addition, we clarify that, with respect to this
final rule determination, transmission providers are not required to
propose and justify on compliance any technology it studies in the
interconnection process beyond those required in this final rule.
---------------------------------------------------------------------------
\3043\ For example, PacifiCorp notes that it already considers
advanced power flow technologies as potential alternatives to
standard system infrastructure. PacifiCorp Initial Comments at 43.
---------------------------------------------------------------------------
1601. In the NOPR, the Commission generally proposed a method to
allocate the costs of cluster studies and the costs of network upgrades
within a cluster through the interconnection study process.\3044\ With
respect to study costs, the Commission sought comment on how costs
incurred for evaluating alternative transmission technology study
requests would be allocated among interconnection customers in the
cluster under a NOPR proposal in which interconnection customers would
identify and request particular technologies to be studied.\3045\ Given
our modification to the NOPR proposal to require transmission providers
to evaluate the enumerated alternative transmission technologies in the
pro forma LGIP cluster study on behalf of the whole cluster, rather
than upon an individual customer's request, we find that it is not
necessary to consider alternative cost allocation methods for cluster
study costs and network upgrade costs associated with the enumerated
alternative transmission technologies. Specifically, we clarify that
the allocation of cluster study costs for, and substation and system
network upgrades associated with, the enumerated alternative
transmission technologies must be consistent with the allocation of
costs for cluster studies and associated substation and system network
upgrades for any other network upgrades because the enumerated
alternative transmission technologies located on the high-side of the
point of interconnection would fall within the definition of substation
and system network upgrades,\3046\ and they would be adopted only if
they resolve system reliability issues triggered by an interconnection
request. In other words, the enumerated alternative transmission
technologies must be included among the set of options transmission
providers consider when studying a cluster and any implemented
enumerated alternative transmission technologies must receive the same
cost treatment as any other option.
---------------------------------------------------------------------------
\3044\ See NOPR, 179 FERC ] 61,194 at PP 82-83, 88-89.
\3045\ Id. P 301.
\3046\ Network Upgrades are ``the additions, modifications, and
upgrades to the Transmission Provider's Transmission System required
at or beyond the point at which the Interconnection Facilities
connect to the Transmission Provider's Transmission System to
accommodate the interconnection of the Large Generating Facility to
the Transmission Provider's Transmission System.'' Pro forma LGIP
section 1 (Definitions).
---------------------------------------------------------------------------
1602. Accordingly, the cost allocation concerns raised by several
commenters in response to the NOPR proposal are now unfounded.\3047\
Regarding MISO's concern that some alternative transmission
technologies may shift the burden of system impacts to other
[[Page 61237]]
parties,\3048\ we find that the possibility of this burden shifting is
minimal because the revised pro forma LGIP, as adopted in this final
rule, requires transmission providers to evaluate the enumerated
alternative transmission technologies on a cluster-wide basis for
feasibility, cost, and time savings. We recognize that, after the
transmission provider evaluates the enumerated alternative transmission
technologies, the transmission provider, in its sole discretion, may
still decide to remedy an identified reliability problem with a
traditional network upgrade.
---------------------------------------------------------------------------
\3047\ AEP Initial Comments at 52-53; Ameren Initial Comments at
32; NextEra Initial Comments at 38; and Tri-State Initial Comments
at 23.
\3048\ MISO Initial Comments at 122.
---------------------------------------------------------------------------
1603. Regarding cost treatment for the enumerated alternative
transmission technologies in the pro forma SGIP, the Commission did not
propose to require, and this final rule does not adopt, cluster studies
for small generator interconnection requests. Accordingly, the study
process for small generating facilities in the pro forma SGIP remains a
serial process and costs for evaluating the enumerated alternative
transmission technologies must be allocated to the small generator
interconnection request being studied. Likewise, the costs for any
implemented enumerated alternative transmission technologies must be
allocated to a small generator interconnection customer consistent with
the allocation of any other network upgrade costs in the small
generator interconnection process.
1604. As explained in section III.A.3 of this final rule, we are
not requiring transmission providers to allocate study costs on a pro
rata basis, as Fervo Energy requests. Because this final rule does not
adopt the NOPR proposal for interconnection customers to request the
study of particular technologies, we need not address the arguments
raised by NARUC and Indicated PJM TOs related to the study costs
associated with that unadopted proposal.
1605. The Commission sought comment on whether transmission
providers should be required to evaluate whether alternative
transmission technologies can be deployed on a temporary basis to
provide provisional interconnection service. We are not persuaded by
arguments in favor of such a requirement. While we acknowledge
commenters' arguments that alternative transmission technologies could
serve as a temporary solution to reduce the overall costs and delays of
generator interconnection, we agree with MISO that mandatory evaluation
of alternative transmission technologies for provisional
interconnection service could hinder ensuring that interconnection
customers are able to interconnect in a reliable, efficient,
transparent, and timely manner by adding burden and delay.\3049\
---------------------------------------------------------------------------
\3049\ MISO Initial Comments at 124.
---------------------------------------------------------------------------
1606. The Commission also sought comment on whether alternative
transmission technologies as supplements for, or in the place of,
traditional network upgrades was sufficient to guarantee a level of
service to accommodate an interconnection customer seeking NRIS, or
whether such a network upgrade could only relate to ERIS.\3050\ We
agree with commenters that the enumerated alternative transmission
technologies may enable NRIS, but such a determination will be
dependent on the analysis by the particular transmission provider and
the particular technology under evaluation. We decline to adopt Clean
Energy Association's proposal that transmission providers be required
to post additional information beyond the explanation of the results of
the evaluation of each alternative transmission technology. As
discussed above, transmission providers must include, in the applicable
study report, an explanation of the results of the evaluation of the
enumerated alternative transmission technologies for feasibility, cost,
and time savings.
---------------------------------------------------------------------------
\3050\ NOPR, 179 FERC ] 61,194 at P 301.
---------------------------------------------------------------------------
1607. We find that the following commenters' proposals are outside
the scope of this proceeding and, therefore, we do not address the
substance: (1) requiring transmission providers to consider alternative
transmission technologies in market operations at the request of the
interconnection customer; \3051\ (2) adding language to the pro forma
LGIA that would allow interconnection facilities to convert to
distribution or regional transmission facilities; \3052\ and (3)
requiring transmission providers to study and implement advanced
transmission technologies when network upgrades are needed but cannot
be completed within three years of being identified.\3053\
---------------------------------------------------------------------------
\3051\ EDF Renewables Initial Comments at 14-15.
\3052\ Enel Initial Comments at 80-81.
\3053\ [Oslash]rsted Reply Comments at 8.
---------------------------------------------------------------------------
1608. Because we adopt a requirement for transmission providers to
evaluate the enumerated alternative transmission technologies, rather
than at the request of the interconnection customer, we do not address
comments regarding the following issues, which become moot by this
modification to the NOPR proposal: the timing of submission of the
alternative transmission technology evaluation request; \3054\ the
burden of proof for a submission of an alternative transmission
technology evaluation request; \3055\ whether there should be a limit
on alternative transmission technology evaluation requests; \3056\
whether transmission providers and transmission owners should be able
to reject alternative transmission technology evaluation requests;
\3057\ whether an interconnection customer can request evaluation of an
alternative transmission technology not on the required list; \3058\
and whether transmission providers need to perform a separate study for
each requested alternative transmission technology.\3059\
---------------------------------------------------------------------------
\3054\ Enel Initial Comments at 79; Invenergy Initial Comments
at 55; see also EDF Renewables Initial Comments at 14-15; Fervo
Energy Reply Comments at 9.
\3055\ AECI Initial Comments at 9; NARUC Initial Comments at 40;
ISO-NE Initial Comments at 41; NESCOE Reply Comments at 21.
\3056\ EEI Initial Comments at 21.
\3057\ Indicated PJM TOs Reply Comments at 17.
\3058\ National Grid Initial Comments at 42.
\3059\ NARUC Initial Comments at 40.
---------------------------------------------------------------------------
1609. We do not find compelling commenters' request that the
Commission not require the evaluation of alternative transmission
technologies while other proceedings concerning grid enhancing
technologies are pending.\3060\ The Commission proposed and received
extensive comment on evaluation of alternative transmission
technologies in the interconnection process. Based on the record, we
find that it is appropriate for the Commission to adopt a modified NOPR
proposal to require transmission providers to evaluate the required
list of enumerated alternative transmission technologies.
---------------------------------------------------------------------------
\3060\ EEI Initial Comments at 20; see also Ameren Initial
Comments at 30.
---------------------------------------------------------------------------
b. Annual Informational Report
i. NOPR Proposal
1610. In the NOPR, in order to add transparency to the evaluation
process and deployment of alternative transmission technologies in
generator interconnection processes, the Commission proposed to revise
the pro forma LGIP and pro forma SGIP to require transmission providers
to submit an annual informational report to the Commission that details
whether, and if so how, advanced power flow control, transmission
switching, dynamic line ratings, static synchronous compensators, and
static VAR compensators were considered in interconnection requests
over the last year.\3061\ The Commission proposed to create a new
docket to collect all annual informational report filings, and proposed
that any informational reports that transmission providers file at the
Commission would be for informational
[[Page 61238]]
purposes and would neither be formally noticed nor require additional
action by the Commission. The Commission sought comment on: (1) whether
to require transmission providers to explain why an alternative
transmission technology that was considered was not deployed; and (2)
the scope of the annual informational report, and whether additional
information should be included.
---------------------------------------------------------------------------
\3061\ NOPR, 179 FERC ] 61,194 at P 302.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1611. A broad group of commenters support the NOPR proposal.\3062\
Many commenters agree that the reports would be beneficial to
interconnection customers because they would provide insight as to why
alternative transmission technologies were or were not deployed.\3063\
Some commenters contend that the annual informational report will allow
interconnection customers to better tailor their requests to consider
alternative transmission technologies, such that those requests are
most likely to be successful.\3064\ Similarly, commenters argue that
the annual informational reports would allow sharing of best practices
in the industry on the use of these technologies and their evaluation,
and would lessen concerns over the potential risks of new technologies
by socializing examples of their consideration and
implementation.\3065\ ELCON and Fervo Energy assert that the annual
informational reports will provide interconnection customers with
additional information to ascertain the feasibility of certain
configurations and interconnection points.\3066\
---------------------------------------------------------------------------
\3062\ APPA-LPPC Initial Comments at 32; Clean Energy Buyers
Initial Comments at 5; ELCON Initial Comments at 8; Enel Initial
Comments at 81; Eversource Initial Comments at 37-38; CTC Global
Initial Comments at 13; NARUC Initial Comments at 41; Pine Gate
Initial Comments at 59; Public Interest Organizations Initial
Comments at 55; SEIA Initial Comments at 41; WATT Coalition Initial
Comments at 3.
\3063\ NARUC Initial Comments at 41; Pine Gate Initial Comments
at 59.
\3064\ Pine Gate Initial Comments at 59.
\3065\ CTC Global Initial Comments at 13; Eversource Initial
Comments at 37-38.
\3066\ ELCON Initial Comments at 8; Fervo Energy Reply Comments
at 9-10.
---------------------------------------------------------------------------
1612. Additionally, Enel states that transmission providers can be
resistant to using advanced transmission technologies, and the annual
informational report will allow the Commission to evaluate whether a
transmission provider is artificially restricting the use of advanced
transmission technologies, similar to the study completion metrics
required by the Commission in Order No. 845.\3067\ Some commenters
argue that if the Commission observes that transmission providers are
routinely citing certain technical or other reasons for not deploying
certain technologies, the annual informational report will provide a
record from which it can initiate action in a separate proceeding to
remedy the issue.\3068\
---------------------------------------------------------------------------
\3067\ Enel Initial Comments at 81.
\3068\ CTC Global Initial Comments at 13; Pine Gate Initial
Comments at 59.
---------------------------------------------------------------------------
1613. Several commenters argue in support of the annual
informational report to promote transparency between market
participants, interconnection customers, and regulators.\3069\ Lastly,
commenters argue that the additional work and obligation for the annual
informational report would be an effective use of limited resources to
benefit the efficiency, transparency, and modernization of the
interconnection process.\3070\
---------------------------------------------------------------------------
\3069\ Eversource Initial Comments at 37-38; NARUC Initial
Comments at 41.
\3070\ Enel Initial Comments at 81; Eversource Initial Comments
at 37-38.
---------------------------------------------------------------------------
(b) Comments in Opposition
1614. Some commenters oppose the proposal on the basis that it
would be too burdensome.\3071\ Xcel Energy does not believe annual
informational reports are necessary and requests that any informational
reporting requirements be limited to decrease the burden on the
engineers that need to focus on performing the interconnection
studies.\3072\ PacifiCorp states that imposing an additional reporting
obligation on transmission providers would not only be duplicative, but
it would add to an already significant list of administrative tasks
that transmission providers must undertake to comply with existing, and
proposed, interconnection obligations, without clear benefit.\3073\
NYTOs believe that preparing and submitting an annual informational
report with detailed analysis of the consideration of alternative
transmission technologies would require dedicated resources on the part
of the transmission provider.\3074\ MISO asserts that the annual
informational report at this time may not be useful, especially in the
already transparent RTO/ISO context, and could divert scarce staff
resources from the work of moving forward in the study and agreements
process for implementing much-needed new generation.\3075\ Similarly,
Indicated PJM TOs state that PJM currently maintains a publicly
available website that details all the types of network upgrades
necessary to support interconnections, including the types of devices
identified here by the Commission.\3076\ CAISO also opposes the
proposal because CAISO believes that it is contrary to the goal of
reducing interconnection queue backlogs by adding more studies and
reporting requirements onto transmission provider staff.\3077\
---------------------------------------------------------------------------
\3071\ Ameren Initial Comments at 33; CAISO Initial Comments at
39; MISO Initial Comments at 125; NYTOs Initial Comments at 33;
PacifiCorp Initial Comments at 44; Xcel Initial Comments at 48.
\3072\ Xcel Initial Comments at 48.
\3073\ PacifiCorp Initial Comments at 44.
\3074\ NYTOs Initial Comments at 33.
\3075\ MISO Initial Comments at 125; MISO Reply Comments at 18.
\3076\ Indicated PJM TOs Initial Comments at 57-58.
\3077\ CAISO Initial Comments at 38.
---------------------------------------------------------------------------
1615. Idaho Power believes that the report may simply result in
more disputes over why one entity allows a particular technology, while
another one does not.\3078\
---------------------------------------------------------------------------
\3078\ Idaho Power Initial Comments at 16.
---------------------------------------------------------------------------
1616. CAISO and MISO also argue that there is limited value to
interconnection reports.\3079\ CAISO argues that in this NOPR, the
Commission recognizes that imposing reporting requirements in Order No.
845 failed to incentivize transmission providers to meet their study
obligations, and thus the Commission should not repeat that mistake
here by burdening transmission provider staff with yet another
reporting requirement.\3080\ Similarly, MISO points out that neither
the Commission nor any commenter used the interconnection queue reports
required by Order No. 845 to discuss the topic of study delays.\3081\
---------------------------------------------------------------------------
\3079\ CAISO Initial Comments at 39; MISO Reply Comments at 18-
19.
\3080\ CAISO Initial Comments at 39.
\3081\ MISO Reply Comments at 18-19.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
1617. Several commenters emphasize the importance of transparency
when an alternative transmission technology is not selected.\3082\
ENGIE asks the Commission to require transmission providers to provide
publicly available information addressing why or why not an alternative
transmission technology was adopted or rejected in a specific
case.\3083\ CTC Global believes that transmission providers should be
required to include explanations regarding the alternative transmission
technologies considered, deployed, or rejected in the annual
reports.\3084\ CTC
[[Page 61239]]
Global requests that the Commission also mandate reporting on the
energy efficiency of the components used in various network upgrades
and through the interconnection process.\3085\ Eversource suggests
that, in addition to the five technologies listed in the NOPR,
transmission providers be allowed to provide reporting on any other
grid enhancing technology or alternative transmission technology that
was considered during the prior year.\3086\
---------------------------------------------------------------------------
\3082\ CTC Global Initial Comments at 14, 17-18; ENGIE Initial
Comments at 13; Eversource Initial Comments at 37-38; Fervo Energy
Initial Comments at 7.
\3083\ ENGIE Initial Comments at 13.
\3084\ CTC Global Initial Comments at 17-18.
\3085\ Id. at 14.
\3086\ Eversource Initial Comments at 37-38.
---------------------------------------------------------------------------
1618. In contrast, Ameren argues that, if the Commission imposes
this reporting burden on transmission providers, it should not further
exacerbate the burden by requiring the transmission provider to also
report explanations of common obstacles to the use of these alternative
transmission technologies.\3087\ Instead, Ameren states that the
Commission should encourage interconnection customers and transmission
providers to share with Commission staff through a technical conference
or other forum the types of technologies being considered and whether
adopted. Ameren suggests that this type of information gathering should
be undertaken before the Commission imposes specific reforms or
reporting requirements.
---------------------------------------------------------------------------
\3087\ Ameren Initial Comments at 33.
---------------------------------------------------------------------------
iii. Commission Determination
1619. We decline to adopt the NOPR proposal to require transmission
providers to submit an annual informational report to the Commission
that details whether, and if so how, the list of alternative
transmission technologies were considered in interconnection studies
over the last year. We are persuaded by commenters' arguments that the
time and resources required to produce the annual informational report
may hinder the ability to increase the speed of interconnection queue
processing.\3088\ We find that these challenges outweigh the
incremental increased transparency to the evaluation process and
deployment of alternative transmission technologies in generator
interconnection processes, particularly in light of additional
reporting requirements in other parts of this final rule.
---------------------------------------------------------------------------
\3088\ MISO Initial Comments at 125; MISO Reply Comments at 18;
NYTOs Initial Comments at 33; PacifiCorp Initial Comments at 44;
Xcel Initial Comments at 48.
---------------------------------------------------------------------------
1620. Specifically, the annual informational report would be
duplicative of the requirement in section 7.3 of the pro forma LGIP and
sections 3.3.6 and 3.4.10 of the pro forma SGIP that we adopt in this
final rule. Under these provisions, transmission providers must explain
how the required alternative transmission technologies were evaluated
for feasibility, cost, and time savings in each pro forma LGIP cluster
study report or pro forma SGIP feasibility study and system impact
study reports. The description of the results of the evaluation
required in these reports should provide transparency into the
evaluation process and deployment of alternative transmission
technologies in generator interconnection processes. In response to
Enel's argument that an annual informational report will allow the
Commission to evaluate if a transmission provider is artificially
restricting the use of alternative transmission technologies, we find
that this concern is adequately addressed through the modified
requirement that transmission providers evaluate all required
alternative transmission technologies by default in all studies and
restudies.
3. Modeling and Ride-Through Requirements for Non-Synchronous
Generating Facilities
a. Modeling Requirements
i. Need for Reform and NOPR Proposal
1621. In the NOPR, the Commission preliminarily found that the pro
forma LGIP and pro forma SGIP may be unduly discriminatory or
preferential to the extent that they do not require non-synchronous
generating facilities to provide accurate and validated models to
transmission providers during the generator interconnection
process.\3089\ Specifically, the Commission noted that, while
Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2 of
the pro forma SGIP require all generating facilities to submit certain
types of information, the information required is only sufficient to
accurately model the behavior of synchronous generating facilities. The
Commission stated its concern that, without a reform to require
interconnection customers developing non-synchronous generating
facilities \3090\ to provide sufficiently accurate and validated
models, interconnection studies may not identify the appropriate
interconnection facilities and network upgrades, which could lead to
unjust and unreasonable rates for interconnection service.\3091\
---------------------------------------------------------------------------
\3089\ NOPR, 179 FERC ] 61,194 at P 318.
\3090\ Non-synchronous generating facilities are ``connected to
the bulk power system through power electronics, but do not produce
power at system frequency (60 Hz).'' They ``do not operate in the
same way as traditional generators and respond differently to
network disturbances.'' Reactive Power Requirements for Non-
Synchronous Generation, Order No. 827, 81 FR 40793 (June 23, 2016),
155 FERC ] 61,277, at P 10 n.24 (2016).
\3091\ NOPR, 179 FERC ] 61,194 at P 319.
---------------------------------------------------------------------------
1622. The Commission proposed to revise Attachment A to Appendix 1
of the pro forma LGIP and Attachment 2 of the pro forma SGIP to ensure
that all interconnection customers requesting to interconnect a non-
synchronous generating facility must provide the transmission provider
with the models needed for accurate interconnection studies.\3092\
Pursuant to this proposal, interconnection customers requesting to
interconnect a non-synchronous generating facility would be required to
provide models that contain the details necessary to accurately model
the performance of the generating facility in response to system
disturbances in accordance with the control system settings that would
be used by the interconnection customer during the commissioning and
operation of the generating facility.
---------------------------------------------------------------------------
\3092\ Id. P 328.
---------------------------------------------------------------------------
1623. Specifically, the Commission proposed to require each
interconnection customer requesting to interconnect a non-synchronous
generating facility to submit to the transmission provider: (1) a
validated, user-defined root mean square (RMS) positive sequence
dynamic model; (2) an appropriately parameterized, generic library RMS
positive sequence dynamic model, including a model block diagram of the
inverter control system and plant control system, that corresponds to a
model listed in a new table of acceptable models or a model otherwise
approved by WECC; and (3) a validated EMT model, if the transmission
provider performs an EMT study as part of the interconnection study
process.\3093\
---------------------------------------------------------------------------
\3093\ Id. P 329.
---------------------------------------------------------------------------
1624. With regard to the validated, user-defined RMS positive
sequence dynamic model, the Commission proposed to define a user-
defined model as any set of programming code created by equipment
manufacturers or developers that captures the latest features of
controllers that are mainly software-based and represents the entities'
control strategies but does not necessarily correspond to any
particular generic library model.\3094\ The Commission explained that
in order for this model to be ``validated,'' it must be confirmed that
the equipment behavior is consistent with the model behavior, and
described how the interconnection customer may make such confirmation.
---------------------------------------------------------------------------
\3094\ Id. P 330.
---------------------------------------------------------------------------
[[Page 61240]]
1625. With regard to the appropriately parameterized, generic
library RMS positive sequence dynamic model, the Commission proposed a
table of acceptable generic library models based on the current WECC
list of approved dynamic models for renewable energy generating
facilities.\3095\ The Commission noted that WECC's list of approved
dynamic models has also been integrated into NERC reliability
guidelines and that these models represent the current state of the art
with regard to dynamic modeling requirements for non-synchronous
generating facilities.
---------------------------------------------------------------------------
\3095\ Id. P 331.
---------------------------------------------------------------------------
1626. The Commission stated that it believed that these models
represent the full spectrum of modeling data that transmission
providers need to perform accurate interconnection studies for non-
synchronous generating facilities.\3096\ The Commission also recognized
that the modeling data proposed to be required from non-synchronous
generating facilities may be more voluminous than that required of
synchronous generating facilities; however, the Commission noted that
this data submission requirement is intended to result in a comparable
level of modeling accuracy among all generating facilities.
---------------------------------------------------------------------------
\3096\ Id. P 332.
---------------------------------------------------------------------------
1627. The Commission stated that an interconnection customer's
failure to provide the above information within the deadlines
established in the pro forma LGIP and pro forma SGIP would make the
interconnection request incomplete and would be considered invalid in
accordance with section 3.4.3 of the pro forma LGIP and section 1.3 of
the pro forma SGIP.\3097\ Pursuant to those provisions, if the
interconnection customer does not cure the deficiency within the 10-
business day cure period, the interconnection request will be
considered withdrawn pursuant to section 3.7 of the pro forma LGIP and
section 1.3 of the pro forma SGIP. The Commission also proposed to
require that any proposed modification of the interconnection request
be accompanied by updated models of the proposed generating
facility.\3098\
---------------------------------------------------------------------------
\3097\ Id. P 333.
\3098\ Id. P 334.
---------------------------------------------------------------------------
1628. The Commission sought comment on: (1) whether the proposed
reforms are necessary and/or sufficient to ensure that interconnection
customers proposing non-synchronous generating facilities would submit
models during the generator interconnection process that accurately
reflect the behavior of their proposed generating facility; (2) whether
the inclusion of the table based on NERC guidelines that cite WECC-
approved models is appropriate; and (3) if not, how the Commission
could require interconnection customers to submit models that are
widely known in industry to be accurate without listing specific
models.\3099\
---------------------------------------------------------------------------
\3099\ Id. P 335.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1629. Many commenters support the NOPR proposal.\3100\ SPP states
that it has the highest penetration of IBRs \3101\ of any RTO/ISO, so
it is particularly sensitive to potential harm that could occur if
those resources fail to perform as expected.\3102\ ISO-NE argues that
data issues are one of the largest causes of study delays in its
region, and requiring data accuracy will improve study processing time
and support first-ready, first-served reforms.\3103\ NERC contends that
the existing interconnection process does not provide sufficiently
accurate and validated models for IBRs.\3104\
---------------------------------------------------------------------------
\3100\ AEP Initial Comments at 54; APPA-LPPC Initial Comments at
33; APS Initial Comments at 24; CAISO Initial Comments at 39; Clean
Energy Associations Initial Comments at 65; EEI Initial Comments at
23; NERC Initial Comments at 9-10; EPRI Initial Comments at 19;
Eversource Initial Comment at 38; ISO-NE Initial Comments at 42;
MISO Initial Comments at 125; MISO TOs Initial Comments at 33; NARUC
Initial Comments at 42; National Grid Initial Comments at 44; North
Carolina Commission and Staff Initial Comments at 27; NRECA Initial
Comments at 48; NYTOs Initial Comments at 33; Ohio Commission
Initial Comments at 17; OMS Initial Comments at 20; PacifiCorp
Initial Comments at 45; PPL Initial Comments at 25; R Street Initial
Comments at 17; SPP Initial Comments at 27; U.S. Chamber of Commerce
Initial Comments at 13.
\3101\ ``Inverter-based resource'' (IBR) refers to a resource
that is asynchronously connected to the transmission system and is
either completely or partially interfaced with the bulk power system
through power electronics. See Reliability Guideline: BPS-Connected
Inverter-Based Resource Performance, at vii, https://www.nerc.com/comm/RSTC_Reliability_Guidelines/Inverter-Based_Resource_Performance_Guideline.pdf. The term ``non-synchronous
generating facilities'' refers to the same resources.
\3102\ SPP Initial Comments at 27.
\3103\ ISO-NE Initial Comments at 42.
\3104\ NERC Initial Comments at 18.
---------------------------------------------------------------------------
(b) Comments in Opposition
1630. Several commenters oppose the NOPR proposal in its
entirety,\3105\ while additional commenters express concerns about
specific aspects. Pine Gate asserts that the Commission should not
incorporate requirements into the pro forma LGIP and pro forma SGIP
that are already being addressed by NERC through the standards
development process.\3106\ Pine Gate states that the pro forma LGIA and
pro forma SGIA require interconnection customers to remain compliant
with the applicable reliability standards, and recommends that the
Commission address these modeling and performance reforms under the
generic statement regarding compliance with applicable NERC Reliability
Standards or by adding a similar statement in each applicable section
of article 9 in the pro forma LGIA.\3107\
---------------------------------------------------------------------------
\3105\ ENGIE Initial Comment at 13-14; NYISO Initial Comments at
53-54; Pine Gate Initial Comments at 60-61; SEIA Initial Comments at
41.
\3106\ Pine Gate Initial Comments at 60.
\3107\ Id. at 60-61 (citing pro forma LGIA art. 9.1).
---------------------------------------------------------------------------
1631. NYISO argues that the final rule should not include a
modeling requirement because it would be inefficient and necessitate a
rebuild of NYISO's study base case.\3108\ NYISO explains that, if the
NOPR proposal is adopted, its interconnection study analysis would take
much longer to ensure accurate results, significantly slowing the
interconnection process.
---------------------------------------------------------------------------
\3108\ NYISO Initial Comments at 53-54.
---------------------------------------------------------------------------
1632. ENGIE argues that the required models in the NOPR proposal
are very detailed, there are few consultants that perform this
modeling, and the value obtained is low because the study likely will
become outdated as project components are substituted for more advanced
technologies. ENGIE recommends requiring a power flow and dynamic
model, which it contends provides sufficient information on reliability
impacts.\3109\
---------------------------------------------------------------------------
\3109\ ENGIE Initial Comments at 13-14.
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
(1) Cure Period for Modeling Information
1633. AES asserts that a 10-day cure period for interconnection
customers to correct or provide additional information on models for
non-synchronous generating facilities is not adequate and that no less
than a 20 business-day cure period is needed.\3110\
---------------------------------------------------------------------------
\3110\ AES Initial Comments at 25-26.
---------------------------------------------------------------------------
(2) Transmission Provider Requirements
1634. SEIA requests that the Commission modify the NOPR proposal to
require transmission providers to make available to interconnection
customers the necessary system data needed to create accurate models,
provide clear modeling requirements and validation guidelines and
procedures,\3111\ and engage stakeholders before making any modeling
changes.
---------------------------------------------------------------------------
\3111\ SEIA Initial Comments at 42-43 (citing, e.g., CAISO,
Electromagnetic Transient Modeling Requirements (Apr. 14, 2021),
http://www.caiso.com/Documents/CaliforniaISOElectromagneticTransientModelingRequirements.pdf.).
---------------------------------------------------------------------------
[[Page 61241]]
(3) Models Not Available Early in Interconnection Study Process
1635. Multiple commenters argue that accurate models for non-
synchronous generating facilities may not be available early in the
interconnection study process and may need to be updated during the
process.\3112\ Pine Gate and Public Interest Organizations assert that
the Commission should revise the NOPR proposal to allow for later
submission of such models to reduce the administrative burden on
transmission providers and interconnection customers.\3113\
---------------------------------------------------------------------------
\3112\ Alliant Energy Initial Comments at 10-11; Clean Energy
Associations Initial Comments at 66; EPRI Initial Comments at 17-18;
NextEra Initial Comments at 40; [Oslash]rsted Initial Comments at
17; Pine Gate Initial Comments at 61; PPL Initial Comments at 25;
Public Interest Organizations Reply Comments at 13; SEIA Initial
Comments at 42.
\3113\ Pine Gate Initial Comments at 61; Public Interest
Organizations Reply Comments at 13.
---------------------------------------------------------------------------
1636. SEIA requests that the Commission modify the NOPR proposal to
require interconnection customers to provide all operating models
within one year before the commercial operation date of the generating
facility, so that the models reflect the most accurate operating
information.\3114\ Clean Energy Associations assert that models
requested very early in the interconnection study process, before
product feature details have been finalized, may need to be updated
prior to commercial operation, and argue that minor model changes
should not result in excessive triggering of material modification
rules.\3115\
---------------------------------------------------------------------------
\3114\ SEIA Initial Comments at 42.
\3115\ Clean Energy Associations Initial Comments at 66.
---------------------------------------------------------------------------
1637. Alliant Energy and PPL state that technical information
provided at the time an interconnection request is submitted can become
outdated during the interconnection study process,\3116\ and Alliant
Energy asserts that the Commission should therefore provide for
flexibility as to when and how required information for modeling
requirements is provided.\3117\ [Oslash]rsted argues that offshore wind
interconnection customers may not be able to provide a validated model
at the time of the interconnection request due to long lead times in
generating facility development and equipment that is still being
developed.\3118\
---------------------------------------------------------------------------
\3116\ Alliant Energy Initial Comments at 10-11; PPL Initial
Comments at 25.
\3117\ Alliant Energy Initial Comments at 10-11.
\3118\ [Oslash]rsted Initial Comments at 17.
---------------------------------------------------------------------------
1638. EPRI suggests that an alternative approach to the NOPR
proposal is to require the use of models that generally conform to the
capability and performance standards Institute of Electrical and
Electronics Engineers (IEEE) Standard 2800-022 and IEEE Standard 1547-
2018 during the interconnection study process, and notes that such
studies are subject to further assessment once a detailed, site-
specific model is available.\3119\
---------------------------------------------------------------------------
\3119\ EPRI Initial Comments at 18.
---------------------------------------------------------------------------
(4) RMS Models
1639. Several commenters request modifications to the proposed
requirements for RMS models.\3120\ Tesla and SEIA argue that the
Commission should require transmission providers to accept user-defined
library RMS positive sequence dynamics models, as these models better
reflect the actual technology intended to be used by the resource,
results in a much greater degree of modeling accuracy, and can help
support greater penetration of renewable resources.\3121\ In addition,
Tesla suggests that the Commission seek informational submissions from
transmission providers regarding software tools and resources needed to
integrate more accurate user-defined RMS modeling. Clean Energy
Associations argue that the transmission provider should have
discretion to require a user-defined RMS model, a generic library RMS
model (with site-specific parameterization), or both, instead of always
being required to collect both.\3122\ MISO encourages the Commission to
require that the user-defined model be compatible with the transmission
provider's software.\3123\ Further, MISO requests that the Commission
confirm that the user-defined model meets the transmission provider's
MOD-032-1 requirements. Longroad Energy recommends that the Commission
require NERC to improve the degree to which power flow software vendors
allow accurate modeling of IBR technology before the Commission
establishes modeling standards that might stifle technological
improvements.\3124\
---------------------------------------------------------------------------
\3120\ Clean Energy Associations Initial Comments at 65-66;
Eversource Initial Comments at 39; ISO-NE Initial Comments at 42-43;
MISO Initial Comments at 125; SEIA Initial Comments at 43; Tesla
Initial Comments at 11.
\3121\ SEIA Initial Comments at 43; Tesla Initial Comments at
11.
\3122\ Clean Energy Associations Initial Comments at 65-66.
\3123\ MISO Initial Comments at 125.
\3124\ Longroad Energy Reply Comments at 20.
---------------------------------------------------------------------------
1640. Other commenters express concern with the difficulties of
user-defined models.\3125\ Eversource requests that the Commission
specify that all positive sequence models provided must be non-
proprietary and accessible to neighboring utilities, system operators,
and other entities that need to access them.\3126\ ISO-NE asserts that
it does not accept user-defined models under its interconnection study
procedures and requests that the final rule allow for a process where
accurate, working, non-proprietary models are provided and screened in
advance of the study process.\3127\
---------------------------------------------------------------------------
\3125\ Eversource Initial Comments at 39; ISO-NE Initial
Comments at 42.
\3126\ Eversource Initial Comments at 39.
\3127\ ISO-NE Initial Comments at 43.
---------------------------------------------------------------------------
(5) Model Validation
1641. Some commenters argue that the Commission should provide
further direction regarding model validation requirements for non-
synchronous generating facilities.\3128\ NERC and SDG&E argue that
reliability assessments indicate that model validation with actual
installed equipment and a ``true-up'' of generator interconnection
modeling would help ensure proper analysis and studies prior to
commissioning.\3129\ NERC recommends that the Commission enhance the
interconnection process by ensuring more rigorous plant commissioning,
with both the interconnection customer and the transmission provider
signing off on models used in studies as compared with actual installed
equipment.\3130\ In addition, NERC asks the Commission to require
transmission providers to conduct quality review of models before study
and require interconnection customers to satisfy quality review
milestones.\3131\
---------------------------------------------------------------------------
\3128\ Clean Energy Associations Initial Comments at 66-67; NERC
Initial Comments at 18-20; EPRI Initial Comments at 14-15;
[Oslash]rsted Initial Comments at 16, 18; SDG&E Reply Comments at 3;
Tesla Initial Comments at 10.
\3129\ NERC Initial Comments at 18; SDG&E Reply Comments at 3.
\3130\ NERC Initial Comments at 18.
\3131\ Id. at 20.
---------------------------------------------------------------------------
1642. Tesla argues that, in lieu of multiple attestations or test
data, the Commission should develop an approach to validation that
requires interconnection customers to submit ``model-to-model'' and
``product-to-model'' benchmarking data for non-synchronous generating
facilities.\3132\
---------------------------------------------------------------------------
\3132\ Tesla Initial Comments at 10.
---------------------------------------------------------------------------
1643. Clean Energy Associations assert that the Commission should
add language that provides that the attestation required for model
validation be the best available by the original equipment manufacturer
at the time of model delivery.\3133\ In addition, Clean Energy
Associations and [Oslash]rsted argue that the Commission should define
the
[[Page 61242]]
phrase ``accurate and validated models.'' \3134\ Clean Energy
Associations explain that it is common practice to submit an
interconnection request with advanced, next-generation equipment that
the manufacturer may still be developing, in which case the product and
validated models may not be available at the time of the
interconnection request, and request that the Commission allow
transmission providers flexibility to accommodate such new equipment in
their interconnection studies.\3135\
---------------------------------------------------------------------------
\3133\ Clean Energy Associations Initial Comments at 66.
\3134\ Id.; [Oslash]rsted Initial Comments at 16, 18.
\3135\ Clean Energy Associations Initial Comments at 67.
---------------------------------------------------------------------------
1644. Clean Energy Associations and [Oslash]rsted assert that, if
accurate and validated models require a comparison with unit level
factory tests, then this may not be feasible for offshore wind farms,
especially if they are connecting with HVDC transmission
technology.\3136\ They explain that these types of configurations are
often project-specific and do not have a definition of a ``validated
model.'' [Oslash]rsted also requests that the Commission explain why a
``model block diagram of the inverter control system and plant control
system'' is necessary given the availability of WECC model block
diagrams in simulation tools.\3137\
---------------------------------------------------------------------------
\3136\ Id. at 66-67; [Oslash]rsted Initial Comments at 16-17.
\3137\ [Oslash]rsted Initial Comments at 18.
---------------------------------------------------------------------------
1645. EPRI argues that the Commission should modify the language in
the pro forma LGIA and pro forma SGIA to ensure that all models are
validated and appropriately parameterized.\3138\ EPRI contends that the
NOPR proposal fails to provide adequate directions and requirements
with respect to model validation, testing, verification, and conformity
assessment, as required during various stages of the interconnection
process. EPRI asserts that a ``validated'' plant model would not be
available during the interconnection study stage because validation of
the plant model is not possible--within reasonable efforts--until after
the commissioning and commercial operation of the generating facility.
EPRI states that alternatives to this would be requiring generic models
that are appropriately parametrized and conform to IEEE Standard 2800-
2022 requirements.
---------------------------------------------------------------------------
\3138\ EPRI Initial Comments at 14-15.
---------------------------------------------------------------------------
(6) Table of Acceptable RMS Models
1646. Several commenters agree that a table of acceptable RMS
models based on NERC guidelines that cite WECC-approved models is
appropriate.\3139\ Ameren asserts that the Commission should provide a
table based on NERC guidelines that cite WECC-approved models as one
but not the only example.\3140\ Shell agrees that a table based on NERC
guidelines is appropriate as long as the functionality and proprietary
controls are adequately reflected (e.g., mimic the actual inverter
performance of manufacturers' models).\3141\ Shell explains that a
generic model may not be able to support the operational
characteristics of inverters. SPP states that, in its experience, some
manufacturers do not support WECC-approved generic dynamics models and
that having Commission support for more specific, detailed, and vetted
modeling information requirements will be helpful to improve data
quality and access.\3142\
---------------------------------------------------------------------------
\3139\ Ameren Initial Comments at 34; Bonneville Initial
Comments at 24; Shell Initial Comments, app. A, at vi; Tri-State
Initial Comments at 24.
\3140\ Ameren Initial Comments at 34.
\3141\ Shell Initial Comments, app. A, at vi.
\3142\ SPP Initial Comments at 28.
---------------------------------------------------------------------------
1647. R Street and EPRI offer alternatives to a table based on NERC
guidelines that cite WECC-approved models.\3143\ R Street argues that
providing a list of models in the final rule is not prudent given the
dynamic nature of the table, and that the list should instead be posted
on relevant public industry websites, including those of NERC.\3144\
EPRI states that one alternative could be to include a reference and
hyperlink to the NERC and WECC-approved models lists.\3145\ EPRI also
suggests that if the Commission retains the table, it should consider
revising the description of the DER_A model to add the word
``aggregated'' to the description and also consider adding columns with
the model names from other applicable software tools.
---------------------------------------------------------------------------
\3143\ EPRI Initial Comments at 20; R Street Initial Comments at
17.
\3144\ R Street Initial Comments at 17.
\3145\ EPRI Initial Comments at 20.
---------------------------------------------------------------------------
(7) EMT Modeling
1648. NERC and EPRI support the EMT modeling proposal in the
NOPR.\3146\ NERC recommends that all non-synchronous generating
facilities perform EMT models prior to interconnection for
consideration by transmission operators and planners.\3147\ NERC
contends that event analysis underscores the value of EMT studies in
helping manage reliability risks of the modern transmission system.
---------------------------------------------------------------------------
\3146\ Id. at 15, 19; NERC Initial Comments at 21.
\3147\ NERC Initial Comments at 21.
---------------------------------------------------------------------------
1649. EPRI agrees that performing EMT studies should be at the
discretion of the transmission provider.\3148\ However, EPRI recommends
collecting validated and appropriately parametrized EMT models during
the interconnection process regardless of whether the transmission
provider performs an EMT study because an EMT study may become
necessary in the future, and the interconnection stage is the best time
to obtain models due to the close coordination between interconnection
customers, consultants, equipment manufacturers, and generating
facility designers. EPRI also suggests that an industry-accepted
generic EMT model could be required in lieu of a validated EMT
model.\3149\
---------------------------------------------------------------------------
\3148\ EPRI Initial Comments at 19.
\3149\ Id. at 15.
---------------------------------------------------------------------------
1650. Clean Energy Associations argue that the Commission should
require submission of an EMT model one year before the scheduled
commercial operation date of the non-synchronous generating facility if
the transmission provider performs an EMT study as part of the
interconnection study process.\3150\ Clean Energy Associations assert
that, if the Commission moves forward with a requirement for
interconnection customers to provide EMT models, it should require the
transmission provider and its consultants to protect these models with
the highest degree of confidentiality because these models contain
proprietary and highly commercially sensitive material that could pose
a reliability risk if obtained by malicious actors.
---------------------------------------------------------------------------
\3150\ Clean Energy Associations Initial Comments at 68-70.
---------------------------------------------------------------------------
1651. Several commenters oppose the EMT modeling proposal.\3151\
AES contends that EMT modeling is not yet used widely in the industry
and thus should not be adopted as a minimum standard.\3152\
---------------------------------------------------------------------------
\3151\ AES Initial Comments at 26; Bonneville Initial Comments
at 24; Invenergy Initial Comments at 57-58; Longroad Energy Reply
Comments at 21; SEIA Initial Comments at 41-42.
\3152\ AES Initial Comments at 26.
---------------------------------------------------------------------------
1652. Longroad Energy argues that EMT studies are more expensive
than transient stability studies, require highly specialized
engineering experience to perform, and are limited to modeling a
fraction of a transmission provider's transmission system.\3153\
Longroad Energy asserts that the Commission should continue to allow
transmission providers the discretion to determine where such studies
will meaningfully
[[Page 61243]]
impact the interconnection requirements for an interconnection request.
Further, Longroad Energy asserts that the Commission should require
transmission providers to publish studies demonstrating the need for
EMT studies to prevent unnecessarily imposing a costly, time-consuming
step in the interconnection study process.
---------------------------------------------------------------------------
\3153\ Longroad Energy Reply Comments at 21.
---------------------------------------------------------------------------
1653. SEIA asserts that EMT models are not yet industry standard
models, require significant processing power compared to RMS models,
and are not necessarily more accurate than RMS models.\3154\ Bonneville
asserts that it has found that EMT modeling studies are rarely
necessary, and therefore any requirement to provide EMT models or
studies should be left to the transmission provider's discretion.\3155\
---------------------------------------------------------------------------
\3154\ SEIA Initial Comments at 41-42 (citing Summary of the
Joint Generator Interconnection Workshop, at 28 (Aug. 9-11, 2022),
https://www.esig.energy/wp-content/uploads/2022/10/Joint-Generator-Workshop-Summary-1.pdf (Generator Interconnection Workshop
Summary)).
\3155\ Bonneville Initial Comments at 24.
---------------------------------------------------------------------------
(d) Requests for Clarification
1654. Invenergy requests that the Commission clarify that, if a
validated EMT model is unavailable at the time of submission of an
interconnection request: (1) whether the interconnection request may
proceed and provide a generic EMT model, if available; and (2) if a
validated EMT model is determined to be necessary, whether the
interconnection customer may submit this information by the time of
cluster restudy, or as soon thereafter as it becomes available from the
manufacturer.\3156\
---------------------------------------------------------------------------
\3156\ Invenergy Initial Comments at 58.
---------------------------------------------------------------------------
1655. APS requests clarity from the Commission on the process for
curing deficiencies with respect to information provided by the
interconnection customer, such as the number of times an
interconnection customer is allowed to provide inaccurate data and cure
deficiencies, before an interconnection request is deemed
withdrawn.\3157\
---------------------------------------------------------------------------
\3157\ APS Initial Comments at 24.
---------------------------------------------------------------------------
(e) Miscellaneous
1656. ClearPath asserts that the Commission should consider how the
NOPR proposal will align with technological advancements and supply
chain challenges.\3158\ ClearPath explains that the average
interconnection queue wait time is 3.7 years, which may present
opportunities for interconnection customers to adopt newer, more
advanced equipment after they enter the interconnection queue.
ClearPath further explains that supply chain challenges may force an
interconnection customer to change equipment procurement unexpectedly
while in the interconnection queue, and requests that the Commission
explain whether a change in equipment that necessitates submitting new
models and data is considered a material modification.
---------------------------------------------------------------------------
\3158\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------
1657. Consumers Energy notes that NERC is currently in the
interconnection data gathering process, potentially making inclusion of
additional requirements within the rulemaking duplicative and
recommends consistency between NERC and Commission interconnection
improvement efforts.\3159\
---------------------------------------------------------------------------
\3159\ Consumers Energy Initial Comments at 9.
---------------------------------------------------------------------------
1658. EPRI states that the NOPR proposal does not specify
information and data that the transmission providers may need to
provide to the interconnection customer during the design stage (e.g.,
acceptable voltage ranges, protection details, short circuit levels,
etc.).\3160\ EPRI asserts that the final rule could consider the list
of data from Annex H of IEEE 2800-2022, which includes definitions that
could help define the combined generating and storage service level MW
of a generating facility referred to in the NOPR proposal, including
the continuous rating, continuous absorption rating, and short-term
rating for IBRs.
---------------------------------------------------------------------------
\3160\ EPRI Initial Comments at 22.
---------------------------------------------------------------------------
iii. Commission Determination
1659. We adopt the NOPR proposal to revise Attachment A to Appendix
1 of the pro forma LGIP and Attachment 2 of the pro forma SGIP to
require each interconnection customer requesting to interconnect a non-
synchronous generating facility to submit to the transmission provider:
(1) a validated user-defined RMS positive sequence dynamic model; (2)
an appropriately parameterized generic library RMS positive sequence
dynamic model, including a model block diagram of the inverter control
system and plant control system, that corresponds to a model listed in
a new table of acceptable models or a model otherwise approved by WECC;
and (3) a validated EMT model, if the transmission provider performs an
EMT study as part of the interconnection study process.
1660. We also adopt the NOPR proposals to: (1) define a user-
defined model as any set of programming code created by equipment
manufacturers or developers that captures the latest features of
controllers that are mainly software-based and represent the entities'
control strategies but does not necessarily correspond to any
particular generic library model, as contained in Attachment A to
Appendix 1 of the pro forma LGIP and Attachment 2 of the pro forma
SGIP; (2) revise Attachment A to Appendix 1 of the pro forma LGIP and
Attachment 2 of the pro forma SGIP to add a table of acceptable generic
library models, based on the current WECC list of approved dynamic
models for renewable energy generating facilities; and (3) revise
section 4.4.4 of the pro forma LGIP and section 1.4 of the pro forma
SGIP to require that any proposed modification of the interconnection
request be accompanied by updated models of the proposed generating
facility.
1661. Based on the record before us, we affirm the Commission's
preliminary finding in the NOPR that the pro forma LGIP and pro forma
SGIP are unduly discriminatory or preferential because they do not
require non-synchronous generating facilities to provide accurate and
validated models to transmission providers during the generator
interconnection process that provide a comparable degree of accuracy as
the models required of a synchronous generator. The current pro forma
LGIP and pro forma SGIP provisions ensure that synchronous generating
facilities are required to provide accurate, validated models to
transmission providers during the generator interconnection process.
However, the current pro forma LGIP and pro forma SGIP provisions are
insufficient to ensure that non-synchronous generating facilities
submit models with a comparable level of accuracy.
1662. Additionally, we find that the lack of a requirement for non-
synchronous generating facilities to provide accurate and validated
models to transmission providers in the pro forma LGIP and pro forma
SGIP results in unjust and unreasonable rates. Accurate and validated
models are necessary to minimize study delays and to ensure that
transmission providers conduct accurate interconnection studies that
identify the necessary interconnection facilities and network upgrades
to accommodate the interconnection request. Data issues are commonly
cited as a major source of study delays, which contributes to
interconnection queue backlogs.\3161\ As described above,
interconnection queue backlogs create uncertainty in the timing and
cost of interconnecting to the transmission system and hinders the
timely development of new generation.
[[Page 61244]]
Moreover, without accurate models, transmission providers cannot
conduct accurate interconnection studies that identify the appropriate
interconnection facilities and network upgrades, leading to the
inaccurate assignment of interconnection costs and resulting in
Commission-jurisdictional rates that are unjust and unreasonable.\3162\
---------------------------------------------------------------------------
\3161\ See, e.g., ISO-NE Initial Comments at 42.
\3162\ NARUC Initial Comments at 42; see also EEI Initial
Comments at 23 (explaining that this requirement will improve
transmission provider's ability to identify appropriate
interconnection facilities and network upgrades for non-synchronous
generating facilities); MISO TOs Initial Comments at 33 (stating
that the current lack of accurate modeling means that transmission
providers are unable to fully assess their ability to respond to
system disturbances).
---------------------------------------------------------------------------
1663. Furthermore, many commenters agree that this reform will help
prevent potential reliability concerns if non-synchronous generating
facilities do not perform when in service as modeled during the
interconnection process.\3163\ For example, additional modeling
requirements will significantly improve the accuracy of both
interconnection and reliability studies as well as address concerns
regarding non-synchronous generation disturbance events.\3164\
---------------------------------------------------------------------------
\3163\ APS Initial Comments at 24; CAISO Initial Comments at 39-
40; Clean Energy Associations Initial Comments at 65; NERC Initial
Comments at 9-10; Eversource Initial Comment at 38.
\3164\ Eversource Initial Comment at 38.
---------------------------------------------------------------------------
1664. NYISO argues that the final rule would be inefficient and
necessitate a rebuild of NYISO's study base case, take longer to ensure
accurate results, and significantly slow the interconnection
process.\3165\ While we will not opine here on the NYISO-specific
compliance with the final rule, we disagree that requiring accurate
dynamic models of generating facilities will make the interconnection
process take longer to ensure accurate results. To the contrary, we
find here that a lack of accurate models is a major cause of study
delays and contributes to interconnection study backlogs.
---------------------------------------------------------------------------
\3165\ NYISO Initial Comments at 53-54.
---------------------------------------------------------------------------
1665. The majority of commenters support the NOPR proposal.\3166\
We affirm that, consistent with this final rule, all interconnection
customers requesting to interconnect a non-synchronous generating
facility must provide the transmission provider with the required
models needed for accurate interconnection studies. We find that the
models required herein contain the details necessary to accurately
model the performance of the non-synchronous generating facility in
response to system disturbances, and we decline to adopt alternative
model proposals put forth by commenters. This reform promotes a
consistent approach among all generating facilities with respect to
modeling, such that all interconnection customers are required to
submit information sufficient to accurately model the behavior of their
proposed generating facilities.
---------------------------------------------------------------------------
\3166\ AEP Initial Comments at 54; APPA-LPPC Initial Comments at
33; APS Initial Comments at 24; CAISO Initial Comments at 39; Clean
Energy Associations Initial Comments at 65; EEI Initial Comments at
23; NERC Initial Comments at 9-10; EPRI Initial Comments at 19;
Eversource Initial Comments at 38; ISO-NE Initial Comments at 42;
MISO Initial Comments at 125; MISO TOs Initial Comments at 33; NARUC
Initial Comments at 42; National Grid Initial Comments at 44; North
Carolina Commission and Staff Initial Comments at 27; NRECA Initial
Comments at 48; NYTOs Initial Comments at 33; Ohio Commission
Initial Comments at 17; OMS Initial Comments at 20; PacifiCorp
Initial Comments at 45; PPL Initial Comments at 25; R Street Initial
Comments at 17; SPP Initial Comments at 27; U.S. Chamber of Commerce
Initial Comments at 13.
---------------------------------------------------------------------------
1666. We decline to adopt AES's request for a 20-day cure period
for model deficiencies.\3167\ Under the proposed provisions, if an
interconnection customer fails to provide the required models above
within the deadlines established in the pro forma LGIP and pro forma
SGIP, its interconnection request will be incomplete and considered
invalid in accordance with section 3.4.4 of the pro forma LGIP and
section 1.3 of the pro forma SGIP. Pursuant to those provisions, if the
interconnection customer does not cure such a deficiency within the 10-
business day cure period, the interconnection request will be
considered withdrawn pursuant to section 3.7 of the pro forma LGIP and
section 1.3 of the pro forma SGIP. In it its request, AES provides no
explanation for why the 10-business day cure period is insufficient.
Moreover, we believe that the existing 10-business day cure period
should be consistently applied to all interconnection request
deficiencies and that having an extended cure period for model
deficiencies would potentially introduce delays in the interconnection
process. We note that interconnection customers may submit their
interconnection requests early in the customer request window, which
will allow for more time to ensure their models are valid.
---------------------------------------------------------------------------
\3167\ AES Initial Comments at 25-26.
---------------------------------------------------------------------------
1667. We disagree with Pine Gate that the revisions to the pro
forma LGIP and pro forma SGIP, as adopted, incorporate requirements
into the pro forma LGIP and pro forma SGIP that are already being
addressed by NERC through the standards development process.\3168\ We
note that NERC supports the NOPR proposal and argues that the existing
interconnection process does not provide sufficiently accurate and
validated models for non-synchronous generating facilities to
transmission providers.\3169\ We find that these modeling requirements
are appropriately addressed in the interconnection context, where
interconnection customers must provide information to a transmission
provider for use in interconnection studies, and thus adopt the
revisions in the pro forma LGIP and pro forma SGIP. In addition, the
pro forma LGIA and pro forma SGIA revisions apply to a wide spectrum of
generating facilities, including newly interconnecting generating
facilities that are currently outside the bounds of NERC's
jurisdiction.\3170\ As such, we find that this reform can holistically
address the identified issues alongside the NERC standards; even if
NERC is taking action, that need not prevent us from taking action
here.
---------------------------------------------------------------------------
\3168\ Pine Gate Initial Comments at 60.
\3169\ NERC Initial Comments at 18.
\3170\ But see Registration of Inverter-based Resources, 181
FERC ] 61,124, at P 31, (2022) (``[W]e find it necessary to ensure
that NERC register the owners and operators of those unregistered
IBRs that, in the aggregate, have a material impact on Bulk-Power
System reliability, to ensure those entities are subject to a
relevant set of mandatory and enforceable Reliability Standard
requirements.'').
---------------------------------------------------------------------------
1668. We disagree with ENGIE that the value obtained from the
models in the NOPR proposal is low because of the likelihood that the
study will be outdated as project components are substituted with more
advanced technology.\3171\ We recognize that the project components for
non-synchronous generating facilities may change during the
interconnection process. We find, however, that this does not diminish
the value of a transmission provider receiving the identified
information from interconnection customers requesting to interconnect a
non-synchronous generating facility and receiving models that represent
the best information interconnection customers have available about
their proposed generating facilities because these models will ensure
that the transmission provider can accurately model the impact of the
proposed generating facility throughout the interconnection process. In
addition, proposed section 4.4.4 of the pro forma LGIP and section 1.4
of the pro forma SGIP require that any modification of the
interconnection request be accompanied by updates to the models.
Pursuant to these provisions, the models are required to be updated as
project components are changed. Ensuring that the model of the proposed
generating
[[Page 61245]]
facility is accurate throughout the interconnection study process will
allow the interconnection customer to understand the actual, potential
impact on their interconnection request of changing these project
components as they are considering such technological advancements.
---------------------------------------------------------------------------
\3171\ ENGIE Initial Comments at 13-14.
---------------------------------------------------------------------------
1669. Similarly, we disagree with commenters that argue that
accurate models for non-synchronous generating facilities may not be
available early in the interconnection study process and may need to be
updated during that process.\3172\ We find that the reforms we adopt
herein are consistent with the principles behind other requirements in
the pro forma LGIP and pro forma SGIP, namely those that set forth
requirements for an interconnection request, including requirements
that requests be viable and well-defined.\3173\ The requirement to
submit accurate models also reduces the chance that a transmission
provider would need to perform additional studies, in this case if an
interconnection customer submits models that are inaccurate and those
inaccuracies are not discovered until late in the interconnection
process. In that instance, i.e., if model validation occurs at a point
further into the interconnection process, inaccurate models that are
used in interconnection studies could create errors in the studies,
potentially leading to restudies and subsequent delays which would
frustrate the efficiency gained by moving to a first-ready, first-
served cluster study process. Further, we find that the definition of a
validated model (i.e., confirmation that the equipment behavior is
consistent with the modeled behavior) is sufficiently flexible to
enable interconnection customers to provide such a model with their
interconnection requests.\3174\ Moreover, the option for the
interconnection customer to submit an attestation that the models
accurately reflect the expected behavior of a proposed generating
facility would be based in the interconnection customer's best
understanding at the time of the interconnection request, providing
further flexibility if the interconnection customer chooses to change
the equipment or control systems of the proposed generating facility,
which is permitted as part of the interconnection process.
---------------------------------------------------------------------------
\3172\ Alliant Energy Initial Comments at 10-11; Clean Energy
Associations Initial Comments at 66; EPRI Initial Comments at 17-18;
NextEra Initial Comments at 40; [Oslash]rsted Initial Comments at
17; Pine Gate Initial Comments at 61; PPL Initial Comments at 25;
Public Interest Organizations Reply Comments at 13; SEIA Initial
Comments at 42.
\3173\ Pro forma LGIP section 3.4.1; pro forma SGIP section 1.3.
\3174\ Pro forma LGIP Attachment A to Appendix 1.
---------------------------------------------------------------------------
1670. In addition, we do not believe, as suggested by
commenters,\3175\ that there is a need to require transmission
providers to make available additional information and system data in
order for an interconnection customer to develop an RMS model. Although
measured transmission system information is an input into the RMS
model, the purpose of the model is to represent the behavior of the
facility itself, and the interconnection customer should be able to use
likely transmission system configurations to parameterize and validate
the RMS model. To the extent that the interconnection customer believes
that actual transmission data is required to tune the model block
diagram, the scoping meeting provides a venue for such discussions. The
provisions set forth in new pro forma LGIP section 3.4.6 further detail
scoping meetings, which occur during the customer engagement window.
---------------------------------------------------------------------------
\3175\ SEIA Initial Comments at 42; Tesla Initial Comments at
11.
---------------------------------------------------------------------------
1671. We decline to adopt requirements that constrain the
discretion of transmission providers to use either user-defined RMS
models or generic library RMS models, as suggested by commenters.\3176\
We find that the transmission provider is in the best position to
determine the power flow modeling method that is best suited to
ensuring the reliability of its system.
---------------------------------------------------------------------------
\3176\ Clean Energy Associations Initial Comments at 65-66;
Eversource Initial Comments at 39; ISO-NE Initial Comments at 42-43;
MISO Initial Comments at 125; SEIA Initial Comments at 43; Tesla
Initial Comments at 11.
---------------------------------------------------------------------------
1672. We decline to modify the NOPR proposal to allow the
transmission provider to require either a user-defined RMS model or a
generic library RMS model, as suggested by Clean Energy Associations,
rather than requiring the interconnection customer to submit both, as
adopted in this final rule.\3177\ We believe that requiring the
interconnection customer to submit both models is of value in providing
the transmission provider discretion to choose which model most
accurately represents a given generating facility's behavior. Providing
these models does not represent an unreasonable burden on the
interconnection customer, as the process of developing and
parameterizing an RMS model is significantly simpler than doing so for
an EMT model.
---------------------------------------------------------------------------
\3177\ Clean Energy Associations Initial Comments at 65-66.
---------------------------------------------------------------------------
1673. We decline to require the user-defined RMS model to be
compatible with the transmission provider's software and meet the
transmission provider's MOD-032-1 requirements at the time the
interconnection request is submitted, as requested by MISO.\3178\ While
the user-defined RMS model will have to meet these requirements prior
to the cluster study for generating facilities seeking to interconnect
pursuant to the pro forma LGIP and optional feasibility study or system
impact study for generating facilities seeking to interconnect pursuant
to the pro forma SGIP, the scoping meeting is the appropriate time to
provide and discuss this information in order to correct the model if
it is incompatible with the transmission provider's software or
otherwise causes the transmission system model to be unable to
solve.\3179\
---------------------------------------------------------------------------
\3178\ MISO Initial Comments at 125.
\3179\ The scoping meeting is a meeting between representatives
of the interconnection customer and transmission provider ``to
exchange information including any transmission data and earlier
study evaluations that would be reasonably expected to affect such
interconnection options,'' and ``to analyze such information.''
Appendix C, pro forma LGIP section 1.
---------------------------------------------------------------------------
1674. We decline to require NERC to improve the degree to which
power flow software vendors allow accurate modeling of IBR technology,
as requested by Longroad Energy.\3180\ While we agree that improved
accuracy of IBR modeling is beneficial, this rulemaking is focused on
entities that execute, or request the unexecuted filing of, LGIAs and
SGIAs, and placing obligations on NERC or vendors is outside the scope
of this proceeding. Equipment providers can develop and submit
validated generic models to the software vendors' model libraries or
the WECC model validation process to be included in the WECC table of
approved models, if they desire to do so.
---------------------------------------------------------------------------
\3180\ Longroad Energy Reply Comments at 20.
---------------------------------------------------------------------------
1675. In response to commenters that argue that the Commission
should provide further direction regarding model validation
requirements for non-synchronous generating facilities,\3181\ we note
that Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2
of the pro forma SGIP, as adopted in this final rule, provide that, for
a model to be ``validated,'' the interconnection customer must provide
evidence that the equipment behavior is consistent with the model
behavior. In addition, Attachment A to Appendix 1 of the pro forma LGIP
and Attachment 2 of the pro
[[Page 61246]]
forma SGIP provide that this can involve, for example, an attestation
from the interconnection customer that the model accurately represents
the entire generating facility, attestations from each equipment
manufacturer that the user-defined model accurately represents the
relevant component of the generating facility, or test data. We find
that this definition of a ``validated'' model and examples of an
attestation in the proposal are sufficient and provide flexibility to
allow interconnection customers to provide such a model with their
interconnection requests. Therefore, we decline to adopt alternative
proposals for model validation put forth by commenters.
---------------------------------------------------------------------------
\3181\ EPRI Initial Comments at 14-15; Clean Energy Associations
Initial Comments at 66-67; NERC Initial Comments at 18-20;
[Oslash]rsted Initial Comments at 16, 18; SDG&E Reply Comments at 3;
Tesla Initial Comments at 10.
---------------------------------------------------------------------------
1676. We decline to adopt alternatives and revisions to the table
of acceptable generic library models based on the current WECC list of
approved dynamic models for renewable energy generating facilities, as
suggested by R Street and EPRI.\3182\ We find that the table, as
adopted, is appropriate because it represents the full spectrum of
modeling data that transmission providers need to perform accurate
interconnection studies for non-synchronous generating facilities.
Nevertheless, we recognize that the list of models approved by WECC is
subject to change and note that the table provides that ``a model
otherwise approved by [WECC],'' \3183\ and not reflected in the table,
would also meet the model requirements.
---------------------------------------------------------------------------
\3182\ EPRI Initial Comments at 20; R Street Initial Comments at
17.
\3183\ Pro forma LGIP, app. 1, attach. A; Pro forma SGIP,
attach. 2.
---------------------------------------------------------------------------
1677. In response to commenters that oppose a requirement for a
validated EMT model,\3184\ we note that these concerns mischaracterize
the NOPR proposal as mandating EMT models on a national basis. Rather,
Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2 of
the pro forma SGIP, as adopted, requires that, in circumstances where
the transmission provider performs an EMT study as part of its
interconnection study process, the interconnection customer must
provide an EMT model. We find that the transmission provider is in the
best position to determine whether an EMT study is necessary to ensure
system reliability because the transmission provider has the in-depth
knowledge of its transmission system required to recognize where and
when regular dynamic modeling is inadequate to capture the true
behavior of generating facilities.
---------------------------------------------------------------------------
\3184\ AES Initial Comments at 26; Bonneville Initial Comments
at 24; Invenergy Initial Comments at 57-58; Longroad Energy Reply
Comments at 21; SEIA Initial Comments at 41-42.
---------------------------------------------------------------------------
1678. Similarly, we decline to adopt EPRI's request to require EMT
models regardless of whether the transmission provider performs an EMT
study.\3185\ Developing an EMT model may place an unreasonable
administrative burden on an interconnection customer in situations
where such a model is not used by the transmission provider. We also
decline to adopt EPRI's request to allow use of an industry-accepted,
generic EMT model instead of a validated EMT model, as the record does
not indicate that any such industry-accepted, generic models currently
exist.\3186\
---------------------------------------------------------------------------
\3185\ EPRI Initial Comments at 19.
\3186\ Id. at 15.
---------------------------------------------------------------------------
1679. We decline Clean Energy Associations' request that the
Commission require submission of an EMT model one year before the
scheduled commercial operation date of the non-synchronous generating
facility if the transmission provider performs an EMT study as part of
the interconnection study process.\3187\ As noted above, we find that
the proposal for models to be submitted with the interconnection
request is consistent with the principles behind other requirements in
the pro forma LGIP and pro forma SGIP and that transmission providers
need these models to perform interconnection studies and ensure that
prospective generating facilities do not create reliability risks to
the transmission system. In response to Clean Energy Associations'
request that the Commission require the transmission provider and its
consultants to protect the EMT models and other information with the
highest degree of confidentiality,\3188\ we note that the pro forma
generator interconnection procedures and agreements include provisions
for the treatment of confidential information.\3189\
---------------------------------------------------------------------------
\3187\ Clean Energy Associations Initial Comments at 68-69.
\3188\ Id. at 70.
\3189\ See pro forma LGIP section 13.1; pro forma SGIP section
4.5; pro forma LGIA art. 22; pro forma SGIA art. 9.
---------------------------------------------------------------------------
1680. In response to Invenergy's request for clarification
regarding whether a generic EMT model may be provided if a validated
EMT model is unavailable at the time of submission of an
interconnection request,\3190\ we note that there is currently no
industry-accepted generic EMT model; therefore, a validated EMT model
is required. In response to Invenergy's request for clarification
regarding whether the interconnection customer may submit this
information by the time of a cluster restudy if a validated EMT model
is determined to be necessary, we clarify that a validated EMT model,
if required by the transmission provider, must be submitted with the
interconnection request to proceed in the interconnection study
process. As validation can consist of, for example an attestation from
the interconnection customer that the model accurately represents the
entire generating facility, based on the interconnection customer's
understanding at the time of submission, we believe an interconnection
customer should be able to provide a validated EMT model at the time of
the interconnection request.
---------------------------------------------------------------------------
\3190\ Invenergy Initial Comments at 58.
---------------------------------------------------------------------------
1681. In response to APS' request for clarification on the number
of times an interconnection customer is allowed to provide inaccurate
data and cure deficiencies before an interconnection request is deemed
withdrawn,\3191\ we note that section 3.4.4 of the pro forma LGIP and
section 1.3 of the pro forma SGIP provide the timeline for when a
transmission provider must notify an interconnection customer that its
interconnection request is deficient, and at that point, the
interconnection customer has 10 business days to provide the additional
requested information. We clarify that an interconnection customer has
until the end of the 10 business-day period to cure deficiencies in its
interconnection request. In the case of the pro forma LGIP, the
interconnection customer may submit this information early in the
cluster request window to ensure that there is sufficient time to
address any issues with the interconnection request and the required
models.
---------------------------------------------------------------------------
\3191\ APS Initial Comments at 24.
---------------------------------------------------------------------------
1682. In response to ClearPath's question regarding whether a
change in equipment that necessitates submitting updated models is
considered a material modification,\3192\ we highlight that section 4.4
of the pro forma LGIP and section 1.4 of the pro forma SGIP set forth
procedures for modifications to an interconnection request, including
the evaluation of technical changes to a request. Further, we note that
section 4.6 of the pro forma LGIP contains the transmission provider's
technological change procedure, which was designed to allow
transmission providers to evaluate whether equipment changes to an
interconnection request should trigger the material modification
provisions. A change in equipment may also qualify under the
transmission
[[Page 61247]]
provider's definition of permissible technological advancements in
section 1 of the pro forma LGIP. This definition includes advancements
that the interconnection process can accommodate without triggering the
material modification provision of the pro forma LGIP.
---------------------------------------------------------------------------
\3192\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------
1683. In response to Consumers Energy's recommendation that there
should be consistency between NERC Reliability Standards and data
collection efforts and the Commission's rulemaking,\3193\ we are not
persuaded that there is a conflict or duplication between this final
rule and NERC's Reliability Standards and interconnection data
collection efforts. NERC Reliability Standards apply only to entities
that are registered with NERC. Many smaller non-synchronous generating
facilities are currently excluded from NERC registration but
interconnect under the pro forma SGIP and pro forma LGIP and execute,
or request the unexecuted filing of, the pro forma SGIA or pro forma
LGIA.\3194\ The revisions to the pro forma interconnection procedures
and pro forma interconnection agreements require all new
interconnection customers that interconnect under the pro forma
interconnection procedures and pro forma interconnection agreements to
adhere to the new modeling requirements, regardless of whether the new
interconnection customers must abide by the NERC Reliability Standards.
We also note that NERC supports the proposed reforms.\3195\
---------------------------------------------------------------------------
\3193\ Consumers Energy Initial Comments at 9.
\3194\ NERC Initial Comments at 13-14.
\3195\ Id. at 8-9, 18-20.
---------------------------------------------------------------------------
b. Ride Through Requirements
i. Need for Reform and NOPR Proposal
1684. In the NOPR, the Commission preliminarily found that the pro
forma LGIA and pro forma SGIA ride through provisions could result in
undue discrimination and preferential treatment.\3196\ The Commission
stated that, although synchronous and non-synchronous generating
facilities are able to ``ride through'' system events and remain online
and continue to provide real and reactive power following a
disturbance, the existing pro forma LGIA and pro forma SGIA impose
differing ride through requirements because they fail to account for a
non-synchronous generating facility's ability to engage in momentary
cessation.\3197\ The Commission expressed concern that, given advances
in inverter technology, the lack of performance requirements regarding
the use of momentary cessation by non-synchronous generating facilities
may not be supportable on either a technical or cost basis.\3198\
---------------------------------------------------------------------------
\3196\ NOPR, 179 FERC ] 61,194 at P 320.
\3197\ Id. PP 320-321.
\3198\ Id. P 325.
---------------------------------------------------------------------------
1685. The Commission proposed to require newly interconnecting non-
synchronous generating facilities to continue current injection inside
the ``no trip zone'' of the frequency and voltage ride through curves
of NERC Reliability Standard PRC-024-3 or its successor
standards.\3199\ The Commission explained that the pro forma LGIA
defined the term ``ride through'' as the ability of the large
generating facility to stay connected to and synchronized with the
transmission system during system disturbances within a range of under-
frequency and over-frequency conditions. The Commission proposed to
expand this definition to include the ability of the large generating
facility to stay connected to and synchronized with the transmission
system during system disturbances within under-voltage and over-voltage
conditions.
---------------------------------------------------------------------------
\3199\ Id. P 336. The ``no trip zone'' is defined as a set of
voltage and frequency no trip boundaries within which applicable
protection and controls may not be set to cause the generating
facility to trip or cease current injection. See PRC-024-3--
Frequency and Voltage Protection Settings for Generating Resources,
https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-024-3.pdf.
---------------------------------------------------------------------------
1686. In addition, the Commission proposed to require any newly
interconnecting non-synchronous generating facility to have the
ability, during abnormal frequency conditions and voltage conditions
within the ``no trip zone'' defined by NERC Reliability Standard PRC-
024-3 or its successor standards, to maintain power production at pre-
disturbance levels unless providing primary frequency response or fast
frequency response, and to have the ability to provide dynamic reactive
power to maintain system voltage in accordance with the generating
facility's voltage schedule.\3200\ The Commission sought comment on
whether adherence to these proposed requirements would be readily
achievable through changes to control settings and whether such changes
to control settings could be made at a relatively minor cost.\3201\
---------------------------------------------------------------------------
\3200\ NOPR, 179 FERC ] 61,194 at P 337.
\3201\ Id. P 338.
---------------------------------------------------------------------------
ii. Comments
(a) Comments in Support
1687. Many commenters generally support the goal of the NOPR
proposal.\3202\ CAISO asserts that the proposed reforms are essential
for transmission providers to maintain reliability as non-synchronous
generating facilities proliferate, and it urges the Commission to
impose the proposed requirements on all interconnection customers that
have not yet executed LGIAs as well as all prospective interconnection
customers.\3203\ CAISO argues that interconnection customers that have
already procured certain inverters that cannot meet the requirements
can request non-conforming LGIAs, or request that their LGIAs be filed
unexecuted, but it notes that it recently implemented similar
requirements, and interconnection customers have been able to procure
the inverters and technology necessary to meet the requirements.
---------------------------------------------------------------------------
\3202\ AEP Initial Comments at 54; AES Initial Comments at 27;
Ameren Initial Comments at 34; APPA-LPPC Initial Comments at 33;
CAISO Initial Comments at 39-40; Consumers Energy Initial Comments
at 9; NERC Initial Comments at 4, 23; Eversource Initial Comments at
38; Illinois Commission Initial Comments at 16; MISO TOs Initial
Comments at 32-33; NARUC Initial Comments at 42; National Grid
Initial Comments at 43-44; North Carolina Commission and Staff
Initial Comments at 26-27; NRECA Initial Comments at 48; NYISO
Initial Comments at 54; Ohio Commission Consumer Advocate Initial
Comments at 17; PacifiCorp Initial Comments at 45; Pine Gate Initial
Comments at 59; SPP Initial Comments at 28; U.S. Chamber of Commerce
Initial Comments at 13.
\3203\ CAISO Initial Comments at 39-40.
---------------------------------------------------------------------------
(b) Comments in Opposition
1688. Pine Gate asserts that the Commission should not incorporate
requirements into the pro forma LGIP and pro forma SGIP that are
already being addressed by NERC through the standards development
process, which will add new requirements related to the vast majority
of the modeling and performance issues identified in the NOPR.\3204\ In
addition, Pine Gate notes that the pro forma LGIA and pro forma SGIA
already require interconnection customers to remain compliant with the
applicable reliability standards.\3205\
---------------------------------------------------------------------------
\3204\ Pine Gate Initial Comments at 60.
\3205\ Id. (citing pro forma LGIA art. 9.1).
---------------------------------------------------------------------------
(c) Comments on Specific Proposal
(1) IEEE Standards 2800 and 1547
1689. NERC and MISO support modifying the pro forma LGIP to
incorporate elements of NERC Reliability Standards, NERC guidelines,
and IEEE standards.\3206\ Specifically, MISO supports adopting IEEE
Standard 2800-2022 by reference in the pro forma LGIA.\3207\ MISO
asserts that
[[Page 61248]]
implementing IEEE Standard 2800-2022 will ensure resource capabilities
protect against the types of events described in several recent NERC
disturbance reports. NERC notes that the IEEE standards are inherently
not mandatory unless a governing authority with jurisdiction adopts and
enforces them and include many recommended practices that could be
deemed informational.\3208\ Accordingly, NERC asserts that IEEE
Standard 2800-2022 operates similar to NERC reliability guidelines,
although IEEE Standard 2800-2022 is only available upon purchase.
---------------------------------------------------------------------------
\3206\ NERC Initial Comments at 9; MISO Reply Comments at 26.
\3207\ MISO Reply Comments at 25.
\3208\ NERC Initial Comments at 3.
---------------------------------------------------------------------------
1690. NERC recommends that the Commission explicitly integrate the
requirements and recommendations from IEEE Standard 2800-2022 into the
pro forma interconnection agreements.\3209\ Specifically, NERC contends
that the Commission should prioritize the disturbance ride through,
active power-frequency control, reactive power-voltage control, data
sharing, and modeling provisions of IEEE Standard 2800-2022. However,
NERC states that some transmission system conditions may require
inverter control modes, settings, or protections that will not conform
to IEEE Standard 2800-2022 region-wide expectations. NERC also argues
that transmission providers should be permitted to establish additional
performance requirements for specific locations and instances beyond
region-wide requirements established under pro forma provisions,
subject to transparency and public notice.
---------------------------------------------------------------------------
\3209\ Id. at 6.
---------------------------------------------------------------------------
1691. Some commenters request that the Commission amend its
proposal to reference IEEE Standard 2800 or successor standards for
large generating facilities and IEEE Standard 1547 for small generating
facilities.\3210\ EPRI asserts that these standards have been developed
through a rigorous process and provide for IBR performance that
supports system reliability while providing sufficient flexibility for
RTOs/ISOs and interconnection customers.\3211\ EPRI also notes that
inverter manufacturers have publicly stated that state-of-the-art
equipment already has the majority of the capabilities required by IEEE
Standard 2800.
---------------------------------------------------------------------------
\3210\ Clean Energy Associations Initial Comments at 73; EPRI
Initial Comments at 5; SEIA Initial Comments at 43 (citing Generator
Interconnection Workshop Summary at 20).
\3211\ EPRI Initial Comments at 5.
---------------------------------------------------------------------------
1692. EPRI argues that the Commission should consider narrowly
specifying ride through requirements by reference to IEEE Standards
2800 and 1547; aligning all applicable definitions proposed in the NOPR
with those standards; and evaluating the alignment of additional
definitions or performance specifications with potential future
revisions of those standards.\3212\ EPRI asserts that failing to do so
could create undue technical barriers to IBRs, and that paraphrasing of
IEEE standards, rather than directly referencing the standards'
requirements, could lead to an inconsistent implementation of the final
rule in different regions with insufficient reliability benefits.\3213\
---------------------------------------------------------------------------
\3212\ Id.
\3213\ Id. at 5-6.
---------------------------------------------------------------------------
1693. EPRI asserts that, if the Commission specifies its own ride
through performance requirements, an alternative but less preferred
approach would be to use the precise language and definitions as
published in IEEE Standards 2800 and 1547.\3214\
---------------------------------------------------------------------------
\3214\ Id. at 6.
---------------------------------------------------------------------------
1694. EPRI argues that the NOPR proposal does not seem entirely
aligned with the NERC IBR guidelines and is not as clear as the
applicable industry standards like IEEE Standard 2800-2022.\3215\ EPRI
also asserts that the Commission should consider what it characterizes
as significant improvements in IEEE Standard 2800 over the NERC
reliability guidelines. EPRI contends that the NERC IBR reliability
guidelines cited in the NOPR did not fully consider all technical and
stakeholder concerns considered by IEEE Standard 2800 and are therefore
in contravention of the IEEE Standard 2800-2022 consensus
requirements.\3216\
---------------------------------------------------------------------------
\3215\ Id. at 9.
\3216\ Id. at 3.
---------------------------------------------------------------------------
1695. SEIA states that IBRs are currently capable of riding through
disturbances and that many developers have implemented controls to
ensure they do so following the release of the consensus-based IEEE
standards.\3217\ SEIA argues that incorporating IEEE Standard 2800 into
the pro forma LGIA would bring some certainty in generating facility
design because the reliability requirements for each generating
facility would be known at the time of the interconnection
request.\3218\
---------------------------------------------------------------------------
\3217\ SEIA Initial Comments at 43.
\3218\ Id. at 44.
---------------------------------------------------------------------------
(2) Feasibility of NOPR Proposal
1696. Some commenters argue that the proposed requirement in the
NOPR ``to maintain power production at pre-disturbance levels unless
providing primary frequency response or fast frequency response'' is
not feasible.\3219\ Invenergy asserts that, in order to increase
reactive power output to maintain system voltage, a generator would
necessarily have to reduce real power output: therefore, Invenergy
requests that the NOPR proposal be revised to clarify this potential
inconsistency.\3220\ Clean Energy Associations and Public Interest
Organizations contend that a requirement to maintain active power
injection at pre-disturbance levels would lead to an undesirable
response from generating facilities during a grid disturbance that
could lead to voltage collapse, and the more helpful response would be
to shift some power output to prioritize reactive power.\3221\
---------------------------------------------------------------------------
\3219\ CAISO Initial Comments at 40; Clean Energy Associations
Initial Comments at 71-72; NERC at 4; EPRI Initial Comments at 10;
Invenergy Initial Comments at 58; [Oslash]rsted Initial Comments at
19-20; Public Interest Organizations Reply Comments at 14; Southern
Initial Comments at 34.
\3220\ Invenergy Initial Comments at 58.
\3221\ Clean Energy Associations Initial Comments at 71-72;
Public Interest Organizations Reply Comments at 14.
---------------------------------------------------------------------------
1697. Southern suggests adding a sentence to article 9.7.3 in the
pro forma LGIA to address circumstances under which the generating
facility is unable to maintain active power while delivering reactive
power.\3222\ Clean Energy Associations suggest that the Commission
replace the requirement to maintain active power production with
language from NERC Reliability Standard PRC-024-3, which requires
current injection and not active power injection to continue at pre-
disturbance levels.\3223\ Alternatively, Clean Energy Associations and
Invenergy suggest the proposed language could be made more workable by
only requiring a return to the pre-disturbance level of power
production following voltage recovery, subject to the energy
availability of the resource, which Clean Energy Associations explains
would allow a generator to correctly shift from active power to
reactive power during the voltage disturbance.\3224\
---------------------------------------------------------------------------
\3222\ Southern Initial Comments at 34 (suggesting the addition
of the following sentence: ``If the plant cannot maintain active
power while delivering reactive power due to its current or apparent
power limitation, then the preference should be given to either
active or reactive power as specified by the Transmission
Provider.'').
\3223\ Clean Energy Associations Initial Comments at 76.
\3224\ Id. at 76-77; Invenergy Initial Comments at 58.
---------------------------------------------------------------------------
1698. CAISO requests that the Commission not require that inverters
be able to provide real power during a transitory disturbance.\3225\
CAISO states that, unlike synchronous generating facilities, IBRs are
current limited and generally operate at their maximum output. CAISO
argues that maintaining
[[Page 61249]]
real power output at pre-disturbance levels would likely inhibit a non-
synchronous generating facility's ability to provide reactive power
during a disturbance, and to help ensure reliability CAISO recommends
removing the real power requirements and requiring non-synchronous
generating facilities to provide reactive power at pre-disturbance
levels. EPRI agrees that maintaining active power at the pre-
disturbance levels during and after the abnormal voltage period may not
be practical, given that voltage disturbances tend to be limited to a
region relatively close to the fault location, and is not aligned with
IEEE Standard 2800-2022 or other international requirements.\3226\ EPRI
and NERC recommend that IBR plant performance requirements should
address active and/or reactive current during an abnormal voltage
condition and requirements for the restoration of active power output
in the post-fault period.\3227\
---------------------------------------------------------------------------
\3225\ CAISO Initial Comments at 40.
\3226\ EPRI Initial Comments at 10.
\3227\ Id. at 9-10; NERC Reply Comments at 4.
---------------------------------------------------------------------------
1699. EPRI argues that the implementation of frequency and voltage
protection relay settings should not be exactly aligned with the NERC
Reliability Standard PRC-024 curves but rather be based on the actual
limits of equipment capability, with the objective to avoid potential
damages.\3228\
---------------------------------------------------------------------------
\3228\ EPRI Initial Comments at 12.
---------------------------------------------------------------------------
1700. [Oslash]rsted argues that it is not possible to maintain real
power production with depressed voltage that is still within the no
trip zone of NERC Reliability Standard PRC-024-3, and explains that
prioritizing reactive current during fault ride through mode (even
within the no trip zone) is instrumental to maintain reliability.\3229\
[Oslash]rsted recommends replacing the reference to good utility
practice in proposed article 9.7.3 of the pro forma LGIA and instead
rely on Order No. 842 and its definition of ``Bulk-Power System--
Primary Frequency Response.'' \3230\
---------------------------------------------------------------------------
\3229\ [Oslash]rsted Initial Comments at 19-20.
\3230\ Id. at 20 (referring to Essential Reliability Servs. &
the Evolving Bulk-Power Sys. Primary Frequency Response, Order No.
842, 83 FR 9639 (Mar. 6, 2018), 162 FERC ] 61,128, order on
clarification and reh'g, 164 FERC ] 61,135 (2018)).
---------------------------------------------------------------------------
1701. NERC notes that conventional grid-following IBRs are current-
limited devices, and their active power output is voltage-dependent,
making maintaining 100% of pre-disturbance active power while providing
reactive power to support the bulk-power system during the fault period
not always feasible.\3231\ NERC recommends referring to ``controls that
maintain pre-disturbance active current (Ip)'' in addition to the
provision of reactive current (Iq) (i.e., reactive power support)
rather than referring to ``power.'' \3232\
---------------------------------------------------------------------------
\3231\ NERC Reply Comments at 4.
\3232\ Id.
---------------------------------------------------------------------------
(3) Applicability to All Types of Generating Facilities
1702. Invenergy asserts that the NOPR proposal should go beyond the
pro forma LGIA's current requirements and apply evenly to all
generating facilities, not just non-synchronous generating
facilities.\3233\ Similarly, Clean Energy Associations assert that the
Commission currently only requires that relay settings not trip a
generating facility during a voltage or frequency excursion and that
there is no actual performance standard to ride through a disturbance
for synchronous generating facilities.\3234\ Clean Energy Associations
assert that, to prevent undue discrimination, the Commission should
either proceed with a similar effort to require ride through
performance from synchronous generating facilities; or allow ride
through performance exceptions for non-synchronous generating facility
trips caused by auxiliary equipment performance, which are a primary
cause of ride through failure for both synchronous and non-synchronous
generating facilities.
---------------------------------------------------------------------------
\3233\ Invenergy Initial Comments at 58.
\3234\ Clean Energy Associations Initial Comments at 77.
---------------------------------------------------------------------------
1703. EPRI states that article 9.7.3 of the pro forma LGIA could
benefit from additional modifications that differentiate between the
ride through requirements for synchronous and non-synchronous large
generating facilities because the two technologies have inherently
different technical capabilities and operating principles.\3235\
---------------------------------------------------------------------------
\3235\ EPRI Initial Comments at 11.
---------------------------------------------------------------------------
1704. [Oslash]rsted urges the Commission to take note of the
differences between technologies regarding their ability to ride
through transmission system faults.\3236\ For example, [Oslash]rsted
states that it uses a plant controller for wind turbines that is frozen
in fault ride through mode and that controls aiding voltage recovery
are performed by individual turbines until voltage profile is back
within a normal operating band of 90-110% of rated voltage.
---------------------------------------------------------------------------
\3236\ [Oslash]rsted Initial Comments at 16.
---------------------------------------------------------------------------
[Oslash]rsted concludes that not all non-synchronous generating
facilities are subject to the types of operating and power production
concerns highlighted by the Commission in the NOPR.
(4) Proposed Revisions to the Pro Forma LGIA
1705. [Oslash]rsted asserts that interconnection customers can only
``ensure'' ride through capability of the generating and
interconnection facilities per the definition in article 1 in the pro
forma LGIA. [Oslash]rsted contends that the Commission's use of the
term ``transmission system'' in article 9.7.3 of the pro forma LGIA is
unclear in this context, and thus [Oslash]rsted alleges that it will be
difficult to demonstrate compliance. Accordingly, [Oslash]rsted urges
the Commission to use the term ``generation and interconnection
facilities'' instead of ``transmission system'' in article 9.7.3 of the
pro forma LGIA.\3237\
---------------------------------------------------------------------------
\3237\ Id. at 18-19.
---------------------------------------------------------------------------
1706. [Oslash]rsted states that, in case of severe voltage dip,
IBRs may freeze in phase locked loop, essentially holding the
calculated angle of the external voltage at a certain value.\3238\
[Oslash]rsted argues that this makes IBR units not strictly
synchronized with the transmission system during this period.\3239\
Accordingly, [Oslash]rsted asks the Commission to remove the phrase
``stay synchronized'' from article 9.7.3 of the pro forma LGIA.
---------------------------------------------------------------------------
\3238\ A ``phase locked loop'' is a circuit that synchronizes an
output signal with a reference or input signal in frequency as well
as phase. Roland E. Best, Phase-Locked Loops: Design, Simulation and
Applications, at 1 (6th ed. McGraw-Hill 2007).
\3239\ [Oslash]rsted Initial Comments at 19.
---------------------------------------------------------------------------
(d) Requests for Clarification and Miscellaneous
1707. NV Energy questions the ramifications of non-synchronous
generating facilities failing to maintain a composite power delivery at
continuous rated power output at the high side of the generator
substation at a power factor within the range of 0.95 leading to 0.95
lagging.\3240\ NV Energy suggests in this circumstance the non-
synchronous generating facilities make a payment for failing to
maintain the tariff-required composite power delivery. NV Energy notes
that there is a pending reactive power rulemaking and inquires whether
the industry should assume that payments for reactive power will be
addressed in that rulemaking.
---------------------------------------------------------------------------
\3240\ NV Energy Initial Comments at 8.
---------------------------------------------------------------------------
1708. Eversource requests that the Commission clarify that
transmission providers may include additional performance requirements
in the LGIA appendices for non-synchronous generating facilities that
are necessary to
[[Page 61250]]
ensure reliable interconnection in a given area, such as harmonics or
radio frequency interference.\3241\
---------------------------------------------------------------------------
\3241\ Eversource Initial Comments at 38-39.
---------------------------------------------------------------------------
1709. Invenergy asserts that the Commission should not rely
entirely on ride through and other burdens on interconnection customers
to address larger transmission system issues that should be addressed
through regional transmission planning processes.\3242\
---------------------------------------------------------------------------
\3242\ Invenergy Initial Comments at 59.
---------------------------------------------------------------------------
1710. EPRI states that addressing how to apply grandfathering to
existing facilities is an important consideration that should be
addressed through Commission/NERC requirements. EPRI suggests that the
Commission could add a procedure and criteria for a transmission
provider to waive the grandfathering rule and require retrofits of
existing facilities at the time of plant changes, or upgrades to meet
the specified performance and modelling requirements, or to meet
specific capability and performance standards such as IEEE Standard
2800-2022.\3243\
---------------------------------------------------------------------------
\3243\ EPRI Initial Comments at 21-22.
---------------------------------------------------------------------------
iii. Commission Determination
1711. We adopt, with modifications, the NOPR proposal to revise
article 9.7.3 of the pro forma LGIA and article 1.5.7 of the pro forma
SGIA to establish 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, as set forth in the modified pro forma
LGIA language discussed below. We modify the proposed requirements to
acknowledge the physical limitations of newly interconnecting non-
synchronous generating facilities. In the NOPR, the Commission stated
that compliance with the NOPR proposal would be largely a control
settings issue and may not be costly. We are persuaded by comments that
contend that compliance with the NOPR proposal would be infeasible for
certain types of inverters and non-synchronous generating facilities,
and thus make modifications to address these concerns.
1712. Based on the record, we affirm the Commission's preliminary
finding in the NOPR that the pro forma LGIA and pro forma SGIA fail to
account for a non-synchronous generating facility's ability to engage
in momentary cessation. We note that the physical characteristics of
synchronous generating facilities result in such facilities continuing
to inject electric current during transmission system disturbances,
consistent with the existing requirements to remain ``connected to and
synchronized with the [t]ransmission [s]ystem'' as required by the pro
forma LGIA and pro forma SGIA. As a result of these requirements,
synchronous generating facilities continue to inject current during
such disturbances, such that services provided supporting transmission
system reliability are not disrupted during such events. However, the
existing pro forma LGIA and pro forma SGIA do not currently require
non-synchronous generating facilities to be capable of continuing to
inject current in a manner comparable to synchronous generating
facilities during system disturbances. As a result, non-synchronous
generating facilities often cease injecting current during transmission
system disturbances through ``momentary cessation.'' We agree with
commenters that such behavior by non-synchronous generating facilities
can pose significant risk to the reliability of the bulk-power system,
as documented in several reports and NERC-issued alerts.\3244\
---------------------------------------------------------------------------
\3244\ NERC Initial Comments at 9, 11 (citing NOPR, 179 FERC ]
61,194 at P 313 n.433 (citing San Fernando Disturbance, at vi (Nov.
2020), https://www.nerc.com/pa/rrm/ea/Documents/San_Fernando_Disturbance_Report.pdf; NERC and CAISO, Multiple Solar
PV Disturbances in CAISO (Apr. 2022), https://www.nerc.com/pa/rrm/ea/Documents/NERC_2021_California_Solar_PV_Disturbances_Report.pdf;
NERC, Odessa Disturbance (Sept. 2021) https://www.nerc.com/pa/rrm/ea/Documents/Odessa_Disturbance_Report.pdf)).
---------------------------------------------------------------------------
1713. Moreover, without requirements for non-synchronous generating
facilities to remain connected to and synchronized with the
transmission system, and not to engage in momentary cessation,
interconnection studies may not be able to accurately model expected
behavior and identify the appropriate interconnection facilities and
network upgrades to accommodate the interconnection request, resulting
in an inaccurate assignment of interconnection costs. As a result, we
find that the lack of comparable requirements for non-synchronous
generating facilities to have the capability 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.
1714. While a number of commenters object to the specific
provisions proposed in the NOPR to resolve this issue, addressed
further below, no commenter disagrees that there is a lack of
requirements in the pro forma LGIA and pro forma SGIA regarding the use
of momentary cessation by non-synchronous generating facilities.
Moreover, no commenter disputes the technical ability of non-
synchronous generating facilities to continue to inject current during
transmission system disturbances.
1715. Specifically, we require that 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, the non-synchronous generating facility
must ensure that, within any physical limitations of the generating
facility, its control and protection settings are configured or set to:
(1) continue active power production during disturbance and post
disturbance periods at pre-disturbance levels unless providing primary
frequency response or fast frequency response; \3245\ (2) minimize
reductions in active power and remain within dynamic voltage and
current limits, if reactive power priority mode is enabled, unless
providing primary frequency response or fast frequency response; (3)
not artificially limit dynamic reactive power capability during
disturbances; and (4) return to pre-disturbance active power levels
without artificial ramp rate limits if active power is reduced, unless
providing primary frequency response or fast frequency response.
---------------------------------------------------------------------------
\3245\ Fast frequency response is defined as power injected to
(or absorbed from) the grid in response to changes in measured or
observed frequency during the arresting phase of a frequency
excursion event to improve the frequency nadir or initial rate-of-
change of frequency. See Fast Frequency Response Concepts and Bulk
Power System Reliability Needs, https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts_and_BPS_Reliability_Needs_White_Paper.pdf at 7.
---------------------------------------------------------------------------
1716. In comparison to the NOPR proposal, this language, as
adopted, provides non-synchronous generating facilities, within any
physical limitations of the generating facility, the ability to reduce
active power production in order to prioritize reactive power output in
support of transmission system voltage.\3246\ This language also
recognizes that such facilities may not be able to ride through
disturbances with the same performance as synchronous generating
facilities without costly equipment modification. However, this
language requires non-synchronous generating facilities, within any
physical limitations of the generating facility, to configure or set
their facilities to ride through disturbances and continue to support
[[Page 61251]]
system reliability. This language is consistent with suggestions by a
number of commenters that the final rule recognize that non-synchronous
generating facilities cannot provide both real and reactive power at
pre-disturbance levels during a disturbance,\3247\ allow for the
prioritization of reactive power,\3248\ and address restoration of
active power output in the post-fault period.\3249\
---------------------------------------------------------------------------
\3246\ ``Active power'' as used here and ``real power'' as used
in the NOPR proposal refer to the same concept: power than can be
used by load in order to perform work.
\3247\ CAISO Initial Comments at 40; Clean Energy Associations
Initial Comments at 71-72; NERC at 4; EPRI Initial Comments at 10;
Invenergy Initial Comments at 58; [Oslash]rsted Initial Comments at
19-20; Public Interest Organizations Reply Comments at 14; Southern
Initial Comments at 34.
\3248\ Clean Energy Associations Initial Comments at 71-72;
Public Interest Organizations Reply Comments at 14; [Oslash]rsted
Initial Comments at 19-20.
\3249\ EPRI Initial Comments at 9-10; NERC Reply Comments at 4;
Clean Energy Associations Initial Comments at 76-77; Invenergy
Initial Comments at 58.
---------------------------------------------------------------------------
1717. The adopted language requires non-synchronous generating
facilities, within any physical limitations of the generating facility,
to configure or set their facilities to be able to ride through
disturbances and continuing to support system reliability.
Specifically, while grid-forming inverters are available, they are not
widely commercially deployed due to lack of experience, cost, or other
factors.\3250\ Given the existing technical capabilities of non-
synchronous generating facilities, we agree with commenters that the
NOPR proposal requiring active power to be maintained at pre-
disturbance levels during a system disturbance in all instances may not
be feasible, or preferrable from a reliability perspective. For
example, we agree there may be instances where the injection of
reactive power should be prioritized to maintain reliability during a
system disturbance, which may require non-synchronous generating
facilities to temporarily reduce their injection of active power.\3251\
As a result, we adopt a modified NOPR proposal to accommodate existing
technical capabilities and physical limitations of non-synchronous
generating facilities, by providing for reductions in active power to
prioritize reactive power while prohibiting non-synchronous generating
facilities from configuring or setting their control and protection
settings to effectively artificially limit such resources below their
actual capability.
---------------------------------------------------------------------------
\3250\ A grid-forming inverter is an inverter that is capable of
synthesizing voltage and frequency without an external reference.
See, e.g., Abraham Ellis, Grid Forming Inverters: Requirements and
Practical Applications, at 4 (May 1, 2019) https://www.osti.gov/servlets/purl/1639991.
\3251\ NERC Initial Comments at 23; CAISO Initial Comments at
40.
---------------------------------------------------------------------------
1718. We also adopt the NOPR proposal to revise article 9.7.3 of
the pro forma LGIA to include in the definition of ``ride through'' the
ability of the large generating facility to stay connected to and
synchronized with the transmission system during system disturbances
within under-voltage and over-voltage conditions. This revision ensures
that large generating facilities are capable of remaining connected to
and synchronized with the transmission system, consistent with the
other ride through requirements adopted here and similar requirements
in the pro forma SGIA.
1719. Some commenters request that the Commission either
incorporate IEEE Standard 2800-2022 by reference, or explicitly
incorporate this standard's performance requirements into the pro forma
LGIA. Although we acknowledge the value of IEEE 2800-2022, we decline
to incorporate it by reference. IEEE 2800-2022 was developed for a
different purpose; it is a voluntary guideline that uses discretionary
terms (e.g., ``may,'' ``should,'' ``can,'' or ``upon agreement''). It
is unclear whether IEEE 2800-2022 would adequately address the problem
identified by the Commission because the Commission would have limited
authority to enforce these discretionary provisions.
1720. Invenergy and Clean Energy Associations assert that the
Commission should impose similar ride through requirements on
synchronous generating facilities. Alternatively, Clean Energy
Associations assert that, to prevent undue discrimination, the
Commission should allow ride through performance exceptions for non-
synchronous generating facility trips caused by auxiliary equipment
performance, which are a primary cause of ride through failure for both
synchronous and non-synchronous generating facilities. We do not
believe that imposing similar ride through requirements on synchronous
generating facilities is necessary because the physical characteristics
of synchronous generating facilities result in such facilities
continuing to inject electric current during transmission system
disturbances, i.e., do not allow for momentary cessation.
1721. We also decline to grant Clean Energy Associations'
alternative request because we find that a ride through exception for
non-synchronous generating facility trips caused by auxiliary equipment
performance is not needed. As NERC has noted, protection on auxiliary
equipment for non-synchronous resources, other than the generator-
connected unit auxiliary transformer, is already exempted from the
requirements of NERC Reliability Standard PRC-024-3 specifically
because protection for such auxiliary equipment does not cause a
resource to trip or cease injecting current.\3252\ We do not believe
that auxiliary equipment performance is considered a physical
limitation of a non-synchronous generating facility such that control
and protection settings can be configured or set to reduce active power
production during disturbances, and therefore no exception is needed.
---------------------------------------------------------------------------
\3252\ Petition of the North American Reliability Corporation
for Approval of Proposed Reliability Standard PRC-024-3, Docket No.
RD20-7, at 12 (filed Mar. 20, 2020).
---------------------------------------------------------------------------
1722. Pine Gate asserts that the Commission should not adopt
requirements to the pro forma LGIP and pro forma SGIP that are already
being addressed by NERC through the standards development process. We
disagree because adding such provisions to the pro forma LGIA and pro
forma SGIA will require all newly interconnecting generating facilities
to abide by such provisions regardless of whether such newly
interconnecting generating facilities are outside the bounds of NERC's
jurisdiction. As such, we find that this modified reform can
holistically address the identified issues alongside the NERC
standards.
1723. NV Energy raises questions about the ramifications of non-
synchronous generating facilities failing to maintain reactive power
and whether the Commission is proposing any changes to reactive power
compensation. We clarify that the Commission is not proposing changes
to reactive power compensation in this proceeding.
1724. Invenergy argues that the Commission should not rely entirely
on ride through requirements and other burdens on interconnection
customers to address larger transmission system issues that should be
addressed through regional transmission planning processes. The need to
establish interconnection requirements for generating facilities to
``remain connected to and synchronized with the [t]ransmission
[s]ystem'' during system disturbances is properly addressed in this
proceeding that deals with reforming the interconnection processes for
newly interconnecting generating facilities. Regarding Invenergy's
arguments that larger transmission system issues need to be addressed
in the regional transmission planning processes, we note that while
reforms to regional transmission planning are
[[Page 61252]]
outside the scope of this proceeding, the Commission is considering
addressing regional transmission planning and cost allocation in
another pending proceeding.\3253\
---------------------------------------------------------------------------
\3253\ See Transmission Planning and Cost Allocation NOPR, 179
FERC ] 61,028 (2022).
---------------------------------------------------------------------------
1725. EPRI argues that the grandfathering of existing non-
synchronous generating facilities is an important consideration that
should be addressed through Commission and NERC requirements and
suggests that the Commission could add a procedure and criteria for a
transmission provider to waive the grandfathering rule and require
retrofits of existing non-synchronous generating facilities at the time
of plant changes or require upgrades to meet the specified performance
and modeling requirements. We decline to add the requested procedure.
The final rule changes to the pro forma LGIA and pro forma SGIA adopted
herein apply prospectively to interconnection customers that execute,
or request the unexecuted filing of, an LGIA after the Commission-
approved effective date of the transmission provider's filing in
compliance with this final rule. Both the NOPR proposal and the adopted
language were intended to be achieved through changes to control
settings at minimal cost for current inverter technology; it did not
contemplate imposing potentially significant retrofit or equipment
costs on existing non-synchronous generating facilities.\3254\
---------------------------------------------------------------------------
\3254\ NOPR, 179 FERC ] 61,194 at P 325.
---------------------------------------------------------------------------
1726. [Oslash]rsted requests clarification on how the NOPR proposal
will affect a plant controller for wind turbines that is frozen in
fault ride through mode and control actions aiding voltage recovery are
performed by individual turbines until the voltage profile returns to
the normal operating band of 90-110% of rated voltage. We note that the
reforms, as adopted, apply to a non-synchronous generating facility as
a whole, rather than to any individual component within the facility.
As long as the non-synchronous generating facility as a whole meets the
ride through requirements, it does not matter which part of the
facility is controlling the generating facility's output.
1727. [Oslash]rsted also notes that non-synchronous generating
facilities may freeze in phase locked loop during disturbances, making
them not strictly synchronized with the transmission system.
[Oslash]rsted asks the Commission to remove the phrase ``stay
synchronized'' from article 9.7.3 of the pro forma LGIA. We decline to
do so because the NOPR did not propose to revise this phrase and this
final rule establishes the specific ride through requirements for newly
interconnecting non-synchronous generating facilities.
1728. [Oslash]rsted recommends that instead of references in this
clause to ``good utility practice,'' the Commission should instead rely
on Order No. 842 and its definition of ``Bulk-Power System--Primary
Frequency Response.'' This comment refers to language not subject to
the Commission's proposed revisions and is therefore outside the scope
of this rulemaking proceeding. We also note that ``Bulk-Power System--
Primary Frequency Response'' refers to the title of Order No. 842, and
not any definition within.
c. Applicability of Ride Through Requirements
i. Need for Reform and NOPR Proposal
1729. In the NOPR, the Commission noted that generating facilities
interconnecting under the pro forma LGIA that are subject to
reliability standards are required to ride through frequency and
voltage disturbance events, while generating facilities that are not
already subject to reliability standards are not, despite the fact that
all generating facilities newly interconnecting under the pro forma
LGIA are technically capable of riding through disturbances.\3255\ The
Commission explained that there is an existing gap in the applicability
of ride through requirements for large generating facilities with a
capacity above 20 MW and with a gross plant/facility aggregate
nameplate rating of 75 MVA or less.\3256\ The Commission preliminarily
found that the pro forma LGIA requirements could result in unduly
discriminatory or preferential treatment due to this gap in the
applicability of ride through performance requirements to similarly
situated generating facilities.
---------------------------------------------------------------------------
\3255\ NOPR, 179 FERC ] 61,194 at P 326.
\3256\ Id. P 340.
---------------------------------------------------------------------------
1730. The Commission proposed to revise the pro forma LGIA to
require that all newly interconnecting large generating facilities
provide ride through capability consistent with any standards and
guidelines that are applied to other generating facilities in the
balancing authority area on a comparable basis.\3257\ The Commission
noted that the proposed reform is consistent with existing language in
article 1.5.7 of the pro forma SGIA that requires newly interconnecting
small generating facilities to ride through abnormal frequency and
voltage events and not disconnect during such events.
---------------------------------------------------------------------------
\3257\ Id.
---------------------------------------------------------------------------
1731. In addition to the substantive changes, the Commission
proposed to replace the term ``applicable reliability council'' with
``electric reliability organization,'' and replace the term ``control
area'' with ``balancing authority area'' throughout the pro forma LGIP
and pro forma LGIA. The Commission explained that these proposed
replacements reflect updated terminology.\3258\
---------------------------------------------------------------------------
\3258\ Id. P 341.
---------------------------------------------------------------------------
ii. Comments
1732. Several commenters support the NOPR proposal.\3259\ Enel
notes that the Commission's proposed definition of ``electric
reliability organization'' includes NERC, but it does not include the
applicable regional entity, which Enel asserts should be included
because the regional entity may have approved the regional reliability
standards.\3260\
---------------------------------------------------------------------------
\3259\ Ameren Initial Comments at 34; APPA-LPPC Initial Comments
at 33; CAISO Initial Comments at 39-40.
\3260\ Enel Initial Comments at 81.
---------------------------------------------------------------------------
iii. Commission Determination
1733. We adopt the NOPR proposal to revise the pro forma LGIA to
require 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.
Adopting this reform enables the Commission to address an existing gap
in the applicability of ride through requirements for large generating
facilities with a capacity above 20 MW and with a gross plant/facility
aggregate nameplate rating 75 MVA or less.
1734. Based on the record before us, we confirm the Commission's
preliminary finding in the NOPR that the pro forma LGIP is unduly
discriminatory or preferential insofar as generating facilities that
are not already subject to reliability standards are not required to
ride through frequency and voltage disturbance events, despite being
technically capable of doing so. We note that no commenter opposes this
reform.
1735. We also adopt the NOPR proposal to replace the term
``applicable reliability council'' with ``electric reliability
organization,'' and the term ``control area'' with ``balancing
authority area,'' throughout the pro forma LGIP and pro forma LGIA. In
response to Enel's concerns, we note that, while regional reliability
standards may be developed by the applicable
[[Page 61253]]
regional entity, the Commission has found that regional reliability
standards are considered part of the electric reliability
organization's set of reliability standards and are therefore covered
under the proposed definition.\3261\
---------------------------------------------------------------------------
\3261\ Order No. 672, 114 FERC ] 61,104, at P 296, order on
reh'g, Order No. 672-A, 114 FERC ] 61,328.
---------------------------------------------------------------------------
D. Issues Beyond the Scope of This Rulemaking
1. Comments
1736. Multiple commenters ask the Commission to consider additional
information or interconnection reforms not specifically raised in the
NOPR. For example, some commenters address foundational issues such as
generator retirement and/or replacement processes; \3262\ the
application of generator interconnection standards to merchant
transmission and HVDC projects; \3263\ conducting a root-cause
investigation of interconnection queue delays to identify and address
key barriers to bringing new generating facilities online; \3264\
initiating a technical conference to identify additional reforms to
meet present and future challenges; \3265\ establishing a process to
provide access to transmission data to third-party businesses; \3266\
introduction of competition into the interconnection process or
construction of network upgrades; \3267\ the introduction of project
prioritization to allocate scarce interconnection access; \3268\
changes to operational practices to reduce network upgrade
requirements; \3269\ and issues particular to different regions or
transmission providers.\3270\
---------------------------------------------------------------------------
\3262\ AEP Initial Comments at 43-44; Elevate Initial Comments
at 3-7, 8-11; Illinois Commission Initial Comments at 11; New York
State Department Reply Comments at 4.
\3263\ Invenergy Initial Comments at 64-65.
\3264\ Equinor Wind Reply Comments at 7.
\3265\ Pine Gate Reply Comments at 5.
\3266\ Tesla Initial Comments at 6, 8.
\3267\ Enel Initial Comments at 5, 52-56; Shell Reply Comments
at 5-18.
\3268\ Arizona Commission Initial Comments at 1; Colorado
Commission Initial Comments at 9.
\3269\ Clean Energy Associations Initial Comments at 64.
\3270\ Avangrid Initial Comments at 24-25; New York State
Department Initial Comments at 10; PJM Part 1 Reply Comments at 1;
Roy J Shanker Initial Comments at 2-7; Roy J Shanker Reply Comments
at 3-9; Southern Reply Comments at 8-9.
---------------------------------------------------------------------------
1737. Other commenters seek changes to tariff language such as
additional reforms specific to small generating facilities and the
small generator interconnection process; \3271\ explicitly stating that
interconnection terms may be subject to remedial waiver upon
appropriate Commission action; \3272\ requiring detailed information be
made available concerning either transmission congestion on
transmission providers' systems or technical information associated
with a particular point of interconnection; \3273\ clarifications to
the interconnection service types (i.e., energy-only or network
resource); \3274\ replacing power flow studies with security
constrained economic dispatch analysis for energy-only service studies;
\3275\ the three-year suspension option in the pro forma LGIA; \3276\
and additional pro forma LGIA language on termination and breach.\3277\
---------------------------------------------------------------------------
\3271\ Bonneville Initial Comments at 25; EPRI Initial Comments
at 24-38; Hydropower Commenters Initial Comments at 10-11; IREC
Initial Comments at 2-3; R Street Initial Comments at 9; and Xcel
Initial Comments at 19.
\3272\ OSPA Reply Comments at 14.
\3273\ CREA and NewSun Initial Comments at 21-22; [Oslash]rsted
Initial Comments at 5-6.
\3274\ Enel Initial Comments at 27-28; North Dakota Commission
Initial Comments at 7; R Street Initial Comments at 7; Tri-State
Initial Comments at 26; Xcel Initial Comments at 16.
\3275\ Enel Initial Comments at 73-75.
\3276\ El Paso Electric Initial Comments at 4-5.
\3277\ Tri-State Initial Comments at 34-35.
---------------------------------------------------------------------------
1738. Several commenters focus on process-specific reforms, such as
automation of the interconnection queue process to ease delays; \3278\
aligning the interconnection queue and the project development
processes; \3279\ interconnection study issues such as staffing to
conduct studies and study criteria and scope; \3280\ additional
transparency from transmission providers on the interconnection study
process, such as online interconnection queue tracking and performance
metrics; \3281\ and whether to implement an independent transmission
monitor or allow third parties to conduct interconnection studies to
reduce interconnection queue backlogs.\3282\
---------------------------------------------------------------------------
\3278\ CESA Initial Comments at 5; NextEra Initial Comments at
2.
\3279\ Enel Initial Comments at 2-4.
\3280\ Affected Interconnection Customers Initial Comments at
14-15; Clean Energy Associations Initial Comments at 27; CREA and
NewSun Initial Comments at 21-22; Cypress Creek Initial Comments at
3-8; New York State Department Initial Comments at 3.
\3281\ Public Interest Organizations Initial Comments at 23-25.
\3282\ Dominion Reply Comments at 22-24; EPSA Initial Comments
at 13-14; SDG&E Reply Comments at 2; Southern Reply Comments at 6-7;
ACORE Initial Comments at 5.
---------------------------------------------------------------------------
1739. Some commenters focus on network upgrade cost issues, in
particular the participant funding model currently in place in certain
RTOs/ISOs; \3283\ minimum thresholds for identifying network upgrades;
\3284\ a self-build option for stand-alone facilities; \3285\ and the
``good faith'' standard applied to cost and timeline estimates for
network upgrades and related transmission facilities.\3286\
---------------------------------------------------------------------------
\3283\ ACORE Initial Comments at 8; CREA and NewSun Initial
Comments at 93-104; NextEra Reply Comments at 3, 16; North Carolina
Commission and Staff Initial Comments at 2-16; OSPA Reply Comments
at 4-7; Public Interest Organizations Reply Comments at 13-14;
Senators Hickenlooper and King Initial Comments at 1-2.
\3284\ Enel Initial Comments at 2-4.
\3285\ CESA Initial Comments at 16-17; EEI Reply Comments at 14-
15; Interwest Initial Comments at 5.
\3286\ Pattern Energy Initial Comments at 14-15.
---------------------------------------------------------------------------
1740. Commenters raising resource-specific concerns address the
interconnection of qualifying facilities; \3287\ challenges specific to
the hydropower industry, including modifications to the readiness
standard and site control requirements; \3288\ steps to promote new
pumped storage projects; \3289\ using regional planning to develop
operating assumptions applied to the study of electric storage
resources; \3290\ and greater clarity on interconnection of battery
storage additions to existing and proposed generating facilities.\3291\
---------------------------------------------------------------------------
\3287\ CREA and NewSun Initial Comments at 104-106; Uda Law Firm
Initial Comments at 1-9.
\3288\ Hydropower Commenters Initial Comments at 7.
\3289\ Id. at 27-28.
\3290\ Interwest Reply comments at 15.
\3291\ SEIA Reply Comments at 21-22.
---------------------------------------------------------------------------
1741. Several commenters argue in favor of greater coordination
between generator interconnection and transmission planning \3292\ or
identify interconnection as a matter requiring interregional
planning.\3293\
---------------------------------------------------------------------------
\3292\ ACORE Initial Comments at 2-4; ACEG Initial Comments at
1-4; CESA Initial Comments at 13-14; Clean Energy Associations
Initial Comments at 10-11; Consumer Protection Coalition Reply
Comments at 1-2; Cypress Creek Initial Comments at 10-11; EDF
Renewables Initial Comments at 12-13; ELCON Initial Comments at 11-
13; Enel Reply Comments at 2; ENGIE Reply Comments at 4; Google
Initial Comments at 6-7, 22; Invenergy Initial Comments at 62-63;
Interwest Reply Comments at 15; National Grid Initial Comments at
45-46; New York State Department Reply Comments at 2-4; NYTOs
Initial Comments at 23-24; OSPA Reply Comments at 15; Pattern Energy
Initial Comments at 6-7; Public Interest Organizations Reply
Comments at 16; R Street Initial Comments at 6-7; Union of Concerned
Scientists Reply Comments at 8.
\3293\ North Carolina Commission and Staff Initial Comments at
2-3; Pattern Energy Initial Comments at 8-11.
---------------------------------------------------------------------------
1742. Some comments request that the Commission provide distinct
treatment for Native American energy projects by adopting rules and
policies that meet the unique needs of Tribes and that allow
alternative means for fulfilling interconnection requirements, such as
by providing additional time for the posting of deposits or eliminating
commercial readiness requirements.\3294\
[[Page 61254]]
Other comments request that the Commission incorporate environmental
justice considerations into the interconnection process by quantifying
in the proportional impact analysis the remediation of past economic
injustice and benefits of renewable development in impoverished areas
\3295\ or by prioritizing the provision of low-cost, clean energy to
low income and people of color communities under the FPA's public
interest standard.\3296\
---------------------------------------------------------------------------
\3294\ OSPA Reply Comments at 15-16.
\3295\ OSPA Initial Comments at 15-16; OSPA Reply Comments at 3.
\3296\ Energy Keepers Initial Comments at 3; Navajo Utility
Initial Comments at 13. Public Interest Organizations Reply Comments
at 11.
---------------------------------------------------------------------------
2. Commission Determination
1743. We consider the comments referenced in the section above to
be beyond the scope of this proceeding. The Commission proposed
specific reforms in the NOPR, to which commenters have responded and
for which a record has been established. Even for those issues
tangentially connected to NOPR proposals, the record here is inadequate
to support their full consideration. Further, we consider issues
regarding the coordination of transmission planning with generator
interconnection to be beyond the scope of this rulemaking. We note that
the Commission proposed reforms related to coordination between
regional transmission planning and cost allocation and generator
interconnection in Docket No. RM21-17-000.\3297\
---------------------------------------------------------------------------
\3297\ ANOPR, 176 FERC ] 61,024.
---------------------------------------------------------------------------
IV. Compliance Procedures
A. NOPR Proposal
1744. In the NOPR, the Commission proposed to require each
transmission provider to submit a compliance filing within 180 days of
the effective date of the final rule revising its LGIP, LGIA, SGIP, and
SGIA, as necessary, to demonstrate that it meets the requirements set
forth in the final rule.\3298\ The Commission also proposed to permit
appropriate entities to seek an ``independent entity variation'' or a
``regional reliability variation'' from the proposed
requirements.\3299\ The Commission further noted that some transmission
providers may have provisions in their existing LGIPs, LGIAs, SGIPs,
and SGIAs subject to the Commission's jurisdiction that the Commission
has previously deemed to be consistent with or superior to the pro
forma LGIP, pro forma LGIA, pro forma SGIP, and/or pro forma SGIA or
permissible under the independent entity variation standard or regional
reliability variation standard. Where these provisions would be
modified by the final rule, the Commission proposed to require
transmission providers to either comply with the final rule or
demonstrate that these previously approved variations continue to meet
the ``consistent with or superior to'' and ``regional reliability
variation'' standard for non-RTO/ISO transmission providers and the
independent entity variation standard for RTOs/ISOs.
---------------------------------------------------------------------------
\3298\ NOPR, 179 FERC ] 61,194 at P 342.
\3299\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 822-
827; Order No. 2006, 111 FERC ] 61,220 at PP 546-550).
---------------------------------------------------------------------------
1745. The Commission explained that it would assess whether each
compliance filing satisfies the proposed requirements and issue
additional orders as necessary to ensure that each transmission
provider meets the requirements of the final rule.\3300\
---------------------------------------------------------------------------
\3300\ Id. P 343.
---------------------------------------------------------------------------
1746. The Commission also proposed that non-public utility
transmission providers would have to adopt the proposed requirements as
a condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No.
888.\3301\
---------------------------------------------------------------------------
\3301\ Id. P 344.
---------------------------------------------------------------------------
B. Comments
1. Compliance Filing Deadline
1747. Consumers Energy and NRECA support the proposed requirement
for transmission providers to submit compliance filings within 180 days
of the effective date of a final rule in this proceeding.\3302\ NRECA
states that 180 days is a reasonable amount of time for transmission
providers to assess their generation portfolios and for interconnection
customers to gauge project viability and withdraw those interconnection
requests that are not commercially ready.\3303\ Consumers Energy
suggests that the Commission require RTOs/ISOs to justify any
individual extensions for compliance filings.\3304\ NRECA asks the
Commission to waive any existing withdrawal penalties during the period
between a final rule and compliance filings to encourage the rapid
withdrawal of speculative interconnection requests and the pursuit of
ready interconnection requests.\3305\
---------------------------------------------------------------------------
\3302\ Consumers Energy Initial Comments at 10; NRECA Initial
Comments at 7, 49.
\3303\ NRECA Initial Comments at 7, 49.
\3304\ Consumers Energy Initial Comments at 10.
\3305\ NRECA Initial Comments at 49.
---------------------------------------------------------------------------
1748. Some commenters argue that the Commission should provide a
longer time period for compliance filings because the scope and
complexity of the reforms will require substantial time and resources
and will involve lengthy stakeholder processes.\3306\ Some commenters
also note that transmission providers will need to balance other
priorities while developing compliance filings, such as administering
the interconnection queue and pursuing transmission planning
reforms.\3307\ Some commenters state that the 180-day period will be
difficult for large, multi-state RTOs/ISOs that must develop large-
scale tariff revisions in conjunction with large stakeholder
communities.\3308\ EEI suggests a 240-day deadline for compliance
filings,\3309\ while other commenters state that one year would be more
appropriate.\3310\
---------------------------------------------------------------------------
\3306\ Dominion Initial Comments at 6; EEI Initial Comments at
22; MISO Initial Comments at 126; NEPOOL Initial Comments at 12.
\3307\ EEI Initial Comments at 22; MISO Initial Comments at 126.
\3308\ Avangrid Initial Comments at 36-37; Dominion Initial
Comments at 41-42; MISO Initial Comments at 126.
\3309\ EEI Initial Comments at 22.
\3310\ Dominion Initial Comments at 6; MISO Initial Comments at
126.
---------------------------------------------------------------------------
1749. PJM asks the Commission to hold its compliance filing
obligation in abeyance until PJM completes the transition mechanism
from its recent interconnection queue reform in Docket No. ER22-2110-
000, which was the result of an 18-month stakeholder process.\3311\ PJM
states that, if it is required to submit a compliance filing during the
transition process, that will cast a cloud over the transition process
while the request for an independent entity variation works through a
prolonged regulatory process, bringing into doubt interconnection
agreements finalized as part of the transition and further aggravating
backlogs.\3312\ PJM explains that, when it completes this transition
process, it can evaluate whether to adopt the final rule's reforms or
demonstrate that its reforms are superior.\3313\ PJM asserts that such
a ``staged'' compliance process aligns with past Commission decisions
and would bring more certainty to interconnection customers.\3314\
---------------------------------------------------------------------------
\3311\ PJM Initial Comments at 2-5, 11; see also OPSI Initial
Comments at 2-3 (explaining that it will be crucial that this
proceeding does not disrupt PJM's ongoing interconnection queue
reform); see also PJM Interconnection, L.L.C., 181 FERC ] 61,162.
\3312\ PJM Initial Comments at 2, 5, 11.
\3313\ Id. at 12.
\3314\ Id. at 3 (citing, e.g., Order No. 890, 118 FERC ] 61,119
at P 135 (adopting a two-tiered implementation process of the final
rule)).
---------------------------------------------------------------------------
2. Regional Flexibility
1750. A number of commenters call for the final rule to provide
regional flexibility to account for differences in geography, state
policies and regulatory
[[Page 61255]]
frameworks, different network electrical characteristics, market
structures, resource mixes, and other factors.\3315\ Many commenters
explain that many transmission providers have already adopted or are in
the process of adopting some of the NOPR proposals or similar processes
targeting the challenges cited in the NOPR.\3316\ Many commenters ask
the Commission to ensure the final rule acknowledges and accommodates
existing interconnection queue reform efforts and does not undo or
disrupt progress.\3317\ Some commenters specifically ask the Commission
to allow transmission providers like PJM and Dominion to implement
recent interconnection queue reform proposals, even though they differ
in some aspects from the NOPR.\3318\ Some commenters ask the Commission
to continue applying its current standards for variations from the pro
forma LGIP (i.e., independent entity variations for RTOs/ISOs and
consistent with or superior to variations for non-RTOs/ISOs).\3319\ For
example, ISO-NE contends that the Commission should respect its
existing independent entity variations and allow it to continue
building upon those variations.\3320\
---------------------------------------------------------------------------
\3315\ APPA-LPPC Initial Comments at 2-3; Avangrid Initial
Comments at 36; Avangrid Reply Comments at 4; Dominion Reply
Comments at 4; EEI Initial Comments at 3-4; EEI Reply Comments at
13; Idaho Power Initial Comments at 1; Illinois Commission Comments
at 3; Indicated PJM TOs Initial Comments at 1-2; Indicated PJM TOs
Reply Comments at 43; ISO-NE Initial Comments at 3, 13, 15-16, 38;
MISO TOs Initial Comments at 13; NARUC Initial Comments at 6-7;
National Grid Initial Comments at 4-5; NEPOOL Initial Comments at 3-
4, 12, 17; NESCOE Reply Comments at 4; NRECA Initial Comments at 7;
NYTOs Initial Comments at 6; North Dakota Commission Initial
Comments at 2; Southern Initial Comments at 14-15; U.S. Chamber of
Commerce Initial Comments at 2-3.
\3316\ ACORE Reply Comments at 6; Alliant Initial Comments at 1;
Ameren Initial Comments at 35; APPA-LPPC Initial Comments at 2-3;
ClearPath Initial Comments at 6; Early Adopters Coalition Initial
Comments at 2, 13; EEI Initial Comments at 3-4; MISO Initial
Comments at 2-3, 18; MISO Reply Comments at 2; NARUC Initial
Comments at 10-11; National Grid Initial Comments at 4-5; NYISO
Reply Comments at 2; NYTOs Initial Comments at 6; Omaha Public Power
Initial Comments at 13; U.S. Chamber of Commerce Initial Comments at
2-3.
\3317\ ACORE Reply Comments at 6; Alliant Initial Comments at 1;
APPA-LPPC Initial Comments at 2-3; Ameren Initial Comments at 35;
Early Adopters Coalition Initial Comments at 2-3, 13, 19, 21;
Dominion Initial Comments at 42; Dominion Reply Comments at 4; Duke
Southeast Utilities Initial Comments at 3-4; Illinois Commission
Comments at 3; Indicated PJM TOs Initial Comments at 1-2; Indicated
PJM TOs Reply Comments at 9; MISO Initial Comments at 4-5, 18-19,
128; MISO TOs Initial Comments at 7-9; NARUC Initial Comments at 7,
11; National Grid Initial Comments at 4-5; NRECA Initial Comments at
8; NYTOs Initial Comments at 6; Omaha Public Power Initial Comments
at 13; OMS Initial Comments at 3-4; PacifiCorp Initial Comments at
2; U.S. Chamber of Commerce Initial Comments at 2-3.
\3318\ ClearPath Initial Comments at 6; Dominion Initial
Comments at 5-6; Indicated PJM TOs Initial Comments at 1-2; MISO
Reply Comments at 2; PJM Initial Comments at 2.
\3319\ Ameren Initial Comments at 35; Consumer Protection
Coalition Reply Comments at 2; EEI Initial Comments at 3; Google
Reply Comments at 7-8; Indicated PJM TOs Initial Comments at 9;
Indicated PJM TOs Reply Comments at 44; ISO-NE Initial Comments at
13-15; National Grid Initial Comments at 4-5; NEPOOL Initial
Comments at 3; NYTOs Initial Comments at 6; PG&E Initial Comments at
2; PG&E Reply Comments at 2; PJM Initial Comments at 3, 12.
\3320\ ISO-NE Initial Comments at 8-15 (providing a detailed
overview of ISO-NE's existing independent entity variations, which
align the interconnection process with the forward capacity market,
provide for targeted clustering, and allow interconnection customers
to pursue elective transmission upgrades to support queued
interconnection requests).
---------------------------------------------------------------------------
1751. In contrast, other commenters request that the Commission
apply a new standard when evaluating variations from the pro forma
requirements.\3321\ OMS asks the Commission to allow transmission
providers initiating their own stakeholder-supported interconnection
reforms to continue developing regionally appropriate solutions upon a
compliance showing of ``substantial conformity'' with the final rule
requirements.\3322\ MISO argues that the Commission should create an
``independent entity presumption of reasonableness,'' under which the
Commission would rebuttably presume that any previous, proactive RTO/
ISO reform that addresses the objectives of a final rule requirement
(but does not conform to every detail) is eligible for an independent
entity variation, unless an intervenor demonstrates that the previous
reform does not provide the benefit that technical compliance with the
final rule would.\3323\ NextEra also states that requiring transmission
providers and stakeholders to have to justify whether their past reform
initiatives match the Commission's new rule would likely waste time and
resources.\3324\
---------------------------------------------------------------------------
\3321\ MISO Initial Comments at 18-19.
\3322\ OMS Initial Comments at 4.
\3323\ MISO Initial Comments at 18-19.
\3324\ NextEra Reply Comments at 7.
---------------------------------------------------------------------------
1752. Similarly, the Early Adopters Coalition ask the Commission to
rebuttably presume that first-ready, first-served interconnection queue
reforms already in place continue to be just and reasonable and not
unduly discriminatory and consistent with or superior to the pro forma
requirements.\3325\ Further, the Early Adopters Coalition and Indicated
PJM TOs argue that there is an insufficient legal foundation under FPA
section 206 to conclude that the Early Adopters Coalition's tariffs are
unjust, unreasonable, and unduly discriminatory or preferential because
the Commission's FPA section 206 finding only speaks to the generic pro
forma requirements, while many transmission providers' tariffs have
already departed from those requirements.\3326\ Indicated PJM TOs state
that the Commission lacks the authority under FPA section 206 to
require modification of a tariff that does not include the elements
determined in the final rule to be unjust and unreasonable or unduly
discriminatory.\3327\
---------------------------------------------------------------------------
\3325\ Early Adopters Coalition Initial Comments at 18.
\3326\ Id. at 2, 15 (citing Emera Maine v. FERC, 854 F.3d 9, 25
(D.C. Cir. 2017)); Indicated PJM TOs Reply Comments at 8; PacifiCorp
Initial Comments at 6-7.
\3327\ Indicated PJM TOs Reply Comments at 7-9.
---------------------------------------------------------------------------
1753. The Early Adopters Coalition also express concern that the
proposed reforms would result in a higher burden of proof to justify
departures from the pro forma requirements in future filings and signal
that the Commission may not accept further incremental improvements;
therefore, they ask the Commission to clarify that the final rule will
not stifle their ability to improve their existing tariffs.\3328\
---------------------------------------------------------------------------
\3328\ Early Adopters Coalition Initial Comments at 21.
---------------------------------------------------------------------------
1754. PacifiCorp expresses concern that the NOPR proposal could
disrupt some of PacifiCorp's unique processes, including its inclusion
of small generating facilities in the cluster study process with large
generating facilities and its incorporation of the Commission-
jurisdictional interconnection process into its state-level
interconnection procedures.\3329\
---------------------------------------------------------------------------
\3329\ PacifiCorp Initial Comments at 7-9.
---------------------------------------------------------------------------
1755. CREA and NewSun contest PacifiCorp's and the other Early
Adopters Coalition's argument that the Commission's approval of their
LGIPs under FPA section 205 exempts them from any reforms adopted in a
final rule in this proceeding because the Commission has an obligation
under FPA section 206 to remedy unjust, unreasonable, and unduly
discriminatory or preferential practices.\3330\ CREA and NewSun also
note that neither utility- nor region-specific findings are necessary
in a generic rulemaking; rather, the Commission can rely on basic
economic theory and generic factual predictions.\3331\ CREA and NewSun
also
[[Page 61256]]
assert that the sole authority cited by the Early Adopters Coalition,
Emera Maine v. FERC, is inapposite, because it involved a challenge to
a specific transmission owners' base return on equity, not a nationwide
rulemaking.\3332\
---------------------------------------------------------------------------
\3330\ CREA and NewSun Reply Comments at 15-16.
\3331\ Id. at 17-18 (citing Transmission Access Policy Study
Grp. v. FERC, 225 F.3d 667, 687 (D.C. Cir. 2000), aff'd sub nom. New
York v. FERC, 535 U.S. 1, 14 (2002); Xcel Energy Servs. v. FERC, 41
F.4th 548, 560-61 (D.C. Cir. 2022)).
\3332\ Id. at 19.
---------------------------------------------------------------------------
1756. In response to requests for additional flexibility, Public
Interest Organizations and Clean Energy Associations assert that
transmission providers should be required to demonstrate in compliance
filings that their approach to a given requirement complies with the
Commission's final rule.\3333\
---------------------------------------------------------------------------
\3333\ Clean Energy Associations Reply Comments at 11; Public
Interest Organizations Reply Comments at 14.
---------------------------------------------------------------------------
1757. Xcel asks the Commission to state in the final rule that
there is not just one just and reasonable approach to interconnection
reform.\3334\ Xcel requests that the Commission confirm that
alternative approaches used by RTOs/ISOs that achieve the policy goals
of prioritizing ready interconnection requests and increasing the speed
of interconnection queue processing are consistent with and superior to
the pro forma LGIP, instead of using the independent entity variation
standard when approving those RTOs/ISOs' compliance filings. Xcel
explains that its preferred approach would allow non-RTOs/ISOs to
replicate processes that are working efficiently in RTOs/ISOs.
---------------------------------------------------------------------------
\3334\ Xcel Initial Comments at 17.
---------------------------------------------------------------------------
1758. ACORE expresses concern that too much flexibility would
detract from the benefits of a final rule.\3335\ ACORE explains that a
consistent minimum set of requirements and common interconnection study
methods and best practices is essential across all transmission
providers.
---------------------------------------------------------------------------
\3335\ ACORE Reply Comments at 6.
---------------------------------------------------------------------------
3. Reciprocity Tariffs
1759. APPA-LPPC and NRECA seek clarification on the NOPR's
statements regarding reciprocity tariffs.\3336\ They point out that
Commission precedent allows non-public utilities to satisfy the
reciprocity requirement of Order No. 888 through one of three means:
(1) providing service to a public utility transmission provider under a
safe harbor tariff; (2) providing service under a bilateral agreement;
or (3) seeking waiver.\3337\ APPA-LPPC and NRECA explain that the
NOPR's statement that non-public utility transmission providers ``will
have to adopt the requirements of this Proposed Rule as a condition of
maintaining the status of their safe harbor tariff or otherwise
satisfying the reciprocity requirement of Order No. 888'' could be read
to suggest that the other ways of satisfying the reciprocity
requirement no longer exist.\3338\ APPA-LPPC and NRECA ask the
Commission to clarify that non-public utilities will still be able to
satisfy reciprocity requirements through bilateral arrangements or
waiver.
---------------------------------------------------------------------------
\3336\ APPA-LPPC Initial Comments at 34-36; NRECA Initial
Comments at 10, 50.
\3337\ APPA-LPPC Initial Comments at 34; NRECA Initial Comments
at 50.
\3338\ APPA-LPPC Initial Comments at 36; NRECA Initial Comments
at 51.
---------------------------------------------------------------------------
4. Effective Date
1760. MISO asks the Commission to make the reforms effective when
orders on compliance are issued, rather than on the final rule's
effective date, to avoid retroactive implementation of the proposed
reforms and disruption in administering interconnection queues.\3339\
MISO explains that an effective date prior to the date of accepted
compliance provisions would require a transmission provider to file new
agreements with pending language, which means that transmission
providers will need to file interconnection agreements and service
agreements instead of using the electronic quarterly report (EQR)
process.
---------------------------------------------------------------------------
\3339\ MISO Initial Comments at 127; MISO Reply Comments at 27.
---------------------------------------------------------------------------
5. Miscellaneous
1761. SoCal Edison states that the final rule should not
automatically apply to a wholesale distribution access tariff without
further consideration in a separate rulemaking.\3340\ SoCal Edison
argues that the Commission should allow entities to align distribution-
level tariffs with corresponding transmission-level tariffs to avoid
gaming of interconnection locations and contends that the changes
proposed in this NOPR are too extensive to apply to the unique
characteristics of the distribution system.\3341\ SoCal Edison states
that the Commission has previously confirmed that reforms to the LGIP
and LGIA are not required for the interconnection agreements under the
wholesale distribution access tariff, and different processes,
interconnection costs, and penalties could introduce new challenges for
wholesale distribution providers and interconnection efficiencies that
have not been addressed in the NOPR.
---------------------------------------------------------------------------
\3340\ SoCal Edison Initial Comments at 10; SoCal Edison Reply
Comments at 2.
\3341\ SoCal Edison Initial Comments at 10-11.
---------------------------------------------------------------------------
C. Commission Determination
1762. We modify the deadline for transmission providers to submit a
compliance filing to adopt the requirements of this final rule as
revisions to the LGIP, LGIA, SGIP, and SGIA in their tariffs. We
require the submission of such compliance filings within 90 calendar
days of the publication date of this final rule in the Federal Register
rather than the proposed 180 days from the effective date of the final
rule. We believe that it is important to implement this final rule in a
timely manner, given the pressing need to reform the interconnection
processes, as discussed in this final rule. On the Commission-approved
effective date of the transmission provider's compliance filing with
this final rule, the transmission provider will commence the transition
study process.\3342\ After the conclusion of the transition study
process, the transmission provider will begin the first standard
cluster study process,\3343\ and in its compliance filing, the
transmission provider will indicate the number of calendar days after
the conclusion of the transition study process when it will begin this
first standard cluster study process (e.g., 30 calendar days after the
conclusion of the transition study process).\3344\ By setting a 90-
calendar day compliance filing deadline, the Commission may be in a
position to act on the filings sooner, which will allow transmission
providers to commence the transition process and progress to the first
standard cluster study process earlier, and thereby implement the
reforms contemplated by this final rule earlier rather than later.
---------------------------------------------------------------------------
\3342\ Pro forma LGIP section 5.1.1.1 (Transitional Serial
Study); Pro forma LGIP section 5.1.1.2 (Transitional Cluster Study).
\3343\ We note that this standard cluster study process is
distinct from the transitional cluster study process described
above. See supra section III.A.7.c.
\3344\ Pro forma LGIP section 3.4.1 (Cluster Request Window).
---------------------------------------------------------------------------
1763. We note that 90 days is longer than the 60 days provided for
compliance with Order No. 2003. In their compliance filings for Order
No. 2003, transmission providers were required to adopt the pro forma
LGIP and pro forma LGIA. Under this final rule, transmission providers
are required to revise the LGIP, LGIA, SGIP, and SGIA in their tariffs,
but are not provided significant discretion as to the terms of those
documents, except for those who request deviations, as discussed below.
While we recognize that the compliance filings for some transmission
providers will entail more complexity, we believe that 90 calendar
[[Page 61257]]
days should be sufficient time to prepare and submit even the more
complex compliance filings. Further, the need to implement the reforms
set forth in this final rule earlier rather than later outweighs the
concerns raised about the timing of the compliance filing deadline.
1764. Consistent with Order Nos. 888, 890, 2003, 2006, and 845, we
adopt 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 this final
rule.\3345\ Consistent with Order Nos. 2003, 2006, and 845, we adopt
the NOPR proposal to continue to use the ``independent entity
variation'' standard when considering such proposals from RTOs/
ISOs.\3346\ Consistent with Order Nos. 888, 890, 2003, 2006, and 845,
we adopt 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 reliability
requirements.\3347\ In this final rule, we make no changes to the
standards used to judge requested variations, as described in Order
Nos. 888, 890, 2003, 2006, and 845.
---------------------------------------------------------------------------
\3345\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,769-
770; Order No. 890, 118 FERC ] 61,119 at P 109 (``[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).
\3346\ 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.
\3347\ 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.
---------------------------------------------------------------------------
1765. We reject requests to presume that any transmission
provider's tariff meets the requirements of this final rule. 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 discussed above, which the Commission will consider on a
case-by-case basis.
1766. We disagree with commenters that suggest that FPA section 206
requires the Commission to make findings specific to each transmission
provider's tariff in this final rule to require transmission providers
to comply with the requirements of this final rule. As some commenters
recognize, neither utility- nor region-specific findings are necessary
in a generic rulemaking.\3348\
---------------------------------------------------------------------------
\3348\ See Transmission Access Policy Study Grp., 225 F.3d at
687-88.
---------------------------------------------------------------------------
1767. In response to commenters that prefer regional reform over
generic one-size-fits-all reform, we note that transmission providers
may seek the appropriate variation on compliance provided the reason
for the variation is sufficiently justified and may continue to propose
solutions to interconnection issues under FPA section 205. However,
given the nation-wide need for reforms to ensure that interconnection
customers are able to interconnect to the transmission system in a
reliable, efficient, transparent, and timely manner, as well as prevent
undue discrimination, we believe that a generic rulemaking is
appropriate, as explained above in section II and throughout this final
rule.
1768. In the NOPR, the Commission stated that non-public utility
transmission providers ``will have to adopt the requirements of this
Proposed Rule as a condition of maintaining the status of their safe
harbor tariff or otherwise satisfying the reciprocity requirement of
Order No. 888.'' \3349\ As requested by NRECA and APPA-LPPC,\3350\ we
clarify that this final rule does not modify the Commission's
reciprocity requirement in Order Nos. 888 and 2003.\3351\ Thus, while a
non-public utility's adoption of the proposed LGIP/LGIA and SGIP/SGIA
changes is a condition of maintaining a safe harbor tariff,\3352\ non-
public utilities may still use a request for waiver or bilateral
agreements to satisfy the reciprocity requirement of Order No. 888-
A.\3353\
---------------------------------------------------------------------------
\3349\ NOPR, 179 FERC ] 61,194 at P 344.
\3350\ APPA-LLC Initial Comments at 34-36; NRECA Initial
Comments at 50-51.
\3351\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,760-
761; Order No. 2003, 104 FERC ] 61,103 at PP 840-842.
\3352\ Order No. 2003, 104 FERC ] 61,103 at P 842 (``A non-
public utility that has a `safe harbor' Tariff may add to its Tariff
an interconnection agreement and interconnection procedures that
substantially conform or are superior to the Final Rule LGIP and
Final Rule LGIA if it wishes to continue to qualify for safe harbor
treatment.'')
\3353\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,285-
86; see also Order No. 2003, 104 FERC ] 61,103 at P 841; Order No.
2003-A, 106 FERC ] 61,220 at P 760 (clarifying that reciprocity
applies to interconnection service in a manner consistent with the
reciprocity provision in the pro forma open access transmission
tariff); Order No. 2006, 111 FERC ] 61,220 at P 534.
---------------------------------------------------------------------------
1769. With respect to MISO's comments, as explained below, this
final rule is effective November 6, 2023. This final rule will be
effective as described above; however, the pro forma LGIP, pro forma
LGIA, pro forma SGIP, and pro forma SGIP requirements in transmission
providers' tariffs will not be effective until the Commission-approved
effective date of the transmission provider's filing in compliance with
this final rule. In other words, interconnection customers seeking to
interconnect to MISO's transmission system will not be subject to the
requirements of this final rule until the Commission issues an order on
MISO's compliance filing with a Commission-approved effective date for
MISO's tariff revisions.
1770. In response to SoCal Edison's request for the Commission to
clarify that the reforms described herein will not automatically apply
to wholesale distribution access tariffs, we note that in Order No.
2003, the Commission stated that the pro forma LGIA and pro forma LGIP
adopted in that final rule apply to a request to interconnect to a
public utility's ``distribution'' facilities used to transmit electric
energy in interstate commerce on behalf of a wholesale purchaser
pursuant to a Commission-filed open access transmission tariff.\3354\
To the extent that SoCal Edison has concerns about its specific
wholesale distribution access
[[Page 61258]]
tariff, this is a matter better suited to SoCal Edison's compliance
filing.\3355\
---------------------------------------------------------------------------
\3354\ See Order No. 2003, 104 FERC ] 61,103 at P 804; id. P 803
(some lower-voltage facilities are ``local distribution'' facilities
not under our jurisdiction, but some are used for jurisdictional
service such as carrying power to a wholesale power customer for
resale and are included in a public utility's open access
transmission tariff (although in some instances, there is a separate
open access transmission tariff rate for using them, sometimes
called a wholesale distribution rate.)); Order No. 2003-A, 106 FERC
] 61,220 at P 733 (``We clarify that Order No. 2003 applies to all
facilities subject to a Commission-approved [open access
transmission tariff], regardless of how the facilities may be
labeled by the Transmission Provider) (citing N. Y. v. FERC, 535
U.S. at 12; Puget Sound Energy, Inc., 104 FERC ] 61,272, at PP 16-18
(2003)).
\3355\ See Order No. 2003-A, 106 FERC ] 61,220 at P 734. We
note, however, that the Commission has previously accepted SoCal
Edison's filing, made in compliance with Order No. 2003, to
implement provisions from the Commission's pro forma LGIA and pro
forma LGIP into its wholesale distribution access tariff. See S.
Cal. Edison Co., 110 FERC ] 61,176 (2005).
---------------------------------------------------------------------------
1771. We also note that, in addition to the modifications described
above, the pro forma LGIP, pro forma LGIA, pro forma SGIP, pro forma
SGIP language below includes several corrections of clerical errors and
other minor, clarifying edits: see, e.g., pro forma LGIA article 8.4,
pro forma LGIP appendix G.
V. Information Collection Statement
1772. The information collection requirements contained in this
final rule are subject to review by the Office of Management and Budget
(OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\3356\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\3357\ Respondents
subject to the filing requirements of this final rule will not be
penalized for failing to respond to the collection of information
unless the collection of information displays a valid OMB control
number.
---------------------------------------------------------------------------
\3356\ 44 U.S.C. 3507(d).
\3357\ 5 CFR 1320.11 (2022).
---------------------------------------------------------------------------
1773. The reforms adopted in this final rule revise the
Commission's standard large generator interconnection procedures and
agreements (i.e., the pro forma LGIP and pro forma LGIA) and the
Commission's standard small generator interconnection procedures and
agreement (i.e., the pro forma SGIP and pro forma SGIA) that every
public utility transmission provider is required to include in their
tariff under Sec. 35.28 of the Commission's regulations.\3358\ This
final rule requires each transmission provider to amend the standard
large generator interconnection procedures and agreement and the
standard small generator interconnection procedures and agreement in
its tariff to implement the reforms adopted in this final rule, which
are intended to ensure that the generator interconnection process is
just, reasonable, and not unduly discriminatory or preferential. These
provisions affect the following collections of information: FERC-516,
Electric Rate Schedules and Tariff Filings (Control No. 1902-0096); and
FERC-516A, Standardization of Small Generator Interconnection
Agreements and Procedures (Control No. 1902-0203).
---------------------------------------------------------------------------
\3358\ 18 CFR 35.28(f)(1) (2022).
---------------------------------------------------------------------------
1774. In the NOPR, the Commission solicited comments on: the
Commission's need for this information; whether the information will
have practical utility; the accuracy of the burden estimates; ways to
enhance the quality, utility, and clarity of the information to be
collected or retained; and any suggested methods for minimizing
respondents' burden. In response to comments on the NOPR,\3359\ we note
that this information collection statement estimates only those burdens
\3360\ to generate, maintain, retain, or disclose or provide
information to or for a Federal agency, and does not intend to estimate
overall compliance or implementation costs for transmission providers.
---------------------------------------------------------------------------
\3359\ Indicated PJM TOs state that the NOPR did not attempt to
quantify the administrative burden for the transmission provider's
staff to perform the tasks required by the proposed reforms, and SPP
offered an estimated range of its potential costs of administering
the proposed procedures. See Indicated PJM TOs Initial Comments at
7; SPP Initial Comments at 28; see also NOPR, 179 FERC ] 61,194 at P
358 & n.480.
\3360\ ``Burden'' is the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. For
further explanation of what is included in the information
collection burden, refer to 5 CFR 1320.3 (2022).
---------------------------------------------------------------------------
1775. Summary of the Revisions to the Collection of Information due
to the final rule in Docket No. RM22-14-000:
FERC-516: This final rule revises the Commission's pro
forma LGIP and pro forma LGIA (and thus requires each public utility to
amend its LGIP and LGIA) to ensure that interconnection customers are
able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner, and prevent undue
discrimination. As illustrated in the table below, most reforms affect
the pro forma LGIP and pro forma LGIA.
FERC-516A: Among other requirements, this final rule
amends the Commission's standard small generator interconnection
procedures and agreement (i.e., the pro forma SGIP and pro forma SGIA)
regarding evaluation of alternative transmission technologies, modeling
required for accurate interconnection studies, and maintenance of power
production during abnormal frequency conditions and certain voltage
conditions.
Title: Electric Rate Schedules and Tariff Filings (FERC-
516) and Standardization of Small Generator Interconnection Agreements
and Procedures (FERC-516A).
Action: Revision of collections of information in
accordance with Docket No. RM22-14-000.
OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0203
(FERC-516A).
Respondents: Public utility transmission providers,
including RTOs/ISOs.
Frequency of Information Collection: One time during Year
1. Multiple times during subsequent years.
Necessity of Information: The reforms in this final rule
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner, and prevent undue discrimination. The reforms are intended to
ensure that the generator interconnection process is just, reasonable,
and not unduly discriminatory or preferential.
Internal Review: We have reviewed the reforms that impose
information collection burdens and have determined that such reforms
are necessary. These requirements conform to the Commission's need for
efficient information collection, communication, and management within
the energy industry. We have specific, objective support for the burden
estimates associated with the information collection requirements.
Public Reporting Burden: Our estimate of the number of
reporting entities is based on the number of transmission providers
that submitted compliance filings to the Commission in response to
Order No. 845, which is the Commission's most recent rulemaking that
required transmission providers to revise their generator
interconnection procedures and agreements, and Order No. 881, which is
the Commission's most recent major rulemaking adopting reforms to the
pro forma tariff. As such, we estimate that 44 transmission providers,
including RTOs/ISOs, will be subject to this rulemaking. The burden and
cost estimates below are based on (1) the initial need for transmission
providers to file revised versions of the standard interconnection
procedures and agreements in Year 1 and (2) ongoing information
collection activities in connection with reporting and disclosure
requirements in subsequent years. For many reforms, we estimate no
ongoing information collection burden because there is either no
information collection aspect of the reform or the requirements would
merely supplant existing ones.
1776. The Commission estimates that the final rule in Docket No.
RM22-14-000 will adjust the burden and cost of FERC-516 and FERC-516A
as follows:
[[Page 61259]]
Table 1--Information Collection Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Changes due to Final Rule in Docket No. RM22-14-000
---------------------------------------------------------------------------------------------------------------------------------------------------------
Annual number of Average burden (hr.) & Total annual burden
Reforms Number of responses per Total number of cost ($) per response hours & total annual
respondents respondent responses (rounded) \3361\ cost ($) (rounded)
(1) (2).................... (1) * (2) = (3)....... (4)................... (3) * (4) = (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC-516
--------------------------------------------------------------------------------------------------------------------------------------------------------
Interconnection Information Access.. 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 2............. Ongoing: 88........... Ongoing: 4 hr; $364... $16,016
Ongoing: 352 hr;
$32,032
First Ready, First Served Cluster 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Study Process. Ongoing: 4............. Ongoing: 176.......... Ongoing: 4 hr; $364... $320,320
Ongoing: 704 hr;
$64,064
Allocation of Cluster Study Costs... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Allocation of Cluster Network 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Upgrade Costs. Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Study Deposits and LGIA Deposit..... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Demonstration of Site Control....... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $320,320
Ongoing: 0
Commercial Readiness................ 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Withdrawal Penalties................ 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Transition Process.................. 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $320,320
Ongoing: 0
Elimination of Reasonable Efforts 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Standard.\3362\. Ongoing: 4............. Ongoing: 176.......... Ongoing: 4 hr; $364... $320,320
Ongoing: 704 hr;
$64,064
Affected System Study Process....... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Ongoing: 0............. Ongoing: 44........... Ongoing: 0............ $320,320
Ongoing: 0
Affected System Pro Forma Agreements 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Affected System Modeling and Study 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Assumptions. Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Co-Located Generating Facilities 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Behind One Point of Interconnection Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
with Shared Interconnection Ongoing: 0
Requests.
Revisions to Modification to Require 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Consideration of Generating Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $320,320
Facility Additions. Ongoing: 0
Availability of Surplus 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Interconnection Service. Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Operating Assumptions for 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Interconnection Studies. Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $320,320
Ongoing: 0
Incorporating Enumerated Alternative 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Transmission Technologies into the Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $320,320
Generator Interconnection Process. Ongoing: 0
Modeling Requirements............... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Ride-Through Requirements........... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Applicability of Ride-Through 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Requirements. Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
-------------------------------------------------------------------------------------------------------------------
Total New Burden for FERC-516 ................. Year 1: 924 Ongoing: 1,760 hr; $160,160
(due to Docket No. RM22-14-000).
Year 1: 30,448 hr; $2,770,768 Ongoing: 484
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 61260]]
FERC-516A
--------------------------------------------------------------------------------------------------------------------------------------------------------
Incorporating Enumerated Alternative 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 80 hr; $7,280. Year 1: 3,520 hr;
Transmission Technologies into the Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $320,320
Generator Interconnection Process. Ongoing: 0
Modeling Requirements............... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
Ride-Through Requirements........... 44 (TPs) Year 1: 1.............. Year 1: 44............ Year 1: 4 hr; $364.... Year 1: 176 hr;
Ongoing: 0............. Ongoing: 0............ Ongoing: 0............ $16,016
Ongoing: 0
-------------------------------------------------------------------------------------------------------------------
Total New Burden for FERC-516A ................. Year 1: 132 responses Ongoing: 0
(due to Docket No. RM22-14-000).
Year 1: 3,872 hr; $352,352 Ongoing: 0
-------------------------------------------------------------------------------------------------------------------
Grand Total (FERC-516 plus ................. Year 1: 1,056 Ongoing: 484
FERC-516A, including all
respondents).
Year 1: 34,320 hr; $3,123,120 Ongoing:
1,760 hr; $160,160
-------------------------------------------------------------------------------------------------------------------
Grand Total Average Per ................. ....................... ...................... Year 1: $70,980 Ongoing: $3,640
Entity Cost (44 TPs).
--------------------------------------------------------------------------------------------------------------------------------------------------------
1777. In this final rule, after accounting for the adjustments and
inputs noted above, updated labor costs, and reforms not being adopted,
the Commission used the numbers provided in the NOPR for all reforms
being adopted.
---------------------------------------------------------------------------
\3361\ Commission staff estimate that respondents' hourly wages
plus benefits are comparable to those of FERC employees. Therefore,
the hourly cost used in this analysis is $91 per hour ($188,922 per
year).
\3362\ Commission staff only estimates the information
collection burden associated with the requirements outlined in the
final rule and does not estimate the potential appeal process
burden, which an applicant can pursue voluntarily.
---------------------------------------------------------------------------
1778. Interested persons may obtain information on the reporting
requirements by contacting Ellen Brown, Office of the Executive
Director, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 via email ([email protected]) or telephone
((202) 502-8663).
VI. Environmental Analysis
1779. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\3363\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this final rule under Sec.
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts, and regulations that affect rates, charges, classification,
and services.\3364\
---------------------------------------------------------------------------
\3363\ Regulations Implementing the National Environmental
Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regs. Preambles 1986-1990 ] 30,783 (1987) (cross-referenced at 41
FERC ] 61,284).
\3364\ 18 CFR 380.4(a)(15) (2022).
---------------------------------------------------------------------------
VII. Regulatory Flexibility Act
1780. The Regulatory Flexibility Act of 1980 \3365\ requires a
description and analysis of proposed and final rules that will have
significant economic impact on a substantial number of small entities.
The Small Business Administration (SBA) sets the threshold for what
constitutes a small business. Under SBA's size standards,\3366\
transmission providers and RTOs/ISOs fall under the category of
Electric Bulk Power Transmission and Control (North American Industry
Classification System (NAICS) code 221121), that has a size threshold
of under 950 employees (including the entity and its associates).\3367\
---------------------------------------------------------------------------
\3365\ 5 U.S.C. 601-612.
\3366\ 13 CFR 121.201 (2022).
\3367\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administration's regulations define the threshold for
a small Electric Bulk Power Transmission and Control entity (NAICS
code 221121) to be 950 employees (``the maximum allowed for a
concern and its affiliates to be considered small''). See 13 CFR
121.201 (2022); see also 5 U.S.C. 601(3) (citing to section 3 of the
Small Business Act, 15 U.S.C. 632).
---------------------------------------------------------------------------
1781. We estimate that there are 44 transmission providers affected
by the reforms proposed in this final rule. Furthermore, we estimate
that 6 of the 44 total transmission providers, approximately 14%
(rounded), are small entities.
1782. We estimate that one-time costs (in Year 1) associated with
the reforms required by this final rule for one transmission provider
(as shown in the table above) would be $70,980. Following Year 1, we
estimate that the annual ongoing costs for one transmission provider
would be $3,640. According to SBA guidance, the determination of
significance of impact ``should be seen as relative to the size of the
business, the size of the competitor's business, and the impact the
regulation has on larger competitors.'' \3368\ We do not consider the
estimated cost to be a significant economic impact. As a result, we
certify that the reforms proposed in this final rule would not have a
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------
\3368\ U.S. Small Business Administration, A Guide for
Government Agencies How to Comply with the Regulatory Flexibility
Act, at 18 (Aug. 2017), https://cdn.advocacy.sba.gov/wp-content/uploads/2019/06/21110349/How-to-Comply-with-the-RFA.pdf.
---------------------------------------------------------------------------
VIII. Document Availability
1783. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the
[[Page 61261]]
Commission's Home Page (https://www.ferc.gov).
1784. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number in the docket number field. User assistance is
available for eLibrary and the Commission's website during normal
business hours from the Commission's Online Support at (202) 502-6652
(toll free at 1-866-208-3676) or email at [email protected],
or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659.
Email the Public Reference Room at [email protected].
IX. Effective Date and Congressional Notification
1785. The final rule is effective November 6, 2023. The Commission
has determined, with the concurrence of the Administrator of the Office
of Information and Regulatory Affairs of OMB, that this rule is a
``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission. Commissioner Danly is concurring with a separate
statement attached.
Commissioner Clements is concurring with a separate statement
attached.
Commissioner Christie is concurring with a separate statement
attached.
Issued: July 28, 2023.
Kimberly D. Bose,
Secretary.
In consideration of the foregoing, the Commission amends part 35,
chapter I, title 18, Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
0
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
0
2. Amend Sec. 35.28 by adding paragraph (f)(1)(ii) to read as follows:
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(f) * * *
(1) * * *
(ii) Any public utility that conducts interconnection studies shall
be liable for and eligible to appeal certain penalties under the
interconnection procedures and agreements adopted by the Commission-
approved independent system operator or regional transmission
organization under paragraph (f)(1) of this section following that
public utility's failure to complete an interconnection study by the
appropriate deadline.
* * * * *
NOTE: The following appendices will not appear in the Code of
Federal Regulations.
Appendix A: Abbreviated Names of Commenters
------------------------------------------------------------------------
------------------------------------------------------------------------
Americans for a Clean Energy Grid............... ACEG.
Alliance for Clean Energy-New York.............. ACE-NY.
American Council on Renewable Energy............ ACORE.
Associated Electric Cooperative, Inc............ AECI.
Advanced Energy Economy......................... AEE.
American Electric Power Service Corporation..... AEP.
AES Clean Energy Development, LLC............... AES.
Acciona Energy USA Global LLC; Copenhagen Affected
Infrastructure IV K/S; Hecate Energy LLC; Interconnection
Leeward Renewable Energy Development, LLC; and Customers.
Tri Global Energy, LLC.
Allen Meyer..................................... Allen Meyer.
Alliant Energy Corporate Services, Inc.......... Alliant Energy.
Amazon Energy LLC............................... Amazon.
Ameren Services Company......................... Ameren.
Ampjack Industries Ltd.......................... Ampjack.
Anbaric Development Partners, LLC............... Anbaric.
American Public Power Association and Large APPA-LPPC.
Public Power Council.
Apple Inc....................................... Apple.
Arizona Public Service Company.................. APS.
Arizona Corporation Commission.................. Arizona Commission.
Avangrid, Inc................................... Avangrid.
Bonneville Power Administration................. Bonneville.
Bretton C Little................................ Bretton C Little.
California Independent System Operator CAISO.
Corporation.
California Energy Storage Alliance.............. CESA.
The American Clean Power Association and RENEW Clean Energy
Northeast. Associations.
Clean Energy Buyers Association................. Clean Energy Buyers.
Clean Energy States Alliance.................... Clean Energy States.
ClearPath, Inc.................................. ClearPath.
Colorado Public Utilities Commission............ Colorado Commission.
Interconnection Cost Consumer Protection Consumer Protection
Coalition. Coalition.
Consumers Energy Company........................ Consumers Energy.
Community Renewable Energy Association and CREA and NewSun.
NewSun Energy LLC.
CTC Global Corporation.......................... CTC Global.
Cypress Creek Renewables, LLC................... Cypress Creek.
Dominion Energy Services, Inc................... Dominion.
Duke Energy Carolinas, LLC; Duke Energy Duke Southeast
Progress, LLC; and Duke Energy Florida, LLC. Utilities.
Duke Energy Carolinas, LLC; Duke Energy Early Adopters
Progress, LLC; Dominion Energy South Carolina Coalition.
Inc.; PacifiCorp; Public Service Company of
Colorado; and Tri-State Generation and
Transmission Association, Inc.
Environmental Defense Fund...................... Environmental Defense
Fund.
EDF Renewables LLC.............................. EDF Renewables.
Edison Electric Institute....................... EEI.
El Paso Electric Company........................ El Paso Electric.
Electricity Consumers Resource Council.......... ELCON.
Elevate Renewable Energy F7, LLC................ Elevate.
North American Electric Reliability Corporation; NERC.
Midwest Reliability Organization; Northeast
Power Coordinating Council, Inc.;
ReliabilityFirst Corporation; SERC Reliability
Corporation; Texas Reliability Entity, Inc.;
and Western Electricity Coordinating Council.
Enel North America, Inc......................... Enel.
[[Page 61262]]
Energy Keepers, Inc............................. Energy Keepers.
ENGIE North America, Inc........................ ENGIE.
Electric Power Research Institute............... EPRI.
Electric Power Supply Association............... EPSA.
Equinor Wind US LLC............................. Equinor Wind.
Evergreen Action................................ Evergreen Action.
Eversource Energy Service Company............... Eversource.
Fervo Energy Company............................ Fervo Energy.
Golden State Clean Energy....................... GCSE.
Google LLC...................................... Google.
Guzman Energy LLC............................... Guzman Energy.
Hannon Armstrong Sustainable Infrastructure Hannon Armstrong.
Capital, Inc.
Rye Development, LLC; rPlus Hydro, LLP; Nelson Hydropower Commenters.
Energy LLC; Advanced Hydro Solutions LLC; Hydro
Green Energy, LLC; Natel Energy, Inc.; and
Sorenson Engineering, Inc. and its affiliates,
Cat Creek Energy, LLC and National Hydropower
Association.
Idaho Power Company............................. Idaho Power.
Illinois Commerce Commission.................... Illinois Commission.
Citizens Utility Board of Illinois.............. Illinois CUB.
Indicated PJM Transmission Owners............... Indicated PJM TOs.
4,293 people collected Evergreen Action......... Individual
Signatories.
Interwest Energy Alliance....................... Interwest.
Invenergy Solar Development North America LLC; Invenergy.
Invenergy Thermal Development LLC; Invenergy
Wind Development North America LLC; and
Invenergy Transmission LLC.
Iowa Utilities Board............................ Iowa Commission.
Interstate Renewable Energy Council............. IREC.
ISO New England Inc............................. ISO-NE.
ISO/RTO Council................................. ISO/RTO Council.
Los Angeles Department of Water and Power....... LADWP.
Longroad Energy Holdings, LLC................... Longroad Energy.
Lori Ecker...................................... Lori Ecker.
Microgrid Resources Coalition................... Microgrid Resources.
Midcontinent Independent System Operator, Inc... MISO.
MISO Transmission Owners........................ MISO TOs.
National Association of Regulatory Utility NARUC.
Commissioners.
National Grid Plc............................... National Grid.
New England Power Pool Participants Committee... NEPOOL.
New England States Committee on Electricity..... NESCOE.
New Jersey Board of Public Utilities............ New Jersey Commission.
New York State Department of State Utility New York State
Intervention Unit. Department.
NextEra Energy, Inc............................. NextEra.
North Carolina Utilities Commission and North North Carolina
Carolina Utilities Commission Public Staff. Commission and Staff.
North Dakota Public Service Commission.......... North Dakota
Commission.
Northwest & Intermountain Power Producers Northwest and
Coalition. Intermountain.
National Rural Electric Cooperative Association. NRECA.
Navajo Tribal Utility Authority................. Navajo Utility.
Nevada Power Company and Sierra Pacific Power NV Energy.
Company.
New York Public Service Commission and New York NY Commission and
State Energy Research and Development Authority. NYSERDA.
New York Transmission Owners.................... NYTOs.
New York Independent System Operator, Inc....... NYISO.
Public Commission of Ohio's Office of the Ohio Commission
Federal Energy Advocate. Consumer Advocate.
Omaha Public Power District..................... Omaha Public Power.
Organization of MISO States, Inc................ OMS.
[Oslash]rsted North America, Inc................ [Oslash]rsted.
OCETI Sakowin Power Authority................... OSPA.
Renewable Northwest and NW Energy Coalition..... Pacific Northwest
Organizations.
Avista Corporation; Idaho Power Company; Pacific Northwest
Portland General Electric Company; and Puget Utilities.
Sound Energy, Inc.
PacifiCorp...................................... PacifiCorp.
Pattern Energy Group LP......................... Pattern Energy.
Payton Alaama................................... Payton Alaama.
Pennsylvania Public Utility Commission.......... Pennsylvania
Commission.
Pacific Gas and Electric Company................ PG&E.
Pine Gate Renewables, LLC....................... Pine Gate.
PJM Interconnection, L.L.C...................... PJM.
PJM Cities and Communities Coalition............ PJM Coalition.
Organization of PJM States, Inc................. OPSI.
PPL Electric Utilities Corporation.............. PPL.
Puget Sound Energy, Inc......................... Puget Sound.
Sustainable FERC Project, Sierra Club, Natural Public Interest
Resources Defense Council, Earthjustice, Acadia Organizations.
Center, Environmental Defense Fund, National
Audubon Society, Southern Environmental Law
Center, and Southface.
R Street Institute.............................. R Street.
Rick K. Lathrop................................. Rick K Lathrop.
Roy J Shanker Ph.D.............................. Roy J Shanker.
rPlus Hydro, LLLP............................... rPlus.
RWE Renewables Americas, LLC.................... RWE Renewables.
San Diego Gas & Electric Company................ SDG&E.
Solar Energy Industries Association............. SEIA.
U.S. Senators John D. Hickenlooper and Angus Senators Hickenlooper
King. and King.
Shell Energy North America...................... Shell.
Southern California Edison Company.............. SoCal Edison.
Southern Company Services, Inc.................. Southern.
Southwest Power Pool, Inc....................... SPP.
Connecticut Department of Energy and State Agencies.
Environmental Protection, Connecticut Attorney
General, Connecticut Office of Consumer
Counsel, Delaware Attorney General, Delaware
Division of the Public Advocate, Attorney
General for the District of Columbia, District
of Columbia Office of People's Counsel,
Attorney General of Maryland, Maryland Office
of People's Counsel, Massachusetts Attorney
General, Pennsylvania Office of Consumer
Advocate, and the Rhode Island Attorney General.
[[Page 61263]]
Sue Hilton...................................... Sue Hilton.
Transmission Access Policy Study Group.......... TAPS.
Tesla, Inc...................................... Tesla.
Tri-State Generation and Transmission Tri-State.
Association, Inc.
Uda Law Firm, P.C............................... Uda Law Firm.
Utah Municipal Power Agency..................... UMPA.
Union of Concerned Scientists................... Union of Concerned
Scientists.
U.S. Chamber of Commerce........................ U.S. Chamber of
Commerce.
United States Department of Energy.............. U.S. DOE.
VEIR Inc........................................ VEIR.
Vermont Electric Power Company, Inc............. Vermont Electric and
Vermont Transco.
Vistra Corp..................................... Vistra.
Western Area Power Administration............... WAPA.
WATT Coalition.................................. WATT Coalition.
Colorado Public Utilities Commission Chair Megan Western Regulators.
Decker, Oregon Public Utility Commission Chair
Cynthia Hall, New Mexico Public Regulation
Commission Chair Cynthia Hall and Vice-Chair
Joe Maestas, Arizona Corporation Commission
Chair Lea Marquez Peterson, Nevada Public
Utilities Commission Chair Hayley Williamson,
California Public Utilities Commission
Commissioner Cliff Rechtschaffen, and
Washington Utilities and Transportation
Commission Commissioner Ann Rendahl.
WIRES........................................... WIRES.
Xcel Energy Services Inc........................ Xcel.
------------------------------------------------------------------------
Appendix B: Interconnection Study Metrics
Table 2--RTOS/ISOS Interconnection Study Metrics 2022 \1\
----------------------------------------------------------------------------------------------------------------
Studies Delayed
Transmission provider Completed completed past studies at end Withdrawals Withdrawn pre-
studies deadline of year study
----------------------------------------------------------------------------------------------------------------
CAISO........................... 340 340 .............. 108 1
ISO-NE.......................... 51 46 23 24 8
MISO............................ 609 597 285 49 0
NYISO........................... 84 72 25 34 28
PJM \2\......................... 153 152 2,211 240 137
----------------------------------------------------------------------------------------------------------------
\1\ We do not include data from SPP in this table. SPP is transitioning to a new interconnection study process
and thus its data is not clearly comparable to the other RTOs/ISOs.
\2\ Data drawn from the following sources, respectively: http://www.caiso.com/Documents/FERC845_InterconnectionStudyStatistics.pdf (CAISO); https://cdn.misoenergy.org/MISO%20Generator%20Interconnection%20Study%20Metrics%20Q1%202023444684.pdf (MISO); https://www.oasis.oati.com/isne/ isne/ (ISO-NE) https://www.nyiso.com/interconnections (NYISO); and https://www.pjm.com/-/media/planning/services-requests/interconnection-study-statistics.ashx (PJM).
Table 3--Non-RTOS/ISOS Interconnection Study Metrics 2022 \3\
----------------------------------------------------------------------------------------------------------------
Delayed
Transmission provider Completed Completed past studies at end Withdrawals Withdrawn pre-
studies deadline of year study
----------------------------------------------------------------------------------------------------------------
Alabama Power Company (Southern 148 0 0 45 5
Company).......................
Arizona Public Service.......... 40 40 106 12 5
Avista Corp..................... 14 5 1 11 3
Black Hills Colorado............ 4 0 5 0 0
Black Hills Power............... 7 1 4 1 0
Cheyenne Light, Fuel, and Power 4 0 2 0 0
Co.............................
Deseret Generation and 4 0 0 0 0
Transmission Coop..............
Dominion Energy South Carolina.. 2 2 0 23 21
Duke Energy Carolinas........... 1 1 0 4 0
El Paso Electric Co............. 6 2 0 7 1
Florida Power & Light........... 60 43 78 0 0
GridLiance...................... 1 0 0 0 0
Idaho Power..................... 98 20 7 15 5
Louisville Gas and Electric..... 18 16 15 2 1
Nevada Power.................... 103 0 0 15 4
Northwestern Corp (Montana)..... 33 14 4 10 2
PacifiCorp...................... 202 0 0 41 7
Portland General Electric 10 9 9 0 0
Company........................
Public Service Company of 41 39 28 12 1
Colorado.......................
Public Service Company of New 21 21 29 8 0
Mexico.........................
Puget Sound Energy.............. 50 37 6 6 2
Tampa Electric Company.......... 25 13 1 4 2
Tri-State Generation and 30 0 0 11 10
Transmission...................
Tucson Electric Power Co.\4\.... 20 20 0 3 2
----------------------------------------------------------------------------------------------------------------
\3\ This table excludes the following non-RTO/ISO transmission providers that did not report any completed or
ongoing interconnection studies for 2022: Basin Electric Power Coop.; Cube Yadkin Transmission, LLC; Golden
Spread Coop; Gulf Power Company; MATL LLP; UNS Electric, Inc.; and Versant Power.
[[Page 61264]]
\4\ Data drawn from the following sources, respectively: https://www.oasis.oati.com/SOCO/index.html (Alabama
Power Company (Southern Company)); https://www.oasis.oati.com/azps/ (Arizona Public Service); https://www.oasis.oati.com/avat/ (Avista Corp.); https://www.blackhillscorp.com/utilities-businesses/transmission/electric-transmission-services (Black Hills Colorado); https://www.blackhillscorp.com/utilities-businesses/transmission/electric-transmission-services (Black Hills Power); http://www.oatioasis.com/CLPT/index.html
(Cheyenne Light, Fuel, and Power Co.); https://www.oasis.oati.com/dgt/index.html (Deseret Generation and
Transmission Coop.); https://www.oasis.oati.com/SCEG/(DominionEnergySouthCarolina); http://www.oasis.oati.com/duk/index.html (Duke Energy Carolinas); https://www.oasis.oati.com/epe/index.html (El Paso Electric Co.);
https://www.oasis.oati.com/FPL/index.html (Florida Power & Light); https://www.oasis.oati.com/SMCN/index.html
(GridLiance); https://www.oasis.oati.com/ipco/ (Idaho Power); https://www.oasis.oati.com/LGEE/index.html
(Louisville Gas and Electric); http://www.oasis.oati.com/NEVP/ (Nevada Power); http://www.oatioasis.com/NWMT/
(Northwestern Corp (Montana); https://www.oasis.oati.com/PPW/ (PacifiCorp); https://www.oasis.oati.com/PGE/
(Portland General Electric Company); https://www.oasis.oati.com/psco/index.html (Public Service Company of
Colorado); https://www.oasis.oati.com/PNM/ (Public Service Company of New Mexico); https://www.oasis.oati.com/psei/index.html (Puget Sound Energy); https://www.oasis.oati.com/TEC/ (Tampa Electric Company); https://www.oasis.oati.com/tsgt/index.html (Tri-State Generation and Transmission); and https://www.oasis.oati.com/tepc/_ (Tucson Electric Power Co.).
Table 4--RTO/ISO End Of Year Delayed Interconnection Studies \5\
----------------------------------------------------------------------------------------------------------------
Delayed Delayed Delayed
Transmission provider studies at end studies at end studies at end
of 2020 of 2021 of 2022
----------------------------------------------------------------------------------------------------------------
CAISO........................................................... .............. .............. ..............
ISO-NE.......................................................... 12 19 23
MISO............................................................ 479 385 285
NYISO........................................................... 26 48 25
PJM............................................................. 272 1,281 2,211
----------------------------------------------------------------------------------------------------------------
\5\ We do not include data from SPP in this table. SPP is transitioning to a new interconnection study process
and thus its data is not clearly comparable to the other RTOs/ISOs.
Table 5--Non-RTO/ISO End Of Year Delayed Interconnection Studies
----------------------------------------------------------------------------------------------------------------
Delayed Delayed Delayed
Transmission provider studies at end studies at end studies at end
of 2020 of 2021 of 2022
----------------------------------------------------------------------------------------------------------------
Alabama Power Company (Southern Company)........................ 0 0 0
Arizona Public Service.......................................... 29 55 106
Avista Corp..................................................... 2 7 1
Black Hills Colorado............................................ 0 0 5
Black Hills Power............................................... 0 0 4
Cheyenne Light, Fuel, and Power Co.............................. 0 0 2
Deseret Generation and Transmission Coop........................ 0 0 0
Dominion Energy South Carolina.................................. 16 19 0
Duke Energy Carolinas........................................... 6 1 0
El Paso Electric Co............................................. 1 0 0
Florida Power & Light........................................... 48 21 78
GridLiance...................................................... 0 0 0
Gulf Power Co................................................... 13 12 ..............
Idaho Power..................................................... 0 0 7
Louisville Gas and Electric..................................... 3 12 15
Nevada Power.................................................... 0 0 0
Northwestern Corp (Montana)..................................... 2 1 4
PacifiCorp...................................................... 0 0 0
Portland General Electric Company............................... 2 0 9
Public Service Company of Colorado.............................. 0 0 28
Public Service Company of New Mexico............................ 20 17 29
Puget Sound Energy.............................................. 0 2 6
Tampa Electric Company.......................................... 16 5 1
Tri-State Generation and Transmission........................... 28 0 0
Tucson Electric Power Co........................................ 2 1 0
----------------------------------------------------------------------------------------------------------------
Appendix C: Pro forma LGIP
Note: Deletions are in brackets and additions are in italics.
Section 1. Definitions
Adverse System Impact shall mean the negative effects due to
technical or operational limits on conductors or equipment being
exceeded that may compromise the safety and reliability of the
electric system.
Affected System shall mean an electric system other than
[the]Transmission Provider's Transmission System that may be
affected by the proposed interconnection.
Affected System Facilities Construction Agreement shall mean the
agreement contained in Appendix 11 to this LGIP that is made between
Transmission Provider and Affected System Interconnection Customer
to facilitate the construction of and to set forth cost
responsibility for necessary Affected System Network Upgrades on
Transmission Provider's Transmission System.
Affected System Interconnection Customer shall mean any entity
that submits an interconnection request for a generating facility to
a transmission system other than Transmission Provider's
Transmission System that may cause the need for Affected System
Network Upgrades on the Transmission Provider's Transmission System.
Affected System Network Upgrades shall mean the additions,
modifications, and upgrades to Transmission Provider's Transmission
System required to accommodate Affected System Interconnection
Customer's proposed interconnection to a transmission system other
than Transmission Provider's Transmission System.
[[Page 61265]]
Affected System Operator shall mean the entity that operates an
Affected System.
Affected System Queue Position shall mean the queue position of
an Affected System Interconnection Customer in Transmission
Provider's interconnection queue relative to Transmission Provider's
Interconnection Customers' Queue Positions.
Affected System Study shall mean the evaluation of Affected
System Interconnection Customers' proposed interconnection(s) to a
transmission system other than Transmission Provider's Transmission
System that have an impact on Transmission Provider's Transmission
System, as described in Section 9 of this LGIP.
Affected System Study Agreement shall mean the agreement
contained in Appendix 9 to this LGIP that is made between
Transmission Provider and Affected System Interconnection Customer
to conduct an Affected System Study pursuant to Section 9 of this
LGIP.
Affected System Study Report shall mean the report issued
following completion of an Affected System Study pursuant to Section
9.6 of this LGIP.
Affiliate shall mean, with respect to a corporation, partnership
or other entity, each such other corporation, partnership or other
entity that directly or indirectly, through one or more
intermediaries, controls, is controlled by, or is under common
control with, such corporation, partnership or other entity.
Ancillary Services shall mean those services that are necessary
to support the transmission of capacity and energy from resources to
loads while maintaining reliable operation of the Transmission
Provider's Transmission System in accordance with Good Utility
Practice.
Applicable Laws and Regulations shall mean all duly promulgated
applicable federal, state and local laws, regulations, rules,
ordinances, codes, decrees, judgments, directives, or judicial or
administrative orders, permits and other duly authorized actions of
any Governmental Authority.
[Applicable Reliability Council shall mean the reliability
council applicable to the Transmission System to which the
Generating Facility is directly interconnected.]
Applicable Reliability Standards shall mean the requirements and
guidelines of [NERC,] the [Applicable Reliability Council] Electric
Reliability Organization and the [Control Area] Balancing Authority
Area of the Transmission System to which the Generating Facility is
directly interconnected.
Balancing Authority shall mean an entity that integrates
resource plans ahead of time, maintains demand and resource balance
within a Balancing Authority Area, and supports interconnection
frequency in real time.
Balancing Authority Area shall mean the collection of
generation, transmission, and loads within the metered boundaries of
the Balancing Authority. The Balancing Authority maintains load-
resource balance within this area.
Base Case shall mean the base case power flow, short circuit,
and stability data bases used for the Interconnection Studies by
[the] Transmission Provider or Interconnection Customer.
Breach shall mean the failure of a Party to perform or observe
any material term or condition of the Standard Large Generator
Interconnection Agreement.
Breaching Party shall mean a Party that is in Breach of the
Standard Large Generator Interconnection Agreement.
Business Day shall mean Monday through Friday, excluding Federal
Holidays.
Calendar Day shall mean any day including Saturday, Sunday or a
Federal Holiday.
Cluster shall mean a group of one or more Interconnection
Requests that are studied together for the purpose of conducting a
Cluster Study.
Cluster Request Window shall mean the time period set forth in
Section 3.4.1 of this LGIP.
Cluster Restudy shall mean a restudy of a Cluster Study
conducted pursuant to Section 7.5 of this LGIP.
Cluster Restudy Report Meeting shall mean the meeting held to
discuss the results of a Cluster Restudy pursuant to Section 7.5 of
this LGIP.
Cluster Restudy Report shall mean the report issued following
completion of a Cluster Restudy pursuant to Section 7.5 of this
LGIP.
Cluster Study shall mean the evaluation of one or more
Interconnection Requests within a Cluster as described in Section 7
of this LGIP.
Cluster Study Agreement shall mean the agreement contained in
Appendix 2 to this LGIP for conducting the Cluster Study.
Cluster Study Process shall mean the following processes,
conducted in sequence: the Cluster Request Window; the Customer
Engagement Window and Scoping Meetings therein; the Cluster Study;
any needed Cluster Restudies; and the Interconnection Facilities
Study.
Cluster Study Report shall mean the report issued following
completion of a Cluster Study pursuant to Section 7 of this LGIP.
Cluster Study Report Meeting shall mean the meeting held to
discuss the results of a Cluster Study pursuant to Section 7 of this
LGIP.
Clustering shall mean the process whereby one or more [a group
of] Interconnection Requests [is] are studied together, instead of
serially, [for the purpose of conducting the Interconnection System
Impact Study] as described in Section 7 of this LGIP.
Commercial Operation shall mean the status of a Generating
Facility that has commenced generating electricity for sale,
excluding electricity generated during Trial Operation.
Commercial Operation Date of a unit shall mean the date on which
the Generating Facility commences Commercial Operation as agreed to
by the Parties pursuant to Appendix E to the Standard Large
Generator Interconnection Agreement.
Commercial Readiness Deposit shall mean a deposit paid as set
forth in Sections 3.4.2, 7.5, and 8.1 of this LGIP.
Confidential Information shall mean any confidential,
proprietary or trade secret information of a plan, specification,
pattern, procedure, design, device, list, concept, policy or
compilation relating to the present or planned business of a Party,
which is designated as confidential by the Party supplying the
information, whether conveyed orally, electronically, in writing,
through inspection, or otherwise.
Contingent Facilities shall mean those unbuilt Interconnection
Facilities and Network Upgrades upon which the Interconnection
Request's costs, timing, and study findings are dependent, and if
delayed or not built, could cause a need for [Re-Studies] restudies
of the Interconnection Request or a reassessment of the
Interconnection Facilities and/or Network Upgrades and/or costs and
timing.
[Control Area shall mean an electrical system or systems bounded
by interconnection metering and telemetry, capable of controlling
generation to maintain its interchange schedule with other Control
Areas and contributing to frequency regulation of the
interconnection. A Control Area must be certified by an Applicable
Reliability Council.]
Customer Engagement Window shall mean the time period set forth
in Section 3.4.5 of this LGIP.
Default shall mean the failure of a Breaching Party to cure its
Breach in accordance with Article 17 of the Standard Large Generator
Interconnection Agreement.
Dispute Resolution shall mean the procedure for resolution of a
dispute between the Parties in which they will first attempt to
resolve the dispute on an informal basis.
Distribution System shall mean the Transmission Provider's
facilities and equipment used to transmit electricity to ultimate
usage points such as homes and industries directly from nearby
generators or from interchanges with higher voltage transmission
networks which transport bulk power over longer distances. The
voltage levels at which distribution systems operate differ among
areas.
Distribution Upgrades shall mean the additions, modifications,
and upgrades to the Transmission Provider's Distribution System at
or beyond the Point of Interconnection to facilitate interconnection
of the Generating Facility and render the transmission service
necessary to effect Interconnection Customer's wholesale sale of
electricity in interstate commerce. Distribution Upgrades do not
include Interconnection Facilities.
Effective Date shall mean the date on which the Standard Large
Generator Interconnection Agreement becomes effective upon execution
by the Parties subject to acceptance by FERC, or if filed
unexecuted, upon the date specified by FERC.
Electric Reliability Organization shall mean the North American
Electric Reliability Corporation or its successor organization.
Emergency Condition shall mean a condition or situation: (1)
that in the judgment of the Party making the claim is imminently
likely to endanger life or property; or (2) that, in the case of a
Transmission Provider, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the
security of, or damage to Transmission
[[Page 61266]]
Provider's Transmission System, Transmission Provider's
Interconnection Facilities or the electric systems of others to
which the Transmission Provider's Transmission System is directly
connected; or (3) that, in the case of Interconnection Customer, is
imminently likely (as determined in a non-discriminatory manner) to
cause a material adverse effect on the security of, or damage to,
the Generating Facility or Interconnection Customer's
Interconnection Facilities. System restoration and black start shall
be considered Emergency Conditions; provided that Interconnection
Customer is not obligated by the Standard Large Generator
Interconnection Agreement to possess black start capability.
Energy Resource Interconnection Service shall mean an
Interconnection Service that allows the Interconnection Customer to
connect its Generating Facility to the Transmission Provider's
Transmission System to be eligible to deliver the Generating
Facility's electric output using the existing firm or nonfirm
capacity of the Transmission Provider's Transmission System on an as
available basis. Energy Resource Interconnection Service in and of
itself does not convey transmission service.
Engineering & Procurement (E&P) Agreement shall mean an
agreement that authorizes the Transmission Provider to begin
engineering and procurement of long lead-time items necessary for
the establishment of the interconnection in order to advance the
implementation of the Interconnection Request.
Environmental Law shall mean Applicable Laws or Regulations
relating to pollution or protection of the environment or natural
resources.
Federal Power Act shall mean the Federal Power Act, as amended,
16 U.S.C. Sec. Sec. 791a et seq.
FERC shall mean the Federal Energy Regulatory Commission
(Commission) or its successor.
Force Majeure shall mean any act of God, labor disturbance, act
of the public enemy, war, insurrection, riot, fire, storm or flood,
explosion, breakage or accident to machinery or equipment, any
order, regulation or restriction imposed by governmental, military
or lawfully established civilian authorities, or any other cause
beyond a Party's control. A Force Majeure event does not include
acts of negligence or intentional wrongdoing by the Party claiming
Force Majeure.
Generating Facility shall mean Interconnection Customer's
[device]device(s) for the production and/or storage for later
injection of electricity identified in the Interconnection Request,
but shall not include [the]Interconnection Customer's
Interconnection Facilities.
Generating Facility Capacity shall mean the net capacity of the
Generating Facility [and] or the aggregate net capacity of the
Generating Facility where it includes [multiple energy production
devices] more than one device for the production and/or storage for
later injection of electricity.
Good Utility Practice shall mean any of the practices, methods
and acts engaged in or approved by a significant portion of the
electric industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices,
reliability, safety and expedition. Good Utility Practice is not
intended to be limited to the optimum practice, method, or act to
the exclusion of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region.
Governmental Authority shall mean any federal, state, local or
other governmental regulatory or administrative agency, court,
commission, department, board, or other governmental subdivision,
legislature, rulemaking board, tribunal, or other governmental
authority having jurisdiction over the Parties, their respective
facilities, or the respective services they provide, and exercising
or entitled to exercise any administrative, executive, police, or
taxing authority or power; provided, however, that such term does
not include Interconnection Customer, Transmission Provider, or any
Affiliate thereof.
Hazardous Substances shall mean any chemicals, materials or
substances defined as or included in the definition of ``hazardous
substances,'' ``hazardous wastes,'' ``hazardous materials,''
``hazardous constituents,'' ``restricted hazardous materials,''
``extremely hazardous substances,'' ``toxic substances,''
``radioactive substances,'' ``contaminants,'' ``pollutants,''
``toxic pollutants'' or words of similar meaning and regulatory
effect under any applicable Environmental Law, or any other
chemical, material or substance, exposure to which is prohibited,
limited or regulated by any applicable Environmental Law.
Initial Synchronization Date shall mean the date upon which the
Generating Facility is initially synchronized and upon which Trial
Operation begins.
In-Service Date shall mean the date upon which the
Interconnection Customer reasonably expects it will be ready to
begin use of the Transmission Provider's Interconnection Facilities
to obtain back feed power.
Interconnection Customer shall mean any entity, including the
Transmission Provider, Transmission Owner or any of the Affiliates
or subsidiaries of either, that proposes to interconnect its
Generating Facility with the Transmission Provider's Transmission
System.
Interconnection Customer's Interconnection Facilities shall mean
all facilities and equipment, as identified in Appendix A of the
Standard Large Generator Interconnection Agreement, that are located
between the Generating Facility and the Point of Change of
Ownership, including any modification, addition, or upgrades to such
facilities and equipment necessary to physically and electrically
interconnect the Generating Facility to [the] Transmission
Provider's Transmission System. Interconnection Customer's
Interconnection Facilities are sole use facilities.
Interconnection Facilities shall mean [the]Transmission
Provider's Interconnection Facilities and [the]Interconnection
Customer's Interconnection Facilities. Collectively, Interconnection
Facilities include all facilities and equipment between the
Generating Facility and the Point of Interconnection, including any
modification, additions or upgrades that are necessary to physically
and electrically interconnect the Generating Facility to
[the]Transmission Provider's Transmission System. Interconnection
Facilities are sole use facilities and shall not include
Distribution Upgrades, Stand Alone Network Upgrades or Network
Upgrades.
Interconnection Facilities Study shall mean a study conducted by
[the]Transmission Provider or a third party consultant for
[the]Interconnection Customer to determine a list of facilities
(including Transmission Provider's Interconnection Facilities and
Network Upgrades as identified in the [Interconnection System
Impact]Cluster Study), the cost of those facilities, and the time
required to interconnect the Generating Facility with[the]
Transmission Provider's Transmission System. The scope of the study
is defined in Section 8 of this LGIP[the Standard Large Generator
Interconnection Procedures].
Interconnection Facilities Study Agreement shall mean the form
of agreement contained in Appendix 3[4] of this LGIP [the Standard
Large Generator Interconnection Procedures] for conducting the
Interconnection Facilities Study.
Interconnection Facilities Study Report shall mean the report
issued following completion of an Interconnection Facilities Study
pursuant to Section 8 of this LGIP.
[Interconnection Feasibility Study shall mean a preliminary
evaluation of the system impact and cost of interconnecting the
Generating Facility to Transmission Provider's Transmission System,
the scope of which is described in Section 6 of the Standard Large
Generator Interconnection Procedures.]
[Interconnection Feasibility Study Agreement shall mean the form
of agreement contained in Appendix 2 of the Standard Large Generator
Interconnection Procedures for conducting the Interconnection
Feasibility Study.]
Interconnection Request shall mean an Interconnection Customer's
request, in the form of Appendix 1 to this LGIP [the Standard Large
Generator Interconnection Procedures], in accordance with the
Tariff, to interconnect a new Generating Facility, or to increase
the capacity of, or make a Material Modification to the operating
characteristics of, an existing Generating Facility that is
interconnected with the Transmission Provider's Transmission System.
Interconnection Service shall mean the service provided by the
Transmission Provider associated with interconnecting the
Interconnection Customer's Generating Facility to the Transmission
Provider's Transmission System and enabling it to receive electric
energy and capacity from the Generating Facility at the Point of
Interconnection, pursuant to the terms of the Standard Large
Generator Interconnection Agreement and, if applicable, the
Transmission Provider's Tariff.
[[Page 61267]]
Interconnection Study shall mean any of the following studies:
[the Interconnection Feasibility Study, the Interconnection System
Impact Study,] the Cluster Study, the Cluster Restudy, the Surplus
Interconnection Service System Impact Study, and the Interconnection
Facilities Study, described in this LGIP [the Standard Large
Generator Interconnection Procedures].
[Interconnection System Impact Study shall mean an engineering
study that evaluates the impact of the proposed interconnection on
the safety and reliability of Transmission Provider's Transmission
System and, if applicable, an Affected System. The study shall
identify and detail the system impacts that would result if the
Generating Facility were interconnected without project
modifications or system modifications, focusing on the Adverse
System Impacts identified in the Interconnection Feasibility Study,
or to study potential impacts, including but not limited to those
identified in the Scoping Meeting as described in the Standard Large
Generator Interconnection Procedures.]
[Interconnection System Impact Study Agreement shall mean the
form of agreement contained in Appendix 3 of the Standard Large
Generator Interconnection Procedures for conducting the
Interconnection System Impact Study.]
IRS shall mean the Internal Revenue Service.
Joint Operating Committee shall be a group made up of
representatives from Interconnection Customers and the Transmission
Provider to coordinate operating and technical considerations of
Interconnection Service.
Large Generating Facility shall mean a Generating Facility
having a Generating Facility Capacity of more than 20 MW.
LGIA Deposit shall mean the deposit Interconnection Customer
submits when returning the executed LGIA, or within 10 Business Days
of requesting that the LGIA be filed unexecuted at the Commission,
in accordance with Section 11.3 of this LGIP.
Loss shall mean any and all losses relating to injury to or
death of any person or damage to property, demand, suits,
recoveries, costs and expenses, court costs, attorney fees, and all
other obligations by or to third parties, arising out of or
resulting from the other Party's performance, or non-performance of
its obligations under the Standard Large Generator Interconnection
Agreement on behalf of the [indemnifying] Indemnifying Party, except
in cases of gross negligence or intentional wrongdoing by the
[indemnifying]Indemnifying Party.
Material Modification shall mean those modifications that have a
material impact on the cost or timing of any Interconnection Request
with an equal or later Queue Position [queue priority date].
Metering Equipment shall mean all metering equipment installed
or to be installed at the Generating Facility pursuant to the
Standard Large Generator Interconnection Agreement at the metering
points, including but not limited to instrument transformers, MWh-
meters, data acquisition equipment, transducers, remote terminal
unit, communications equipment, phone lines, and fiber optics.
Multiparty Affected System Facilities Construction Agreement
shall mean the agreement contained in Appendix 12 to this LGIP that
is made among Transmission Provider and multiple Affected System
Interconnection Customers to facilitate the construction of and to
set forth cost responsibility for necessary Affected System Network
Upgrades on Transmission Provider's Transmission System.
Multiparty Affected System Study Agreement shall mean the
agreement contained in Appendix 10 to this LGIP that is made among
Transmission Provider and multiple Affected System Interconnection
Customers to conduct an Affected System Study pursuant to Section 9
of this LGIP.
[NERC shall mean the North American Electric Reliability Council
or its successor organization.]
Network Resource shall mean any designated generating resource
owned, purchased, or leased by a Network Customer under the Network
Integration Transmission Service Tariff. Network Resources do not
include any resource, or any portion thereof, that is committed for
sale to third parties or otherwise cannot be called upon to meet the
Network Customer's Network Load on a non-interruptible basis.
Network Resource Interconnection Service shall mean an
Interconnection Service that allows the Interconnection Customer to
integrate its Large Generating Facility with the Transmission
Provider's Transmission System (1) in a manner comparable to that in
which the Transmission Provider integrates its generating facilities
to serve native load customers; or (2) in an RTO or ISO with market
based congestion management, in the same manner as Network
Resources. Network Resource Interconnection Service in and of itself
does not convey transmission service.
Network Upgrades shall mean the additions, modifications, and
upgrades to the Transmission Provider's Transmission System required
at or beyond the point at which the Interconnection Facilities
connect to the Transmission Provider's Transmission System to
accommodate the interconnection of the Large Generating Facility to
the Transmission Provider's Transmission System.
Notice of Dispute shall mean a written notice of a dispute or
claim that arises out of or in connection with the Standard Large
Generator Interconnection Agreement or its performance.
Optional Interconnection Study shall mean a sensitivity analysis
based on assumptions specified by the Interconnection Customer in
the Optional Interconnection Study Agreement.
Optional Interconnection Study Agreement shall mean the form of
agreement contained in Appendix 4[5] of this LGIP [the Standard
Large Generator Interconnection Procedures] for conducting the
Optional Interconnection Study.
Party or Parties shall mean Transmission Provider, Transmission
Owner, Interconnection Customer or any combination of the above.
Permissible Technological Advancement {Transmission Provider
inserts definition here.{time}
Point of Change of Ownership shall mean the point, as set forth
in Appendix A to the Standard Large Generator Interconnection
Agreement, where the Interconnection Customer's Interconnection
Facilities connect to the Transmission Provider's Interconnection
Facilities.
Point of Interconnection shall mean the point, as set forth in
Appendix A to the Standard Large Generator Interconnection
Agreement, where the Interconnection Facilities connect to the
Transmission Provider's Transmission System.
Proportional Impact Method shall mean a technical analysis
conducted by Transmission Provider to determine the degree to which
each Generating Facility in the Cluster Study contributes to the
need for a specific System Network Upgrade.
Provisional Interconnection Service shall mean Interconnection
Service provided by Transmission Provider associated with
interconnecting the Interconnection Customer's Generating Facility
to Transmission Provider's Transmission System and enabling that
Transmission System to receive electric energy and capacity from the
Generating Facility at the Point of Interconnection, pursuant to the
terms of the Provisional Large Generator Interconnection Agreement
and, if applicable, the Tariff.
Provisional Large Generator Interconnection Agreement shall mean
the interconnection agreement for Provisional Interconnection
Service established between Transmission Provider and/or the
Transmission Owner and the Interconnection Customer. This agreement
shall take the form of the Large Generator Interconnection
Agreement, modified for provisional purposes.
Queue Position shall mean the order of a valid Interconnection
Request, relative to all other pending valid Interconnection
Requests, [that is] established pursuant to Section 4.1 of this
LGIP. [based upon the date and time of receipt of the valid
Interconnection Request by the Transmission Provider.]
Reasonable Efforts shall mean, with respect to an action
required to be attempted or taken by a Party under the Standard
Large Generator Interconnection Agreement, efforts that are timely
and consistent with Good Utility Practice and are otherwise
substantially equivalent to those a Party would use to protect its
own interests.
Scoping Meeting shall mean the meeting between representatives
of [the]Interconnection Customer(s) and Transmission Provider
conducted for the purpose of discussing the proposed Interconnection
Request and any alternative interconnection options,
[to]exchang[e]ing information including any transmission data and
earlier study evaluations that would be reasonably expected to
impact such interconnection options, refining information and models
provided by Interconnection Customer(s), discussing the Cluster
Study materials posted to OASIS pursuant to Section 3.5 of this
LGIP, and [to]analyz[e]ing such information[, and to determine the
potential feasible Points of Interconnection].
Site Control shall mean [documentation reasonably
demonstrating]the exclusive land
[[Page 61268]]
right to develop, construct, operate, and maintain the Generating
Facility over the term of expected operation of the Generating
Facility. Site Control may be demonstrated by documentation
establishing: (1) ownership of, a leasehold interest in, or a right
to develop a site [for the purpose of constructing]of sufficient
size to construct and operate the Generating Facility; (2) an option
to purchase or acquire a leasehold site of sufficient size to
construct and operate the Generating Facility[for such purpose]; or
(3) [an exclusivity or other business relationship between]any other
documentation that clearly demonstrates the right of Interconnection
Customer[and the entity having the right to sell, lease or grant
Interconnection Customer the right to possess or]to exclusively
occupy a site [for such purpose.]of sufficient size to construct and
operate the Generating Facility. Transmission Provider will maintain
acreage requirements for each Generating Facility type on its OASIS
or public website.
Small Generating Facility shall mean a Generating Facility that
has a Generating Facility Capacity of no more than 20 MW.
Stand Alone Network Upgrades shall mean Network Upgrades that
are not part of an Affected System that an Interconnection Customer
may construct without affecting day-to-day operations of the
Transmission System during their construction and the following
conditions are met: (1) a Substation Network Upgrade must only be
required for a single Interconnection Customer in the Cluster and no
other Interconnection Customer in that Cluster is required to
interconnect to the same Substation Network Upgrades, and (2) a
System Network Upgrade must only be required for a single
Interconnection Customer in the Cluster, as indicated under the
Transmission Provider's Proportional Impact Method. Both
[the]Transmission Provider and [the]Interconnection Customer must
agree as to what constitutes Stand Alone Network Upgrades and
identify them in Appendix A to the Standard Large Generator
Interconnection Agreement. If [the]Transmission Provider and
Interconnection Customer disagree about whether a particular Network
Upgrade is a Stand Alone Network Upgrade, [the]Transmission Provider
must provide [the]Interconnection Customer a written technical
explanation outlining why [the]Transmission Provider does not
consider the Network Upgrade to be a Stand Alone Network Upgrade
within 15 days of its determination.
Standard Large Generator Interconnection Agreement (LGIA) shall
mean the form of interconnection agreement applicable to an
Interconnection Request pertaining to a Large Generating Facility
that is included in the Transmission Provider's Tariff.
Standard Large Generator Interconnection Procedures (LGIP) shall
mean the interconnection procedures applicable to an Interconnection
Request pertaining to a Large Generating Facility that are included
in the Transmission Provider's Tariff.
Substation Network Upgrades shall mean Network Upgrades that are
required at the substation located at the Point of Interconnection.
Surplus Interconnection Service shall mean any unneeded portion
of Interconnection Service established in a Large Generator
Interconnection Agreement, such that if Surplus Interconnection
Service is utilized, the total amount of Interconnection Service at
the Point of Interconnection would remain the same.
System Network Upgrades shall mean Network Upgrades that are
required beyond the substation located at the Point of
Interconnection.
System Protection Facilities shall mean the equipment, including
necessary protection signal communications equipment, required to
protect (1) the Transmission Provider's Transmission System from
faults or other electrical disturbances occurring at the Generating
Facility and (2) the Generating Facility from faults or other
electrical system disturbances occurring on the Transmission
Provider's Transmission System or on other delivery systems or other
generating systems to which the Transmission Provider's Transmission
System is directly connected.
Tariff shall mean the Transmission Provider's Tariff through
which open access transmission service and Interconnection Service
are offered, as filed with FERC, and as amended or supplemented from
time to time, or any successor tariff.
Transitional Cluster Study shall mean an Interconnection Study
evaluating a Cluster of Interconnection Requests during the
transition to the Cluster Study Process, as set forth in Section
5.1.1.2 of this LGIP.
Transitional Cluster Study Report shall mean the report issued
following completion of a Transitional Cluster Study pursuant to
Section 5.1.1.2 of this LGIP.
Transitional Serial Interconnection Facilities Study shall mean
an Interconnection Facilities Study evaluating an Interconnection
Request on a serial basis during the transition to the Cluster Study
Process, as set forth in Section 5.1.1.1 of this LGIP.
Transitional Serial Interconnection Facilities Study Report
shall mean the report issued following completion of a Transitional
Interconnection Facilities Study pursuant to Section 5.1.1.1 of this
LGIP.
Transmission Owner shall mean an entity that owns, leases or
otherwise possesses an interest in the portion of the Transmission
System at the Point of Interconnection and may be a Party to the
Standard Large Generator Interconnection Agreement to the extent
necessary.
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 electricity in
interstate commerce and provides transmission service under the
Tariff. The term Transmission Provider should be read to include the
Transmission Owner when the Transmission Owner is separate from the
Transmission Provider.
Transmission Provider's Interconnection Facilities shall mean
all facilities and equipment owned, controlled, or operated by
[the]Transmission Provider from the Point of Change of Ownership to
the Point of Interconnection as identified in Appendix A to the
Standard Large Generator Interconnection Agreement, including any
modifications, additions or upgrades to such facilities and
equipment. Transmission Provider's Interconnection Facilities are
sole use facilities and shall not include Distribution Upgrades,
Stand Alone Network Upgrades or Network Upgrades.
Transmission System shall mean the facilities owned, controlled
or operated by the Transmission Provider or Transmission Owner that
are used to provide transmission service under the Tariff.
Trial Operation shall mean the period during which
Interconnection Customer is engaged in on-site test operations and
commissioning of the Generating Facility prior to Commercial
Operation.
Withdrawal Penalty shall mean the penalty assessed by
Transmission Provider to an Interconnection Customer that chooses to
withdraw or is deemed withdrawn from Transmission Provider's
interconnection queue or whose Generating Facility does not
otherwise reach Commercial Operation. The calculation of the
Withdrawal Penalty is set forth in Section 3.7.1 of this LGIP.
Section 2. Scope and Application
2.1 Application of Standard Large Generator Interconnection Procedures
Sections 2 through 13 apply to processing an Interconnection
Request pertaining to a Large Generating Facility.
2.2 Comparability
Transmission Provider shall receive, process and analyze all
Interconnection Requests in a timely manner as set forth in this
LGIP. Transmission Provider [will use the same Reasonable
Efforts]shall process[ing] and analyze[ing] Interconnection Requests
from all Interconnection Customers comparably, regardless of whether
the Generating Facilities are owned by Transmission Provider, its
subsidiaries or Affiliates or others.
2.3 Base Case Data
Transmission Provider shall maintain base power flow, short
circuit and stability databases, including all underlying
assumptions, and contingency list on either its OASIS site or a
password-protected website, subject to confidentiality provisions in
LGIP Section 13.1. In addition, Transmission Provider shall maintain
network models and underlying assumptions on either its OASIS site
or a password-protected website. Such network models and underlying
assumptions should reasonably represent those used during the most
recent interconnection study and be representative of current system
conditions. If Transmission Provider posts this information on a
password-protected website, a link to the information must be
provided on Transmission Provider's OASIS site. Transmission
Provider is permitted to require that Interconnection Customers,
OASIS site users and password-protected website users sign a
confidentiality agreement before the release of commercially
sensitive information or Critical Energy Infrastructure Information
in the Base Case data. Such databases and lists, hereinafter
referred to as Base Cases, shall include all (1) generation projects
and
[[Page 61269]]
(2) transmission projects, including merchant transmission projects
that are proposed for the Transmission System for which a
transmission expansion plan has been submitted and approved by the
applicable authority.
2.4 No Applicability to Transmission Service
Nothing in this LGIP shall constitute a request for transmission
service or confer upon an Interconnection Customer any right to
receive transmission service.
Section 3. Interconnection Requests
3.1 [General.] Interconnection Requests
3.1.1 Study Deposits
3.1.1.1 Study Deposit
[An ]Interconnection Customer shall submit to Transmission
Provider, during a Cluster Request Window, an Interconnection
Request in the form of Appendix 1 to this LGIP, an application fee
of $5,000, and a refundable study deposit of[$10,000]:
a. $35,000 plus $1,000 per MW for Interconnection Requests
=20 MW <80 MW, or;
b. $150,000 for Interconnection Requests =80 MW <200
MW; or
c. $250,000 for Interconnection Requests >=200 MW.
Transmission Provider shall apply the study deposit toward the
cost of the Cluster [an Interconnection Feasibility]Study Process.
3.1.2 Submission
Interconnection Customer shall submit a separate Interconnection
Request for each site [and may submit multiple Interconnection
Requests for a single site. Interconnection Customer must submit a
deposit with each Interconnection Request even when more than one
request is submitted for a single site]. Where multiple Generating
Facilities share a site, Interconnection Customer(s) may submit
separate Interconnection Requests or a single Interconnection
Request. An Interconnection Request to evaluate one site at two
different voltage levels shall be treated as two Interconnection
Requests.
At Interconnection Customer's option, Transmission Provider and
Interconnection Customer will identify alternative Point(s) of
Interconnection and configurations at [the]a Scoping Meeting within
the Customer Engagement Window to evaluate in this process and
attempt to eliminate alternatives in a reasonable fashion given
resources and information available. Interconnection Customer will
select the definitive Point[(s)] of Interconnection to be studied no
later than the execution of the [Interconnection Feasibility Study
Agreement.]Cluster Study Agreement. For purposes of clustering
Interconnection Requests, Transmission Provider may propose changes
to the requested Point of Interconnection to facilitate efficient
interconnection of Interconnection Customers at common Point(s) of
Interconnection. Transmission Provider shall notify Interconnection
Customers in writing of any intended changes to the requested Point
of Interconnection within the Customer Engagement Window, and the
Point of Interconnection shall only change upon mutual agreement.
Transmission Provider shall have a process in place to consider
requests for Interconnection Service below the Generating Facility
Capacity. These requests for Interconnection Service shall be
studied at the level of Interconnection Service requested for
purposes of Interconnection Facilities, Network Upgrades, and
associated costs, but may be subject to other studies at the full
Generating Facility Capacity to ensure safety and reliability of the
system, with the study costs borne by [the]Interconnection Customer.
If after the additional studies are complete, Transmission Provider
determines that additional Network Upgrades are necessary, then
Transmission Provider must: (1) specify which additional Network
Upgrade costs are based on which studies; and (2) provide a detailed
explanation of why the additional Network Upgrades are necessary.
Any Interconnection Facility and/or Network Upgrade costs required
for safety and reliability also would be borne by
[the]Interconnection Customer. Interconnection Customers may be
subject to additional control technologies as well as testing and
validation of those technologies consistent with Article 6 of the
LGIA. The necessary control technologies and protection systems
shall be established in Appendix C of that executed, or requested to
be filed unexecuted, LGIA.
Transmission Provider shall have a process in place to study
Generating Facilities that include at least one electric storage
resource using operating assumptions (i.e., whether the
interconnecting Generating Facility will or will not charge at peak
load) that reflect the proposed charging behavior of the Generating
Facility as requested by Interconnection Customer, unless
Transmission Provider determines that Good Utility Practice,
including Applicable Reliability Standards, otherwise requires the
use of different operating assumptions. If Transmission Provider
finds Interconnection Customer's requested operating assumptions
conflict with Good Utility Practice, Transmission Provider must
provide Interconnection Customer an explanation in writing of why
the submitted operating assumptions are insufficient or
inappropriate by no later than thirty (30) Calendar Days before the
end of the Customer Engagement Window and allow Interconnection
Customer to revise and resubmit requested operating assumptions one
time at least ten (10) Calendar Days prior to the end of the
Customer Engagement Window. Transmission Provider shall study these
requests for Interconnection Service, with the study costs borne by
Interconnection Customer, using the submitted operating assumptions
for purposes of Interconnection Facilities, Network Upgrades, and
associated costs. These requests for Interconnection Service also
may be subject to other studies at the full Generating Facility
Capacity to ensure safety and reliability of the system, with the
study costs borne by Interconnection Customer. Interconnection
Customer's Generating Facility may be subject to additional control
technologies as well as testing and validation of such additional
control technologies consistent with Article 6 of the LGIA. The
necessary control technologies and protection systems shall be set
forth in Appendix C of the Interconnection Customer's LGIA.
3.2 Identification of Types of Interconnection Services
At the time the Interconnection Request is submitted,
Interconnection Customer must request either Energy Resource
Interconnection Service or Network Resource Interconnection Service,
as described; provided, however, any Interconnection Customer
requesting Network Resource Interconnection Service may also request
that it be concurrently studied for Energy Resource Interconnection
Service, up to the point when an Interconnection Facilit[y]ies Study
Agreement is executed. Interconnection Customer may then elect to
proceed with Network Resource Interconnection Service or to proceed
under a lower level of interconnection service to the extent that
only certain upgrades will be completed.
3.2.1 Energy Resource Interconnection Service
3.2.1.1 The Product
Energy Resource Interconnection Service allows Interconnection
Customer to connect the Large Generating Facility to the
Transmission System and be eligible to deliver the Large Generating
Facility's output using the existing firm or non-firm capacity of
the Transmission System on an ``as available'' basis. Energy
Resource Interconnection Service does not in and of itself convey
any right to deliver electricity to any specific customer or Point
of Delivery.
3.2.1.2 The Study
The study consists of short circuit/fault duty, steady state
(thermal and voltage) and stability analyses. The short circuit/
fault duty analysis would identify direct Interconnection Facilities
required and the Network Upgrades necessary to address short circuit
issues associated with the Interconnection Facilities. The stability
and steady state studies would identify necessary upgrades to allow
full output of the proposed Large Generating Facility, except for
Generating Facilities that include at least one electric storage
resource that request to use operating assumptions pursuant to
Section 3.1.2, unless the Transmission Provider determines that Good
Utility Practice, including Applicable Reliability Standards,
otherwise requires the use of different operating assumptions, and
would also identify the maximum allowed output, at the time the
study is performed, of the interconnecting Large Generating Facility
without requiring additional Network Upgrades.
3.2.2 Network Resource Interconnection Service
3.2.2.1 The Product
Transmission Provider must conduct the necessary studies and
construct the Network
[[Page 61270]]
Upgrades needed to integrate the Large Generating Facility (1) in a
manner comparable to that in which Transmission Provider integrates
its generating facilities to serve native load customers; or (2) in
an ISO or RTO with market based congestion management, in the same
manner as Network Resources. Network Resource Interconnection
Service Allows Interconnection Customer's Large Generating Facility
to be designated as a Network Resource, up to the Large Generating
Facility's full output, on the same basis as existing Network
Resources interconnected to Transmission Provider's Transmission
System, and to be studied as a Network Resource on the assumption
that such a designation will occur.
3.2.2.2 The Study
The Interconnection Study for Network Resource Interconnection
Service shall assure that Interconnection Customer's Large
Generating Facility meets the requirements for Network Resource
Interconnection Service and as a general matter, that such Large
Generating Facility's interconnection is also studied with
Transmission Provider's Transmission System at peak load, under a
variety of severely stressed conditions, to determine whether, with
the Large Generating Facility at full output, except for Generating
Facilities that include at least one electric storage resource that
request to use, and for which Transmission Provider approves,
operating assumptions pursuant to Section 3.1.2, the aggregate of
generation in the local area can be delivered to the aggregate of
load on Transmission Provider's Transmission System, consistent with
Transmission Provider's reliability criteria and procedures. This
approach assumes that some portion of existing Network Resources are
displaced by the output of Interconnection Customer's Large
Generating Facility. Network Resource Interconnection Service in and
of itself does not convey any right to deliver electricity to any
specific customer or Point of Delivery. The Transmission Provider
may also study the Transmission System under non-peak load
conditions. However, upon request by the Interconnection Customer,
the Transmission Provider must explain in writing to the
Interconnection Customer why the study of non-peak load conditions
is required for reliability purposes.
3.3 Utilization of Surplus Interconnection Service
Transmission Provider must provide a process that allows an
Interconnection Customer to utilize or transfer Surplus
Interconnection Service at an existing Point of Interconnection. The
original Interconnection Customer or one of its affiliates shall
have priority to utilize Surplus Interconnection Service. If the
existing Interconnection Customer or one of its affiliates does not
exercise its priority, then that service may be made available to
other potential Interconnection Customers.
3.3.1 Surplus Interconnection Service Request
Surplus Interconnection Service requests may be made by the
existing Interconnection Customer [whose Generating Facility is
already interconnected]or one of its affiliates or may be submitted
once Interconnection Customer has executed the LGIA or requested
that the LGIA be filed unexecuted. Surplus Interconnection Service
requests also may be made by another Interconnection Customer.
Transmission Provider shall provide a process for evaluating
Interconnection Requests for Surplus Interconnection Service.
Studies for Surplus Interconnection Service shall consist of
reactive power, short circuit/fault duty, stability analyses, and
any other appropriate studies. Steady-state (thermal/voltage)
analyses may be performed as necessary to ensure that all required
reliability conditions are studied. If the Surplus Interconnection
Service was not studied under off-peak conditions, off-peak steady
state analyses shall be performed to the required level necessary to
demonstrate reliable operation of the Surplus Interconnection
Service. If the original system impact study report or Cluster Study
Report is not available for the Surplus Interconnection Service,
both off-peak and peak analysis may need to be performed for the
existing Generating Facility associated with the request for Surplus
Interconnection Service. The reactive power, short circuit/fault
duty, stability, and steady-state analyses for Surplus
Interconnection Service will identify any additional Interconnection
Facilities and/or Network Upgrades necessary.
Transmission Provider shall study Surplus Interconnection
Service requests for a Generating Facility that includes at least
one electric storage resource using operating assumptions (i.e.,
whether the interconnecting Generating Facility will or will not
charge at peak load) that reflect the proposed charging behavior of
the Generating Facility as requested by Interconnection Customer,
unless Transmission Provider determines that Good Utility Practice,
including Applicable Reliability Standards, otherwise requires the
use of different operating assumptions.
3.4 Valid Interconnection Request
3.4.1 Cluster Request Window
Transmission Provider shall accept Interconnection Requests
during a forty-five (45) Calendar Day period (the Cluster Request
Window). The initial Cluster Request Window shall open for
Interconnection Requests beginning {Transmission Provider to provide
number of Calendar Days{time} after the conclusion of the
transition process set out in Section 5.1 of this LGIP and
successive Cluster Request Windows shall open annually every
{Transmission Provider to provide Month and Day (e.g., January
1){time} thereafter.
3.4.[1]2 Initiating an Interconnection Request
An Interconnection Customer seeking to join a Cluster shall
submit its Interconnection Request to Transmission Provider within,
and no later than the close of, the Cluster Request Window.
Interconnection Requests submitted outside of the Cluster Request
Window will not be considered. To initiate an Interconnection
Request, Interconnection Customer must submit all of the following:
(i) [a $10,000 deposit,]applicable study deposit amount,
pursuant to Section 3.1.1.1 of this LGIP,
(ii) a completed application in the form of Appendix 1, [and]
(iii) demonstration of no less than ninety percent (90%) Site
Control or [a posting of an additional deposit of $10,000. Such
deposits shall be applied toward any Interconnection Studies,
pursuant to the Interconnection Request. If Interconnection Customer
demonstrates Site Control within the cure period specified in
Section 3.4.3 after submitting its Interconnection Request, the
additional deposit shall be refundable; otherwise, all such
deposit(s), additional and initial, become non-refundable.] (1) a
signed affidavit from an officer of the company indicating that Site
Control is unobtainable due to regulatory limitations as such term
is defined by the Transmission Provider; and (2) documentation
sufficiently describing and explaining the source and effects of
such regulatory limitations, including a description of any
conditions that must be met to satisfy the regulatory limitations
and the anticipated time by which Interconnection Customer expects
to satisfy the regulatory requirements and (3) a deposit in lieu of
Site Control of $10,000 per MW, subject to a minimum of $500,000 and
a maximum of $2,000,000. Interconnection Requests from multiple
Interconnection Customers for multiple Generating Facilities that
share a site must include a contract or other agreement that allows
for shared land use.
(iv) Generating Facility Capacity (MW) (and requested
Interconnection Service level if the requested Interconnection
Service is less than the Generating Facility Capacity),
(v) If applicable, (1) the requested operating assumptions
(i.e., whether the interconnecting Generating Facility will or will
not charge at peak load) to be used by Transmission Provider that
reflect the proposed charging behavior of the Generating Facility
that includes at least one electric storage resource, and (2) a
description of any control technologies (software and/or hardware)
that will limit the operation of the Generating Facility to the
operating assumptions submitted by Interconnection Customer.
(vi) A Commercial Readiness Deposit equal to two times the study
deposit described in Section 3.1.1.1 of this LGIP in the form of an
irrevocable letter of credit or cash. This Commercial Readiness
Deposit is refunded to Interconnection Customer according to Section
3.7 of this LGIP,
(vii) A Point of Interconnection, and
(viii) Whether the Interconnection Request shall be studied for
Network Resource Interconnection Service or for Energy Resource
Interconnection Service, consistent with Section 3.2 of this LGIP.
An Interconnection Customer that submits a deposit in lieu of
Site Control due to demonstrated regulatory limitations must
demonstrate that it is taking identifiable steps to secure the
necessary regulatory approvals from the applicable federal, state,
and/or tribal entities before execution of the Cluster Study
Agreement. Such deposit will be held by Transmission Provider until
[[Page 61271]]
Interconnection Customer provides the required Site Control
demonstration for its point in the Cluster Study Process.
Interconnection Customers facing qualifying regulatory limitations
must demonstrate one-hundred percent (100%) Site Control within one-
hundred eighty (180) Calendar Days of the effective date of the
LGIA.
Interconnection Customer shall promptly inform Transmission
Provider of any material change to Interconnection Customer's
demonstration of Site Control under Section 3.4.2(iii) of this LGIP.
If Transmission Provider determines, based on Interconnection
Customer's information, that Interconnection Customer no longer
satisfies the Site Control requirement, Transmission Provider shall
give Interconnection Customer ten (10) Business Days to demonstrate
satisfaction with the applicable requirement subject to Transmission
Provider's approval. Absent such, Transmission Provider shall deem
the Interconnection Request withdrawn pursuant to Section 3.7 of
this LGIP.
The expected In-Service Date of the new Large Generating
Facility or increase in capacity of the existing Generating Facility
shall be no more than the process window for the regional expansion
planning period (or in the absence of a regional planning process,
the process window for Transmission Provider's expansion planning
period) not to exceed seven years from the date the Interconnection
Request is received by Transmission Provider, unless Interconnection
Customer demonstrates that engineering, permitting and construction
of the new Large Generating Facility or increase in capacity of the
existing Generating Facility will take longer than the regional
expansion planning period. The In-Service Date may succeed the date
the Interconnection Request is received by Transmission Provider by
a period up to ten years, or longer where Interconnection Customer
and Transmission Provider agree, such agreement not to be
unreasonably withheld.
3.4.[2]3 Acknowledgment of Interconnection Request
Transmission Provider shall acknowledge receipt of the
Interconnection Request within five (5) Business Days of receipt of
the request and attach a copy of the received Interconnection
Request to the acknowledgement.
3.4.[3]4 Deficiencies in Interconnection Request
An Interconnection Request will not be considered to be a valid
request until all items in Section [3.4.1]3.4.2 of this LGIP have
been received by Transmission Provider. If an Interconnection
Request fails to meet the requirements set forth in Section
[3.4.1]3.4.2 of this LGIP, Transmission Provider shall notify
Interconnection Customer within five (5) Business Days of receipt of
the initial Interconnection Request of the reasons for such failure
and that the Interconnection Request does not constitute a valid
request. Interconnection Customer shall provide Transmission
Provider the additional requested information needed to constitute a
valid request within ten (10) Business Days after receipt of such
notice but no later than the close of the Cluster Request Window. 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. In the
event that [Failure by] Interconnection Customer fails to comply
with this Section 3.4.[3]4 of this LGIP, Transmission Providers
shall deem the Interconnection Request withdrawn (without the cure
period provided under Section 3.7 of this LGIP), the application fee
is forfeited to the Transmission Provider, and the study deposit and
Commercial Readiness Deposit shall be returned to Interconnection
Customer [shall be treated in accordance with Section 3.7].
3.4.5 Customer Engagement Window
Upon the close of each Cluster Request Window, Transmission
Provider shall open a sixty (60) Calendar Day period (Customer
Engagement Window). During the Customer Engagement Window,
Transmission Provider shall hold a Scoping Meeting with all
interested Interconnection Customers. Notwithstanding the preceding
requirements and upon written consent of all Interconnection
Customers within the Cluster, Transmission Provider may shorten the
Customer Engagement Window and begin the Cluster Study. Within ten
(10) Business Days of the opening of the Customer Engagement Window,
Transmission Provider shall post on its OASIS a list of
Interconnection Requests for that Cluster. The list shall identify,
for each anonymized Interconnection Request: (1) the requested
amount of Interconnection Service; (2) the location by county and
state; (3) the station or transmission line or lines where the
interconnection will be made; (4) the projected In-Service Date; (5)
the type of Interconnection Service requested; and (6) the type of
Generating Facility or Facilities to be constructed, including fuel
types, such as coal, natural gas, solar, or wind. The Transmission
Provider must ensure that project information is anonymized and does
not reveal the identity or commercial information of interconnection
customers with submitted requests. During the Customer Engagement
Window, Transmission Provider shall provide to Interconnection
Customer a non-binding updated good faith estimate of the cost and
timeframe for completing the Cluster Study and a Cluster Study
Agreement to be executed prior to the close of the Customer
Engagement Window.
At the end of the Customer Engagement Window, all
Interconnection Requests deemed valid that have executed a Cluster
Study Agreement in the form of Appendix 2 to this LGIP shall be
included in the Cluster Study. Any Interconnection Requests not
deemed valid at the close of the Customer Engagement Window shall be
deemed withdrawn (without the cure period provided under Section 3.7
of this LGIP) by Transmission Provider, the application fee shall be
forfeited to the Transmission Provider, and the Transmission
Provider shall return the study deposit and Commercial Readiness
Deposit to Interconnection Customer. Immediately following the
Customer Engagement Window, Transmission Provider shall initiate the
Cluster Study described in Section 7 of this LGIP.
3.4.[4]6 Cluster Study Scoping Meetings
[Within ten (10) Business Days after receipt of a valid
Interconnection Request]During the Customer Engagement Window,
Transmission Provider shall [establish a date agreeable to]hold a
Scoping Meeting with all Interconnection Customers whose valid
Interconnection Requests were received in that Cluster Request
Window.
The purpose of the Cluster Study Scoping Meeting shall be to
discuss alternative interconnection options, to exchange information
including any transmission data and earlier study evaluations that
would reasonably be expected to impact such interconnection options,
to discuss the Cluster Study materials posted to OASIS pursuant to
Section 3.5 of this LGIP, if applicable, and to analyze such
information [and to determine the potential feasible Points of
Interconnection]. Transmission Provider and Interconnection
Customer(s) will bring to the meeting such technical data,
including, but not limited to: (i) general facility loadings, (ii)
general instability issues, (iii) general short circuit issues, (iv)
general voltage issues, and (v) general reliability issues as may be
reasonably required to accomplish the purpose of the meeting.
Transmission Provider and Interconnection Customer(s) will also
bring to the meeting personnel and other resources as may be
reasonably required to accomplish the purpose of the meeting in the
time allocated for the meeting. On the basis of the meeting,
Interconnection Customer(s) shall designate its Point of
Interconnection.[, pursuant to Section 6.1,] and one or more
available alternative Point(s) of Interconnection. The duration of
the meeting shall be sufficient to accomplish its purpose. If the
Cluster Study Scoping Meeting consists of more than one
Interconnection Customer, Transmission Provider shall issue, no
later than fifteen (15) Business Days after the commencement of the
Customer Engagement Window, and Interconnection Customer shall
execute a non-disclosure agreement prior to a group Cluster Study
Scoping Meeting, which will provide for confidentiality of
identifying commercially sensitive information pertaining to any
other Interconnection Customers.
3.5 OASIS Posting
3.5.1 OASIS Posting
Transmission Provider will maintain on its OASIS a list of all
Interconnection Requests. The list will identify, for each
Interconnection Request: (i) the maximum summer and winter megawatt
electrical output; (ii) the location by county and state; (iii) the
station or transmission line or lines where the interconnection will
be made; (iv) the projected In-Service Date; (v) the status of the
Interconnection Request, including Queue Position; (vi) the type of
Interconnection Service being requested; and (vii) the availability
of any studies related to the Interconnection Request; (viii) the
date of the Interconnection Request; (ix) the type of
[[Page 61272]]
Generating Facility to be constructed [(combined cycle, base load or
combustion turbine and fuel type)]; and (x) for Interconnection
Requests that have not resulted in a completed interconnection, an
explanation as to why it was not completed. Except in the case of an
Affiliate, the list will not disclose the identity of
Interconnection Customer until Interconnection Customer executes an
LGIA or requests that Transmission Provider file an unexecuted LGIA
with FERC. Before holding a Scoping Meeting with its Affiliate,
Transmission Provider shall post on OASIS an advance notice of its
intent to do so. Transmission Provider shall post to its OASIS site
any deviations from the study timelines set forth herein.
Interconnection Study reports and Optional Interconnection Study
reports shall be posted to Transmission Provider's OASIS site
subsequent to the meeting between Interconnection Customer and
Transmission Provider to discuss the applicable study results.
Transmission Provider shall also post any known deviations in the
Large Generating Facility's In-Service Date.
3.5.2 Requirement To Post Interconnection Study Metrics
Transmission Provider will maintain on its OASIS or its website
summary statistics related to processing Interconnection Studies
pursuant to Interconnection Requests, updated quarterly. If
Transmission Provider posts this information on its website, a link
to the information must be provided on Transmission Provider's OASIS
site. For each calendar quarter, Transmission Providers must
calculate and post the information detailed in [sections]Sections
3.5.2.1 through 3.5.2.4 of this LGIP.
3.5.2.1 Interconnection [Feasibility Studies]Cluster Study Processing
Time
(A) Number of Interconnection Requests that had [Interconnection
Feasibility]Cluster Studies completed within Transmission Provider's
coordinated region during the reporting quarter,
(B) Number of Interconnection Requests that had [Interconnection
Feasibility]Cluster Studies completed within Transmission Provider's
coordinated region during the reporting quarter that were completed
more than [[timeline as listed in Transmission Provider's LGIP]]one
hundred fifty (150) Calendar Days after [receipt by Transmission
Provider of the Interconnection Customer's executed Interconnection
Feasibility Study Agreement]the close of the Customer Engagement
Window,
(C) At the end of the reporting quarter, the number of active
valid Interconnection Requests with ongoing incomplete
[Interconnection Feasibility] Cluster Studies where such
Interconnection Requests had executed [Interconnection Feasibility]a
Cluster Study Agreement[s] received by Transmission Provider more
than [[timeline as listed in Transmission Provider's LGIP]]one
hundred fifty (150) Calendar Days before the reporting quarter end,
(D) Mean time (in days), [Interconnection Feasibility]Cluster
Studies completed within Transmission Provider's coordinated region
during the reporting quarter, from the [date when Transmission
Provider received the executed Interconnection Feasibility Study
Agreement]commencement of the Cluster Study to the date when
Transmission Provider provided the completed [Interconnection
Feasibility]Cluster Study Report to [the] Interconnection Customer,
(E) Mean time (in days), Cluster Studies were completed within
Transmission Provider's coordinated region during the reporting
quarter, from the close of the Cluster Request Window to the date
when Transmission Provider provided the completed Cluster Study
Report to Interconnection Customer.
[(E)](F) Percentage of [Interconnection Feasibility]Cluster
Studies exceeding [[timeline as listed in Transmission Provider's
LGIP]]one hundred fifty (150) Calendar Days to complete this
reporting quarter, calculated as the sum of 3.5.2.1(B) plus
3.5.2.1(C) divided by the sum of 3.5.2.1(A) plus 3.5.2.1(C)[)].
3.5.2.2 [Interconnection System Impact Studies]Cluster Restudies
Processing Time
(A) Number of Interconnection Requests that had [Interconnection
System Impact Studies]Cluster Restudies completed within
Transmission Provider's coordinated region during the reporting
quarter,
(B) Number of Interconnection Requests that had [Interconnection
System Impact Studies]Cluster Restudies completed within
Transmission Provider's coordinated region during the reporting
quarter that were completed more than [[timeline as listed in
Transmission Provider's LGIP]]one hundred fifty (150) Calendar Days
after [receipt by] Transmission Provider notifies Interconnection
Customers in the Cluster that a Cluster Restudy is required pursuant
to Section 7.5(4) of this LGIP [of the Interconnection Customer's
executed Interconnection System Impact Study Agreement],
(C) At the end of the reporting quarter, the number of active
valid Interconnection Requests with ongoing incomplete [System
Impact Studies]Cluster Restudies where Transmission Provider
notified Interconnection Customers in the Cluster that a Cluster
Restudy is required pursuant to Section 7.5(4) of this LGIP [such
Interconnection Requests had executed Interconnection System Impact
Study Agreements received by Transmission Provider] more than
[[timeline as listed in Transmission Provider's LGIP]]one hundred
fifty (150) Calendar Days before the reporting quarter end,
(D) Mean time (in days), [Interconnection System Impact
Studies]Cluster Restudies completed within Transmission Provider's
coordinated region during the reporting quarter, from the date when
Transmission Provider notifies Interconnection Customers in the
Cluster that a Cluster Restudy is required pursuant to Section
7.5(4) of this LGIP [received the executed Interconnection System
Impact Study Agreement] to the date when Transmission Provider
provided the completed [Interconnection System Impact Study]Cluster
Restudy Report to [the]Interconnection Customer,
(E) Mean time (in days), Cluster Restudies completed within
Transmission Provider's coordinated region during the reporting
quarter, from the close of the Cluster Request Window to the date
when Transmission Provider provided the completed Cluster Restudy
Report to Interconnection Customer.
[(E)](F) Percentage of [Interconnection System Impact
Studies]Cluster Restudies exceeding [[timeline as listed in
Transmission Provider's LGIP]]one hundred fifty (150) Calendar Days
to complete this reporting quarter, calculated as the sum of
3.5.2.2(B) plus 3.5.2.2(C) divided by the sum of 3.5.2.2(A) plus
3.5.2.2(C)).
3.5.2.3 Interconnection Facilities Studies Processing Time
(A) Number of Interconnection Requests that had Interconnection
Facilities Studies that are completed within Transmission Provider's
coordinated region during the reporting quarter,
(B) Number of Interconnection Requests that had Interconnection
Facilities Studies that are completed within Transmission Provider's
coordinated region during the reporting quarter that were completed
more than {timeline as listed in Transmission Provider's LGIP{time}
after receipt by Transmission Provider of the Interconnection
Customer's executed Interconnection Facilities Study Agreement,
(C) At the end of the reporting quarter, the number of active
valid Interconnection Service requests with ongoing incomplete
Interconnection Facilities Studies where such Interconnection
Requests had executed Interconnection Facilities Studies Agreement
received by Transmission Provider more than {timeline as listed in
Transmission Provider's LGIP{time} before the reporting quarter
end,
(D) Mean time (in days), for Interconnection Facilities Studies
completed within Transmission Provider's coordinated region during
the reporting quarter, calculated from the date when Transmission
Provider received the executed Interconnection Facilities Study
Agreement to the date when Transmission Provider provided the
completed Interconnection Facilities Study to the Interconnection
Customer,
(E) Mean time (in days), Interconnection Facilities Studies
completed within Transmission Provider's coordinated region during
the reporting quarter, from the close of the Cluster Request Window
to the date when Transmission Provider provided the completed
Interconnection Facilities Study to Interconnection Customer.
[(E)](F) Percentage of delayed Interconnection Facilities
Studies this reporting quarter, calculated as the sum of 3.5.2.3(B)
plus 3.5.2.3(C) divided by the sum of 3.5.2.3(A) plus 3.5.2.3(C)).
3.5.2.4 Interconnection Service Requests Withdrawn From Interconnection
Queue
(A) Number of Interconnection Requests withdrawn from
Transmission Provider's interconnection queue during the reporting
quarter,
(B) Number of Interconnection Requests withdrawn from
Transmission Provider's interconnection queue during the reporting
quarter before completion of any interconnection studies or
execution of any interconnection study agreements,
[[Page 61273]]
(C) Number of Interconnection Requests withdrawn from
Transmission Provider's interconnection queue during the reporting
quarter before completion of [an Interconnection System Impact]a
Cluster Study,
(D) Number of Interconnection Requests withdrawn from
Transmission Provider's interconnection queue during the reporting
quarter before completion of an Interconnection Facilities Study,
(E) Number of Interconnection Requests withdrawn from
Transmission Provider's interconnection queue after execution of a
generator interconnection agreement or Interconnection Customer
requests the filing of an unexecuted, new interconnection agreement,
(F) Mean time (in days), for all withdrawn Interconnection
Requests, from the date when the request was determined to be valid
to when Transmission Provider received the request to withdraw from
the queue.
3.5.3
Transmission Provider is required to post on OASIS or its
website the measures in paragraph 3.5.2.1(A) through paragraph
3.5.2.4(F) for each calendar quarter within 30 days of the end of
the calendar quarter. Transmission Provider will keep the quarterly
measures posted on OASIS or its website for three calendar years
with the first required report to be in the first quarter of 2020.
If Transmission Provider retains this information on its website, a
link to the information must be provided on Transmission Provider's
OASIS site.
3.5.4
In the event that any of the values calculated in paragraphs
3.5.2.1(E), 3.5.2.2(E) or 3.5.2.3(E) exceeds 25 percent for two
consecutive calendar quarters, Transmission Provider will have to
comply with the measures below for the next four consecutive
calendar quarters and must continue reporting this information until
Transmission Provider reports four consecutive calendar quarters
without the values calculated in 3.5.2.1(E), 3.5.2.2(E) or
3.5.2.3(E) exceeding 25 percent for two consecutive calendar
quarters:
(i) Transmission Provider must submit a report to the Commission
describing the reason for each Cluster Study, Cluster Restudy, or
individual Interconnection Facilities S[s]tudy [or group of
clustered studies]pursuant to[an] one or more Interconnection
Request(s) that exceeded its deadline (i.e., [45,]150, 90 or 180
days) for completion [(excluding any allowance for Reasonable
Efforts)]. Transmission Provider must describe the reasons for each
study delay and any steps taken to remedy these specific issues and,
if applicable, prevent such delays in the future. The report must be
filed at the Commission within 45 days of the end of the calendar
quarter.
(ii) Transmission Provider shall aggregate the total number of
employee-hours and third party consultant hours expended towards
interconnection studies within its coordinated region that quarter
and post on OASIS or its website. If Transmission Provider posts
this information on its website, a link to the information must be
provided on Transmission Provider's OASIS site. This information is
to be posted within 30 days of the end of the calendar quarter.
3.6 Coordination With Affected Systems
Transmission Provider will coordinate the conduct of any studies
required to determine the impact of the Interconnection Request on
Affected Systems with Affected System Operators[and, if possible,
include those results in its applicable Interconnection Study within
the time frame specified in this LGIP. Transmission Provider will
include such Affected System Operators in all meetings held with
Interconnection Customer as required by this LGIP]. Interconnection
Customer will cooperate with Transmission Provider and Affected
System Operator in all matters related to the conduct of studies and
the determination of modifications to Affected Systems.
A Transmission Provider whose system may be impacted by a
proposed interconnection on another transmission provider's
transmission system [which may be an Affected System] shall
cooperate with the [T]transmission [P]provider with whom
interconnection has been requested in all matters related to the
conduct of studies and the determination of modifications to
Transmission Provider's Transmission System[Affected Systems].
3.6.1 Initial Notification
Transmission Provider must notify Affected System Operator of a
potential Affected System impact caused by an Interconnection
Request within ten (10) Business Days of the completion of the
Cluster Study or, if the potential Affected System impact is only
determined in the Cluster Restudy, the completion of the Cluster
Restudy.
At the time of initial notification, Transmission Provider must
provide Interconnection Customer with a list of potential Affected
Systems, along with relevant contact information.
3.7 Withdrawal
Interconnection Customer may withdraw its Interconnection
Request at any time by written notice of such withdrawal to
Transmission Provider. In addition, if Interconnection Customer
fails to adhere to all requirements of this LGIP, except as provided
in Section 13.5 (Disputes), Transmission Provider shall deem the
Interconnection Request to be withdrawn and shall provide written
notice to Interconnection Customer of the deemed withdrawal and an
explanation of the reasons for such deemed withdrawal. Upon receipt
of such written notice, Interconnection Customer shall have fifteen
(15) Business Days in which to either respond with information or
actions that cures the deficiency or to notify Transmission Provider
of its intent to pursue Dispute Resolution.
Withdrawal shall result in the loss of Interconnection
Customer's Queue Position. If an Interconnection Customer disputes
the withdrawal and loss of its Queue Position, then during Dispute
Resolution, Interconnection Customer's Interconnection Request is
eliminated from the queue until such time that the outcome of
Dispute Resolution would restore its Queue Position. An
Interconnection Customer that withdraws or is deemed to have
withdrawn its Interconnection Request shall pay to Transmission
Provider all costs that Transmission Provider prudently incurs with
respect to that Interconnection Request prior to Transmission
Provider's receipt of notice described above. Interconnection
Customer must pay all monies due to Transmission Provider before it
is allowed to obtain any Interconnection Study data or results.
If Interconnection Customer withdraws its Interconnection
Request or is deemed withdrawn by Transmission Provider under
Section 3.7 of this LGIP, Transmission Provider shall (i) update the
OASIS Queue Position posting; (ii) impose the Withdrawal Penalty
described in Section 3.7.1 of this LGIP; and (iii) refund to
Interconnection Customer any portion of the refundable portion of
Interconnection Customer's study deposit [or study payments] that
exceeds the costs that Transmission Provider has incurred, including
interest calculated in accordance with Section 35.19a(a)(2) of
FERC's regulations. Transmission Provider shall also refund any
portion of the Commercial Readiness Deposit not applied to the
Withdrawal Penalty and, if applicable, the deposit in lieu of site
control. In the event of such withdrawal, Transmission Provider,
subject to the confidentiality provisions of Section 13.1 of this
LGIP, shall provide, at Interconnection Customer's request, all
information that Transmission Provider developed for any completed
study conducted up to the date of withdrawal of the Interconnection
Request.
3.7.1 Withdrawal Penalty
Interconnection Customer shall be subject to a Withdrawal
Penalty if it withdraws its Interconnection Request or is deemed
withdrawn, or the Generating Facility does not otherwise reach
Commercial Operation unless: (1) the withdrawal does not have a
material impact on the cost or timing of any Interconnection Request
with an equal or lower Queue Position; (2) Interconnection Customer
withdraws after receiving Interconnection Customer's most recent
Cluster Restudy Report and the Network Upgrade costs assigned to the
Interconnection Request identified in that report have increased by
more than twenty-five percent (25%) compared to costs identified in
Interconnection Customer's preceding Cluster Study Report or Cluster
Restudy Report; or (3) Interconnection Customer withdraws after
receiving Interconnection Customer's Interconnection Facilities
Study Report and the Network Upgrade costs assigned to the
Interconnection Request identified in that report have increased by
more than one hundred percent (100%) compared to costs identified in
the Cluster Study Report.
3.7.1.1 Calculation of the Withdrawal Penalty
If Interconnection Customer withdraws its Interconnection
Request or is deemed withdrawn prior to the commencement of the
initial Cluster Study, Interconnection Customer shall not be subject
to a
[[Page 61274]]
Withdrawal Penalty. If Interconnection Customer withdraws, is deemed
withdrawn, or otherwise does not reach Commercial Operation at any
point after the commencement of the initial Cluster Study, that
Interconnection Customer's Withdrawal Penalty will be the greater
of: (1) the Interconnection Customer's study deposit required under
Section 3.1.1.1 of this LGIP; or (2) as follows in (a)-(d):
(a) If Interconnection Customer withdraws or is deemed withdrawn
during the Cluster Study or after receipt of a Cluster Study Report,
but prior to commencement of the Cluster Restudy or Interconnection
Facilities Study, Interconnection Customer shall be charged two (2)
times its actual allocated cost of all studies performed for
Interconnection Customers in the Cluster up until that point in the
interconnection study process.
(b) If Interconnection Customer withdraws or is deemed withdrawn
during the Cluster Restudy or after receipt of any applicable
restudy reports issued pursuant to Section 7.5 of this LGIP, but
prior to commencement of the Interconnection Facilities Study,
Interconnection Customer shall be charged five percent (5%) its
estimated Network Upgrade costs.
(c) If Interconnection Customer withdraws or is deemed withdrawn
during the Interconnection Facilities Study, after receipt of the
Interconnection Facilities Study Report issued pursuant to Section
8.3 of this LGIP, or after receipt of the draft LGIA but before
Interconnection Customer has executed an LGIA or has requested that
its LGIA be filed unexecuted, and has satisfied the other
requirements described in Section 11.3 of this LGIP (i.e., Site
Control demonstration, LGIA Deposit, reasonable evidence of one or
more milestones in the development of the Generating Facility),
Interconnection Customer shall be charged ten percent (10%) its
estimated Network Upgrade costs.
(d) If Interconnection Customer has executed an LGIA or has
requested that its LGIA be filed unexecuted and has satisfied the
other requirements described in Section 11.3 of this LGIP (i.e.,
Site Control demonstration, LGIA Deposit, reasonable evidence of one
or more milestones in the development of the Generating Facility)
and subsequently withdraws its Interconnection Request or if
Interconnection Customer's Generating Facility otherwise does not
reach Commercial Operation, that Interconnection Customer's
Withdrawal Penalty shall be twenty percent (20%) its estimated
Network Upgrade costs.
3.7.1.2 Distribution of the Withdrawal Penalty
3.7.1.2.1 Initial Distribution of Withdrawal Penalties Prior To
Assessment of Network Upgrade Costs Previously Shared With
Withdrawn Interconnection Customers in the Same Cluster
For a single cluster, Transmission Provider shall hold all
Withdrawal Penalty funds until all Interconnection Customers in that
Cluster have either: (1) withdrawn or been deemed withdrawn; (2)
executed an LGIA; or (3) requested an LGIA to be filed unexecuted.
Any Withdrawal Penalty funds collected from the Cluster shall first
be used to fund studies conducted under the Cluster Study Process
for Interconnection Customers in the same Cluster that have executed
the LGIA or requested the LGIA to be filed unexecuted. Next, after
the Withdrawal Penalty funds are applied to relevant study costs in
the same Cluster, Transmission Provider will apply the remaining
Withdrawal Penalty funds to reduce net increases, for
Interconnection Customers in the same Cluster, in Interconnection
Customers' Network Upgrade cost assignment and associated financial
security requirements under Article 11.5 of the pro forma LGIA
attributable to the impacts of withdrawn Interconnection Customers
that shared an obligation with the remaining Interconnection
Customers to fund a Network Upgrade, as described in more detail in
Sections 3.7.1.2.3 and 3.7.1.2.4.
Withdrawal Penalty funds shall first be applied as a refund to
invoiced study costs for Interconnection Customers in the same
Cluster that did not withdraw within 30 Calendar Days of such
Interconnection Customers executing their LGIA or requesting to have
their LGIA filed unexecuted. Distribution of Withdrawal Penalty
funds within one specific Cluster Study for study costs shall not
exceed the total actual Cluster Study costs. Withdrawal Penalty
funds applied to study costs shall be allocated within the same
Cluster to Interconnection Customers in a manner consistent with the
Transmission Provider's method in Section 13.3 of this LGIP for
allocating the costs of interconnection studies conducted on a
clustered basis. Transmission Provider shall post the balance of
Withdrawal Penalty funds held by Transmission Provider but not yet
dispersed on its OASIS site and update this posting on a quarterly
basis.
If an Interconnection Customer withdraws after it executes, or
requests the unexecuted filing of, its LGIA, Transmission Provider
shall first apply such Interconnection Customer's Withdrawal Penalty
funds to any restudy costs required due to the Interconnection
Customer's withdrawal as a credit to as-yet-to be invoiced study
costs to be charged to the remaining Interconnection Customers in
the same Cluster in a manner consistent with the Transmission
Provider's method in Section 13.3 of this LGIP for allocating the
costs of interconnection studies conducted on a clustered basis.
Distribution of the Withdrawal Penalty funds for such restudy costs
shall not exceed the total actual restudy costs.
3.7.1.2.2 Assessment of Network Upgrade Costs Previously Shared
With Withdrawn Interconnection Customers in the Same Cluster
If Withdrawal Penalty funds remain for the same Cluster after
the Withdrawal Penalty funds are applied to relevant study costs,
Transmission Provider will determine if the withdrawn
Interconnection Customers, at any point in the Cluster Study
Process, shared cost assignment for one or more Network Upgrades
with any remaining Interconnection Customers in the same Cluster
based on the Cluster Study Report, Cluster Restudy Report(s),
Interconnection Facilities Study Report, and any subsequent issued
restudy report issued for the Cluster.
In section 3.7.1.2 of this LGIP, shared cost assignments for
Network Upgrades refers to the cost of Network Upgrades still needed
for the same Cluster for which an Interconnection Customer, prior to
withdrawing its Interconnection Request, shared the obligation to
fund along with Interconnection Customers that have executed an
LGIA, or requested the LGIA to filed unexecuted.
If Transmission Provider's assessment determines that there are
no shared cost assignments for any Network Upgrades in the same
Cluster for the withdrawn Interconnection Customer, or determines
that the withdrawn Interconnection Customer's withdrawal did not
cause a net increase in the shared cost assignment for any remaining
Interconnection Customers' Network Upgrade(s) in the same Cluster,
Transmission Provider will return any remaining Withdrawal Penalty
funds to the withdrawn Interconnection Customer(s). Such remaining
Withdrawal Penalty funds will be returned to withdrawn
Interconnection Customers based on the proportion of each withdrawn
Interconnection Customer's contribution to the total amount of
Withdrawal Penalty funds collected for the Cluster (i.e., the total
amount before the initial disbursement required under Section
3.7.1.2.1 of this LGIP). Transmission Provider must make such
disbursement within sixty (60) Calendar Days of the date on which
all Interconnection Customers in the same Cluster have either: (1)
withdrawn or been deemed withdrawn; (2) executed an LGIA; or (3)
requested an LGIA to be filed unexecuted. For the withdrawn
Interconnection Customers that Transmission Provider determines have
caused a net increase in the shared cost assignment for one or more
Network Upgrade(s) in the same Cluster under subsection
3.7.1.2.3(a), Transmission Provider will determine each such
withdrawn Interconnection Customers' Withdrawal Penalty funds
remaining balance that will be applied toward net increases in
Network Upgrade shared costs calculated under subsections
3.7.1.2.3(a) and 3.7.1.2.3(b) based on each such withdrawn
Interconnection Customer's proportional contribution to the total
amount of Withdrawal Penalty funds collected for the same Cluster
(i.e., the total amount before the initial disbursement requirement
under Section 3.7.1.2.1 of this LGIP).
If the Transmission Provider's assessment determines that there
are shared cost assignments for Network Upgrades in the same
Cluster, Transmission Provider will calculate the remaining
Interconnection Customers' net increase in cost assignment for
Network Upgrades due to a shared cost assignment for Network
Upgrades with the withdrawn Interconnection Customer and distribute
Withdrawal Penalty funds as described in Section 3.7.1.2.3,
depending on whether the withdrawal occurred before the withdrawing
Interconnection Customer executed the LGIA (or filed unexecuted), as
described in subsection 3.7.1.2.3(a), or after such execution (or
filing unexecuted) of an LGIA, as described in subsection
3.7.1.2.3(b).
As discussed in subsection 3.7.1.2.4, Transmission Provider will
amend executed (or filed unexecuted) LGIAs of the remaining
[[Page 61275]]
Interconnection Customers in the same Cluster to apply the remaining
Withdrawal Penalty funds to reduce net increases in Interconnection
Customers' Network Upgrade cost assignment and associated financial
security requirements under Article 11.5 of the pro forma LGIA
attributable to the impacts of withdrawn Interconnection Customers
on Interconnection Customers remaining in the same Cluster that had
a shared cost assignment for Network Upgrades with the withdrawn
Interconnection Customers.
3.7.1.2.3 Impact Calculations
3.7.1.2.3(a) Impact Calculation for Withdrawals During the Cluster
Study Process
If an Interconnection Customer withdraws before it executes, or
requests the unexecuted filing of, its LGIA, the Transmission
Provider will distribute in the following manner the Withdrawal
Penalty funds to reduce the Network Upgrade cost impact on the
remaining Interconnection Customers in the same Cluster who had a
shared cost assignment for a Network Upgrade with the withdrawn
Interconnection Customer.
To calculate the reduction in the remaining Interconnection
Customers' net increase in Network Upgrade costs and associated
financial security requirements under Article 11.5 of the pro forma
LGIA, the Transmission Provider will determine the financial impact
of a withdrawing Interconnection Customer on other Interconnection
Customers in the same Cluster that shared an obligation to fund the
same Network Upgrade(s). Transmission Provider shall calculate this
financial impact once all the Interconnection Customers in the same
Cluster either: (1) have withdrawn or have been deemed withdrawn;
(2) executed an LGIA; or (3) request an LGIA to be filed unexecuted.
Transmission Provider will perform the financial impact calculation
using the following steps.
First, Transmission Provider must determine which withdrawn
Interconnection Customers shared an obligation to fund Network
Upgrades with Interconnection Customers from the same Cluster that
have LGIAs that are executed or have been requested to be filed
unexecuted. Next, Transmission Provider shall perform the
calculation of the financial impact of a withdrawal on another
Interconnection Request in the same Cluster by performing a
comparison of the Network Upgrade cost estimates between each of the
following:
(1) Cluster Study phase to Cluster Restudy phase (if Cluster
Restudy was necessary);
(2) Cluster Restudy phase to Facilities Study phase (if a
Cluster Restudy was necessary);
(3) Cluster Study phase to Facilities Study phase (if no Cluster
Restudy was performed);
(4) Facilities Study phase to any subsequent restudy that was
performed before the execution or filing of an unexecuted LGIA;
(5) the restudy to the executed, or filed unexecuted, LGIA (if a
restudy was performed after the Facilities Study phase and before
the execution or filing of an unexecuted LGIA).
If, based on the above calculations, Transmission Provider
determines:
(i) that the costs assigned to an Interconnection Customer in
the same Cluster for Network Upgrades that a withdrawn
Interconnection Customer shared cost assignment for increased
between any two studies, and
(ii) after the impacted Interconnection Customer's LGIA was
executed or filed unexecuted, the Interconnection Customer's cost
assignment for the relevant Network Upgrade is greater than it was
prior to the withdrawal of the Interconnection Customer in the same
Cluster that shared cost assignment for the Network Upgrade,
then Transmission Provider shall apply the withdrawn
Interconnection Customer's Withdrawal Penalty funds that has not
already been applied to study costs in the amount of the financial
impact by reducing, in the same Cluster, the remaining
Interconnection Customer's Network Upgrade costs and associated
financial security requirements under Article 11.5 of the pro forma
LGIA.
If Transmission Provider determines that more than one
Interconnection Customer in the same Cluster was financially
impacted by the same withdrawn Interconnection Customer,
Transmission Provider will apply the relevant withdrawn
Interconnection Customer's Withdrawal Penalty funds that has not
already been applied to study costs to reduce the financial impact
to each Interconnection Customer based on each Interconnection
Customer's proportional share of the financial impact, as determined
by either the proportional impact method if it is a System Network
Upgrade or on a per capita basis if it is a Substation Network
Upgrade, as described under Section 4.2.1 of this LGIP.
3.7.1.2.3(b) Impact Calculation for Withdrawals in the Same Cluster
After the Cluster Study Process
If an Interconnection Customer withdraws after it executes, or
requests the unexecuted filing of, its LGIA, Transmission Provider
will distribute in the following manner the remaining Withdrawal
Penalty funds to reduce the Network Upgrade cost impact on the
remaining Interconnection Customers in the same Cluster who had a
shared cost assignment with the withdrawn Interconnection Customer
for one or more Network Upgrades.
Transmission Provider will determine the financial impact on the
remaining Interconnection Customers in the same Cluster within 30
calendar days after the withdrawal occurs. The Transmission Provider
will determine that financial impact by comparing the Network
Upgrade cost funding obligations the Interconnection Customers
shared with the withdrawn Interconnection Customer before the
withdrawal of the Interconnection Customer and after the withdrawal
of the Interconnection Customer. If that comparison indicates an
increase in Network Upgrade costs for an Interconnection Customer,
Transmission Provider shall apply the withdrawn Interconnection
Customer's Withdrawal Penalty funds to the increased costs each
impacted Interconnection Customer in the same Cluster experienced
associated with such Network Upgrade(s) in proportion to each
Interconnection Customer's increased cost assignment, as determined
by Transmission Provider.
3.7.1.2.4 Amending LGIA To Apply Reductions To Interconnection
Customer's Assigned Network Upgrade Costs and Associated Financial
Security Requirement With Respect To Withdrawals in the Same Cluster
Within 30 Calendar Days of all Interconnection Customers in the
same Cluster having: (1) withdrawn or been deemed withdrawn; (2)
executed an LGIA; or (3) requested an LGIA to be filed unexecuted,
Transmission Provider must perform the calculations described in
subsection 3.7.1.2.3(a) of this LGIP and provide such
Interconnection Customers with an amended LGIA that provides the
reduction in Network Upgrade cost assignment and associated
reduction to the Interconnection Customer's financial security
requirements, under Article 11.5 of the pro forma LGIA, due from the
Interconnection Customer to the Transmission Provider.
Where an Interconnection Customer executes the LGIA (or requests
the filing of an unexecuted LGIA) and is later withdrawn or its LGIA
is terminated, Transmission Provider must, within 30 Calendar Days
of such withdrawal or termination, perform the calculations
described in subsection 3.7.1.2.3(b) of this LGIP and provide such
Interconnection Customers in the same Cluster with an amended LGIA
that provides the reduction in Network Upgrade cost assignment and
associated reduction to the Interconnection Customer's financial
security requirements, under Article 11.5 of the pro forma LGIA, due
from the Interconnection Customer to Transmission Provider.
Any repayment by Transmission Provider to Interconnection
Customer under Article 11.4 of the pro forma LGIA of amounts
advanced for Network Upgrades after the Generating Facility achieves
Commercial Operation shall be limited to the Interconnection
Customer's total amount of Network Upgrade costs paid and associated
financial security provided to Transmission Provider under Article
11.5 of the pro forma LGIA.
3.7.1.2.5 Final Distribution of Withdrawal Penalty Funds
If Withdrawal Penalty funds remain for the Cluster after the
Withdrawal Penalty funds are applied to relevant study costs and net
increases in shared cost assignments for Network Upgrades to
remaining Interconnection Customers, Transmission Provider will
return any remaining Withdrawal Penalty funds to the withdrawn
Interconnection Customers in the same Cluster net of the amount of
each withdrawn Interconnection Customer's Withdrawal Penalty funds
applied to study costs and net increases in shared cost assignments
for Network Upgrades to remaining Interconnection Customers.
3.8 Identification of Contingent Facilities
Transmission Provider shall post in this section a method for
identifying the
[[Page 61276]]
Contingent Facilities to be provided to Interconnection Customer at
the conclusion of the [System Impact]Cluster Study and included in
Interconnection Customer's Large Generator Interconnection
Agreement. The method shall be sufficiently transparent to determine
why a specific Contingent Facility was identified and how it relates
to the Interconnection Request. Transmission Provider shall also
provide, upon request of [the]Interconnection Customer, the
estimated Interconnection Facility and/or Network Upgrade costs and
estimated in-service completion time of each identified Contingent
Facility when this information is readily available and not
commercially sensitive.
3.9 Penalties for Failure To Meet Study Deadlines
(1) Transmission Provider shall be subject to a penalty if it
fails to complete a Cluster Study, Cluster Restudy, Interconnection
Facilities Study, or Affected Systems Study by the applicable
deadline set forth in this LGIP. Transmission Provider must pay the
penalty for each late Cluster Study, Cluster Restudy, and
Interconnection Facilities Study on a pro rata basis per
Interconnection Request to all Interconnection Customer(s) included
in the relevant study that did not withdraw, or were not deemed
withdrawn, from Transmission Provider's interconnection queue before
the missed study deadline. Transmission Provider must pay the
penalty for a late Affected Systems Study on a pro rata basis per
interconnection request to all Affected System Interconnection
Customer(s) included in the relevant Affected System Study that did
not withdraw, or were not deemed withdrawn, from the host
transmission provider's interconnection queue before the missed
study deadline. The study delay penalty for each late study shall be
distributed no later than forty-five (45) Calendar Days after the
late study has been completed.
(2) For penalties assessed in accordance with this Section, the
penalty amount will be equal to: $1,000 per Business Day for delays
of Cluster Studies beyond the applicable deadline set forth in this
LGIP; $2,000 per Business Day for delays of Cluster Re-Studies
beyond the applicable deadline set forth in this LGIP; $2,000 per
Business Day for delays of Affected System Studies beyond the
applicable deadline set forth in this LGIP; and $2,500 per Business
Day for delays of Interconnection Facilities Studies beyond the
applicable deadline set forth in this LGIP. The total amount of a
penalty assessed under this Section shall not exceed: (a) one
hundred percent (100%) of the initial study deposit(s) received for
all of the Interconnection Requests in the Cluster for Cluster
Studies and Cluster Restudies; (b) one hundred percent (100%) of the
initial study deposit received for the single Interconnection
Request in the study for Facilities Studies; and (c) one hundred
percent (100%) of the study deposit(s) that Transmission Provider
collects for conducting the Affected System Study.
(3) Transmission Provider may appeal to the Commission any
penalties imposed under this Section. Any such appeal must be filed
no later than forty-five (45) Calendar Days after the late study has
been completed. While an appeal to the Commission is pending,
Transmission Provider shall remain liable for the penalty, but need
not distribute the penalty until forty-five (45) Calendar Days after
(1) the deadline for filing a rehearing request has ended, if no
requests for rehearing of the appeal have been filed, or (2) the
date that any requests for rehearing of the Commission's decision on
the appeal are no longer pending before the Commission. The
Commission may excuse Transmission Provider from penalties under
this Section for good cause.
(4) No penalty will be assessed under this Section where a study
is delayed by ten (10) Business Days or less. If the study is
delayed by more than ten (10) Business Days, the penalty amount will
be calculated from the first Business Day the Transmission Provider
misses the applicable study deadline.
(5) If (a) Transmission Provider needs to extend the deadline
for a particular study subject to penalties under this Section and
(b) all Interconnection Customers or Affected System Interconnection
Customers included in the relevant study mutually agree to such an
extension, the deadline for that study shall be extended thirty (30)
Business Days from the original deadline. In such a scenario, no
penalty will be assessed for Transmission Provider missing the
original deadline.
(6) No penalties shall be assessed until the third Cluster Study
cycle (including any Transitional Cluster Study cycle, but not
Transitional Serial Studies) after the Commission-approved effective
date of Transmission Provider's filing made in compliance with the
Final rule in Docket No. RM22-14-000.
(7) Transmission Provider must maintain on its OASIS or its
public website summary statistics related to penalties assessed
under this Section, updated quarterly. For each calendar quarter,
Transmission Provider must calculate and post (1) the total amount
of penalties assessed under this Section during the previous
reporting quarter and (2) the highest penalty assessed under this
Section paid to a single Interconnection Customer or Affected System
Interconnection Customer during the previous reporting quarter.
Transmission Provider must post on its OASIS or its website these
penalty amounts for each calendar quarter within thirty (30)
Calendar Days of the end of the calendar quarter. Transmission
Provider must maintain the quarterly measures posted on its OASIS or
its website for three (3) calendar years with the first required
posting to be the third Cluster Study cycle (including any
Transitional Cluster Study cycle, but not Transitional Serial
Studies) after Transmission Provider transitions to the Cluster
Study Process.
Section 4. Interconnection Request Evaluation Process [Queue Position]
Once an Interconnection Customer has submitted a valid
Interconnection Request pursuant to Section 3.4 of this LGIP, such
Interconnection Request shall become part of the Transmission
Provider's interconnection queue for further processing pursuant to
the following procedures.
4.1 Queue Position [General]
4.1.1 Assignment of Queue Position
Transmission Provider shall assign a Queue Position as follows:
the Queue Position within the queue shall be assigned based upon the
date and time of receipt of all items required pursuant to the
provisions of Section 3.4 of this LGIP. All Interconnection Requests
submitted and validated in a single Cluster Request Window shall be
considered equally queued. [based upon the date and time of receipt
of the valid Interconnection Request; provided that, if the sole
reason an Interconnection Request is not valid is the lack of
required information on the application form, and Interconnection
Customer provides such information in accordance with Section 3.4.3,
then Transmission Provider shall assign Interconnection Customer a
Queue Position based on the date the application form was originally
filed. Moving a Point of Interconnection shall result in a lowering
of Queue Position if it is deemed a Material Modification under
Section 4.4.3.]
[The Queue Position of each Interconnection Request will be used
to determine the order of performing the Interconnection Studies and
determination of cost responsibility for the facilities necessary to
accommodate the Interconnection Request. A higher queued]
4.1.2 Higher Queue Position
A higher Queue Position assigned to an Interconnection Request
is one that has been placed ``earlier'' in the queue in relation to
another Interconnection Request that is [lower queued. Transmission
Provider may allocate the cost of the common upgrades for clustered
Interconnection Requests without regard to Queue Position.]assigned
a lower Queue Position. All requests studied in a single Cluster
shall be considered equally queued. Interconnection Customers that
are part of Clusters initiated earlier in time than an instant Queue
shall be considered to have a higher Queue Position than
Interconnection Customers that are part of Clusters initiated later
than an instant Queue.
[4.2 Clustering
At Transmission Provider's option, Interconnection Requests may
be studied serially or in clusters for the purpose of the
Interconnection System Impact Study.
Clustering shall be implemented on the basis of Queue Position.
If Transmission Provider elects to study Interconnection Requests
using Clustering, all Interconnection Requests received within a
period not to exceed one hundred and eighty (180) Calendar Days,
hereinafter referred to as the ``Queue Cluster Window'' shall be
studied together without regard to the nature of the underlying
Interconnection Service, whether Energy Resource Interconnection
Service or Network Resource Interconnection Service. The deadline
for completing all Interconnection System Impact Studies for which
an Interconnection System Impact Study Agreement has been executed
during a Queue Cluster Window shall be in accordance with Section
7.4, for all Interconnection Requests assigned to the same Queue
Cluster Window. Transmission
[[Page 61277]]
Provider may study an Interconnection Request separately to the
extent warranted by Good Utility Practice based upon the electrical
remoteness of the proposed Large Generating Facility.]
4.2 General Study Process
[Clustering Interconnection System Impact
Studies]Interconnection Studies performed within the Cluster Study
Process shall be conducted in such a manner to ensure the efficient
implementation of the applicable regional transmission expansion
plan in light of the Transmission System's capabilities at the time
of each study and consistent with Good Utility Practice.
Transmission Provider may use subgroups in the Cluster Study
Process. In all instances in which Transmission Provider elects to
use subgroups in the cluster study process, Transmission Provider
must publish the criteria used to define and determine subgroups on
its OASIS or public website.
[The Queue Cluster Window shall have a fixed time interval based
on fixed annual opening and closing dates. Any changes to the
established Queue Cluster Window interval and opening or closing
dates shall be announced with a posting on Transmission Provider's
OASIS beginning at least one hundred and eighty (180) Calendar Days
in advance of the change and continuing thereafter through the end
date of the first Queue Cluster Window that is to be modified.]
4.2.1 Cost Allocation for Interconnection Facilities and Network
Upgrades
(1) For Network Upgrades identified in Cluster Studies,
Transmission Provider shall calculate each Interconnection
Customer's share of the costs as follows:
(a) Substation Network Upgrades, including all switching
stations, shall be allocated per capita to each Generating Facility
interconnecting at the same substation.
(b) System Network Upgrades shall be allocated based on the
proportional impact of each individual Generating Facility in the
Cluster Study on the need for a specific System Network Upgrade.
{Transmission Provider shall include in this section a description
of how cost for each facility type designated as a network upgrade
will be allocated using its proportional impact method.{time}
(c) An Interconnection Customer that funds Substation Network
Upgrades and/or System Network Upgrades shall be entitled to
transmission credits as provided in Article 11.4 of the LGIA.
(2) The costs of any needed Interconnection Facilities
identified in the Cluster Study Process will be directly assigned to
the Interconnection Customer(s) using such facilities. Where
Interconnection Customers in the Cluster agree to share
Interconnection Facilities, the cost of such Interconnection
Facilities shall be allocated based on the number of Generating
Facilities sharing use of such Interconnection Facilities on a per
capita basis (i.e., on a per Generating Facility basis), unless
Parties mutually agree to a different cost sharing arrangement.
4.3 Transferability of Queue Position
An Interconnection Customer may transfer its Queue Position to
another entity only if such entity acquires the specific Generating
Facility identified in the Interconnection Request and the Point of
Interconnection does not change.
4.4 Modifications
Interconnection Customer shall submit to Transmission Provider,
in writing, modifications to any information provided in the
Interconnection Request. Interconnection Customer shall retain its
Queue Position if the modifications are in accordance with Sections
4.4.1, 4.4.2, or 4.4.5 of this LGIP, or are determined not to be
Material Modifications pursuant to Section 4.4.3 of this LGIP.
Notwithstanding the above, during the course of the
Interconnection Studies, either Interconnection Customer or
Transmission Provider may identify changes to the planned
interconnection that may improve the costs and benefits (including
reliability) of the interconnection, and the ability of the proposed
change to accommodate the Interconnection Request. To the extent the
identified changes are acceptable to Transmission Provider[,] and
Interconnection Customer, such acceptance not to be unreasonably
withheld, Transmission Provider shall modify the Point of
Interconnection prior to return of the executed Cluster Study
Agreement, [and/or configuration in accordance with such changes and
proceed with any re-studies necessary to do so in accordance with
Section 6.4, Section 7.6 and Section 8.5 as applicable] and
Interconnection Customer shall retain its Queue Position.
4.4.1 Prior to the return of the executed [Interconnection
System Impact]Cluster Study Agreement to Transmission Provider,
modifications permitted under this Section shall include
specifically: (a) a decrease of up to 60 percent of electrical
output (MW) of the proposed project, through either (1) a decrease
in plant size or (2) a decrease in Interconnection Service level
(consistent with the process described in Section 3.1 of this LGIP)
accomplished by applying Transmission Provider-approved injection-
limiting equipment; (b) modifying the technical parameters
associated with the Large Generating Facility technology or the
Large Generating Facility step-up transformer impedance
characteristics; and (c) modifying the interconnection
configuration. For plant increases, the incremental increase in
plant output will go [to]in the [end of the queue]next Cluster Study
Window for the purposes of cost allocation and study analysis.
4.4.2 Prior to the return of the executed Interconnection
Facilit[y]ies Study Agreement to Transmission Provider, the
modifications permitted under this Section shall include
specifically: (a) additional 15 percent decrease of electrical
output of the proposed project through either (1) a decrease in
plant size (MW) or (2) a decrease in Interconnection Service level
(consistent with the process described in Section 3.1) accomplished
by applying Transmission Provider-approved injection-limiting
equipment; (b) Large Generating Facility technical parameters
associated with modifications to Large Generating Facility
technology and transformer impedances; provided, however, the
incremental costs associated with those modifications are the
responsibility of the requesting Interconnection Customer; and (c) a
Permissible Technological Advancement for the Large Generating
Facility after the submission of the Interconnection Request.
Section 4.4.6 specifies a separate technological change procedure
including the requisite information and process that will be
followed to assess whether the Interconnection Customer's proposed
technological advancement under Section 4.4.2(c) is a Material
Modification. Section 1 contains a definition of Permissible
Technological Advancement.
4.4.3 Prior to making any modification other than those
specifically permitted by Sections 4.4.1, 4.4.2, and 4.4.5 of this
LGIP, Interconnection Customer may first request that Transmission
Provider evaluate whether such modification is a Material
Modification. In response to Interconnection Customer's request,
Transmission Provider shall evaluate the proposed modifications
prior to making them and inform Interconnection Customer in writing
of whether the modifications would constitute a Material
Modification. Any change to the Point of Interconnection, except
those deemed acceptable under Sections 3.1.2 or 4.4 of this LGIP[.1,
6.1, 7.2] or so allowed elsewhere, shall constitute a Material
Modification. Interconnection Customer may then withdraw the
proposed modification or proceed with a new Interconnection Request
for such modification. Transmission Provider shall study the
addition of a Generating Facility that includes at least one
electric storage resource using operating assumptions (i.e., whether
the interconnecting Generating Facility will or will not charge at
peak load) that reflect the proposed charging behavior of the
Generating Facility as requested by Interconnection Customer, unless
Transmission Provider determines that Good Utility Practice,
including Applicable Reliability Standards, otherwise requires the
use of different operating assumptions.
{Transmission Providers using fuel-based dispatch assumptions in
Interconnection Studies are not required to include Section 4.4.3.1
because it does not apply to them{time}
4.4.3.1 Interconnection Customer may request, and Transmission
Provider shall evaluate, the addition to the Interconnection Request
of a Generating Facility with the same Point of Interconnection
indicated in the initial Interconnection Request, if the addition of
the Generating Facility does not increase the requested
Interconnection Service level. Transmission Provider must evaluate
such modifications prior to deeming them a Material Modification,
but only if Interconnection Customer submits them prior to the
return of the executed Facilities Study Agreement by Interconnection
Customer to Transmission Provider. Interconnection Customers
requesting that such a modification be evaluated must demonstrate
the required Site Control at the time such request is made.
[[Page 61278]]
4.4.4 Upon receipt of Interconnection Customer's request for
modification permitted under this Section 4.4, Transmission Provider
shall commence and perform any necessary additional studies as soon
as practicable, but in no event shall Transmission Provider commence
such studies later than thirty (30) Calendar Days after receiving
notice of Interconnection Customer's request. Any additional studies
resulting from such modification shall be done at Interconnection
Customer's cost. Any such request for modification of the
Interconnection Request must be accompanied by any resulting updates
to the models described in Attachment A to Appendix 1 of this LGIP.
4.4.5 Extensions of less than three (3) cumulative years in the
Commercial Operation Date of the Large Generating Facility to which
the Interconnection Request relates are not material and should be
handled through construction sequencing. For purposes of this
section, the Commercial Operation Date reflected in the initial
Interconnection Request shall be used to calculate the permissible
extension prior to Interconnection Customer executing an LGIA or
requesting that the LGIA be filed unexecuted. After an LGIA is
executed or requested to be filed unexecuted, the Commercial
Operation Date reflected in the LGIA shall be used to calculate the
permissible extension. Such cumulative extensions may not exceed
three years including both extensions requested after execution of
the LGIA by Interconnection Customer or the filing of an unexecuted
LGIA by Transmission Provider and those requested prior to execution
of the LGIA by Interconnection Customer or the filing of an
unexecuted LGIA by Transmission Provider.
4.4.6 Technological Change Procedures
{Insert technological change procedure here{time}
Section 5. Procedures for Interconnection Requests Submitted Prior to
Effective Date of the Cluster Study Revisions[Standard Large Generator
Interconnection Procedures]
5.1 Procedures for Transitioning to the Cluster Study Process [Queue
Position for Pending Requests.]
5.1.1
[Any Interconnection Customer assigned a Queue Position prior to
the effective date of this LGIP shall retain that Queue Position.]
Any Interconnection Customer assigned a Queue Position as of
thirty (30) Calendar Days after {Transmission Provider to insert
filing date{time} (the filing date of this LGIP) shall retain that
Queue Position subject to the requirements in Sections 5.1.1.1 and
5.1.1.2 of this LGIP. Any Interconnection Customer that fails to
meet these requirements 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.
Any Interconnection Customer that has received a final
Interconnection Facilities Study Report before the commencement of
the studies under the transition process set forth in this section
shall be tendered an LGIA pursuant to Section 11 of this LGIP, and
shall not be required to enter this transition process.
5.1.1.1 Transitional Serial Study
[If an Interconnection Study Agreement has not been executed as
of the effective date of this LGIP, then such Interconnection Study,
and any subsequent Interconnection Studies, shall be processed in
accordance with this LGIP.]
An Interconnection Customer that has been tendered an
Interconnection Facilities Study Agreement as of thirty (30)
Calendar Days after {Transmission Provider to insert filing
date{time} (the filing date of this LGIP) may opt to proceed with
an Interconnection Facilities Study. Transmission Provider shall
tender each eligible Interconnection Customer a Transitional Serial
Interconnection Facilities Study Agreement, in the form of Appendix
8 to this LGIP, no later than the Commission-approved effective date
of this LGIP. Transmission Provider shall proceed with the
Interconnection Facilities Study, provided that the Interconnection
Customer: (1) meets each of the following requirements; and (2)
executes the Transitional Serial Interconnection Facilities Study
Agreement within sixty (60) Calendar Days of the Commission-approved
effective date of this LGIP. If an eligible Interconnection Customer
does not meet these requirements, its Interconnection Request shall
be deemed withdrawn without penalty. Transmission Provider must
commence the Transitional Serial Interconnection Facilities Study at
the conclusion of this sixty (60) Calendar Day period. Transitional
Serial Interconnection Facilities Study costs shall be allocated
according to the method described in Section 13.3 of this LGIP.
All of the following must be included when an Interconnection
Customer returns the Transitional Serial Interconnection Facilities
Study Agreement:
(1) A deposit equal to one hundred percent (100%) of the costs
identified for Transmission Provider's Interconnection Facilities
and Network Upgrades in Interconnection Customer's system impact
study report. If Interconnection Customer does not withdraw, the
deposit shall be trued up to actual costs once they are known and
applied to future construction costs described in Interconnection
Customer's eventual LGIA. Any amounts in excess of the actual
construction costs shall be returned to Interconnection Customer
within thirty (30) Calendar Days of the issuance of a final invoice
for construction costs, in accordance with Article 12.2 of the pro
forma LGIA. If Interconnection Customer withdraws or otherwise does
not reach Commercial Operation, Transmission Provider shall refund
the remaining deposit after the final invoice for study costs and
Withdrawal Penalty is settled. The deposit shall be in the form of
an irrevocable letter of credit or cash where cash deposits shall be
treated according to Section 3.7 of this LGIP.
(2) Exclusive Site Control for 100% of the proposed Generating
Facility.
Transmission Provider shall conduct each Transitional Serial
Interconnection Facilities Study and issue the associated
Transitional Serial Interconnection Facilities Study Report within
one hundred fifty (150) Calendar Days of the Commission-approved
effective date of this LGIP.
After Transmission Provider issues each Transitional
Interconnection Facilities Study Report, Interconnection Customer
shall proceed pursuant to Section 11 of this LGIP. If
Interconnection Customer withdraws its Interconnection Request or if
Interconnection Customer's Generating Facility otherwise does not
reach Commercial Operation, a Withdrawal Penalty shall be imposed on
Interconnection Customer equal to nine (9) times Interconnection
Customer's total study cost incurred since entering the Transmission
Provider's interconnection queue (including the cost of studies
conducted under Section 5 of this LGIP).
5.1.1.2 Transitional Cluster Study
[If an Interconnection Study Agreement has been executed prior
to the effective date of this LGIP, such Interconnection Study shall
be completed in accordance with the terms of such agreement. With
respect to any remaining studies for which an Interconnection
Customer has not signed an Interconnection Study Agreement prior to
the effective date of the LGIP, Transmission Provider must offer
Interconnection Customer the option of either continuing under
Transmission Provider's existing interconnection study process or
going forward with the completion of the necessary Interconnection
Studies (for which it does not have a signed Interconnection Studies
Agreement) in accordance with this LGIP.]
An Interconnection Customer with an assigned Queue Position as
of thirty (30) Calendar Days after {Transmission Provider to insert
filing date{time} (the filing date of this LGIP) may opt to proceed
with a Transitional Cluster Study. Transmission Provider shall
tender each eligible Interconnection Customer a Transitional Cluster
Study Agreement, in the form of Appendix 7 to this LGIP, no later
than the Commission-approved effective date of this LGIP.
Transmission Provider shall proceed with the Transitional Cluster
Study that includes each Interconnection Customer that: (1) meets
each of the following requirements listed as (1)-(3) in this
section; and (2) executes the Transitional Cluster Study Agreement
within sixty (60) Calendar Days of the Commission-approved effective
date of this LGIP. All Interconnection Requests that enter the
Transitional Cluster Study shall be considered to have an equal
Queue Position that is lower than Interconnection Customer(s)
proceeding with Transitional Serial Interconnection Facilities
Study. If an eligible Interconnection Customer does not meet these
requirements, its Interconnection Request shall be deemed withdrawn
without penalty. Transmission Provider must commence the
Transitional Cluster Study at the conclusion of this sixty (60)
Calendar Day period. All identified Transmission Provider's
Interconnection Facilities and Network Upgrade costs shall be
allocated according to Section 4.2.1 of this LGIP. Transitional
Cluster Study costs shall be allocated according to the method
described in Section 13.3 of this LGIP.
[[Page 61279]]
Interconnection Customer may make a one-time extension to its
requested Commercial Operation Date upon entry into the Transitional
Cluster Study, where any such extension shall not result in a
Commercial Operation Date later than December 31, 2027.
All of the following must be included when an Interconnection
Customer returns the Transitional Cluster Study Agreement:
(1) A selection of either Energy Resource Interconnection
Service or Network Resource Interconnection Service.
(2) A deposit of five million dollars ($5,000,000) in the form
of an irrevocable letter of credit or cash where cash deposits will
be treated according to Section 3.7 of this LGIP. If Interconnection
Customer does not withdraw, the deposit shall be reconciled with and
applied towards future construction costs described in the LGIA. Any
amounts in excess of the actual construction costs shall be returned
to Interconnection Customer within thirty (30) Calendar Days of the
issuance of a final invoice for construction costs, in accordance
with Article 12.2 of the pro forma LGIA. If Interconnection Customer
withdraws or otherwise does not reach Commercial Operation,
Transmission Provider must refund the remaining deposit once the
final invoice for study costs and Withdrawal Penalty is settled.
(3) Exclusive Site Control for 100% of the proposed Generating
Facility.
Transmission Provider shall conduct the Transitional Cluster
Study and issue both an associated interim Transitional Cluster
Study Report and an associated final Transitional Cluster Study
Report. The interim Transitional Cluster Study Report shall provide
the following information:
--identification of any circuit breaker short circuit capability
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations
resulting from the interconnection;
--identification of any instability or inadequately damped response
to system disturbances resulting from the interconnection; and
--Transmission Provider's Interconnection Facilities and Network
Upgrades that are expected to be required as a result of the
Interconnection Request(s) and a non-binding, good faith estimate of
cost responsibility and a non-binding, good faith estimated time to
construct.
In addition to the information provided in the interim
Transitional Cluster Study Report, the final Transitional Cluster
Study Report shall provide a description of, estimated cost of, and
schedule for construction of the Transmission Provider's
Interconnection Facilities and Network Upgrades required to
interconnect the Generating Facility to the Transmission System that
resolve issues identified in the interim Transitional Cluster Study
Report.
The interim and final Transitional Cluster Study Reports shall
be issued within three hundred (300) and three hundred sixty (360)
Calendar Days of the Commission-approved effective date of this
LGIP, respectively, and shall be posted on Transmission Provider's
OASIS consistent with the posting of other study results pursuant to
Section 3.5.1 of this LGIP. Interconnection Customer shall have
thirty (30) Calendar Days to comment on the interim Transitional
Cluster Study Report, once it has been received.
After Transmission Provider issues the final Transitional
Cluster Study Report, Interconnection Customer shall proceed
pursuant to Section 11 of this LGIP. If Interconnection Customer
withdraws its Interconnection Request or if Interconnection
Customer's Generating Facility otherwise does not reach Commercial
Operation, a Withdrawal Penalty will be imposed om Interconnection
Customer equal to nine (9) times Interconnection Customer's total
study cost incurred since entering the Transmission Provider's
interconnection queue (including the cost of studies conducted under
Section 5 of this LGIP).
[5.1.1.3 If an LGIA has been submitted to FERC for approval
before the effective date of the LGIP, then the LGIA would be
grandfathered.
5.1.2 Transition Period
To the extent necessary, Transmission Provider and
Interconnection Customers with an outstanding request (i.e., an
Interconnection Request for which an LGIA has not been submitted to
FERC for approval as of the effective date of this LGIP) shall
transition to this LGIP within a reasonable period of time not to
exceed sixty (60) Calendar Days. The use of the term ``outstanding
request'' herein shall mean any Interconnection Request, on the
effective date of this LGIP: (i) that has been submitted but not yet
accepted by Transmission Provider; (ii) where the related
interconnection agreement has not yet been submitted to FERC for
approval in executed or unexecuted form, (iii) where the relevant
Interconnection Study Agreements have not yet been executed, or (iv)
where any of the relevant Interconnection Studies are in process but
not yet completed. Any Interconnection Customer with an outstanding
request as of the effective date of this LGIP may request a
reasonable extension of any deadline, otherwise applicable, if
necessary to avoid undue hardship or prejudice to its
Interconnection Request. A reasonable extension shall be granted by
Transmission Provider to the extent consistent with the intent and
process provided for under this LGIP.]
5.2 New Transmission Provider
If Transmission Provider transfers control of its Transmission
System to a successor Transmission Provider during the period when
an Interconnection Request is pending, the original Transmission
Provider shall transfer to the successor Transmission Provider any
amount of the deposit or payment with interest thereon that exceeds
the cost that it incurred to evaluate the request for
interconnection. Any difference between such net amount and the
deposit or payment required by this LGIP shall be paid by or
refunded to the Interconnection Customer, as appropriate. The
original Transmission Provider shall coordinate with the successor
Transmission Provider to complete any Interconnection Study, as
appropriate, that the original Transmission Provider has begun but
has not completed. If Transmission Provider has tendered a draft
LGIA to Interconnection Customer but Interconnection Customer has
not either executed the LGIA or requested the filing of an
unexecuted LGIA with FERC, unless otherwise provided,
Interconnection Customer must complete negotiations with the
successor Transmission Provider.
Section 6. Interconnection Information Access [Feasibility Study]
6.1 Publicly Posted Interconnection Information
Transmission Provider shall maintain and make publicly
available: (1) an interactive visual representation of the estimated
incremental injection capacity (in megawatts) available at each
point of interconnection in Transmission Provider's footprint under
N-1 conditions, and (2) a table of metrics concerning the estimated
impact of a potential Generating Facility on Transmission Provider's
Transmission System based on a user-specified addition of a
particular number of megawatts at a particular voltage level at a
particular point of interconnection. At a minimum, for each
transmission facility impacted by the user-specified megawatt
addition, the following information will be provided in the table:
(1) the distribution factor; (2) the megawatt impact (based on the
megawatt values of the proposed Generating Facility and the
distribution factor); (3) the percentage impact on each impacted
transmission facility (based on the megawatt values of the proposed
Generating Facility and the facility rating); (4) the percentage of
power flow on each impacted transmission facility before the
injection of the proposed project; (5) the percentage power flow on
each impacted transmission facility after the injection of the
proposed Generating Facility. These metrics must be calculated 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 Network Resource
Interconnection Service), and with the incremental capacity at each
point of interconnection decremented by the existing and queued
Generating Facilities (based on the existing or requested
interconnection service limit of the generation). These metrics must
be updated within thirty (30) Calendar Days after the completion of
each Cluster Study and Cluster Restudy. This information must be
publicly posted, without a password or a fee. The website will
define all underlying assumptions, including the name of the most
recent Cluster Study or Restudy used in the Base Case.
[6.1 Interconnection Feasibility Study Agreement
Simultaneously with the acknowledgement of a valid
Interconnection Request Transmission Provider shall provide to
Interconnection Customer an Interconnection Feasibility Study
Agreement in the form of Appendix 2. The Interconnection Feasibility
Study Agreement shall: specify that Interconnection Customer is
responsible for the actual cost of the Interconnection Feasibility
Study. Within five (5) Business
[[Page 61280]]
Days following the Scoping Meeting Interconnection Customer shall
specify for inclusion in the attachment to the Interconnection
Feasibility Study Agreement the Point(s) of Interconnection and any
reasonable alternative Point(s) of Interconnection. Within five (5)
Business Days following Transmission Provider's receipt of such
designation, Transmission Provider shall tender to Interconnection
Customer the Interconnection Feasibility Study Agreement signed by
Transmission Provider, which includes a good faith estimate of the
cost for completing the Interconnection Feasibility Study.
Interconnection Customer shall execute and deliver to Transmission
Provider the Interconnection Feasibility Study Agreement along with
a $10,000 deposit no later than thirty (30) Calendar Days after its
receipt.
On or before the return of the executed Feasibility Study
Agreement to Transmission Provider, Interconnection Customer shall
provide the technical data called for in Appendix 1, Attachment A.
If the Interconnection Feasibility Study uncovers any unexpected
result(s) not contemplated during the Scoping Meeting, a substitute
Point of Interconnection identified by either Interconnection
Customer or Transmission Provider, and acceptable to the other, such
acceptance not to be unreasonably withheld, will be substituted for
the designated Point of Interconnection specified above without loss
of Queue Position, and Re-studies shall be completed pursuant to
Section 6.4 as applicable. For the purpose of this Section 6.1, if
Transmission Provider and Interconnection Customer cannot agree on
the substituted Point of Interconnection, then Interconnection
Customer may direct that one of the alternatives as specified in the
Interconnection Feasibility Study Agreement, as specified pursuant
to Section 3.4.4, shall be the substitute.
If Interconnection Customer and Transmission Provider agree to
forgo the Interconnection Feasibility Study, Transmission Provider
will initiate an Interconnection System Impact Study under Section 7
of this LGIP and apply the $10,000 deposit towards the
Interconnection System Impact Study.]
[6.2 Scope of Interconnection Feasibility Study
The Interconnection Feasibility Study shall preliminarily
evaluate the feasibility of the proposed interconnection to the
Transmission System.
The Interconnection Feasibility Study will consider the Base
Case as well as all generating facilities (and with respect to
(iii), any identified Network Upgrades) that, on the date the
Interconnection Feasibility Study is commenced: (i) are directly
interconnected to the Transmission System; (ii) are interconnected
to Affected Systems and may have an impact on the Interconnection
Request; (iii) have a pending higher queued Interconnection Request
to interconnect to the Transmission System; and (iv) have no Queue
Position but have executed an LGIA or requested that an unexecuted
LGIA be filed with FERC. The Interconnection Feasibility Study will
consist of a power flow and short circuit analysis. The
Interconnection Feasibility Study will provide a list of facilities
and a non-binding good faith estimate of cost responsibility and a
non-binding good faith estimated time to construct.]
[6.3 Interconnection Feasibility Study Procedures
Transmission Provider shall utilize existing studies to the
extent practicable when it performs the study. Transmission Provider
shall use Reasonable Efforts to complete the Interconnection
Feasibility Study no later than forty-five (45) Calendar Days after
Transmission Provider receives the fully executed Interconnection
Feasibility Study Agreement. At the request of Interconnection
Customer or at any time Transmission Provider determines that it
will not meet the required time frame for completing the
Interconnection Feasibility Study, Transmission Provider shall
notify Interconnection Customer as to the schedule status of the
Interconnection Feasibility Study. If Transmission Provider is
unable to complete the Interconnection Feasibility Study within that
time period, it shall notify Interconnection Customer and provide an
estimated completion date with an explanation of the reasons why
additional time is required. Upon request, Transmission Provider
shall provide Interconnection Customer supporting documentation,
workpapers and relevant power flow, short circuit and stability
databases for the Interconnection Feasibility Study, subject to
confidentiality arrangements consistent with Section 13.1.
Transmission Provider shall study the Interconnection Request at
the level of service requested by the Interconnection Customer,
unless otherwise required to study the full Generating Facility
Capacity due to safety or reliability concerns.]
[6.3.1 Meeting With Transmission Provider
Within ten (10) Business Days of providing an Interconnection
Feasibility Study report to Interconnection Customer, Transmission
Provider and Interconnection Customer shall meet to discuss the
results of the Interconnection Feasibility Study.]
[6.4 Re-Study
If Re-Study of the Interconnection Feasibility Study is required
due to a higher queued project dropping out of the queue, or a
modification of a higher queued project subject to Section 4.4, or
re-designation of the Point of Interconnection pursuant to Section
6.1 Transmission Provider shall notify Interconnection Customer in
writing. Such Re-Study shall take not longer than forty-five (45)
Calendar Days from the date of the notice. Any cost of Re-Study
shall be borne by the Interconnection Customer being re-studied.]
Section 7. [Interconnection System Impact] Cluster Study
7.1 [Interconnection System Impact] Cluster Study Agreement
[Unless otherwise agreed, pursuant to the Scoping Meeting
provided in Section 3.4.4, simultaneously with the delivery of the
Interconnection Feasibility Study to Interconnection Customer] No
later than five (5) Business Days after the close of a Cluster
Request Window, Transmission Provider shall [provide ] tender to
each Interconnection Customer [an] that submitted a valid
Interconnection[ System Impact] Request a Cluster Study Agreement in
the form of Appendix 2[3] to this LGIP. The [Interconnection System
Impact] Cluster Study Agreement shall [provide that ] require
Interconnection Customer [shall] to compensate Transmission Provider
for the actual cost of the [Interconnection System Impact
Study.]Cluster Study pursuant to Section 13.3 of this LGIP. The
specifications, assumptions, or other provisions in the appendices
of the Cluster Study Agreement provided pursuant to Section 7.1 of
this LGIP shall be subject to change by Transmission Provider
following the conclusion of the Scoping Meeting. [Within three (3)
Business Days following the Interconnection Feasibility Study
results meeting, Transmission Provider shall provide to
Interconnection Customer a non-binding good faith estimate of the
cost and timeframe for completing the Interconnection System Impact
Study.]
7.2 Execution of [Interconnection System Impact]Cluster Study Agreement
Interconnection Customer shall execute the [Interconnection
System Impact]Cluster Study Agreement and deliver the executed
[Interconnection System Impact]Cluster Study Agreement to
Transmission Provider no later than [thirty (30) Calendar Days after
its receipt along with demonstration of Site Control, and a $50,000
deposit] the close of the Customer Engagement Window.
If Interconnection Customer does not provide all [such] required
technical data when it delivers the [Interconnection System
Impact]Cluster Study Agreement, Transmission Provider shall notify
Interconnection Customer of the deficiency within five (5) Business
Days of the receipt of the executed [Interconnection System Impact]
Cluster Study Agreement and Interconnection Customer shall cure the
deficiency within ten (10) Business Days of receipt of the notice,
provided, however, such deficiency does not include failure to
deliver the executed [Interconnection System Impact]Cluster Study
Agreement or Study Deposit.
[If the Interconnection System Impact Study uncovers any
unexpected result(s) not contemplated during the Scoping Meeting and
the Interconnection Feasibility Study, a substitute Point of
Interconnection identified by either Interconnection Customer or
Transmission Provider, and acceptable to the other, such acceptance
not to be unreasonably withheld, will be substituted for the
designated Point of Interconnection specified above without loss of
Queue Position, and restudies shall be completed pursuant to Section
7.6 as applicable. For the purpose of this Section 7.2, if
Transmission Provider and Interconnection Customer cannot agree on
the substituted Point of Interconnection, then Interconnection
Customer may direct that one of the alternatives as specified in the
Interconnection Feasibility Study Agreement,
[[Page 61281]]
as specified pursuant to Section 3.4.4, shall be the substitute.]
7.3 Scope of [Interconnection System Impact] Cluster Study
The [Interconnection System Impact]Cluster Study shall evaluate
the impact of the proposed interconnection on the reliability of the
Transmission System. The [Interconnection System Impact] Cluster
Study will consider the Base Case as well as all Generating
Facilities (and with respect to (iii) below, any identified Network
Upgrades associated with such higher queued interconnection) that,
on the date the [Interconnection System Impact] Cluster Study is
commenced: (i) are directly interconnected to the Transmission
System; (ii) are interconnected to Affected Systems and may have an
impact on the Interconnection Request; (iii) have a pending higher
queued Interconnection Request to interconnect to the Transmission
System; and (iv) have no Queue Position but have executed an LGIA or
requested that an unexecuted LGIA be filed with FERC.
For purposes of determining necessary Interconnection Facilities
and Network Upgrades, the Cluster Study shall use the level of
Interconnection Service requested by Interconnection Customers in
the Cluster, except where the Transmission Provider otherwise
determines that it must study the full Generating Facility Capacity
due to safety or reliability concerns.
The [Interconnection System Impact] Cluster Study will consist
of [a short circuit analysis, a] power flow, stability [analysis,
and a power flow analysis. The Interconnection System Impact Study],
and short circuit analyses, the results of which are documented in a
single Cluster Study Report, as applicable. At the conclusion of the
Cluster Study, Transmission Provider shall issue a Cluster Study
Report. The Cluster Study Report will state the assumptions upon
which it is based; state the results of the analyses; and provide
the requirements or potential impediments to providing the requested
interconnection service, including a preliminary indication of the
cost and length of time that would be necessary to correct any
problems identified in those analyses and implement the
interconnection. [For purposes of determining necessary] The Cluster
Study Report shall identify the Interconnection Facilities and
Network Upgrades [, the System Impact Study shall consider the level
of Interconnection Service requested by the Interconnection
Customer, unless otherwise required to study the full Generating
Facility Capacity due to safety or reliability concerns.] expected
to be required to reliably interconnect the Generating Facilities in
that Cluster Study at the requested Interconnection Service level
and shall provide non-binding cost estimates for required Network
Upgrades. The Cluster Study Report shall identify each
Interconnection Customer's estimated allocated costs for
Interconnection Facilities and Network Upgrades pursuant to the
method in Section 4.2.1 of this LGIP. Transmission Provider shall
hold an open stakeholder meeting pursuant to Section 7.4 of this
LGIP.
For purposes of determining necessary Interconnection Facilities
and Network Upgrades, the Cluster Study shall use operating
assumptions (i.e., whether the interconnecting Generating Facility
will or will not charge at peak load) that reflect the proposed
charging behavior of a Generating Facility that includes at least
one electric storage resource as requested by Interconnection
Customer, unless Transmission Provider determines that Good Utility
Practice, including Applicable Reliability Standards, otherwise
requires the use of different operating assumptions. Transmission
Provider may require the inclusion of control technologies
sufficient to limit the operation of the Generating Facility per the
operating assumptions as set forth in the Interconnection Request
and to respond to dispatch instructions by Transmission Provider. As
determined by Transmission Provider, Interconnection Customer may be
subject to testing and validation of those control technologies
consistent with Article 6 of the LGIA.
[The Interconnection System Impact Study] The Cluster Study
Report will provide a list of facilities that are required as a
result of the Interconnection [Request] Requests within the Cluster
and a non-binding good faith estimate of cost responsibility and a
non-binding good faith estimated time to construct.
Upon issuance of a Cluster Study Report, or Cluster Restudy
Report, if any, Transmission Provider shall simultaneously tender a
draft Interconnection Facilities Study Agreement to each
Interconnection Customer within the Cluster, subject to the
conditions in Section 8.1 of this LGIP.
The Cluster Study shall evaluate the use of static synchronous
compensators, static VAR compensators, advanced power flow control
devices, transmission switching, synchronous condensers, voltage
source converters, advanced conductors, and tower lifting.
Transmission Provider shall determine whether the above technologies
should be used, consistent with Good Utility Practice and other
applicable regulatory requirements. Transmission Provider shall
include an explanation of the results of the Transmission Provider's
evaluation for each technology in the Cluster Study Report.
7.4 [Interconnection System Impact] Cluster Study Procedures
Transmission Provider shall coordinate the [Interconnection
System Impact] Cluster Study with any Affected System that is
affected by the Interconnection Request pursuant to Section 3.6
[above] of this LGIP. Transmission Provider shall utilize existing
studies to the extent practicable when it performs the [study]
Cluster Study. Interconnection Requests for a Cluster Study may be
submitted only within the Cluster Request Window and Transmission
Provider shall [use Reasonable Efforts to complete the
Interconnection System Impact Study within ninety (90) Calendar Days
after the receipt of the Interconnection System Impact Study
Agreement or notification to proceed, study payment, and technical
data. If Transmission Provider uses Clustering, Transmission
Provider shall use Reasonable Efforts to deliver a completed
Interconnection System Impact Study within ninety (90) Calendar Days
after the close of the Queue Cluster Window.] initiate the Cluster
Study process pursuant to Section 7 of this LGIP.
Transmission Provider shall complete the Cluster Study within
one hundred fifty (150) Calendar Days of the close of the Customer
Engagement Window.
Within ten (10) Business Days of simultaneously furnishing a
Cluster Study Report to each Interconnection Customer within the
Cluster and posting such report on OASIS, Transmission Provider
shall convene a Cluster Study Report Meeting.
At the request of Interconnection Customer or at any time
Transmission Provider determines that it will not meet the required
time frame for completing the [Interconnection System Impact]
Cluster Study, Transmission Provider shall notify Interconnection
Customers as to the schedule status of the [Interconnection System
Impact] Cluster Study. If Transmission Provider is unable to
complete the [Interconnection System Impact] Cluster Study within
the time period, it shall notify Interconnection Customers and
provide an estimated completion date with an explanation of the
reasons why additional time is required. Upon request, Transmission
Provider shall provide to Interconnection Customers all supporting
documentation, workpapers and relevant pre-Interconnection Request
and post-Interconnection Request power flow, short circuit and
stability databases for the [Interconnection System Impact] Cluster
Study, subject to confidentiality arrangements consistent with
Section 13.1 of this LGIP.
7.5 Cluster Study Restudies
(1) Within twenty (20) Calendar Days after the Cluster Study
Report Meeting, Interconnection Customer must provide the following:
(a) Demonstration of continued Site Control pursuant to Section
3.4.2(iii) of this LGIP; and
(b) An additional deposit that brings the total Commercial
Readiness Deposit submitted to Transmission Provider to five percent
(5%) of the Interconnection Customer's Network Upgrade cost
assignment identified in the Cluster Study in the form of an
irrevocable letter of credit or cash. Transmission Provider shall
refund the deposit to Interconnection Customer upon withdrawal in
accordance with Section 3.7 of this LGIP.
Interconnection Customer shall promptly inform Transmission
Provider of any material change to Interconnection Customer's
demonstration of Site Control under Section 3.4.2(iii) of this LGIP.
Upon Transmission Provider determining that Interconnection Customer
no longer satisfies the Site Control requirement, Transmission
Provider shall notify Interconnection Customer. Within ten (10)
Business Days of such notification, Interconnection Customer must
demonstrate compliance with the applicable requirement subject to
Transmission Provider's approval, not to be unreasonably withheld.
Absent such demonstration, Transmission Provider shall deem the
subject Interconnection Request
[[Page 61282]]
withdrawn pursuant to Section 3.7 of this LGIP.
(2) If no Interconnection Customer withdraws from the Cluster
after completion of the Cluster Study or Cluster Restudy or is
deemed withdrawn pursuant to Section 3.7 of this LGIP after
completion of the Cluster Study or Cluster Restudy, Transmission
Provider shall notify Interconnection Customers in the Cluster that
a Cluster Restudy is not required.
(3) If one or more Interconnection Customers withdraw from the
Cluster or are deemed withdrawn pursuant to Section 3.7 of this
LGIP, Transmission Provider shall determine if a Cluster Restudy is
necessary within thirty (30) Calendar Days after the Cluster Study
Report Meeting. If Transmission Provider determines a Cluster
Restudy is not necessary, Transmission Provider shall notify
Interconnection Customers in the Cluster that a Cluster Restudy is
not required and Transmission Provider shall provide an updated
Cluster Study Report within thirty (30) Calendar Days of such
determination.
(4) If one or more Interconnection Customers withdraws from the
Cluster or is deemed withdrawn pursuant to Section 3.7 of this LGIP,
and Transmission Provider determines a Cluster Restudy is necessary
as a result, Transmission Provider shall notify Interconnection
Customers in the Cluster and post on OASIS that a Cluster Restudy is
required within thirty (30) Calendar Days after the Cluster Study
Report Meeting. Transmission Provider shall continue with such
restudies until Transmission Provider determines that no further
restudies are required. If an Interconnection Customer withdraws or
is deemed withdrawn pursuant to Section 3.7 of this LGIP during the
Interconnection Facilities Study, or after other Interconnection
Customers in the same Cluster have executed LGIAs, or requested that
unexecuted LGIAs be filed, and Transmission Provider determines a
Cluster Restudy is necessary, the Cluster shall be restudied.
(5) The scope of any Cluster Restudy shall be consistent with
the scope of an initial Cluster Study pursuant to Section 7.3 of
this LGIP. Transmission Provider shall complete the Cluster Restudy
within one hundred fifty (150) Calendar Days of the Transmission
Provider informing the Interconnection Customers in the cluster that
restudy is needed. The results of the Cluster Restudy shall be
combined into a single report (Cluster Restudy Report). Transmission
Provider shall hold a meeting with the Interconnection Customers in
the cluster (Cluster Restudy Report Meeting) within ten (10)
Business Days of simultaneously furnishing the Cluster Restudy
Report to each Interconnection Customer in the Cluster Restudy and
publishing the Cluster Restudy Report on OASIS.
If additional restudies are required, Interconnection Customer
and Transmission Provider shall follow the procedures of this
Section 7.5 of this LGIP until such time that Transmission Provider
determines that no further restudies are required. Transmission
Provider shall notify each Interconnection Customer within the
Cluster when no further restudies are required.
[Meeting With Transmission Provider
Within ten (10) Business Days of providing an Interconnection
System Impact Study report to Interconnection Customer, Transmission
Provider and Interconnection Customer shall meet to discuss the
results of the Interconnection System Impact Study.
7.6 Re-Study
If Re-Study of the Interconnection System Impact Study is
required due to a higher queued project dropping out of the queue,
or a modification of a higher queued project subject to 4.4, or re-
designation of the Point of Interconnection pursuant to Section 7.2
Transmission Provider shall notify Interconnection Customer in
writing. Such Re-Study shall take no longer than sixty (60) Calendar
Days from the date of notice. Any cost of Re-Study shall be borne by
the Interconnection Customer being re-studied.]
Section 8. Interconnection Facilities Study
8.1 Interconnection Facilities Study Agreement
Simultaneously with the delivery of the [Interconnection System
Impact Study to Interconnection Customer] Cluster Study Report, or
Cluster Restudy Report if applicable, Transmission Provider shall
provide to Interconnection Customer an Interconnection Facilities
Study Agreement in the form of Appendix 3[4] to this LGIP. [The
Interconnection Facilities Study Agreement shall provide that]
Interconnection Customer shall compensate Transmission Provider for
the actual cost of the Interconnection Facilities Study. Within five
(5) Business Days following the Cluster Report Meeting or Cluster
Restudy Report Meeting if applicable, [Interconnection System Impact
Study results meeting], Transmission Provider shall provide to
Interconnection Customer a non-binding good faith estimate of the
cost and timeframe for completing the Interconnection Facilities
Study.
Interconnection Customer shall execute the Interconnection
Facilities Study Agreement and deliver the executed Interconnection
Facilities Study Agreement to Transmission Provider within thirty
(30) Calendar Days after its receipt, together with [the]:
(1) any required technical data[and the greater of $100,000 or
Interconnection Customer's portion of the estimated monthly cost of
conducting the Interconnection Facilities Study.];
(2) Demonstration of one-hundred percent (100%) Site Control or
demonstration of a regulatory limitation and applicable deposit in
lieu of Site Control provided to the Transmission Provider in
accordance with section 3.4.2 of this LGIP; and
(3) An additional deposit that brings the total Commercial
Readiness Deposit submitted to the Transmission Provider to ten
percent (10%) of the Interconnection Customer's Network Upgrade cost
assignment identified in the Cluster Study or Cluster Restudy, if
applicable, in the form of an irrevocable letter of credit or cash.
Transmission Provider shall refund the deposit to Interconnection
Customer upon withdrawal in accordance with Section 3.7 of this
LGIP.
Interconnection Customer shall promptly inform Transmission
Provider of any material change to Interconnection Customer's
demonstration of Site Control under Section 3.4.2(iii) of this LGIP.
Upon Transmission Provider determining separately that
Interconnection Customer no longer satisfies the Site Control
requirement, Transmission Provider shall notify Interconnection
Customer. Within ten (10) Business Days of such notification,
Interconnection Customer must demonstrate compliance with the
applicable requirement subject to Transmission Provider's approval,
not to be unreasonably withheld. Absent such demonstration,
Transmission Provider shall deem the subject Interconnection Request
withdrawn pursuant to Section 3.7 of this LGIP.
[8.1.1 Transmission Provider shall invoice Interconnection
Customer on a monthly basis for the work to be conducted on the
Interconnection Facilities Study each month. Interconnection
Customer shall pay invoiced amounts within thirty (30) Calendar Days
of receipt of invoice. Transmission Provider shall continue to hold
the amounts on deposit until settlement of the final invoice.]
8.2 Scope of Interconnection Facilities Study
The Interconnection Facilities Study shall be specific to each
Interconnection Request and performed on an individual, i.e., non-
clustered, basis. The Interconnection Facilities Study shall specify
and provide a non-binding estimate of the cost of the equipment,
engineering, procurement and construction work needed to implement
the conclusions of the [Interconnection System Impact Study]Cluster
Study Report (and any associated restudies) in accordance with Good
Utility Practice to physically and electrically connect the
Interconnection [Facility ] Facilities to the Transmission System.
The Interconnection Facilities Study shall also identify the
electrical switching configuration of the connection equipment,
including, without limitation: the transformer, switchgear, meters,
and other station equipment; the nature and estimated cost of any
Transmission Provider's Interconnection Facilities and Network
Upgrades necessary to accomplish the interconnection; and an
estimate of the time required to complete the construction and
installation of such facilities. The Interconnection Facilities
Study will also identify any potential control equipment for
[requests for](1) requests for Interconnection Service that are
lower than the Generating Facility Capacity[.], and/or (2) requests
to study a Generating Facility that includes at least one electric
storage resource using operating assumptions (i.e., whether the
interconnecting Generating Facility will or will not charge at peak
load) that reflect its proposed charging behavior, as requested by
Interconnection Customer, unless Transmission Provider determines
that Good Utility Practice, including Applicable Reliability
Standards, otherwise require the use of different operating
assumptions.
[[Page 61283]]
8.3 Interconnection Facilities Study Procedures
Transmission Provider shall coordinate the Interconnection
Facilities Study with any Affected System pursuant to Section 3.6 of
this LGIP. Transmission Provider shall utilize existing studies to
the extent practicable in performing the Interconnection Facilities
Study. Transmission Provider shall [use Reasonable Efforts to]
complete the study and issue a draft Interconnection Facilities
Study [r]Report to Interconnection Customer within the following
number of days after receipt of an executed Interconnection
Facilities Study Agreement: ninety (90) Calendar Days after receipt
of an executed Interconnection Facilities Study Agreement, with no
more than a +/-20 percent cost estimate contained in the report; or
one hundred eighty (180) Calendar Days, if Interconnection Customer
requests a +/-10 percent cost estimate.
At the request of Interconnection Customer or at any time
Transmission Provider determines that it will not meet the required
time frame for completing the Interconnection Facilities Study,
Transmission Provider shall notify Interconnection Customer as to
the schedule status of the Interconnection Facilities Study. If
Transmission Provider is unable to complete the Interconnection
Facilities Study and issue a draft Interconnection Facilities Study
[r]Report within the time required, it shall notify Interconnection
Customer and provide an estimated completion date and an explanation
of the reasons why additional time is required.
Interconnection Customer may, within thirty (30) Calendar Days
after receipt of the draft Interconnection Facilities Study
[r]Report, provide written comments to Transmission Provider, which
Transmission Provider shall include in completing the final
Interconnection Facilities Study [r]Report. Transmission Provider
shall issue the final Interconnection Facilities Study [r]Report
within fifteen (15) Business Days of receiving Interconnection
Customer's comments or promptly upon receiving Interconnection
Customer's statement that it will not provide comments. Transmission
Provider may reasonably extend such fifteen[-day] (15) Business Day
period upon notice to Interconnection Customer if Interconnection
Customer's comments require Transmission Provider to perform
additional analyses or make other significant modifications prior to
the issuance of the final Interconnection Facilities Study Report.
Upon request, Transmission Provider shall provide Interconnection
Customer supporting documentation, workpapers, and databases or data
developed in the preparation of the Interconnection Facilities
Study, subject to confidentiality arrangements consistent with
Section 13.1 of this LGIP.
8.4 Meeting With Transmission Provider
Within ten (10) Business Days of providing a draft
Interconnection Facilities Study [r]Report to Interconnection
Customer, Transmission Provider and Interconnection Customer shall
meet to discuss the results of the Interconnection Facilities Study.
8.5 [Re-Study]Restudy
If [Re-Study]Restudy of the Interconnection Facilities Study is
required due to a higher or equally queued project [dropping out of]
withdrawing from the queue or a modification of a higher or equally
queued project pursuant to Section 4.4 of this LGIP, Transmission
Provider shall so notify Interconnection Customer in writing.
[Such]Transmission Provider shall ensure that such [Re-Study]Restudy
[shall] takes no longer than sixty (60) Calendar Days from the date
of notice. Except as provided in Section 3.7 of this LGIP in the
case of withdrawing Interconnection Customers, any cost of [Re-
Study]Restudy shall be borne by [the]Interconnection Customer being
[re-studied]restudied.
Section 9 [Engineering & Procurement (`E&P') Agreement] Affected System
Study
9.1 Applicability
This Section 9 outlines the duties of Transmission Provider when
it receives notification that an Affected System Interconnection
Customer's proposed interconnection to its host transmission
provider may impact Transmission Provider's Transmission System.
9.2 Response to Initial Notification
When Transmission Provider receives notification that an
Affected System Interconnection Customer's proposed interconnection
to its host transmission provider may impact Transmission Provider's
Transmission System, Transmission Provider must respond in writing
within twenty (20) Business Days whether it intends to conduct an
Affected System Study.
By fifteen (15) Business Days after the Transmission Provider
responds with its affirmative intent to conduct an Affected System
Study, Transmission Provider shall share with Affected System
Interconnection Customer(s) and the Affected System Interconnection
Customer's host transmission provider a non-binding good faith
estimate of the cost and the schedule to complete the Affected
System Study.
9.3 Affected System Queue Position
Transmission Provider must assign an Affected System Queue
Position to Affected System Interconnection Customer(s) that
require(s) an Affected System Study. Such Affected System Queue
Position shall be assigned based upon the date of execution of the
Affected System Study Agreement. Relative to the Transmission
Provider's Interconnection Customers, this Affected System Queue
Position shall be higher-queued than any Cluster that has not yet
received its Cluster Study Report and shall be lower-queued than any
Cluster that has already received its Cluster Study Report.
Consistent with Section 9.7 of this LGIP, Transmission Provider
shall study the Affected System Interconnection Customer(s) via
Clustering, and all Affected System Interconnection Customers
studied in the same Cluster under Section 9.7 shall be equally
queued. For Affected System Interconnection Customers that are
equally queued, the Affected System Queue Position shall have no
bearing on the assignment of Affected System Network Upgrades
identified in the applicable Affected System Study. The costs of the
Affected System Network Upgrades shall be allocated among the
Affected System Interconnection Customers in accordance with Section
9.9 of this LGIP.
9.4 Affected System Study Agreement/Multiparty Affected System
Study Agreement
Unless otherwise agreed, Transmission Provider shall provide to
Affected System Interconnection Customer(s) an Affected System Study
Agreement/Multiparty Affected System Study Agreement, in the form of
Appendix 9 or Appendix 10 to this LGIP, as applicable, within ten
(10) Business Days of Transmission Provider sharing the schedule for
the Affected System Study per Section 9.2 of this LGIP.
Upon Affected System Interconnection Customer(s)' receipt of the
Affected System Study Report, Affected System Interconnection
Customer(s) shall compensate Transmission Provider for the actual
cost of the Affected System Study. Any difference between the study
deposit and the actual cost of the Affected System Study shall be
paid by or refunded to the Affected System Interconnection
Customer(s). Any invoices for the Affected System Study shall
include a detailed and itemized accounting of the cost of the study.
Affected System Interconnection Customer(s) shall pay any excess
costs beyond the already-paid Affected System Study deposit or be
reimbursed for any costs collected over the actual cost of the
Affected System Study within thirty (30) Calendar Days of receipt of
an invoice thereof. If Affected System Interconnection Customer(s)
fail to pay such undisputed costs within the time allotted, it shall
lose its Affected System Queue Position. Transmission Provider shall
notify Affected System Interconnection Customer's host transmission
provider of such failure to pay.
9.5 Execution of Affected System Study Agreement/Multiparty
Affected System Study Agreement
Affected System Interconnection Customer(s) shall execute the
Affected System Study Agreement/Multiparty Affected System Study
Agreement, deliver the executed Affected System Study Agreement/
Multiparty Affected System Study Agreement to Transmission Provider,
and provide the Affected System Study deposit within ten (10)
Business Days of receipt.
If Affected System Interconnection Customer does not provide all
required technical data when it delivers the Affected System Study
Agreement/Multiparty Affected System Study Agreement, Transmission
Provider shall notify the deficient Affected System Interconnection
Customer, as well as the host transmission provider with which
Affected System Interconnection Customer seeks to interconnect, of
the deficiency within five (5) Business Days of the receipt of the
executed Affected System Study Agreement/Multiparty Affected System
Study Agreement and the deficient Affected System Interconnection
Customer shall cure the deficiency within ten (10) Business Days of
receipt of the notice: provided, however, that
[[Page 61284]]
such deficiency does not include failure to deliver the executed
Affected System Study Agreement/Multiparty Affected System Study
Agreement or deposit for the Affected System Study Agreement/
Multiparty Affected System Study Agreement. If Affected System
Interconnection Customer does not cure the deficiency or fails to
execute the Affected System Study Agreement/Multiparty Affected
System Study Agreement or provide the deposit, the Affected System
Interconnection Customer shall lose its Affected System Queue
Position.
9.6 Scope of Affected System Study
The Affected System Study shall evaluate the impact that any
Affected System Interconnection Customer's proposed interconnection
to another transmission provider's transmission system will have on
the reliability of Transmission Provider's Transmission System. The
Affected System Study shall consider the Base Case as well as all
Generating Facilities (and with respect to (iii) below, any
identified Affected System Network Upgrades associated with such
higher-queued Interconnection Request) that, on the date the
Affected System Study is commenced: (i) are directly interconnected
to Transmission Provider's Transmission System; (ii) are directly
interconnected to another transmission provider's transmission
system and may have an impact on Affected System Interconnection
Customer's interconnection request; (iii) have a pending higher-
queued Interconnection Request to interconnect to Transmission
Provider's Transmission System; and (iv) have no queue position but
have executed an LGIA or requested that an unexecuted LGIA be filed
with FERC. Transmission Provider has no obligation to study impacts
of Affected System Interconnection Customers of which it is not
notified.
The Affected System Study shall consist of a power flow,
stability, and short circuit analysis. The Affected System Study
will: state the assumptions upon which it is based; state the
results of the analyses; and provide the potential impediments to
Affected System Interconnection Customer's receipt if
interconnection service on its host transmission provider's
transmission system, including a preliminary indication of the cost
and length of time that would be necessary to correct any problems
identified in those analyses and implement the interconnection. For
purposes of determining necessary Affected System Network Upgrades,
the Affected System Study shall consider the level of
interconnection service requested in megawatts by Affected System
Interconnection Customer, unless otherwise required to study the
full generating facility capacity due to safety or reliability
concerns. The Affected System Study shall provide a list of
facilities that are required as a result of Affected System
Interconnection Customer's proposed interconnection to another
transmission provider's system, a non-binding good faith estimate of
cost responsibility, and a non-binding good faith estimated time to
construct. The Affected System Study may consist of a system impact
study, a facilities study, or some combination thereof.
9.7 Affected System Study Procedures
Transmission Provider shall use Clustering in conducting the
Affected System Study and shall use existing studies to the extent
practicable, when multiple Affected System Interconnection Customers
that are part of a single Cluster may cause the need for Affected
System Network Upgrades. Transmission Provider shall complete the
Affected System Study and provide the Affected System Study Report
to Affected System Interconnection Customer(s) and the host
transmission provider with whom interconnection has been requested
within one hundred fifty (150) Calendar Days after the receipt of
the Affected System Study Agreement and deposit.
At the request of Affected System Interconnection Customer,
Transmission Provider shall notify Affected System Interconnection
Customer as to the status of the Affected System Study. If
Transmission Provider is unable to complete the Affected System
Study within the requisite time period, it shall notify Affected
System Interconnection Customer(s), as well as the transmission
provider with which Affected System Interconnection Customer seeks
to interconnect, and shall provide an estimated completion date with
an explanation of the reasons why additional time is required. If
Transmission Provider does not meet the deadlines in this section,
Transmission Provider shall be subject to the financial penalties as
described in Section 3.9 of this LGIP. Upon request, Transmission
Provider shall provide Affected System Interconnection Customer(s)
with all supporting documentation, workpapers and relevant power
flow, short circuit and stability databases for the Affected System
Study, subject to confidentiality arrangements consistent with
Section 13.1 of this LGIP.
Transmission Provider must study an Affected System
Interconnection Customer using the Energy Resource Interconnection
Service modeling standard used for Interconnection Requests on its
own Transmission System, regardless of the level of interconnection
service that Affected System Interconnection Customer is seeking
from the host transmission provider with whom it seeks to
interconnect.
9.8 Meeting With Transmission Provider
Within ten (10) Business Days of providing the Affected System
Study Report to Affected System Interconnection Customer(s),
Transmission Provider and Affected System Interconnection
Customer(s) shall meet to discuss the results of the Affected System
Study.
9.9 Affected System Cost Allocation
Transmission Provider shall allocate Affected System Network
Upgrade costs identified during the Affected System Study to
Affected System Interconnection Customer(s) using a proportional
impact method, consistent with Section 4.2.1(1)(b) of this LGIP.
9.10 Tender of Affected Systems Facilities Construction Agreement/
Multiparty Affected System Facilities Construction Agreement
Transmission Provider shall tender to Affected System
Interconnection Customer(s) an Affected System Facilities
Construction Agreement/Multiparty Affected System Facilities
Construction Agreement, as applicable, in the form of Appendix 11 or
12 to this LGIP, within thirty (30) Calendar Days of providing the
Affected System Study Report. Within ten (10) Business Days of the
receipt of the Affected System Facilities Construction Agreement/
Multiparty Affected System Facilities Construction Agreement, the
Affected System Interconnection Customer(s) must execute the
agreement or request the agreement to be filed unexecuted with FERC.
Transmission Provider shall execute the agreement or file the
agreement unexecuted within five (5) Business Days after receiving
direction from Affected System Interconnection Customer(s). Affected
System Interconnection Customer's failure to execute the Affected
System Facilities Construction Agreement/Multiparty Affected System
Facilities Construction Agreement, or failure to request the
agreement to be filed unexecuted with FERC, shall result in the loss
of its Affected System Queue Position.
9.11 Restudy
If restudy of the Affected System Study is required,
Transmission Provider shall notify Affected System Interconnection
Customer(s) in writing within thirty (30) Calendar Days of discovery
of the need for restudy. Such restudy shall take no longer than
sixty (60) Calendar Days from the date of notice. Any cost of
restudy shall be borne by the Affected System Interconnection
Customer(s) being restudied.
[Prior to executing an LGIA, an Interconnection Customer may, in
order to advance the implementation of its interconnection, request
and Transmission Provider shall offer the Interconnection Customer,
an E&P Agreement that authorizes Transmission Provider to begin
engineering and procurement of long lead-time items necessary for
the establishment of the interconnection. However, Transmission
Provider shall not be obligated to offer an E&P Agreement if
Interconnection Customer is in Dispute Resolution as a result of an
allegation that Interconnection Customer has failed to meet any
milestones or comply with any prerequisites specified in other parts
of the LGIP. The E&P Agreement is an optional procedure and it will
not alter the Interconnection Customer's Queue Position or In-
Service Date. The E&P Agreement shall provide for Interconnection
Customer to pay the cost of all activities authorized by
Interconnection Customer and to make advance payments or provide
other satisfactory security for such costs.
Interconnection Customer shall pay the cost of such authorized
activities and any cancellation costs for equipment that is already
ordered for its interconnection, which cannot be mitigated as
hereafter described, whether or not such items or equipment later
become unnecessary. If Interconnection Customer withdraws its
[[Page 61285]]
application for interconnection or either Party terminates the E&P
Agreement, to the extent the equipment ordered can be canceled under
reasonable terms, Interconnection Customer shall be obligated to pay
the associated cancellation costs. To the extent that the equipment
cannot be reasonably canceled, Transmission Provider may elect: (i)
to take title to the equipment, in which event Transmission Provider
shall refund Interconnection Customer any amounts paid by
Interconnection Customer for such equipment and shall pay the cost
of delivery of such equipment, or (ii) to transfer title to and
deliver such equipment to Interconnection Customer, in which event
Interconnection Customer shall pay any unpaid balance and cost of
delivery of such equipment.]
Section 10. Optional Interconnection Study
10.1 Optional Interconnection Study Agreement
On or after the date when Interconnection Customer receives
[Interconnection System Impact Study] Cluster Study results,
Interconnection Customer may request, and Transmission Provider
shall perform a reasonable number of Optional Studies. The request
shall describe the assumptions that Interconnection Customer wishes
Transmission Provider to study within the scope described in Section
10.2. Within five (5) Business Days after receipt of a request for
an Optional Interconnection Study, Transmission Provider shall
provide to Interconnection Customer an Optional Interconnection
Study Agreement in the form of Appendix 4[5].
The Optional Interconnection Study Agreement shall: (i) specify
the technical data that Interconnection Customer must provide for
each phase of the Optional Interconnection Study, (ii) specify
Interconnection Customer's assumptions as to which Interconnection
Requests with earlier queue priority dates will be excluded from the
Optional Interconnection Study case and assumptions as to the type
of interconnection service for Interconnection Requests remaining in
the Optional Interconnection Study case, and (iii) Transmission
Provider's estimate of the cost of the Optional Interconnection
Study. To the extent known by Transmission Provider, such estimate
shall include any costs expected to be incurred by any Affected
System whose participation is necessary to complete the Optional
Interconnection Study. Notwithstanding the above, Transmission
Provider shall not be required as a result of an Optional
Interconnection Study request to conduct any additional
Interconnection Studies with respect to any other Interconnection
Request.
Interconnection Customer shall execute the Optional
Interconnection Study Agreement within ten (10) Business Days of
receipt and deliver the Optional Interconnection Study Agreement,
the technical data and a $10,000 deposit to Transmission Provider.
10.2 Scope of Optional Interconnection Study
The Optional Interconnection Study will consist of a sensitivity
analysis based on the assumptions specified by Interconnection
Customer in the Optional Interconnection Study Agreement. The
Optional Interconnection Study will also identify Transmission
Provider's Interconnection Facilities and the Network Upgrades, and
the estimated cost thereof, that may be required to provide
transmission service or Interconnection Service based upon the
results of the Optional Interconnection Study. The Optional
Interconnection Study shall be performed solely for informational
purposes. Transmission Provider shall use Reasonable Efforts to
coordinate the study with any Affected Systems that may be affected
by the types of Interconnection Services that are being studied.
Transmission Provider shall utilize existing studies to the extent
practicable in conducting the Optional Interconnection Study.
10.3 Optional Interconnection Study Procedures
The executed Optional Interconnection Study Agreement, the
prepayment, and technical and other data called for therein must be
provided to Transmission Provider within ten (10) Business Days of
Interconnection Customer receipt of the Optional Interconnection
Study Agreement. Transmission Provider shall use Reasonable Efforts
to complete the Optional Interconnection Study within a mutually
agreed upon time period specified within the Optional
Interconnection Study Agreement. If Transmission Provider is unable
to complete the Optional Interconnection Study within such time
period, it shall notify Interconnection Customer and provide an
estimated completion date and an explanation of the reasons why
additional time is required. Any difference between the study
payment and the actual cost of the study shall be paid to
Transmission Provider or refunded to Interconnection Customer, as
appropriate. Upon request, Transmission Provider shall provide
Interconnection Customer supporting documentation and workpapers and
databases or data developed in the preparation of the Optional
Interconnection Study, subject to confidentiality arrangements
consistent with Section 13.1.
Section 11. Standard Large Generator Interconnection Agreement (LGIA)
11.1 Tender
Interconnection Customer shall tender comments on the draft
Interconnection Facilities Study Report within thirty (30) Calendar
Days of receipt of the report. Within thirty (30) Calendar Days
after the comments are submitted or after Interconnection Customer
notifies Transmission Provider that it will not provide comments,
Transmission Provider shall tender a draft LGIA, together with draft
appendices. The draft LGIA shall be in the form of Transmission
Provider's FERC-approved standard form LGIA, which is in Appendix
5[6]. Interconnection Customer shall execute and return the LGIA and
completed draft appendices within thirty (30) Calendar Days, unless
(1) the sixty (60) Calendar Day negotiation period under Section
11.2 of this LGIP has commenced, or (2) LGIA execution, or filing
unexecuted, has been delayed to await the Affected System Study
Report pursuant to Section 11.2.1 of this LGIP.
11.2 Negotiation
Notwithstanding Section 11.1, at the request of Interconnection
Customer Transmission Provider shall begin negotiations with
Interconnection Customer concerning the appendices to the LGIA at
any time after Interconnection Customer executes the Interconnection
Facilities Study Agreement. Transmission Provider and
Interconnection Customer shall negotiate concerning any disputed
provisions of the appendices to the draft LGIA for not more than
sixty (60) Calendar Days after tender of the final Interconnection
Facilities Study Report. If Interconnection Customer determines that
negotiations are at an impasse, it may request termination of the
negotiations at any time after tender of the draft LGIA pursuant to
Section 11.1 and request submission of the unexecuted LGIA with FERC
or initiate Dispute Resolution procedures pursuant to Section 13.5.
If Interconnection Customer requests termination of the
negotiations, but within sixty (60) Calendar Days thereafter fails
to request either the filing of the unexecuted LGIA or initiate
Dispute Resolution, it shall be deemed to have withdrawn its
Interconnection Request. Unless otherwise agreed by the Parties, if
Interconnection Customer has not executed the LGIA, requested filing
of an unexecuted LGIA, or initiated Dispute Resolution procedures
pursuant to Section 13.5 within sixty (60) Calendar Days of tender
of draft LGIA, it shall be deemed to have withdrawn its
Interconnection Request. Transmission Provider shall provide to
Interconnection Customer a final LGIA within fifteen (15) Business
Days after the completion of the negotiation process.
11.2.1 Delay in LGIA Execution, or Filing Unexecuted, To Await
Affected System Study Report
If Interconnection Customer has not received its Affected System
Study Report from the Affected System Operator prior to the date
that it would be required to execute its LGIA (or request that its
LGIA be filed unexecuted) pursuant to Section 11.1 of this LGIP,
Transmission Provider shall, upon request of Interconnection
Customer, extend this deadline to thirty (30) Calendar Days after
Interconnection Customer's receipt of the Affected System Study
Report. If Interconnection Customer, after delaying LGIA execution,
or requesting unexecuted filing, to await Affected System Study
Results, decides to proceed to LGIA execution, or request unexecuted
filing, without those results, it may notify Transmission Provider
of its intent to proceed with LGIA execution (or request that its
LGIA be filed unexecuted) pursuant to Section 11.1 of this LGIP. If
Transmission Provider determines that further delay to the LGIA
execution date would cause a material impact on the cost or timing
of an equal- or lower-queued interconnection customer, Transmission
Provider must notify Interconnection Customer of such impacts and
set the deadline to execute the LGIA (or
[[Page 61286]]
request that the LGIA be filed unexecuted) to thirty (30) Calendar
Days after such notice is provided.
11.3 Execution and Filing
Simultaneously with submitting the executed LGIA to Transmission
Provider, or within ten (10) Business Days after the Interconnection
Customer requests that the Transmission Provider file the LGIA
unexecuted at the Commission, [Within fifteen (15) Business Days
after receipt of the final executed LGIA,]Interconnection Customer
shall provide Transmission Provider with [(A) reasonable evidence
that continued Site Control or (B) posting of $250,000, non-
refundable additional security, which shall be applied toward future
construction costs](1) demonstration of continued Site Control
pursuant to Section 8.1(2) of this LGIP; and (2) the LGIA Deposit
equal to twenty percent (20%) of Interconnection Customer's
estimated Network Upgrade costs identified in the draft LGIA minus
the total amount of Commercial Readiness Deposits that
Interconnection Customer has provided to Transmission Provider for
its Interconnection Request. Transmission Provider shall use LGIA
Deposit as (or as a portion of) the Interconnection Customer's
security required under LGIA Article 11.5. Interconnection Customer
may not request to suspend its LGIA under LGIA Article 5.16 until
Interconnection Customer has provided (1) and (2) to Transmission
Provider. If Interconnection Customer fails to provide (1) and (2)
to Transmission Provider within the thirty (30) Calendar Days
allowed for returning the executed LGIA and appendices under LGIP
Section 11.1, or within ten (10) Business Days after Interconnection
Customer requests that Transmission Provider file the LGIA
unexecuted at the Commission as allowed in this Section 11.3 of this
LGIP, the Interconnection Request will be deemed withdrawn pursuant
to Section 3.7 of this LGIP.
At the same time, Interconnection Customer also shall provide
reasonable evidence that one or more of the following milestones in
the development of the Large Generating Facility, at Interconnection
Customer election, has been achieved (unless such milestone is
inapplicable due to the characteristics of the Generating Facility):
(i) the execution of a contract for the supply or transportation of
fuel to the Large Generating Facility; (ii) the execution of a
contract for the supply of cooling water to the Large Generating
Facility; (iii) execution of a contract for the engineering for,
procurement of major equipment for, or construction of, the Large
Generating Facility; (iv) execution of a contract (or comparable
evidence) for the sale of electric energy or capacity from the Large
Generating Facility; or (v) application for an air, water, or land
use permit.
Interconnection Customer shall either: (i) execute two originals
of the tendered LGIA and return them to Transmission Provider; or
(ii) request in writing that Transmission Provider file with FERC an
LGIA in unexecuted form. As soon as practicable, but not later than
ten (10) Business Days after receiving either the two executed
originals of the tendered LGIA (if it does not conform with a FERC-
approved standard form of interconnection agreement) or the request
to file an unexecuted LGIA, Transmission Provider shall file the
LGIA with FERC, together with its explanation of any matters as to
which Interconnection Customer and Transmission Provider disagree
and support for the costs that Transmission Provider proposes to
charge to Interconnection Customer under the LGIA. An unexecuted
LGIA should contain terms and conditions deemed appropriate by
Transmission Provider for the Interconnection Request. If the
Parties agree to proceed with design, procurement, and construction
of facilities and upgrades under the agreed-upon terms of the
unexecuted LGIA, they may proceed pending FERC action.
11.4 Commencement of Interconnection Activities
If Interconnection Customer executes the final LGIA,
Transmission Provider and Interconnection Customer shall perform
their respective obligations in accordance with the terms of the
LGIA, subject to modification by FERC. Upon submission of an
unexecuted LGIA, Interconnection Customer and Transmission Provider
shall promptly comply with the unexecuted LGIA, subject to
modification by FERC.
Section 12. Construction of Transmission Provider's Interconnection
Facilities and Network Upgrades
12.1 Schedule
Transmission Provider and Interconnection Customer shall
negotiate in good faith concerning a schedule for the construction
of Transmission Provider's Interconnection Facilities and the
Network Upgrades.
12.2 Construction Sequencing
12.2.1 General
In general, the In-Service Date of an Interconnection Customers
seeking interconnection to the Transmission System will determine
the sequence of construction of Network Upgrades.
12.2.2 Advance Construction of Network Upgrades That Are an Obligation
of an Entity Other Than Interconnection Customer
An Interconnection Customer with an LGIA, in order to maintain
its In-Service Date, may request that Transmission Provider advance
to the extent necessary the completion of Network Upgrades that: (i)
were assumed in the Interconnection Studies for such Interconnection
Customer, (ii) are necessary to support such In-Service Date, and
(iii) would otherwise not be completed, pursuant to a contractual
obligation of an entity other than Interconnection Customer that is
seeking interconnection to the Transmission System, in time to
support such In-Service Date. Upon such request, Transmission
Provider will use Reasonable Efforts to advance the construction of
such Network Upgrades to accommodate such request; provided that
Interconnection Customer commits to pay Transmission Provider: (i)
any associated expediting costs and (ii) the cost of such Network
Upgrades. Transmission Provider will refund to Interconnection
Customer both the expediting costs and the cost of Network Upgrades,
in accordance with Article 11.4 of the LGIA. Consequently, the
entity with a contractual obligation to construct such Network
Upgrades shall be obligated to pay only that portion of the costs of
the Network Upgrades that Transmission Provider has not refunded to
Interconnection Customer. Payment by that entity shall be due on the
date that it would have been due had there been no request for
advance construction. Transmission Provider shall forward to
Interconnection Customer the amount paid by the entity with a
contractual obligation to construct the Network Upgrades as payment
in full for the outstanding balance owed to Interconnection
Customer. Transmission Provider then shall refund to that entity the
amount that it paid for the Network Upgrades, in accordance with
Article 11.4 of the LGIA.
12.2.3 Advancing Construction of Network Upgrades That Are Part of an
Expansion Plan of the Transmission Provider
An Interconnection Customer with an LGIA, in order to maintain
its In-Service Date, may request that Transmission Provider advance
to the extent necessary the completion of Network Upgrades that: (i)
are necessary to support such In-Service Date and (ii) would
otherwise not be completed, pursuant to an expansion plan of
Transmission Provider, in time to support such In-Service Date. Upon
such request, Transmission Provider will use Reasonable Efforts to
advance the construction of such Network Upgrades to accommodate
such request; provided that Interconnection Customer commits to pay
Transmission Provider any associated expediting costs.
Interconnection Customer shall be entitled to transmission credits,
if any, for any expediting costs paid.
12.2.4 Amended Interconnection [System Impact]Cluster Study Report
An Interconnection [System Impact]Cluster Study Report will be
amended to determine the facilities necessary to support the
requested In-Service Date. This amended study report will include
those transmission and Large Generating Facilities that are expected
to be on or before the requested In-Service Date.
Section 13. Miscellaneous
13.1 Confidentiality
Confidential Information shall include, without limitation, all
information relating to a Party's technology, research and
development, business affairs, and pricing, and any information
supplied by either of the Parties to the other prior to the
execution of an LGIA.
Information is Confidential Information only if it is clearly
designated or marked in writing as confidential on the face of the
document, or, if the information is conveyed orally or by
inspection, if the Party providing the information orally informs
the Party receiving the information that the information is
confidential.
If requested by either Party, the other Party shall provide in
writing, the basis for asserting that the information referred to in
[[Page 61287]]
this Article warrants confidential treatment, and the requesting
Party may disclose such writing to the appropriate Governmental
Authority. Each Party shall be responsible for the costs associated
with affording confidential treatment to its information.
13.1.1 Scope
Confidential Information shall not include information that the
receiving Party can demonstrate: (1) is generally available to the
public other than as a result of a disclosure by the receiving
Party; (2) was in the lawful possession of the receiving Party on a
non-confidential basis before receiving it from the disclosing
Party; (3) was supplied to the receiving Party without restriction
by a third party, who, to the knowledge of the receiving Party after
due inquiry, was under no obligation to the disclosing Party to keep
such information confidential; (4) was independently developed by
the receiving Party without reference to Confidential Information of
the disclosing Party; (5) is, or becomes, publicly known, through no
wrongful act or omission of the receiving Party or Breach of the
LGIA; or (6) is required, in accordance with Section 13.1.6, Order
of Disclosure, to be disclosed by any Governmental Authority or is
otherwise required to be disclosed by law or subpoena, or is
necessary in any legal proceeding establishing rights and
obligations under the LGIA. Information designated as Confidential
Information will no longer be deemed confidential if the Party that
designated the information as confidential notifies the other Party
that it no longer is confidential.
13.1.2 Release of Confidential Information
Neither Party shall release or disclose Confidential Information
to any other person, except to its Affiliates (limited by the
Standards of Conduct requirements), employees, consultants, or to
parties who may be or considering providing financing to or equity
participation with Interconnection Customer, or to potential
purchasers or assignees of Interconnection Customer, on a need-to-
know basis in connection with these procedures, unless such person
has first been advised of the confidentiality provisions of this
Section 13.1 and has agreed to comply with such provisions.
Notwithstanding the foregoing, a Party providing Confidential
Information to any person shall remain primarily responsible for any
release of Confidential Information in contravention of this Section
13.1.
13.1.3 Rights
Each Party retains all rights, title, and interest in the
Confidential Information that each Party discloses to the other
Party. The disclosure by each Party to the other Party of
Confidential Information shall not be deemed a waiver by either
Party or any other person or entity of the right to protect the
Confidential Information from public disclosure.
13.1.4 No Warranties
By providing Confidential Information, neither Party makes any
warranties or representations as to its accuracy or completeness. In
addition, by supplying Confidential Information, neither Party
obligates itself to provide any particular information or
Confidential Information to the other Party nor to enter into any
further agreements or proceed with any other relationship or joint
venture.
13.1.5 Standard of Care
Each Party shall use at least the same standard of care to
protect Confidential Information it receives as it uses to protect
its own Confidential Information from unauthorized disclosure,
publication or dissemination. Each Party may use Confidential
Information solely to fulfill its obligations to the other Party
under these procedures or its regulatory requirements.
13.1.6 Order of Disclosure
If a court or a Government Authority or entity with the right,
power, and apparent authority to do so requests or requires either
Party, by subpoena, oral deposition, interrogatories, requests for
production of documents, administrative order, or otherwise, to
disclose Confidential Information, that Party shall provide the
other Party with prompt notice of such request(s) or requirement(s)
so that the other Party may seek an appropriate protective order or
waive compliance with the terms of the LGIA. Notwithstanding the
absence of a protective order or waiver, the Party may disclose such
Confidential Information which, in the opinion of its counsel, the
Party is legally compelled to disclose. Each Party will use
Reasonable Efforts to obtain reliable assurance that confidential
treatment will be accorded any Confidential Information so
furnished.
13.1.7 Remedies
The Parties agree that monetary damages would be inadequate to
compensate a Party for the other Party's Breach of its obligations
under this Section 13.1. Each Party accordingly agrees that the
other Party shall be entitled to equitable relief, by way of
injunction or otherwise, if the first Party Breaches or threatens to
Breach its obligations under this Section 13.1, which equitable
relief shall be granted without bond or proof of damages, and the
receiving Party shall not plead in defense that there would be an
adequate remedy at law. Such remedy shall not be deemed an exclusive
remedy for the Breach of this Section 13.1, but shall be in addition
to all other remedies available at law or in equity. The Parties
further acknowledge and agree that the covenants contained herein
are necessary for the protection of legitimate business interests
and are reasonable in scope. No Party, however, shall be liable for
indirect, incidental, or consequential or punitive damages of any
nature or kind resulting from or arising in connection with this
Section 13.1.
13.1.8 Disclosure to FERC, its Staff, or a State
Notwithstanding anything in this Section 13.1 to the contrary,
and pursuant to 18 CFR 1b.20, if FERC or its staff, during the
course of an investigation or otherwise, requests information from
one of the Parties that is otherwise required to be maintained in
confidence pursuant to the LGIP, the Party shall provide the
requested information to FERC or its staff, within the time provided
for in the request for information. In providing the information to
FERC or its staff, the Party must, consistent with 18 CFR 388.112,
request that the information be treated as confidential and non-
public by FERC and its staff and that the information be withheld
from public disclosure. Parties are prohibited from notifying the
other Party prior to the release of the Confidential Information to
FERC or its staff. The Party shall notify the other Party to the
LGIA when its is notified by FERC or its staff that a request to
release Confidential Information has been received by FERC, at which
time either of the Parties may respond before such information would
be made public, pursuant to 18 CFR 388.112. Requests from a state
regulatory body conducting a confidential investigation shall be
treated in a similar manner, consistent with applicable state rules
and regulations.
13.1.9
Subject to the exception in Section 13.1.8 of this LGIP, any
information that a Party claims is competitively sensitive,
commercial or financial information (``Confidential Information'')
shall not be disclosed by the other Party to any person not employed
or retained by the other Party, except to the extent disclosure is
(i) required by law; (ii) reasonably deemed by the disclosing Party
to be required to be disclosed in connection with a dispute between
or among the Parties, or the defense of litigation or dispute; (iii)
otherwise permitted by consent of the other Party, such consent not
to be unreasonably withheld; or (iv) necessary to fulfill its
obligations under this LGIP or as a transmission service provider or
a [Control Area]Balancing Authority Area operator including
disclosing the Confidential Information to an RTO or ISO or to a
subregional, regional or national reliability organization or
planning group. The Party asserting confidentiality shall notify the
other Party in writing of the information it claims is confidential.
Prior to any disclosures of the other Party's Confidential
Information under this subparagraph, or if any third party or
Governmental Authority makes any request or demand for any of the
information described in this subparagraph, the disclosing Party
agrees to promptly notify the other Party in writing and agrees to
assert confidentiality and cooperate with the other Party in seeking
to protect the Confidential Information from public disclosure by
confidentiality agreement, protective order or other reasonable
measures.
13.1.10
This provision shall not apply to any information that was or is
hereafter in the public domain (except as a result of a Breach of
this provision).
13.1.11
Transmission Provider shall, at Interconnection Customer's
election, destroy, in a confidential manner, or return the
Confidential Information provided at the time of Confidential
Information is no longer needed.
13.2 Delegation of Responsibility
Transmission Provider may use the services of subcontractors as
it deems
[[Page 61288]]
appropriate to perform its obligations under this LGIP. Transmission
Provider shall remain primarily liable to Interconnection Customer
for the performance of such subcontractors and compliance with its
obligations of this LGIP. The subcontractor shall keep all
information provided confidential and shall use such information
solely for the performance of such obligation for which it was
provided and no other purpose.
13.3 Obligation for Study Costs
In the event an Interconnection Customer withdraws its
Interconnection Request prior to the commencement of the Cluster
Study, Interconnection Customer must pay Transmission Provider the
actual costs of processing its Interconnection Request. In the event
an Interconnection Customer withdraws after the commencement of the
Cluster Study, Transmission Provider shall charge and
Interconnection Customer shall pay the actual costs of the
Interconnection Studies. The costs of any interconnection study
conducted on a clustered basis shall be allocated among each
Interconnection Customer within the cluster as follows:
{Transmission Provider shall include in this section a description
of how the cost of any clustered interconnection study will be
allocated.{time}
Any difference between the study deposit and the actual cost of
the applicable Interconnection Study shall be paid by or refunded,
except as otherwise provided herein, to Interconnection
[Customer]Customers or offset against the cost of any future
Interconnection Studies associated with the applicable
[Interconnection Request]Cluster prior to beginning of any such
future Interconnection Studies. Any invoices for Interconnection
Studies shall include a detailed and itemized accounting of the cost
of each Interconnection Study. Interconnection [Customer]Customers
shall pay any such undisputed costs within thirty (30) Calendar Days
of receipt of an invoice therefor. If an Interconnection Customer
fails to pay such undisputed costs within the time allotted, its
Interconnection Request shall be deemed withdrawn from the Cluster
Study Process and will be subject to Withdrawal Penalties pursuant
to Section 3.7 of this LGIP. [Transmission Provider shall not be
obligated to perform or continue to perform any studies unless
Interconnection Customer has paid all undisputed amounts in
compliance herewith.]
13.4 Third Parties Conducting Studies
If (i) at the time of the signing of an Interconnection Study
Agreement there is disagreement as to the estimated time to complete
an Interconnection Study, (ii) Interconnection Customer receives
notice pursuant to Sections 6.3, 7.4 or 8.3 that Transmission
Provider will not complete an Interconnection Study within the
applicable timeframe for such Interconnection Study, or (iii)
Interconnection Customer receives neither the Interconnection Study
nor a notice under Sections 6.3, 7.4 or 8.3 within the applicable
timeframe for such Interconnection Study, then Interconnection
Customer may require Transmission Provider to utilize a third party
consultant reasonably acceptable to Interconnection Customer and
Transmission Provider to perform such Interconnection Study under
the direction of Transmission Provider. At other times, Transmission
Provider may also utilize a third party consultant to perform such
Interconnection Study, either in response to a general request of
Interconnection Customer, or on its own volition.
In all cases, use of a third party consultant shall be in accord
with Article 26 of the LGIA (Subcontractors) and limited to
situations where Transmission Provider determines that doing so will
help maintain or accelerate the study process for Interconnection
Customer's pending Interconnection Request and not interfere with
Transmission Provider's progress on Interconnection Studies for
other pending Interconnection Requests. In cases where
Interconnection Customer requests use of a third party consultant to
perform such Interconnection Study, Interconnection Customer and
Transmission Provider shall negotiate all of the pertinent terms and
conditions, including reimbursement arrangements and the estimated
study completion date and study review deadline. Transmission
Provider shall convey all workpapers, data bases, study results and
all other supporting documentation prepared to date with respect to
the Interconnection Request as soon as soon as practicable upon
Interconnection Customer's request subject to the confidentiality
provision in Section 13.1. In any case, such third party contract
may be entered into with either Interconnection Customer or
Transmission Provider at Transmission Provider's discretion. In the
case of (iii) Interconnection Customer maintains its right to submit
a claim to Dispute Resolution to recover the costs of such third
party study. Such third party consultant shall be required to comply
with this LGIP, Article 26 of the LGIA (Subcontractors), and the
relevant Tariff procedures and protocols as would apply if
Transmission Provider were to conduct the Interconnection Study and
shall use the information provided to it solely for purposes of
performing such services and for no other purposes. Transmission
Provider shall cooperate with such third party consultant and
Interconnection Customer to complete and issue the Interconnection
Study in the shortest reasonable time.
13.5 Disputes
13.5.1 Submission
In the event either Party has a dispute, or asserts a claim,
that arises out of or in connection with the LGIA, the LGIP, or
their performance, such Party (the ``disputing Party'') shall
provide the other Party with written notice of the dispute or claim
(``Notice of Dispute''). Such dispute or claim shall be referred to
a designated senior representative of each Party for resolution on
an informal basis as promptly as practicable after receipt of the
Notice of Dispute by the other Party. In the event the designated
representatives are unable to resolve the claim or dispute through
unassisted or assisted negotiations within thirty (30) Calendar Days
of the other Party's receipt of the Notice of Dispute, such claim or
dispute may, upon mutual agreement of the Parties, be submitted to
arbitration and resolved in accordance with the arbitration
procedures set forth below. In the event the Parties do not agree to
submit such claim or dispute to arbitration, each Party may exercise
whatever rights and remedies it may have in equity or at law
consistent with the terms of this LGIA.
13.5.2 External Arbitration Procedures
Any arbitration initiated under these procedures shall be
conducted before a single neutral arbitrator appointed by the
Parties. If the Parties fail to agree upon a single arbitrator
within ten (10) Calendar Days of the submission of the dispute to
arbitration, each Party shall choose one arbitrator who shall sit on
a three-member arbitration panel. The two arbitrators so chosen
shall within twenty (20) Calendar Days select a third arbitrator to
chair the arbitration panel. In either case, the arbitrators shall
be knowledgeable in electric utility matters, including electric
transmission and bulk power issues, and shall not have any current
or past substantial business or financial relationships with any
party to the arbitration (except prior arbitration). The
arbitrator(s) shall provide each of the Parties an opportunity to be
heard and, except as otherwise provided herein, shall conduct the
arbitration in accordance with the Commercial Arbitration Rules of
the American Arbitration Association (``Arbitration Rules'') and any
applicable FERC regulations or RTO rules; provided, however, in the
event of a conflict between the Arbitration Rules and the terms of
this Section 13, the terms of this Section 13 shall prevail.
13.5.3 Arbitration Decisions
Unless otherwise agreed by the Parties, the arbitrator(s) shall
render a decision within ninety (90) Calendar Days of appointment
and shall notify the Parties in writing of such decision and the
reasons therefor. The arbitrator(s) shall be authorized only to
interpret and apply the provisions of the LGIA and LGIP and shall
have no power to modify or change any provision of the LGIA and LGIP
in any manner. The decision of the arbitrator(s) shall be final and
binding upon the Parties, and judgment on the award may be entered
in any court having jurisdiction. The decision of the arbitrator(s)
may be appealed solely on the grounds that the conduct of the
arbitrator(s), or the decision itself, violated the standards set
forth in the Federal Arbitration Act or the Administrative Dispute
Resolution Act. The final decision of the arbitrator must also be
filed with FERC if it affects jurisdictional rates, terms and
conditions of service, Interconnection Facilities, or Network
Upgrades.
13.5.4 Costs
Each Party shall be responsible for its own costs incurred
during the arbitration process and for the following costs, if
applicable: (1) the cost of the arbitrator chosen by the Party to
sit on the three member panel and one half of the cost of the third
arbitrator chosen; or (2) one half the cost of the single arbitrator
jointly chosen by the Parties.
[[Page 61289]]
13.5.5 Non-Binding Dispute Resolution Procedures
If a Party has submitted a Notice of Dispute pursuant to
S[s]ection 13.5.1, and the Parties are unable to resolve the claim
or dispute through unassisted or assisted negotiations within the
thirty (30) Calendar Days provided in that section, and the Parties
cannot reach mutual agreement to pursue the S[s]ection 13.5
arbitration process, a Party may request that Transmission Provider
engage in Non-binding Dispute Resolution pursuant to this section by
providing written notice to Transmission Provider (``Request for
Non-binding Dispute Resolution''). Conversely, either Party may file
a Request for Non-binding Dispute Resolution pursuant to this
section without first seeking mutual agreement to pursue the
S[s]ection 13.5 arbitration process. The process in S[s]ection
13.5.5 shall serve as an alternative to, and not a replacement of,
the section 13.5 arbitration process. Pursuant to this process, a
Transmission Provider must within 30 days of receipt of the Request
for Non-binding Dispute Resolution appoint a neutral decision-maker
that is an independent subcontractor that shall not have any current
or past substantial business or financial relationships with either
Party. Unless otherwise agreed by the Parties, the decision-maker
shall render a decision within sixty (60) Calendar Days of
appointment and shall notify the Parties in writing of such decision
and reasons therefore. This decision-maker shall be authorized only
to interpret and apply the provisions of the LGIP and LGIA and shall
have no power to modify or change any provision of the LGIP and LGIA
in any manner. The result reached in this process is not binding,
but, unless otherwise agreed, the Parties may cite the record and
decision in the non-binding dispute resolution process in future
dispute resolution processes, including in a S[s]ection 13.5
arbitration, or in a Federal Power Act section 206 complaint. Each
Party shall be responsible for its own costs incurred during the
process and the cost of the decision-maker shall be divided equally
among each Party to the dispute.
13.6 Local Furnishing Bonds
13.6.1 Transmission Providers That Own Facilities Financed by Local
Furnishing Bonds
This provision is applicable only to a Transmission Provider
that has financed facilities for the local furnishing of electric
energy with tax-exempt bonds, as described in Section 142(f) of the
Internal Revenue Code (``local furnishing bonds''). Notwithstanding
any other provision of this LGIA and LGIP, Transmission Provider
shall not be required to provide Interconnection Service to
Interconnection Customer pursuant to this LGIA and LGIP if the
provision of such Transmission Service would jeopardize the tax-
exempt status of any local furnishing bond(s) used to finance
Transmission Provider's facilities that would be used in providing
such Interconnection Service.
13.6.2 Alternative Procedures for Requesting Interconnection Service
If Transmission Provider determines that the provision of
Interconnection Service requested by Interconnection Customer would
jeopardize the tax-exempt status of any local furnishing bond(s)
used to finance its facilities that would be used in providing such
Interconnection Service, it shall advise the Interconnection
Customer within thirty (30) Calendar Days of receipt of the
Interconnection Request.
Interconnection Customer thereafter may renew its request for
interconnection using the process specified in Article 5.2(ii) of
the Transmission Provider's Tariff.
Section [9]13.7 Engineering & Procurement (`E&P') Agreement
Prior to executing an LGIA, an Interconnection Customer may, in
order to advance the implementation of its interconnection, request
and Transmission Provider shall offer Interconnection Customer, an
E&P Agreement that authorizes Transmission Provider to begin
engineering and procurement of long lead-time items necessary for
the establishment of the interconnection. However, Transmission
Provider shall not be obligated to offer an E&P Agreement if
Interconnection Customer is in Dispute Resolution as a result of an
allegation that Interconnection Customer has failed to meet any
milestones or comply with any prerequisites specified in other parts
of the LGIP. The E&P Agreement is an optional procedure and it will
not alter Interconnection Customer's Queue Position or In-Service
Date. The E&P Agreement shall provide for Interconnection Customer
to pay the cost of all activities authorized by Interconnection
Customer and to make advance payments or provide other satisfactory
security for such costs.
Interconnection Customer shall pay the cost of such authorized
activities and any cancellation costs for equipment that is already
ordered for its interconnection, which cannot be mitigated as
hereafter described, whether or not such items or equipment later
become unnecessary. If Interconnection Customer withdraws its
Interconnection Request or either Party terminates the E&P
Agreement, to the extent the equipment ordered can be canceled under
reasonable terms, Interconnection Customer shall be obligated to pay
the associated cancellation costs. To the extent that the equipment
cannot be reasonably canceled, Transmission Provider may elect: (i)
to take title to the equipment, in which event Transmission Provider
shall refund Interconnection Customer any amounts paid by
Interconnection Customer for such equipment and shall pay the cost
of delivery of such equipment, or (ii) to transfer title to and
deliver such equipment to Interconnection Customer, in which event
Interconnection Customer shall pay any unpaid balance and cost of
delivery of such equipment.
Appendix 1 to LGIP
INTERCONNECTION REQUEST FOR A LARGE GENERATING FACILITY
1. The undersigned Interconnection Customer submits this request to
interconnect its Large Generating Facility with Transmission
Provider's Transmission System pursuant to a Tariff.
2.
2. This Interconnection Request is for (check one):
3. __ A proposed new Large Generating Facility.
4. __ An increase in the generating capacity or a Material
Modification of an existing Generating Facility.
3. The type of interconnection service requested (check one):
5. __ Energy Resource Interconnection Service
6. __ Network Resource Interconnection Service
4. __ Check here only if Interconnection Customer requesting Network
Resource Interconnection Service also seeks to have its Generating
Facility studied for Energy Resource Interconnection Service
7.
5. Interconnection Customer provides the following information:
a. Address or location or the proposed new Large Generating
Facility site (to the extent known) or, in the case of an existing
Generating Facility, the name and specific location of the existing
Generating Facility;
b. Maximum summer at __ degrees C and winter at __ degrees C
megawatt electrical output of the proposed new Large Generating
Facility or the amount of megawatt increase in the generating
capacity of an existing Generating Facility;
c. General description of the equipment configuration;
d. Commercial Operation Date (Day, Month, and Year);
e. Name, address, telephone number, and email address of
Interconnection Customer's contact person;
f. Approximate location of the proposed Point of Interconnection
(optional);
g. Interconnection Customer Data (set forth in Attachment A);
h. Primary frequency response operating range for electric
storage resources;
i. Requested capacity (in MW) of Interconnection Service (if
lower than the Generating Facility Capacity)[.];
j. If applicable, (1) the requested operating assumptions (i.e.,
whether the interconnecting Generating Facility will or will not
charge at peak load) to be used by Transmission Provider that
reflect the proposed charging behavior of a Generating Facility that
includes at least one electric storage resource, and (2) a
description of any control technologies (software and/or hardware)
that will limit the operation of the Generating Facility to its
intended operation.
6. Applicable deposit amount as specified in the LGIP.
8.
7. Evidence of Site Control as specified in the LGIP (check one)
9.
[[Page 61290]]
10. __ Is attached to this Interconnection Request
11. __ Will be provided at a later date in accordance with this LGIP
8. This Interconnection Request shall be submitted to the
representative indicated below:
12. {To be completed by Transmission Provider{time}
9. Representative of Interconnection Customer to contact:
13. [To be completed by Interconnection Customer]
10. This Interconnection Request is submitted by:
14.
15. Name of Interconnection Customer:
By (signature):--------------------------------------------------------
Name (type or print):--------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Attachment A to Appendix 1 Interconnection Request
Large Generating Facility Data Unit Ratings
kVA __ [deg]F __ Voltage __
Power Factor __
Speed (RPM) __ Connection (e.g. Wye) __
Short Circuit Ratio __ Frequency, Hertz __
Stator Amperes at Rated kVA __ Field Volts __
Max Turbine __ MW [deg]F __
Primary frequency response operating range for electric storage
resources:
Minimum State of Charge:-----------------------------------------------
Maximum State of Charge:-----------------------------------------------
Combined Turbine-Generator-Exciter Inertia Data
Inertia Constant, H = __ kW sec/kVA
Moment-of-Inertia, WR\2\ = __ lb. ft.\2\
Reactance Data (per Unit-Rated KVA)
------------------------------------------------------------------------
Direct axis Quadrature axis
------------------------------------------------------------------------
Synchronous--saturated.......... Xdv ___ Xqv ___
Synchronous--unsaturated........ Xdi ___ Xqi ___
Transient--saturated............ X'dv ___ X'qv ___
Transient--unsaturated.......... X'di ___ X'qi ___
Subtransient--saturated......... X''dv ___ X''qv ___
Subtransient--unsaturated....... X''di ___ X''qi ___
Negative Sequence--saturated.... X2v ___
Negative Sequence--unsaturated.. X2i ___
Zero Sequence--saturated........ X0v ___
Zero Sequence--unsaturated...... X0i ___
Leakage Reactance............... Xlm ___
------------------------------------------------------------------------
Field Time Constant Data (SEC)
Open Circuit................ T'do ___ T'qo ___
Three-Phase Short Circuit T'd3 ___ T'q ___
Transient.
Line to Line Short Circuit T'd2 ___
Transient.
Line to Neutral Short T'd1 ___
Circuit Transient.
Short Circuit Subtransient.. T''d ___ T''q ___
Open Circuit Subtransient... T''do ___ T''qo ___
Armature Time Constant Data (SEC)
Three Phase Short Circuit--Ta3 ___
Line to Line Short Circuit--Ta2 ___
Line to Neutral Short Circuit--Ta1 ___
Note: If requested information is not applicable, indicate by
marking ``N/A.''
MW Capability and Plant Configuration Large Generating Facility Data
Armature Winding Resistance Data (per Unit)
Positive--R1 ___
Negative--R2 ___
Zero--R0 ___
Rotor Short Time Thermal Capacity I2\2\t = ___
Field Current at Rated kVA, Armature Voltage and PF = ___ amps
Field Current at Rated kVA and Armature Voltage, 0 PF = ___ amps
Three Phase Armature Winding Capacitance = ___ microfarad
Field Winding Resistance = ___ ohms ___ [deg]C
Armature Winding Resistance (Per Phase) = ___ ohms ___[deg]C
Curves
Provide Saturation, Vee, Reactive Capability, Capacity
Temperature Correction curves. Designate normal and emergency
Hydrogen Pressure operating range for multiple curves.
Generator Step-Up Transformer Data Ratings
Capacity Self-cooled/Maximum Nameplate
___/___ kVA
Voltage Ratio(Generator Side/System side/Tertiary)
___/___/___kV
Winding Connections (Low V/High V/Tertiary V (Delta or Wye))
___/___/___
Fixed Taps Available---------------------------------------------------
Present Tap Setting----------------------------------------------------
Impedance
Positive Z1 (on self-cooled kVA rating) ___ % ___ X/R
Zero Z0 (on self-cooled kVA rating) ___ % ___ X/R
Excitation System Data
Identify appropriate IEEE model block diagram of excitation
system and power system stabilizer (PSS) for computer representation
in power system stability simulations and the corresponding
excitation system and PSS constants for use in the model.
Governor System Data
Identify appropriate IEEE model block diagram of governor system
for computer representation in power system stability simulations
and the corresponding governor system constants for use in the
model.
Wind Generators
Number of generators to be interconnected pursuant to this
Interconnection Request: ___
Elevation:-------------------------------------------------------------
____ Single Phase
____ Three Phase
Inverter manufacturer, model name, number, and version:
-----------------------------------------------------------------------
List of adjustable setpoints for the protective equipment or
software:
-----------------------------------------------------------------------
Note: A completed General Electric Company Power Systems Load
Flow (PSLF) data sheet or other compatible formats, such as IEEE and
PTI power flow models, must be supplied with the Interconnection
Request. If other data sheets are more appropriate to the proposed
device, then they shall be provided and discussed at Scoping
Meeting.
Induction Generators
(*) Field Volts:-------------------------------------------------------
(*) Field Amperes:-----------------------------------------------------
(*) Motoring Power (kW):-----------------------------------------------
(*) Neutral Grounding Resistor (If Applicable):------------------------
(*) I2\2\t or K (Heating Time Constant):--------------------
(*) Rotor Resistance:--------------------------------------------------
[[Page 61291]]
(*) Stator Resistance:-------------------------------------------------
(*) Stator Reactance:--------------------------------------------------
(*) Rotor Reactance:---------------------------------------------------
(*) Magnetizing Reactance:---------------------------------------------
(*) Short Circuit Reactance:-------------------------------------------
(*) Exciting Current:--------------------------------------------------
(*) Temperature Rise:--------------------------------------------------
(*) Frame Size:--------------------------------------------------------
(*) Design Letter:-----------------------------------------------------
(*) Reactive Power Required In Vars (No Load):-------------------------
(*) Reactive Power Required In Vars (Full Load):-----------------------
(*) Total Rotating Inertia, H:___ Per Unit on KVA Base
Note: Please consult Transmission Provider prior to submitting
the Interconnection Request to determine if the information
designated by (*) is required.
Models for Non-Synchronous Generators
For a non-synchronous Large Generating Facility, Interconnection
Customer shall provide (1) a validated user-defined root mean
squared (RMS) positive sequence dynamics model; (2) an appropriately
parameterized generic library RMS positive sequence dynamics model,
including model block diagram of the inverter control and plant
control systems, as defined by the selection in Table 1 or a model
otherwise approved by the Western Electricity Coordinating Council,
that corresponds to Interconnection Customer's Large Generating
Facility; and (3) if applicable, a validated electromagnetic
transient model if Transmission Provider performs an electromagnetic
transient study as part of the interconnection study process. A
user-defined model is a set of programming code created by equipment
manufacturers or developers that captures the latest features of
controllers that are mainly software based and represents the
entities' control strategies but does not necessarily correspond to
any generic library model. Interconnection Customer must also
demonstrate that the model is validated by providing evidence that
the equipment behavior is consistent with the model behavior (e.g.,
an attestation from Interconnection Customer that the model
accurately represents the entire Large Generating Facility;
attestations from each equipment manufacturer that the user defined
model accurately represents the component of the Large Generating
Facility; or test data).
Table 1--Acceptable Generic Library RMS Positive Sequence Dynamics Models
----------------------------------------------------------------------------------------------------------------
GE PSLF Siemens PSS/E* PowerWorld Simulator Description
----------------------------------------------------------------------------------------------------------------
pvd1.................... ....................... PVD1.................. Distributed PV system model.
der_a................... DERAU1................. DER_A................. Distributed energy resource model.
regc_a.................. REGCAU1, REGCA1........ REGC_A................ Generator/converter model.
regc_b.................. REGCBU1................ REGC_B................ Generator/converter model.
wt1g.................... WT1G1.................. WT1G and WT1G1........ Wind turbine model for Type-1 wind
turbines (conventional directly
connected induction generator).
wt2g.................... WT2G1.................. WT2G and WT2G1........ Generator model for generic Type-2
wind turbines.
wt2e.................... WT2E1.................. WT2E and WT2E1........ Rotor resistance control model for
wound-rotor induction wind-turbine
generator wt2g.
reec_a.................. REECAU1, REECA1........ REEC_A................ Renewable energy electrical control
model.
reec_c.................. REECCU1................ REEC_C................ Electrical control model for battery
energy storage system.
reec_d.................. REECDU1................ REEC_D................ Renewable energy electrical control
model.
wt1t.................... WT12T1................. WT1T and WT12T1....... Wind turbine model for Type-1 wind
turbines (conventional directly
connected induction generator).
wt1p_b.................. wt1p_b................. WT12A1U_B............. Generic wind turbine pitch controller
for WTGs of Types 1 and 2.
wt2t.................... WT12T1................. WT2T.................. Wind turbine model for Type-2 wind
turbines (directly connected
induction generator wind turbines
with an external rotor resistance).
wtgt_a.................. WTDTAU1, WTDTA1........ WTGT_A................ Wind turbine drive train model.
wtga_a.................. WTARAU1, WTARA1........ WTGA_A................ Simple aerodynamic model.
wtgp_a.................. WTPTAU1, WTPTA1........ WTGPT_A............... Wind Turbine Generator Pitch
controller.
wtgq_a.................. WTTQAU1, WTTQA1........ WTGTRQ_A.............. Wind Turbine Generator Torque
controller.
wtgwgo_a................ WTGWGOAU............... WTGWGO_A.............. Supplementary control model for Weak
Grids.
wtgibffr_a.............. WTGIBFFRA.............. WTGIBFFR_A............ Inertial-base fast frequency response
control.
wtgp_b.................. WTPTBU1................ WTGPT_B............... Wind Turbine Generator Pitch
controller.
wtgt_b.................. WTDTBU1................ WTGT_B................ Drive train model.
repc_a.................. Type 4: REPCAU1 (v33), REPC_A................ Power Plant Controller.
REPCA1 (v34).
Type 3: REPCTAU1 (v33),
REPCTA1 (v34).
repc_b.................. PLNTBU1................ REPC_B................ Power Plant Level Controller for
controlling several plants/devices.
In regard to Siemens PSS/E*:Names of
other models for interface with
other devices:
REA3XBU1, REAX4BU1--for interface
with Type 3 and 4 renewable
machines.
SWSAXBU1--for interface with SVC
(modeled as switched shunt in
powerflow).
SYNAXBU1--for interface with
synchronous condenser.
FCTAXBU1--for interface with FACTS
device.
repc_c.................. REPCCU................. REPC_C................ Power plant controller.
----------------------------------------------------------------------------------------------------------------
Appendix 2 to LGIP
[Interconnection Feasibility Study Agreement]
[This agreement is made and entered into this _ day of ___, 20 _
by and between_____, a _____ organized and existing under the laws
of _____ the State of (``Interconnection Customer''), and _____, a
_____ existing under the laws of the State of _____(``Transmission
Provider''). Interconnection Customer and Transmission Provider each
may be referred to as a ``Party,'' or collectively as the
``Parties.'']
[Recitals]
[Whereas, Interconnection Customer is proposing to develop a
Large Generating Facility or generating capacity addition to an
existing Generating Facility consistent with the Interconnection
Request submitted by Interconnection customer dated ___; and]
[Whereas, Interconnection Customer desires to interconnect the
Large Generating Facility with the Transmission System; and]
[Whereas, Interconnection Customer has requested Transmission
Provider to perform an Interconnection Feasibility Study to assess
the feasibility of interconnecting the
[[Page 61292]]
proposed Large Generating Facility to the Transmission System, and
of any Affected Systems;]
[Now, therefore, in consideration of and subject to the mutual
covenants contained herein the Parties agree as follows:]
[1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in
Transmission Provider's FERC-approved LGIP]
[2.0 Interconnection Customer elects and Transmission Provider
shall cause to be performed an Interconnection Feasibility Study
consistent with Section 6.0 of this LGIP in accordance with the
Tariff].
[3.0 The scope of the Interconnection Feasibility Study shall be
subject to the assumptions set forth in Attachment A to this
Agreement.]
[4.0 The Interconnection Feasibility Study shall be based on the
technical information provided by Interconnection Customer in the
Interconnection Request, as may be modified as the result of the
Scoping Meeting. Transmission Provider reserves the right to request
additional technical information from Interconnection Customer as
may reasonably become necessary consistent with Good Utility
Practice during the course of the Interconnection Feasibility Study
and as designated in accordance with Section 3.4.4 of the LGIP. If,
after the designation of the Point of Interconnection pursuant to
Section 3.4.4 of the LGIP, Interconnection Customer modifies its
Interconnection Request pursuant to Section 4.4, the time to
complete the Interconnection Feasibility Study may be extended.]
[5.0 The Interconnection Feasibility Study report shall provide
the following information:]
--[preliminary identification of any circuit breaker short circuit
capability limits exceeded as a result of the interconnection;]
--[preliminary identification of any thermal overload or voltage
limit violations resulting from the interconnection; and]
--[preliminary description and non-bonding estimated cost of
facilities required to interconnect the Large Generating Facility to
the Transmission System and to address the identified short circuit
and power flow issues.]
[6.0 Interconnection Customer shall provide a deposit of $10,000
for the performance of the Interconnection Feasibility Study.]
[Upon receipt of the Interconnection Feasibility Study,
Transmission Provider shall charge and Interconnection Customer
shall pay the actual costs of the Interconnection Feasibility
Study.]
[Any difference between the deposit and the actual cost of the
study shall be paid by or refunded to Interconnection Customer, as
appropriate.]
[7.0 Miscellaneous. The Interconnection Feasibility Study
Agreement shall include standard miscellaneous terms including, but
not limited to, indemnities, representations, disclaimers,
warranties, governing law, amendment, execution, waiver,
enforceability and assignment, that reflect best practices in the
electric industry, and that are consistent with regional practices,
Applicable Laws and Regulations, and the organizational nature of
each Party. All of these provisions, to the extent practicable,
shall be consistent with the provisions of this LGIP and the LGIA.]
[In witness whereof, the Parties have caused this Agreement to
be duly executed by their duly authorized officers or agents on the
day and year first above written.
{Insert name of Transmission Provider or Transmission Owner, if
applicable{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of prospective Interconnection Customer{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date: ]----------------------------------------------------------------
[Attachment A to Appendix 2 Interconnection Feasibility Study
Agreement]
[Assumptions Used in Conducting the Interconnection Feasibility Study]
[The Informational Interconnection Feasibility Study will be
based upon the information set forth in the Interconnection Request
and agreed upon in the Scoping Meeting held on ____:
Designation of Point of Interconnection and configuration to be
studied.
Designation of alternative Point(s) of Interconnection and
configuration.
{Above assumptions to be completed by Interconnection Customer
and other assumptions to be provided by Interconnection Customer and
Transmission Provider{time} ]
Appendix 2[3] to LGIP
[Interconnection System Impact]Cluster Study Agreement
This agreement is made and entered into this day of ______, 20
__ by and between ______, a ______organized and existing under the
laws of the State of ______, (``Interconnection Customer,'') and
______, a ______ organized and existing under the laws of the State
of ______ (``Transmission Provider''). Interconnection Customer and
Transmission Provider each may be referred to as a ``Party,'' or
collectively as the ``Parties.''
Recitals
Whereas, Interconnection Customer is proposing to develop a
Large Generating Facility or generating capacity addition to an
existing Generating Facility consistent with the Interconnection
Request submitted by Interconnection Customer dated ______; and
Whereas, Interconnection Customer desires to interconnect the
Large Generating Facility with the Transmission System;
[Whereas, Transmission Provider has completed an Interconnection
Feasibility Study (the ``[Feasibility] Study'') and provided the
results of said study to Interconnection Customer (This recital to
be omitted if Transmission Provider does not require the
Interconnection Feasibility Study.); and]
Whereas, Interconnection Customer has requested Transmission
Provider to perform [an Interconnection System Impact]a Cluster
Study to assess the impact of interconnecting the Large Generating
Facility to the Transmission System, and of any Affected Systems;
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agreed as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in this LGIP.
2.0 Interconnection Customer elects and Transmission Provider
shall cause to be performed [an Interconnection System Impact]a
Cluster Study consistent with Section 7.0 of this LGIP in accordance
with the Tariff.
16.
3.0 The scope of the [Interconnection System Impact]Cluster
Study shall be subject to the assumptions set forth in Attachment A
to this Agreement.
17.
4.0 The [Interconnection System Impact]Cluster Study will be
based upon the [results of the Interconnection Feasibility Study
and] the technical information provided by Interconnection Customer
in the Interconnection Request, subject to any modifications in
accordance with Section 4.4 of this LGIP. Transmission Provider
reserves the right to request additional technical information from
Interconnection Customer as may reasonably become necessary
consistent with Good Utility Practice during the course of the
[Interconnection Customer System Impact]Cluster Study. [If
Interconnection Customer modifies its designated Point of
Interconnection, Interconnection Request, or the technical
information provided therein, the time to complete the
Interconnection System Impact Study may be extended.]
18.
5.0 The [Interconnection System Impact]Cluster Study
[report]Report shall provide the following information:
--identification of any circuit breaker short circuit capability
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations
resulting from the interconnection;
--identification of any instability or inadequately damped response
to system disturbances resulting from the interconnection; and
--description and non-binding, good faith estimated cost of
facilities required to interconnect the Large Generating Facility to
the Transmission System and to address the identified short circuit,
instability, and power flow issues.
6.0 [Interconnection Customer shall provide a deposit of $50,000
for the performance of the Interconnection System Impact
Study.]Transmission Provider's good faith estimate for the time of
completion of the [Interconnection System Impact]Cluster Study is
{insert date{time} .
[[Page 61293]]
Upon receipt of the [Interconnection System Impact]Cluster Study
Report, Transmission Provider shall charge and Interconnection
Customer shall pay its share of the actual costs of the
[Interconnection System Impact]Cluster Study, consistent with
Section 13.3 of this LGIP.
Any difference between the deposit and the actual cost of the
study shall be paid by or refunded to Interconnection Customer, as
appropriate.
7.0 Miscellaneous. The [Interconnection System Impact]Cluster
Study Agreement shall include standard miscellaneous terms
including, but not limited to, indemnities, representations,
disclaimers, warranties, governing law, amendment, execution,
waiver, enforceability and assignment, that reflect best practices
in the electric industry, that are consistent with regional
practices, Applicable Laws and Regulations and the organizational
nature of each Party. All of these provisions, to the extent
practicable, shall be consistent with the provisions of this LGIP
and LGIA.
In witness thereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
{Insert name of Transmission Provider or Transmission Owner, if
applicable{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of Interconnection Customer{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Attachment A to Appendix 2[3]
[Interconnection System Impact]Cluster Study Agreement
Assumptions Used in Conducting the [Interconnection System
Impact]Cluster Study
The [Interconnection System Impact]Cluster Study will be based
upon the technical information provided by Interconnection Customer
in the Interconnection Request, [results of the Interconnection
Feasibility Study,] subject to any modifications in accordance with
Section 4.4 of this[e] LGIP, and the following assumptions:
Designation of Point of Interconnection and configuration to be
studied.
Designation of alternative Point(s) of Interconnection and
configuration.
{Above assumptions to be completed by Interconnection Customer
and other assumptions to be provided by Interconnection Customer and
Transmission Provider{time}
Appendix 3[4] to LGIP
Interconnection Facilities Study Agreement
This Agreement is made and entered into this__day of_____,
20__by and between_____, a_____organized and existing under the laws
of the State of_____, (``Interconnection Customer,'')
and_____a______ existing under the laws of the State of____,
(``Transmission Provider ''). Interconnection Customer and
Transmission Provider each may be referred to as a ``Party,'' or
collectively as the ``Parties.''
Recitals
Whereas, Interconnection Customer is proposing to develop a
Large Generating Facility or generating capacity addition to an
existing Generating Facility consistent with the Interconnection
Request submitted by Interconnection Customer dated____; and
Whereas, Interconnection Customer desires to interconnect the
Large Generating Facility with the Transmission System;
Whereas, Transmission Provider has completed an Interconnection
[System Impact]Cluster Study (the ``[System Impact]Cluster Study'')
and provided the results of said study to Interconnection Customer;
and
Whereas, Interconnection Customer has requested Transmission
Provider to perform an Interconnection Facilities Study to specify
and estimate the cost of the equipment, engineering, procurement and
construction work needed to implement the conclusions of the
[Interconnection System Impact]Cluster Study in accordance with Good
Utility Practice to physically and electrically connect the Large
Generating Facility to the Transmission System.
Now, therefore, in consideration of and subject to the mutual
covenants contained herein the Parties agreed as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in
Transmission Provider's FERC-approved LGIP.
2.0 Interconnection Customer elects and Transmission Provider
shall cause an Interconnection Facilities Study consistent with
Section 8.0 of this LGIP to be performed in accordance with the
Tariff.
3.0 The scope of the Interconnection Facilities Study shall be
subject to the assumptions set forth in Attachment A and the data
provided in Attachment B to this Agreement.
4.0 The Interconnection Facilities Study [r]Report (i) shall
provide a description, estimated cost of (consistent with Attachment
A), schedule for required facilities to interconnect the Large
Generating Facility to the Transmission System and (ii) shall
address the short circuit, instability, and power flow issues
identified in the [Interconnection System Impact]Cluster Study.
5.0 Interconnection Customer shall provide a Commercial
Readiness Deposit per Section 8.1 of this LGIP to enter [deposit of
$100,000 for the performance of] the Interconnection Facilities
Study. The time for completion of the Interconnection Facilities
Study is specified in Attachment A.
[Transmission Provider shall invoice Interconnection Customer on
a monthly basis for the work to be conducted on the Interconnection
Facilities Study each month. Interconnection Customer shall pay
invoiced amounts within thirty (30) Calendar Days of receipt of
invoice. Transmission Provider shall continue to hold the amounts on
deposit until settlement of the final invoice.]
6.0 Miscellaneous. The Interconnection Facilit[y]ies Study
Agreement shall include standard miscellaneous terms including, but
not limited to, indemnities, representations, disclaimers,
warranties, governing law, amendment, execution, waiver,
enforceability and assignment, that reflect best practices in the
electric industry, and that are consistent with regional practices,
Applicable Laws and Regulations, and the organizational nature of
each Party. All of these provisions, to the extent practicable,
shall be consistent with the provisions of the LGIP and the LGIA.
In witness whereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
[Insert name of Transmission Provider or Transmission Owner, if
applicable]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Attachment A to Appendix 3[4]
Interconnection Facilities Study Agreement
Interconnection Customer Schedule Election for Conducting the
Interconnection Facilities Study
Transmission Provider shall [use Reasonable Efforts to]complete
the study and issue a draft Interconnection Facilities Study
[r]Report to Interconnection Customer within the following number of
days after [of]receipt of an executed copy of this Interconnection
Facilities Study Agreement:
--ninety (90) Calendar Days with no more than a 20
percent cost estimate contained in the report, or
--one hundred eighty (180) Calendar Days with no more than a 10 percent cost estimate contained in the report.
Attachment B to Appendix 3[4] Interconnection Facilities Study
Agreement
Data Form To Be Provided by Interconnection Customer With the
Interconnection Facilities Study Agreement
Provide location plan and simplified one-line diagram of the
plant and station facilities. For staged projects, please indicate
future generation, transmission circuits, etc.
One set of metering is required for each generation connection
to the new ring bus or existing Transmission Provider station.
Number of generation connections:
On the one line diagram indicate the generation capacity
attached at each metering location. (Maximum load on CT/PT)
On the one line diagram indicate the location of auxiliary
power. (Minimum load on CT/PT) Amps
Will an alternate source of auxiliary power be available during
CT/PT maintenance? __Yes __No
Will a transfer bus on the generation side of the metering
require that each meter set be
[[Page 61294]]
designed for the total plant generation? __Yes __No (Please indicate
on one line diagram).
What type of control system or PLC will be located at
Interconnection Customer's Large Generating Facility?
-----------------------------------------------------------------------
What protocol does the control system or PLC use?
-----------------------------------------------------------------------
Please provide a 7.5-minute quadrangle of the site. Sketch the
plant, station, transmission line, and property line.
Physical dimensions of the proposed interconnection station:
-----------------------------------------------------------------------
Bus length from generation to interconnection station:
-----------------------------------------------------------------------
Line length from interconnection station to Transmission
Provider's transmission line.
-----------------------------------------------------------------------
Tower number observed in the field. (Painted on tower leg) *
-----------------------------------------------------------------------
Number of third party easements required for transmission lines
*:
-----------------------------------------------------------------------
* To be completed in coordination with Transmission Provider.
Is the Large Generating Facility in the Transmission Provider's
service area? __Yes __No
Local provider:
-----------------------------------------------------------------------
Please provide proposed schedule dates:
Begin Construction
Date:------------------------------------------------------------------
Generator step-up transformer receives back feed power
Date:------------------------------------------------------------------
Generation Testing
Date:------------------------------------------------------------------
Commercial Operation
Date:------------------------------------------------------------------
Appendix 4[5] to LGIP
Optional Interconnection Study Agreement
This Agreement is made and entered into this__day of______,
20__by and between ______, a ______organized and existing under the
laws of the State of______, (``Interconnection Customer,'') and
______ a ______ existing under the laws of the State of ______,
(``Transmission Provider ''). Interconnection Customer and
Transmission Provider each may be referred to as a ``Party,'' or
collectively as the ``Parties.''
Recitals
Whereas, Interconnection Customer is proposing to develop a
Large Generating Facility or generating capacity addition to an
existing Generating Facility consistent with the Interconnection
Request submitted by Interconnection Customer dated ______;
Whereas, Interconnection Customer is proposing to establish an
interconnection with the Transmission System; and
Whereas, Interconnection Customer has submitted to Transmission
Provider an Interconnection Request; and
Whereas, on or after the date when Interconnection Customer
receives the [Interconnection System Impact] Cluster Study results,
Interconnection Customer has further requested that Transmission
Provider prepare an Optional Interconnection Study;
Now, Therefore, in consideration of and subject to the mutual
covenants contained herein the Parties agree as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in
Transmission Provider's FERC-approved LGIP.
2.0 Interconnection Customer elects and Transmission Provider
shall cause an Optional Interconnection Study consistent with
Section 10.0 of this LGIP to be performed in accordance with the
Tariff.
3.0 The scope of the Optional Interconnection Study shall be
subject to the assumptions set forth in Attachment A to this
Agreement.
4.0 The Optional Interconnection Study shall be performed solely
for informational purposes.
5.0 The Optional Interconnection Study report shall provide a
sensitivity analysis based on the assumptions specified by
Interconnection Customer in Attachment A to this Agreement. The
Optional Interconnection Study will identify Transmission Provider's
Interconnection Facilities and the Network Upgrades, and the
estimated cost thereof, that may be required to provide transmission
service or interconnection service based upon the assumptions
specified by Interconnection Customer in Attachment A.
6.0 Interconnection Customer shall provide a deposit of $10,000
for the performance of the Optional Interconnection Study.
Transmission Provider's good faith estimate for the time of
completion of the Optional Interconnection Study is [insert date].
Upon receipt of the Optional Interconnection Study, Transmission
Provider shall charge and Interconnection Customer shall pay the
actual costs of the Optional Study.
Any difference between the initial payment and the actual cost
of the study shall be paid by or refunded to Interconnection
Customer, as appropriate.
7.0 Miscellaneous. The Optional Interconnection Study Agreement
shall include standard miscellaneous terms including, but not
limited to, indemnities, representations, disclaimers, warranties,
governing law, amendment, execution, waiver, enforceability and
assignment, that reflect best practices in the electric industry,
and that are consistent with regional practices, Applicable Laws and
Regulations, and the organizational nature of each Party. All of
these provisions, to the extent practicable, shall be consistent
with the provisions of the LGIP and the LGIA.
In witness whereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
[Insert name of Transmission Provider or Transmission Owner, if
applicable]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Appendix 5[6] to LGIP
Large Generator Interconnection Agreement (See LGIA)
Appendix 6[7]
Interconnection Procedures for A Wind Generating Plant
Appendix 6[7] sets forth procedures specific to a wind
generating plant. All other requirements of this LGIP continue to
apply to wind generating plant interconnections.
A. Special Procedures Applicable to Wind Generators
The wind plant Interconnection Customer, in completing the
Interconnection Request required by S[s]ection 3.3 of this LGIP, may
provide to the Transmission Provider a set of preliminary electrical
design specifications depicting the wind plant as a single
equivalent generator. Upon satisfying these and other applicable
Interconnection Request conditions, the wind plant may enter the
queue and receive the base case data as provided for in this LGIP.
No later than six months after submitting an Interconnection
Request completed in this manner, the wind plant Interconnection
Customer must submit completed detailed electrical design
specifications and other data (including collector system layout
data) needed to allow the Transmission Provider to complete the
[System Impact]Cluster Study.
Appendix 7 to LGIP
Transitional Cluster Study Agreement
This Agreement is made and entered into this __ day of ______,
20 __ by and between ______, a ______ organized and existing under
the laws of the State of ______ (``Interconnection Customer''), and
______, a ______ organized and existing under the laws of the State
of ______ (``Transmission Provider''). Interconnection Customer and
Transmission Provider each may be referred to as a ``Party,'' or
collectively as the ``Parties.''
Recitals
Whereas, Interconnection Customer is proposing to develop a
Large Generating Facility or generating capacity addition to an
existing Generating Facility consistent with the Interconnection
Request submitted by Interconnection Customer dated ______;
Whereas, Interconnection Customer desires to interconnect the
Large Generating Facility with the Transmission System; and
Whereas, Interconnection Customer has requested Transmission
Provider to perform a ``Transitional Cluster Study,'' which combines
the Cluster Study and Interconnection Facilities Study, in a single
[[Page 61295]]
cluster study, followed by any needed restudies, to specify and
estimate the cost of the equipment, engineering, procurement, and
construction work needed to physically and electrically connect the
Large Generating Facility to Transmission Provider's Transmission
System; and
Whereas, Interconnection Customer has a valid Queue Position as
of the {Transmission Provider to insert effective date of compliance
filing{time} .
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agree as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in this LGIP.
2.0 Interconnection Customer elects, and Transmission Provider
shall cause to be performed, a Transitional Cluster Study.
3.0 The Transitional Cluster Study shall be based upon the
technical information provided by Interconnection Customer in the
Interconnection Request. Transmission Provider reserves the right to
request additional technical information from Interconnection
Customer as may reasonably become necessary consistent with Good
Utility Practice during the course of the Transitional Cluster Study
and Interconnection Customer shall provide such data as quickly as
reasonable.
4.0 Pursuant to Section 5.1.1.2 of this LGIP, the interim
Transitional Cluster Study Report shall provide the information
below:
--identification of any circuit breaker short circuit capability
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations
resulting from the interconnection;
19.
--identification of any instability or inadequately damped response
to system disturbances resulting from the interconnection; and
--Transmission Provider's Interconnection Facilities and Network
Upgrades that are expected to be required as a result of the
Interconnection Request(s) and a non-binding, good faith estimate of
cost responsibility and a non-binding, good faith estimated time to
construct.
5.0 Pursuant to Section 5.1.1.2 of this LGIP, the final
Transitional Cluster Study Report shall: (1) provide all the
information included in the interim Transitional Cluster Study
Report; (2) provide a description of, estimated cost of, and
schedule for required facilities to interconnect the Generating
Facility to the Transmission System; and (3) address the short
circuit, instability, and power flow issues identified in the
interim Transitional Cluster Study Report.
6.0 Interconnection Customer has met the requirements described
in Section 5.1.1.2 of this LGIP.
20.
7.0 Interconnection Customer previously provided a deposit for
the performance of Interconnection Studies. Upon receipt of the
final Transitional Cluster Study Report, Transmission Provider shall
charge and Interconnection Customer shall pay the actual costs of
the Transitional Cluster Study. Any difference between the study
deposit and the actual cost of the study shall be paid by or
refunded to Interconnection Customer, in accordance with the
provisions of Section 13.3 of this LGIP.
8.0 Miscellaneous. The Transitional Cluster Study Agreement
shall include standard miscellaneous terms including, but not
limited to, indemnities, representations, disclaimers, warranties,
governing law, amendment, execution, waiver, enforceability and
assignment, that reflect best practices in the electric industry,
and that are consistent with regional practices, Applicable Laws and
Regulations, and the organizational nature of each Party. All of
these provisions, to the extent practicable, shall be consistent
with the provisions of this LGIP and the LGIA.
In Witness Whereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
{Insert name of Transmission Provider or Transmission Owner, if
applicable{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of Interconnection Customer{time} ------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Appendix 8 to LGIP
Transitional Serial Interconnection Facilities Study Agreement
This Agreement is made and entered into this __ day of ______,
20__, by and between ______, a ______ organized and existing under
the laws of the State of ______(``Interconnection Customer'') and
______, a ______organized and existing under the laws of the State
of ______ (``Transmission Provider''). Interconnection Customer and
Transmission Provider each may be referred to as a ``Party,'' or
collectively as the ``Parties.''
Recitals
Whereas, Interconnection Customer is proposing to develop a
Large Generating Facility or generating capacity addition to an
existing Large Generating Facility consistent with the
Interconnection Request submitted by Interconnection Customer dated
______; and
Whereas, Interconnection Customer desires to interconnect the
Large Generating Facility with the Transmission System; and
Whereas, Interconnection Customer has requested Transmission
Provider to continue processing its Interconnection Facilities Study
to specify and estimate the cost of the equipment, engineering,
procurement, and construction work needed to implement the
conclusions of the final interconnection system impact study (from
the previously effective serial study process) in accordance with
Good Utility Practice to physically and electrically connect the
Large Generating Facility to the Transmission System; and
Whereas, Transmission Provider has provided an Interconnection
Facilities Study Agreement to the Interconnection Customer on or
before {Transmission Provider to insert effective date of compliance
filing{time} .
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agree as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in this LGIP.
2.0 Interconnection Customer elects and Transmission Provider
shall cause to be performed an Interconnection Facilities Study
consistent with Section 8 of this LGIP.
3.0 The scope of the Interconnection Facilities Study shall be
subject to the assumptions set forth in Attachment A to this
Agreement, which shall be the same assumptions as the previous
Interconnection Facilities Study Agreement executed by the
Interconnection Customer.
4.0 The Interconnection Facilities Study Report shall: (1)
provide a description, estimated cost of (consistent with Attachment
A), and schedule for required facilities to interconnect the Large
Generating Facility to the Transmission System; and (2) address the
short circuit, instability, and power flow issues identified in the
most recently published Cluster Study Report.
5.0 Interconnection Customer has met the requirements described
in Section 5.1.1.1 of this LGIP. The time for completion of the
Interconnection Facilities Study is specified in Attachment A, and
shall be no later than 150 Calendar Days after {Transmission
Provider to insert effective date accepted on compliance{time} .
6.0 Interconnection Customer previously provided a deposit of
______ dollars ($ __) for the performance of the Interconnection
Facilities Study.
7.0 Upon receipt of the Interconnection Facilities Study
results, Transmission Provider shall charge and Interconnection
Customer shall pay the actual costs of the Interconnection
Facilities Study.
8.0 Any difference between the study deposit and the actual cost
of the study shall be paid by or refunded to Interconnection
Customer, as appropriate.
9.0 Miscellaneous. The Interconnection Facilities Study
Agreement shall include standard miscellaneous terms including, but
not limited to, indemnities, representations, disclaimers,
warranties, governing law, amendment, execution, waiver,
enforceability and assignment, that reflect best practices in the
electric industry, and that are consistent with regional practices,
Applicable Laws and Regulations, and the organizational nature of
each Party. All of these provisions, to the extent practicable,
shall be consistent with the provisions of this LGIP and this LGIA.
In Witness Whereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
{Insert name of Transmission Provider or Transmission Owner, if
applicable{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of Interconnection Customer{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
[[Page 61296]]
Date:------------------------------------------------------------------
Attachment A to Appendix 8
Transitional Serial Interconnection Facilities Study Agreement
Assumptions Used In Conducting The Transitional Serial Interconnection
Facilities Study
{Assumptions to be completed by Interconnection Customer and
Transmission Provider{time}
Appendix 9 to LGIP
Two-Party Affected System Study Agreement
This Agreement is made and entered into this __ day of ______,
20__, by and between ______, a ______ organized and existing under
the laws of the State of ______ (Affected System Interconnection
Customer) and ______, a ______ organized and existing under the laws
of the State of ______ (Transmission Provider). Affected System
Interconnection Customer and Transmission Provider each may be
referred to as a ``Party,'' or collectively as the ``Parties.''
Recitals
Whereas, Affected System Interconnection Customer is proposing
to develop a {description of generating facility or generating
capacity addition to an existing generating facility{time}
consistent with the interconnection request submitted by Affected
System Interconnection Customer to {name of host transmission
provider{time} , dated ______, for which {name of host transmission
provider{time} found impacts on Transmission Provider's
Transmission System; and
Whereas, Affected System Interconnection Customer desires to
interconnect the {generating facility{time} with {name of host
transmission provider{time} 's transmission system;
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agree as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in this LGIP.
2.0 Transmission Provider shall coordinate with Affected System
Interconnection Customer to perform an Affected System Study
consistent with Section 9 of this LGIP.
3.0 The scope of the Affected System Study shall be subject to
the assumptions set forth in Attachment A to this Agreement.
4.0 The Affected System Study will be based upon the technical
information provided by Affected System Interconnection Customer and
{name of host transmission provider{time} . Transmission Provider
reserves the right to request additional technical information from
Affected System Interconnection Customer as may reasonably become
necessary consistent with Good Utility Practice during the course of
the Affected System Study.
5.0 The Affected System Study shall provide the following
information:
--identification of any circuit breaker short circuit capability
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations
resulting from the interconnection;
--identification of any instability or inadequately damped response
to system disturbances resulting from the interconnection;
--non-binding, good faith estimated cost and time required to
construct facilities required on Transmission Provider's
Transmission System to accommodate the interconnection of the
{generating facility{time} to the transmission system of the host
transmission provider; and
--description of how such facilities will address the identified
short circuit, instability, and power flow issues.
6.0 Affected System Interconnection Customer shall provide a
deposit of __ for performance of the Affected System Study. Upon
receipt of the results of the Affected System Study by the Affected
System Interconnection Customer, Transmission Provider shall charge,
and Affected System Interconnection Customer shall pay, the actual
cost of the Affected System Study. Any difference between the
deposit and the actual cost of the Affected System Study shall be
paid by or refunded to Affected System Interconnection Customer, as
appropriate, including interest calculated in accordance with
section 35.19a(a)(2) of FERC's regulations.
7.0 This Agreement shall include standard miscellaneous terms
including, but not limited to, indemnities, representations,
disclaimers, warranties, governing law, amendment, execution,
waiver, enforceability, and assignment, which reflect best practices
in the electric industry, that are consistent with regional
practices, Applicable Laws and Regulations and the organizational
nature of each Party. All of these provisions, to the extent
practicable, shall be consistent with the provisions of the LGIP.
In witness thereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
{Insert name of Transmission Provider{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of Affected System Interconnection Customer{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Project No.------------------------------------------------------------
Attachment A to Appendix 9--Two-Party Affected System Study Agreement
Assumptions Used In Conducting The Affected System Study
The Affected System Study will be based upon the following
assumptions:
{Assumptions to be completed by Affected System Interconnection
Customer and Transmission Provider{time}
Appendix 10 to LGIP
Multiparty Affected System Study Agreement
This Agreement is made and entered into this __ day of ______,
20__, by and among ______, a ______ organized and existing under the
laws of the State of ______ (Affected System Interconnection
Customer); ______, a ______ organized and existing under the laws of
the State of ______ (Affected System Interconnection Customer); and
______, a ______ organized and existing under the laws of the State
of ______ (Transmission Provider). Affected System Interconnection
Customers and Transmission Provider each may be referred to as a
``Party,'' or collectively as the ``Parties.'' When it is not
important to differentiate among them, Affected System
Interconnection Customers each may be referred to as ``Affected
System Interconnection Customer'' or collectively as the ``Affected
System Interconnection Customers.''
Recitals
Whereas, Affected System Interconnection Customers are proposing
to develop {description of generating facilities or generating
capacity additions to an existing generating facility{time} ,
consistent with the interconnection requests submitted by Affected
System Interconnection Customers to {name of host transmission
provider{time} , dated ______, for which {name of host transmission
provider{time} found impacts on Transmission Provider's
Transmission System; and
Whereas, Affected System Interconnection Customers desire to
interconnect the {generating facilities{time} with {name of host
transmission provider{time} 's transmission system;
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agree as follows:
1.0 When used in this Agreement, with initial capitalization,
the terms specified shall have the meanings indicated in this LGIP.
2.0 Transmission Provider shall coordinate with Affected System
Interconnection Customers to perform an Affected System Study
consistent with Section 9 of this LGIP.
3.0 The scope of the Affected System Study shall be subject to
the assumptions set forth in Attachment A to this Agreement.
4.0 The Affected System Study will be based upon the technical
information provided by Affected System Interconnection Customers
and {name of host transmission provider{time} . Transmission
Provider reserves the right to request additional technical
information from Affected System Interconnection Customers as may
reasonably become necessary consistent with Good Utility Practice
during the course of the Affected System Study.
5.0 The Affected System Study shall provide the following
information:
[[Page 61297]]
--identification of any circuit breaker short circuit capability
limits exceeded as a result of the interconnection;
--identification of any thermal overload or voltage limit violations
resulting from the interconnection;
--identification of any instability or inadequately damped response
to system disturbances resulting from the interconnection;
--non-binding, good faith estimated cost and time required to
construct facilities required on Transmission Provider's
Transmission System to accommodate the interconnection of the
{generating facilities{time} to the transmission system of the host
transmission provider; and
--description of how such facilities will address the identified
short circuit, instability, and power flow issues.
6.0 Affected System Interconnection Customers shall each provide
a deposit of __ for performance of the Affected System Study. Upon
receipt of the results of the Affected System Study by the Affected
System Interconnection Customers, Transmission Provider shall
charge, and Affected System Interconnection Customers shall pay, the
actual cost of the Affected System Study. Any difference between the
deposit and the actual cost of the Affected System Study shall be
paid by or refunded to Affected System Interconnection Customers, as
appropriate, including interest calculated in accordance with
section 35.19a(a)(2) of FERC's regulations.
7.0 This Agreement shall include standard miscellaneous terms
including, but not limited to, indemnities, representations,
disclaimers, warranties, governing law, amendment, execution,
waiver, enforceability, and assignment, which reflect best practices
in the electric industry, that are consistent with regional
practices, Applicable Laws and Regulations, and the organizational
nature of each Party. All of these provisions, to the extent
practicable, shall be consistent with the provisions of the LGIP.
In witness thereof, the Parties have caused this Agreement to be
duly executed by their duly authorized officers or agents on the day
and year first above written.
{Insert name of Transmission Provider{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
{Insert name of Affected System Interconnection Customer{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Project No.------------------------------------------------------------
{Insert name of Affected System Interconnection Customer{time}
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Project No.------------------------------------------------------------
Attachment A to Appendix 10--Multiparty Affected System Study Agreement
Assumptions Used in Conducting the Multiparty Affected System Study
The Affected System Study will be based upon the following
assumptions: {Assumptions to be completed by Affected System
Interconnection Customers and Transmission Provider{time}
Appendix 11 to LGIP
Two-Party Affected System Facilities Construction Agreement
This Agreement is made and entered into this __ day of ______,
20__, by and between ______, organized and existing under the laws
of the State of ______ (Affected System Interconnection Customer)
and ______, an entity organized under the laws of the State of
______ (Transmission Provider). Affected System Interconnection
Customer and Transmission Provider each may be referred to as a
``Party'' or collectively as the ``Parties.''
Recitals
Whereas, Affected System Interconnection Customer is proposing
to develop a {description of generating facility or generating
capacity addition to an existing generating facility{time}
consistent with the interconnection request submitted by Affected
System Interconnection Customer to {name of host transmission
provider{time} , dated ______, for which {name of host transmission
provider{time} found impacts on Transmission Provider's
Transmission System; and
Whereas, Affected System Interconnection Customer desires to
interconnect the {generating facility{time} to {name of host
transmission provider{time} 's transmission system; and
Whereas, additions, modifications, and upgrade(s) must be made
to certain existing facilities of Transmission Provider's
Transmission System to accommodate such interconnection; and
Whereas, Affected System Interconnection Customer has requested,
and Transmission Provider has agreed, to enter into this Agreement
for the purpose of facilitating the construction of necessary
Affected System Network Upgrade(s);
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agree as follows:
Article 1--Definitions
When used in this Agreement, with initial capitalization, the
terms specified and not otherwise defined in this Agreement shall
have the meanings indicated in this LGIP.
Article 2--Term of Agreement
2.1 Effective Date. This Agreement shall become effective upon
execution by the Parties subject to acceptance by FERC (if
applicable), or if filed unexecuted, upon the date specified by
FERC.
2.2 Term.
2.2.1 General. This Agreement shall become effective as provided
in Article 2.1 and shall continue in full force and effect until the
earlier of (1) the final repayment, where applicable, by
Transmission Provider of the amount funded by Affected System
Interconnection Customer for Transmission Provider's design,
procurement, construction and installation of the Affected System
Network Upgrade(s) provided in Appendix A; (2) the Parties agree to
mutually terminate this Agreement; (3) earlier termination is
permitted or provided for under Appendix A of this Agreement; or (4)
Affected System Interconnection Customer terminates this Agreement
after providing Transmission Provider with written notice at least
sixty (60) Calendar Days prior to the proposed termination date,
provided that Affected System Interconnection Customer has no
outstanding contractual obligations to Transmission Provider under
this Agreement. No termination of this Agreement shall be effective
until the Parties have complied with all Applicable Laws and
Regulations applicable to such termination. The term of this
Agreement may be adjusted upon mutual agreement of the Parties if
(1) the commercial operation date for the {generating
facility{time} is adjusted in accordance with the rules and
procedures established by {name of host transmission provider{time}
or (2) the in-service date for the Affected System Network
Upgrade(s) is adjusted in accordance with the rules and procedures
established by Transmission Provider.
2.2.2 Termination Upon Default. Default shall mean the failure
of a Breaching Party to cure its Breach in accordance with Article 5
of this Agreement where Breach and Breaching Party are defined in
Article 5. Defaulting Party shall mean the Party that is in Default.
In the event of a Default by a Party, the non-Defaulting Party shall
have the termination rights described in Articles 5 and 6; provided,
however, Transmission Provider may not terminate this Agreement if
Affected System Interconnection Customer is the Defaulting Party and
compensates Transmission Provider within thirty (30) Calendar Days
for the amount of damages billed to Affected System Interconnection
Customer by Transmission Provider for any such damages, including
costs and expenses, incurred by Transmission Provider as a result of
such Default.
2.2.3 Consequences of Termination. In the event of a termination
by either Party, other than a termination by Affected System
Interconnection Customer due to a Default by Transmission Provider,
Affected System Interconnection Customer shall be responsible for
the payment to Transmission Provider of all amounts then due and
payable for construction and installation of the Affected System
Network Upgrade(s) (including, without limitation, any equipment
ordered related to such construction), plus all out-of-pocket
expenses incurred by Transmission Provider in connection with the
construction and installation of the Affected System Network
Upgrade(s), through the date of termination, and, in the event of
the termination of the entire Agreement, any actual costs which
Transmission Provider reasonably incurs in (1) winding up work and
construction demobilization and (2) ensuring the safety of
[[Page 61298]]
persons and property and the integrity and safe and reliable
operation of Transmission Provider's Transmission System.
Transmission Provider shall use Reasonable Efforts to minimize such
costs.
2.2.4 Reservation of Rights. Transmission Provider shall have
the right to make a unilateral filing with FERC to modify this
Agreement with respect to any rates, terms and conditions, charges,
classifications of service, rule or regulation under section 205 or
any other applicable provision of the Federal Power Act and FERC's
rules and regulations thereunder, and Affected System
Interconnection Customer shall have the right to make a unilateral
filing with FERC to modify this Agreement pursuant to section 206 or
any other applicable provision of the Federal Power Act and FERC's
rules and regulations thereunder; provided that each Party shall
have the right to protest any such filing by the other Party and to
participate fully in any proceeding before FERC in which such
modifications may be considered. Nothing in this Agreement shall
limit the rights of the Parties or of FERC under sections 205 or 206
of the Federal Power Act and FERC's rules and regulations
thereunder, except to the extent that the Parties otherwise mutually
agree as provided herein.
2.3 Filing. Transmission Provider shall file this Agreement (and
any amendment hereto) with the appropriate Governmental Authority,
if required. Affected System Interconnection Customer may request
that any information so provided be subject to the confidentiality
provisions of Article 8. If Affected System Interconnection Customer
has executed this Agreement, or any amendment thereto, Affected
System Interconnection Customer shall reasonably cooperate with
Transmission Provider with respect to such filing and to provide any
information reasonably requested by Transmission Provider needed to
comply with applicable regulatory requirements.
2.4 Survival. This Agreement shall continue in effect after
termination, to the extent necessary, to provide for final billings
and payments and for costs incurred hereunder, including billings
and payments pursuant to this Agreement; to permit the determination
and enforcement of liability and indemnification obligations arising
from acts or events that occurred while this Agreement was in
effect; and to permit each Party to have access to the lands of the
other Party pursuant to this Agreement or other applicable
agreements, to disconnect, remove, or salvage its own facilities and
equipment.
2.5 Termination Obligations. Upon any termination pursuant to
this Agreement, Affected System Interconnection Customer shall be
responsible for the payment of all costs or other contractual
obligations incurred prior to the termination date, including
previously incurred capital costs, penalties for early termination,
and costs of removal and site restoration.
Article 3--Construction of Affected System Network Upgrade(s)
3.1 Construction.
3.1.1 Transmission Provider Obligations. Transmission Provider
shall (or shall cause such action to) design, procure, construct,
and install, and Affected System Interconnection Customer shall pay,
consistent with Article 3.2, the costs of all Affected System
Network Upgrade(s) identified in Appendix A. All Affected System
Network Upgrade(s) designed, procured, constructed, and installed by
Transmission Provider pursuant to this Agreement shall satisfy all
requirements of applicable safety and/or engineering codes and
comply with Good Utility Practice, and further, shall satisfy all
Applicable Laws and Regulations. Transmission Provider shall not be
required to undertake any action which is inconsistent with its
standard safety practices, its material and equipment
specifications, its design criteria and construction procedures, its
labor agreements, or any Applicable Laws and Regulations.
3.1.2 Suspension of Work.
3.1.2.1 Right to Suspend. Affected System Interconnection
Customer must provide to Transmission Provider written notice of its
request for suspension. Only the milestones described in the
Appendices of this Agreement are subject to suspension under this
Article 3.1.2. Affected System Network Upgrade(s) will be
constructed on the schedule described in the Appendices of this
Agreement unless: (1) construction is prevented by the order of a
Governmental Authority; (2) the Affected System Network Upgrade(s)
are not needed by any other Interconnection Customer; or (3)
Transmission Provider determines that a Force Majeure event prevents
construction. In the event of (1), (2), or (3), any security paid to
Transmission Provider under Article 4.1 of this Agreement shall be
released by Transmission Provider upon the determination by
Transmission Provider that the Affected System Network Upgrade(s)
will no longer be constructed. If suspension occurs, Affected System
Interconnection Customer shall be responsible for the costs which
Transmission Provider incurs (i) in accordance with this Agreement
prior to the suspension; (ii) in suspending such work, including any
costs incurred to perform such work as may be necessary to ensure
the safety of persons and property and the integrity of Transmission
Provider's Transmission System and, if applicable, any costs
incurred in connection with the cancellation of contracts and orders
for material which Transmission Provider cannot reasonably avoid;
and (iii) reasonably incurs in winding up work and construction
demobilization; provided, however, that, prior to canceling any such
contracts or orders, Transmission Provider shall obtain Affected
System Interconnection Customer's authorization. Affected System
Interconnection Customer shall be responsible for all costs incurred
in connection with Affected System Interconnection Customer's
failure to authorize cancellation of such contracts or orders.
Interest on amounts paid by Affected System Interconnection
Customer to Transmission Provider for the design, procurement,
construction, and installation of the Affected System Network
Upgrade(s) shall not accrue during periods in which Affected System
Interconnection Customer has suspended construction under this
Article 3.1.2.
Transmission Provider shall invoice Affected System
Interconnection Customer pursuant to Article 4 and will use
Reasonable Efforts to minimize its costs. In the event Affected
System Interconnection Customer suspends work by Affected System
Transmission Provider required under this Agreement pursuant to this
Article 3.1.2.1, and has not requested Affected System Transmission
Provider to recommence the work required under this Agreement on or
before the expiration of three (3) years following commencement of
such suspension, this Agreement shall be deemed terminated. The
three-year period shall begin on the date the suspension is
requested, or the date of the written notice to Affected System
Transmission Provider, whichever is earlier, if no effective date of
suspension is specified.
3.1.2.2 Recommencing of Work. If Affected System Interconnection
Customer requests that Transmission Provider recommence construction
of Affected System Network Upgrade(s), Transmission Provider shall
have no obligation to afford such work the priority it would have
had but for the prior actions of Affected System Interconnection
Customer to suspend the work. In such event, Affected System
Interconnection Customer shall be responsible for any costs incurred
in recommencing the work. All recommenced work shall be completed
pursuant to an amended schedule for the interconnection agreed to by
the Parties. Transmission Provider has the right to conduct a
restudy of the Affected System Study if conditions have materially
changed subsequent to the request to suspend. Affected System
Interconnection Customer shall be responsible for the costs of any
studies or restudies required.
3.1.2.3 Right to Suspend Due to Default. Transmission Provider
reserves the right, upon written notice to Affected System
Interconnection Customer, to suspend, at any time, work by
Transmission Provider due to Default by Affected System
Interconnection Customer. Affected System Interconnection Customer
shall be responsible for any additional expenses incurred by
Transmission Provider associated with the construction and
installation of the Affected System Network Upgrade(s) (as set forth
in Article 2.2.3) upon the occurrence of either a Breach that
Affected System Interconnection Customer is unable to cure-pursuant
to Article 5 or a Default pursuant to Article 5. Any form of
suspension by Transmission Provider shall not be barred by Articles
2.2.2, 2.2.3, or 5.2.2, nor shall it affect Transmission Provider's
right to terminate the work or this Agreement pursuant to Article 6.
3.1.3 Construction Status. Transmission Provider shall keep
Affected System Interconnection Customer advised periodically as to
the progress of its design, procurement and construction efforts, as
described in Appendix A. Affected System Interconnection Customer
may, at any time
[[Page 61299]]
and reasonably, request a progress report from Transmission
Provider. If, at any time, Affected System Interconnection Customer
determines that the completion of the Affected System Network
Upgrade(s) will not be required until after the specified in-service
date, Affected System Interconnection Customer will provide written
notice to Transmission Provider of such later date upon which the
completion of the Affected System Network Upgrade(s) would be
required. Transmission Provider may delay the in-service date of the
Affected System Network Upgrade(s) accordingly.
3.1.4 Timely Completion. Transmission Provider shall use
Reasonable Efforts to design, procure, construct, install, and test
the Affected System Network Upgrade(s) in accordance with the
schedule set forth in Appendix A, which schedule may be revised from
time to time by mutual agreement of the Parties. If any event occurs
that will affect the time or ability to complete the Affected System
Network Upgrade(s), Transmission Provider shall promptly notify
Affected System Interconnection Customer. In such circumstances,
Transmission Provider shall, within fifteen (15) Calendar Days of
such notice, convene a meeting with Affected System Interconnection
Customer to evaluate the alternatives available to Affected System
Interconnection Customer. Transmission Provider shall also make
available to Affected System Interconnection Customer all studies
and work papers related to the event and corresponding delay,
including all information that is in the possession of Transmission
Provider that is reasonably needed by Affected System
Interconnection Customer to evaluate alternatives, subject to
confidentiality arrangements consistent with Article 8. Transmission
Provider shall, at Affected System Interconnection Customer's
request and expense, use Reasonable Efforts to accelerate its work
under this Agreement to meet the schedule set forth in Appendix A,
provided that (1) Affected System Interconnection Customer
authorizes such actions, such authorization to be withheld,
conditioned, or delayed by Affected System Interconnection Customer
only if it can demonstrate that the acceleration would have a
material adverse effect on it; and (2) the Affected System
Interconnection Customer funds costs associated therewith in
advance.
3.2 Interconnection Costs.
3.2.1 Costs. Affected System Interconnection Customer shall pay
to Transmission Provider costs (including taxes and financing costs)
associated with seeking and obtaining all necessary approvals and of
designing, engineering, constructing, and testing the Affected
System Network Upgrade(s), as identified in Appendix A, in
accordance with the cost recovery method provided herein. Unless
Transmission Provider elects to fund the Affected System Network
Upgrade(s), they shall be initially funded by Affected System
Interconnection Customer.
3.2.1.1 Lands of Other Property Owners. If any part of the
Affected System Network Upgrade(s) is to be installed on property
owned by persons other than Affected System Interconnection Customer
or Transmission Provider, Transmission Provider shall, at Affected
System Interconnection Customer's expense, use efforts similar in
nature and extent to those that it typically undertakes on its own
behalf or on behalf of its Affiliates, including use of its eminent
domain authority to the extent permitted and consistent with
Applicable Laws and Regulations and, to the extent consistent with
such Applicable Laws and Regulations, to procure from such persons
any rights of use, licenses, rights-of-way, and easements that are
necessary to construct, operate, maintain, test, inspect, replace,
or remove the Affected System Network Upgrade(s) upon such property.
3.2.2 Repayment.
3.2.2.1 Repayment. Consistent with Articles 11.4.1 and 11.4.2 of
the Transmission Provider's pro forma LGIA, Affected System
Interconnection Customer shall be entitled to a cash repayment by
Transmission Provider of the amount paid to Transmission Provider,
if any, for the Affected System Network Upgrade(s), including any
tax gross-up or other tax-related payments associated with the
Affected System Network Upgrade(s), and not refunded to Affected
System Interconnection Customer pursuant to Article 3.3.1 or
otherwise. The Parties may mutually agree to a repayment schedule,
to be outlined in Appendix A, not to exceed twenty (20) years from
the commercial operation date, for the complete repayment for all
applicable costs associated with the Affected System Network
Upgrade(s). Any repayment shall include interest calculated in
accordance with the methodology set forth in FERC's regulations at
18 CFR 35.19 a(a)(2)(iii) from the date of any payment for Affected
System Network Upgrade(s) through the date on which Affected System
Interconnection Customer receives a repayment of such payment
pursuant to this subparagraph. Interest shall not accrue during
periods in which Affected System Interconnection Customer has
suspended construction pursuant to Article 3.1.2. Affected System
Interconnection Customer may assign such repayment rights to any
person.
3.2.2.2 Impact of Failure to Achieve Commercial Operation. If
the Affected System Interconnection Customer's generating facility
fails to achieve commercial operation, but it or another generating
facility is later constructed and makes use of the Affected System
Network Upgrade(s), Transmission Provider shall at that time
reimburse Affected System Interconnection Customer for the amounts
advanced for the Affected System Network Upgrade(s). Before any such
reimbursement can occur, Affected System Interconnection Customer
(or the entity that ultimately constructs the generating facility,
if different), is responsible for identifying the entity to which
the reimbursement must be made.
3.3 Taxes.
3.3.1 Indemnification for Contributions in Aid of Construction.
With regard only to payments made by Affected System Interconnection
Customer to Transmission Provider for the installation of the
Affected System Network Upgrade(s), Transmission Provider shall not
include a gross-up for income taxes in the amounts it charges
Affected System Interconnection Customer for the installation of the
Affected System Network Upgrade(s) unless (1) Transmission Provider
has determined, in good faith, that the payments or property
transfers made by Affected System Interconnection Customer to
Transmission Provider should be reported as income subject to
taxation, or (2) any Governmental Authority directs Transmission
Provider to report payments or property as income subject to
taxation. Affected System Interconnection Customer shall reimburse
Transmission Provider for such costs on a fully grossed-up basis, in
accordance with this Article, within thirty (30) Calendar Days of
receiving written notification from Transmission Provider of the
amount due, including detail about how the amount was calculated.
The indemnification obligation shall terminate at the earlier of
(1) the expiration of the ten (10)-year testing period and the
applicable statute of limitation, as it may be extended by
Transmission Provider upon request of the Internal Revenue Service,
to keep these years open for audit or adjustment, or (2) the
occurrence of a subsequent taxable event and the payment of any
related indemnification obligations as contemplated by this Article.
Notwithstanding the foregoing provisions of this Article 3.3.1, and
to the extent permitted by law, to the extent that the receipt of
such payments by Transmission Provider is determined by any
Governmental Authority to constitute income by Transmission Provider
subject to taxation, Affected System Interconnection Customer shall
protect, indemnify, and hold harmless Transmission Provider and its
Affiliates, from all claims by any such Governmental Authority for
any tax, interest, and/or penalties associated with such
determination. Upon receiving written notification of such
determination from the Governmental Authority, Transmission Provider
shall provide Affected System Interconnection Customer with written
notification within thirty (30) Calendar Days of such determination
and notification. Transmission Provider, upon the timely written
request by Affected System Interconnection Customer and at Affected
System Interconnection Customer's expense, shall appeal, protest,
seek abatement of, or otherwise oppose such determination.
Transmission Provider reserves the right to make all decisions with
regard to the prosecution of such appeal, protest, abatement or
other contest, including the compromise or settlement of the claim;
provided that Transmission Provider shall cooperate and consult in
good faith with Affected System Interconnection Customer regarding
the conduct of such contest. Affected System Interconnection
Customer shall not be required to pay Transmission Provider for the
tax, interest, and/or penalties prior to the seventh (7th) Calendar
Day before the date on which Transmission Provider (1) is required
to pay the tax, interest, and/or penalties or other amount in lieu
thereof pursuant to a compromise or settlement of the appeal,
protest, abatement, or other contest; (2) is required to pay the
tax, interest, and/or penalties as the result of a
[[Page 61300]]
final, non-appealable order by a Governmental Authority; or (3) is
required to pay the tax, interest, and/or penalties as a
prerequisite to an appeal, protest, abatement, or other contest. In
the event such appeal, protest, abatement, or other contest results
in a determination that Transmission Provider is not liable for any
portion of any tax, interest, and/or penalties for which Affected
System Interconnection Customer has already made payment to
Transmission Provider, Transmission Provider shall promptly refund
to Affected System Interconnection Customer any payment attributable
to the amount determined to be non-taxable, plus any interest
(calculated in accordance with 18 CFR 35.19a(a)(2)(iii)) or other
payments Transmission Provider receives or which Transmission
Provider may be entitled with respect to such payment. Affected
System Interconnection Customer shall provide Transmission Provider
with credit assurances sufficient to meet Affected System
Interconnection Customer's estimated liability for reimbursement of
Transmission Provider for taxes, interest, and/or penalties under
this Article 3.3.1. Such estimated liability shall be stated in
Appendix A.
To the extent that Transmission Provider is a limited liability
company and not a corporation, and has elected to be taxed as a
partnership, then the following shall apply: Transmission Provider
represents, and the Parties acknowledge, that Transmission Provider
is a limited liability company and is treated as a partnership for
federal income tax purposes. Any payment made by Affected System
Interconnection Customer to Transmission Provider for Affected
System Network Upgrade(s) is to be treated as an upfront payment. It
is anticipated by the Parties that any amounts paid by Affected
System Interconnection Customer to Transmission Provider for
Affected System Network Upgrade(s) will be reimbursed to Affected
System Interconnection Customer in accordance with the terms of this
Agreement, provided Affected System Interconnection Customer
fulfills its obligations under this Agreement.
3.3.2 Private Letter Ruling. At Affected System Interconnection
Customer's request and expense, Transmission Provider shall file
with the Internal Revenue Service a request for a private letter
ruling as to whether any property transferred or sums paid, or to be
paid, by Affected System Interconnection Customer to Transmission
Provider under this Agreement are subject to federal income
taxation. Affected System Interconnection Customer will prepare the
initial draft of the request for a private letter ruling and will
certify under penalties of perjury that all facts represented in
such request are true and accurate to the best of Affected System
Interconnection Customer's knowledge. Transmission Provider and
Affected System Interconnection Customer shall cooperate in good
faith with respect to the submission of such request.
3.3.3 Other Taxes. Upon the timely request by Affected System
Interconnection Customer, and at Affected System Interconnection
Customer's sole expense, Transmission Provider shall appeal,
protest, seek abatement of, or otherwise contest any tax (other than
federal or state income tax) asserted or assessed against
Transmission Provider for which Affected System Interconnection
Customer may be required to reimburse Transmission Provider under
the terms of this Agreement. Affected System Interconnection
Customer shall pay to Transmission Provider on a periodic basis, as
invoiced by Transmission Provider, Transmission Provider's
documented reasonable costs of prosecuting such appeal, protest,
abatement, or other contest. Affected System Interconnection
Customer and Transmission Provider shall cooperate in good faith
with respect to any such contest. Unless the payment of such taxes
is a prerequisite to an appeal or abatement or cannot be deferred,
no amount shall be payable by Affected System Interconnection
Customer to Transmission Provider for such taxes until they are
assessed by a final, non-appealable order by any court or agency of
competent jurisdiction. In the event that a tax payment is withheld
and ultimately due and payable after appeal, Affected System
Interconnection Customer will be responsible for all taxes, interest
and penalties, other than penalties attributable to any delay caused
by Transmission Provider. Each Party shall cooperate with the other
Party to maintain each Party's tax status. Nothing in this Agreement
is intended to adversely affect any Party's tax-exempt status with
respect to the issuance of bonds including, but not limited to,
local furnishing bonds, as described in section 142(f) of the
Internal Revenue Code.
Article 4
Security, Billing, and Payments
4.1 Provision of Security. By the earlier of (1) thirty (30)
Calendar Days prior to the due date for Affected System
Interconnection Customer's first payment under the payment schedule
specified in Appendix A, or (2) the first date specified in Appendix
A for the ordering of equipment by Transmission Provider for
installing the Affected System Network Upgrade(s), Affected System
Interconnection Customer shall provide Transmission Provider, at
Affected System Interconnection Customer's option, a guarantee, a
surety bond, letter of credit or other form of security that is
reasonably acceptable to Transmission Provider. Such security for
payment shall be in an amount sufficient to cover the costs for
constructing, procuring, and installing the applicable portion of
Affected System Network Upgrade(s) and shall be reduced on a dollar-
for-dollar basis for payments made to Transmission Provider for
these purposes.
The guarantee must be made by an entity that meets the
creditworthiness requirements of Transmission Provider and contain
terms and conditions that guarantee payment of any amount that may
be due from Affected System Interconnection Customer, up to an
agreed-to maximum amount. The letter of credit must be issued by a
financial institution reasonably acceptable to Transmission Provider
and must specify a reasonable expiration date. The surety bond must
be issued by an insurer reasonably acceptable to Transmission
Provider and must specify a reasonable expiration date.
4.2 Invoice. Each Party shall submit to the other Party, on a
monthly basis, invoices of amounts due, if any, for the preceding
month. Each invoice shall state the month to which the invoice
applies and fully describe the services and equipment provided. The
Parties may discharge mutual debts and payment obligations due and
owing to each other on the same date through netting, in which case
all amounts a Party owes to the other Party under this Agreement,
including interest payments, shall be netted so that only the net
amount remaining due shall be paid by the owing Party.
4.3 Payment. Invoices shall be rendered to the paying Party at
the address specified by the Parties. The Party receiving the
invoice shall pay the invoice within thirty (30) Calendar Days of
receipt. All payments shall be made in immediately available funds
payable to the other Party, or by wire transfer to a bank named and
account designated by the invoicing Party. Payment of invoices by a
Party will not constitute a waiver of any rights or claims that
Party may have under this Agreement.
4.4 Final Invoice. Within six (6) months after completion of the
construction of the Affected System Network Upgrade(s), Transmission
Provider shall provide an invoice of the final cost of the
construction of the Affected System Network Upgrade(s) and shall set
forth such costs in sufficient detail to enable Affected System
Interconnection Customer to compare the actual costs with the
estimates and to ascertain deviations, if any, from the cost
estimates. Transmission Provider shall refund, with interest
(calculated in accordance with 18 CFR 35.19a(a)(2)(iii)), to
Affected System Interconnection Customer any amount by which the
actual payment by Affected System Interconnection Customer for
estimated costs exceeds the actual costs of construction within
thirty (30) Calendar Days of the issuance of such final construction
invoice.
4.5 Interest. Interest on any unpaid amounts shall be calculated
in accordance with 18 CFR 35.19a(a)(2)(iii).
4.6 Payment During Dispute. In the event of a billing dispute
among the Parties, Transmission Provider shall continue to construct
the Affected System Network Upgrade(s) under this Agreement as long
as Affected System Interconnection Customer: (1) continues to make
all payments not in dispute; and (2) pays to Transmission Provider
or into an independent escrow account the portion of the invoice in
dispute, pending resolution of such dispute. If Affected System
Interconnection Customer fails to meet these two requirements, then
Transmission Provider may provide notice to Affected System
Interconnection Customer of a Default pursuant to Article 5. Within
thirty (30) Calendar Days after the resolution of the dispute, the
Party that owes money to another Party shall pay the amount due with
interest calculated in accordance with the methodology set forth in
18 CFR 35.19a(a)(2)(iii).
Article 5
Breach, Cure and Default
5.1 Events of Breach. A Breach of this Agreement shall include
the:
[[Page 61301]]
(a) Failure to pay any amount when due;
(b) Failure to comply with any material term or condition of
this Agreement, including but not limited to any material Breach of
a representation, warranty, or covenant made in this Agreement;
(c) Failure of a Party to provide such access rights, or a
Party's attempt to revoke access or terminate such access rights, as
provided under this Agreement; or
(d) Failure of a Party to provide information or data to another
Party as required under this Agreement, provided the Party entitled
to the information or data under this Agreement requires such
information or data to satisfy its obligations under this Agreement.
5.2 Definition. Breaching Party shall mean the Party that is in
Breach.
5.3 Notice of Breach, Cure, and Default. Upon the occurrence of
an event of Breach, the Party not in Breach, when it becomes aware
of the Breach, shall give written notice of the Breach to the
Breaching Party and to any other person representing a Party to this
Agreement identified in writing to the other Party in advance. Such
notice shall set forth, in reasonable detail, the nature of the
Breach, and where known and applicable, the steps necessary to cure
such Breach.
5.3.1 Upon receiving written notice of the Breach hereunder, the
Breaching Party shall have a period to cure such Breach (hereinafter
referred to as the ``Cure Period'') which shall be sixty (60)
Calendar Days.
5.3.2 In the event the Breaching Party fails to cure within the
Cure Period, the Breaching Party will be in Default of this
Agreement, and the non--Defaulting Party may terminate this
Agreement in accordance with Article 6.2 of this Agreement or take
whatever action at law or in equity as may appear necessary or
desirable to enforce the performance or observance of any rights,
remedies, obligations, agreement, or covenants under this Agreement.
5.4 Rights in the Event of Default. Notwithstanding the
foregoing, upon the occurrence of a Default, the non-Defaulting
Party shall be entitled to exercise all rights and remedies it may
have in equity or at law.
Article 6
Termination of Agreement
6.1 Expiration of Term. Except as otherwise specified in this
Article 6, the Parties' obligations under this Agreement shall
terminate at the conclusion of the term of this Agreement.
6.2 Termination. In addition to the termination provisions set
forth in Article 2.2, a Party may terminate this Agreement upon the
Default of the other Party in accordance with Article 5.2.2 of this
Agreement. Subject to the limitations set forth in Article 6.3, in
the event of a Default, the termination of this Agreement by the
non-Defaulting Party shall require a filing at FERC of a notice of
termination, which filing must be accepted for filing by FERC.
6.3 Disposition of Facilities Upon Termination of Agreement.
6.3.1 Transmission Provider Obligations. Upon termination of
this Agreement, unless otherwise agreed to by the Parties in
writing, Transmission Provider:
(a) shall, prior to the construction and installation of any
portion of the Affected System Network Upgrade(s) and to the extent
possible, cancel any pending orders of, or return, such equipment or
material for such Affected System Network Upgrade(s);
(b) may keep in place any portion of the Affected System Network
Upgrade(s) already constructed and installed; and,
(c) shall perform such work as may be necessary to ensure the
safety of persons and property and to preserve the integrity of
Transmission Provider's Transmission System (e.g., construction
demobilization to return the system to its original state, wind-up
work).
6.3.2 Affected System Interconnection Customer Obligations. Upon
billing by Transmission Provider, Affected System Interconnection
Customer shall reimburse Transmission Provider for any costs
incurred by Transmission Provider in performance of the actions
required or permitted by Article 6.3.1 and for the cost of any
Affected System Network Upgrade(s) described in Appendix A.
Transmission Provider shall use Reasonable Efforts to minimize costs
and shall offset the amounts owed by any salvage value of
facilities, if applicable. Affected System Interconnection Customer
shall pay these costs pursuant to Article 4.3 of this Agreement.
6.3.3 Pre-construction or Installation. Upon termination of this
Agreement and prior to the construction and installation of any
portion of the Affected System Network Upgrade(s), Transmission
Provider may, at its option, retain any portion of such Affected
System Network Upgrade(s) not cancelled or returned in accordance
with Article 6.3.1(a), in which case Transmission Provider shall be
responsible for all costs associated with procuring such Affected
System Network Upgrade(s). To the extent that Affected System
Interconnection Customer has already paid Transmission Provider for
any or all of such costs, Transmission Provider shall refund
Affected System Interconnection Customer for those payments. If
Transmission Provider elects to not retain any portion of such
facilities, Transmission Provider shall convey and make available to
Affected System Interconnection Customer such facilities as soon as
practicable after Affected System Interconnection Customer's payment
for such facilities.
6.4 Survival of Rights. Termination or expiration of this
Agreement shall not relieve either Party of any of its liabilities
and obligations arising hereunder prior to the date termination
becomes effective, and each Party may take whatever judicial or
administrative actions as appear necessary or desirable to enforce
its rights hereunder. The applicable provisions of this Agreement
will continue in effect after expiration, or early termination
hereof to the extent necessary to provide for (1) final billings,
billing adjustments, and other billing procedures set forth in this
Agreement; (2) the determination and enforcement of liability and
indemnification obligations arising from acts or events that
occurred while this Agreement was in effect; and (3) the
confidentiality provisions set forth in Article 8.
Article 7
Subcontractors
7.1 Subcontractors. Nothing in this Agreement shall prevent a
Party from utilizing the services of subcontractors, as it deems
appropriate, to perform its obligations under this Agreement;
provided, however, that each Party shall require its subcontractors
to comply with all applicable terms and conditions of this Agreement
in providing such services, and each Party shall remain primarily
liable to the other Party for the performance of such subcontractor.
7.1.1 Responsibility of Principal. The creation of any
subcontract relationship shall not relieve the hiring Party of any
of its obligations under this Agreement. In accordance with the
provisions of this Agreement, each Party shall be fully responsible
to the other Party for the acts or omissions of any subcontractor it
hires as if no subcontract had been made. Any applicable obligation
imposed by this Agreement upon a Party shall be equally binding
upon, and shall be construed as having application to, any
subcontractor of such Party.
7.1.2 No Third-Party Beneficiary. Except as may be specifically
set forth to the contrary herein, no subcontractor or any other
party is intended to be, nor will it be deemed to be, a third-party
beneficiary of this Agreement.
7.1.3 No Limitation by Insurance. The obligations under this
Article 7 will not be limited in any way by any limitation of any
insurance policies or coverages, including any subcontractor's
insurance.
Article 8
Confidentiality
8.1 Confidentiality. Confidential Information shall include,
without limitation, all information relating to a Party's
technology, research and development, business affairs, and pricing,
and any information supplied to the other Party prior to the
execution of this Agreement.
Information is Confidential Information only if it is clearly
designated or marked in writing as confidential on the face of the
document, or, if the information is conveyed orally or by
inspection, if the Party providing the information orally informs
the Party receiving the information that the information is
confidential. The Parties shall maintain as confidential any
information that is provided and identified by a Party as Critical
Energy Infrastructure Information (CEII), as that term is defined in
18 CFR 388.113(c).
Such confidentiality will be maintained in accordance with this
Article 8. If requested by the receiving Party, the disclosing Party
shall provide in writing, the basis for asserting that the
information referred to in this Article warrants confidential
treatment, and the requesting Party may disclose such writing to the
appropriate Governmental Authority. Each Party shall be responsible
for the costs associated with affording confidential treatment to
its information.
8.1.1 Term. During the term of this Agreement, and for a period
of three (3) years after the expiration or termination of this
[[Page 61302]]
Agreement, except as otherwise provided in this Article 8 or with
regard to CEII, each Party shall hold in confidence and shall not
disclose to any person Confidential Information. CEII shall be
treated in accordance with FERC policies and regulations.
8.1.2 Scope. Confidential Information shall not include
information that the receiving Party can demonstrate: (1) is
generally available to the public other than as a result of a
disclosure by the receiving Party; (2) was in the lawful possession
of the receiving Party on a non-confidential basis before receiving
it from the disclosing Party; (3) was supplied to the receiving
Party without restriction by a non-Party, who, to the knowledge of
the receiving Party after due inquiry, was under no obligation to
the disclosing Party to keep such information confidential; (4) was
independently developed by the receiving Party without reference to
Confidential Information of the disclosing Party; (5) is, or
becomes, publicly known, through no wrongful act or omission of the
receiving Party or Breach of this Agreement; or (6) is required, in
accordance with Article 8.1.6 of this Agreement, to be disclosed by
any Governmental Authority or is otherwise required to be disclosed
by law or subpoena, or is necessary in any legal proceeding
establishing rights and obligations under this Agreement.
Information designated as Confidential Information will no longer be
deemed confidential if the Party that designated the information as
confidential notifies the receiving Party that it no longer is
confidential.
8.1.3 Release of Confidential Information. No Party shall
release or disclose Confidential Information to any other person,
except to its Affiliates (limited by the Standards of Conduct
requirements), subcontractors, employees, agents, consultants, or to
non-Parties that may be or are considering providing financing to or
equity participation with Affected System Interconnection Customer,
or to potential purchasers or assignees of Affected System
Interconnection Customer, on a need-to-know basis in connection with
this Agreement, unless such person has first been advised of the
confidentiality provisions of this Article 8 and has agreed to
comply with such provisions. Notwithstanding the foregoing, a Party
providing Confidential Information to any person shall remain
primarily responsible for any release of Confidential Information in
contravention of this Article 8.
8.1.4 Rights. Each Party shall retain all rights, title, and
interest in the Confidential Information that it discloses to the
receiving Party. The disclosure by a Party to the receiving Party of
Confidential Information shall not be deemed a waiver by the
disclosing Party or any other person or entity of the right to
protect the Confidential Information from public disclosure.
8.1.5 Standard of Care. Each Party shall use at least the same
standard of care to protect Confidential Information it receives as
it uses to protect its own Confidential Information from
unauthorized disclosure, publication, or dissemination. Each Party
may use Confidential Information solely to fulfill its obligations
to the other Party under this Agreement or its regulatory
requirements.
8.1.6 Order of Disclosure. If a court or a Government Authority
or entity with the right, power, and apparent authority to do so
requests or requires either Party, by subpoena, oral deposition,
interrogatories, requests for production of documents,
administrative order, or otherwise, to disclose Confidential
Information, that Party shall provide the disclosing Party with
prompt notice of such request(s) or requirement(s) so that the
disclosing Party may seek an appropriate protective order or waive
compliance with the terms of this Agreement. Notwithstanding the
absence of a protective order or waiver, the Party may disclose such
Confidential Information which, in the opinion of its counsel, the
Party is legally compelled to disclose. Each Party will use
Reasonable Efforts to obtain reliable assurance that confidential
treatment will be accorded any Confidential Information so
furnished.
8.1.7 Termination of Agreement. Upon termination of this
Agreement for any reason, each Party shall, within ten (10) Business
Days of receipt of a written request from the other Party, use
Reasonable Efforts to destroy, erase, or delete (with such
destruction, erasure, and deletion certified in writing to the
requesting Party) or return to the requesting Party any and all
written or electronic Confidential Information received from the
requesting Party, except that each Party may keep one copy for
archival purposes, provided that the obligation to treat it as
Confidential Information in accordance with this Article 8 shall
survive such termination.
8.1.8 Remedies. The Parties agree that monetary damages would be
inadequate to compensate a Party for the other Party's Breach of its
obligations under this Article 8. Each Party accordingly agrees that
the disclosing Party shall be entitled to equitable relief, by way
of injunction or otherwise, if the receiving Party Breaches or
threatens to Breach its obligations under this Article 8, which
equitable relief shall be granted without bond or proof of damages,
and the breaching Party shall not plead in defense that there would
be an adequate remedy at law. Such remedy shall not be deemed an
exclusive remedy for the Breach of this Article 8, but it shall be
in addition to all other remedies available at law or in equity. The
Parties further acknowledge and agree that the covenants contained
herein are necessary for the protection of legitimate business
interests and are reasonable in scope. Neither Party, however, shall
be liable for indirect, incidental, or consequential or punitive
damages of any nature or kind resulting from or arising in
connection with this Article 8.
8.1.9 Disclosure to FERC, its Staff, or a State Regulatory Body.
Notwithstanding anything in this Article 8 to the contrary, and
pursuant to 18 CFR 1b.20, if FERC or its staff, during the course of
an investigation or otherwise, requests information from a Party
that is otherwise required to be maintained in confidence pursuant
to this Agreement, the Party shall provide the requested information
to FERC or its staff, within the time provided for in the request
for information. In providing the information to FERC or its staff,
the Party must, consistent with 18 CFR 388.112, request that the
information be treated as confidential and non-public by FERC and
its staff and that the information be withheld from public
disclosure. Parties are prohibited from notifying the other Party to
this Agreement prior to the release of the Confidential Information
to FERC or its staff. The Party shall notify the other Party to the
Agreement when it is notified by FERC or its staff that a request to
release Confidential Information has been received by FERC, at which
time either of the Parties may respond before such information would
be made public, pursuant to 18 CFR 388.112. Requests from a state
regulatory body conducting a confidential investigation shall be
treated in a similar manner if consistent with the applicable state
rules and regulations.
8.1.10 Subject to the exception in Article 8.1.9, any
information that a disclosing Party claims is competitively
sensitive, commercial, or financial information under this Agreement
shall not be disclosed by the receiving Party to any person not
employed or retained by the receiving Party, except to the extent
disclosure is (1) required by law; (2) reasonably deemed by the
disclosing Party to be required to be disclosed in connection with a
dispute between or among the Parties, or the defense of litigation
or dispute; (3) otherwise permitted by consent of the disclosing
Party, such consent not to be unreasonably withheld; or (4)
necessary to fulfill its obligations under this Agreement or as the
Transmission Provider or a balancing authority, including disclosing
the Confidential Information to a regional or national reliability
organization. The Party asserting confidentiality shall notify the
receiving Party in writing of the information that Party claims is
confidential. Prior to any disclosures of that Party's Confidential
Information under this subparagraph, or if any non-Party or
Governmental Authority makes any request or demand for any of the
information described in this subparagraph, the Party that received
the Confidential Information from the disclosing Party agrees to
promptly notify the disclosing Party in writing and agrees to assert
confidentiality and cooperate with the disclosing Party in seeking
to protect the Confidential Information from public disclosure by
confidentiality agreement, protective order, or other reasonable
measures.
Article 9
Information Access and Audit Rights
9.1 Information Access. Each Party shall make available to the
other Party information necessary to verify the costs incurred by
the other Party for which the requesting Party is responsible under
this Agreement and carry out obligations and responsibilities under
this Agreement, provided that the Parties shall not use such
information for purposes other than those set forth in this Article
9.1 and to enforce their rights under this Agreement.
9.2 Audit Rights. Subject to the requirements of confidentiality
under Article
[[Page 61303]]
8 of this Agreement, the accounts and records related to the design,
engineering, procurement, and construction of the Affected System
Network Upgrade(s) shall be subject to audit during the period of
this Agreement and for a period of twenty-four (24) months following
Transmission Provider's issuance of a final invoice in accordance
with Article 4.4. Affected System Interconnection Customer at its
expense shall have the right, during normal business hours, and upon
prior reasonable notice to Transmission Provider, to audit such
accounts and records. Any audit authorized by this Article 9.2 shall
be performed at the offices where such accounts and records are
maintained and shall be limited to those portions of such accounts
and records that relate to obligations under this Agreement.
Article 10
Notices
10.1 General. Any notice, demand, or request required or
permitted to be given by a Party to the other Party, and any
instrument required or permitted to be tendered or delivered by a
Party in writing to another Party, may be so given, tendered, or
delivered, as the case may be, by depositing the same with the
United States Postal Service with postage prepaid, for transmission
by certified or registered mail, addressed to the Parties, or
personally delivered to the Parties, at the address set out below:
To Transmission Provider:
To Affected System Interconnection Customer:
10.2 Billings and Payments. Billings and payments shall be sent
to the addresses shown in Article 10.1 unless otherwise agreed to by
the Parties.
10.3 Alternative Forms of Notice. Any notice or request required
or permitted to be given by a Party to the other Party and not
required by this Agreement to be given in writing may be so given by
telephone, facsimile or email to the telephone numbers and email
addresses set out below:
To Transmission Provider:
To Affected System Interconnection Customer:
10.4 Execution and Filing. Affected System Interconnection
Customer shall either: (i) execute two originals of this tendered
Agreement and return them to Transmission Provider; or (ii) request
in writing that Transmission Provider file with FERC this Agreement
in unexecuted form. As soon as practicable, but not later than ten
(10) Business Days after receiving either the two executed originals
of this tendered Agreement (if it does not conform with a FERC-
approved standard form of this Agreement) or the request to file
this Agreement unexecuted, Transmission Provider shall file this
Agreement with FERC, together with its explanation of any matters as
to which Affected System Interconnection Customer and Transmission
Provider disagree and support for the costs that Transmission
Provider proposes to charge to Affected System Interconnection
Customer under this Agreement. An unexecuted version of this
Agreement should contain terms and conditions deemed appropriate by
Transmission Provider for the Affected System Interconnection
Customer's generating facility. If the Parties agree to proceed with
design, procurement, and construction of facilities and upgrades
under the agreed-upon terms of the unexecuted version of this
Agreement, they may proceed pending FERC action.
Article 11
Miscellaneous
11.1 This Agreement shall include standard miscellaneous terms
including, but not limited to, indemnities, representations,
disclaimers, warranties, governing law, amendment, execution,
waiver, enforceability and assignment, which reflect best practices
in the electric industry, that are consistent with regional
practices, Applicable Laws and Regulations and the organizational
nature of each Party. All of these provisions, to the extent
practicable, shall be consistent with the provisions of this LGIP.
[Signature Page to Follow]
In witness whereof, the Parties have executed this Agreement in
multiple originals, each of which shall constitute and be an
original Agreement among the Parties.
Transmission Provider
{Transmission Provider{time}
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------
Affected System Interconnection Customer
{Affected System Interconnection Customer{time}
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------
Project No.__
Attachment A to Appendix 11
Two-Party Affected System Facilities Construction Agreement
Affected System Network Upgrade(s), Cost Estimates and Responsibility,
Construction Schedule and Monthly Payment Schedule
This Appendix A is a part of the Affected System Facilities
Construction Agreement between Affected System Interconnection
Customer and Transmission Provider.
1.1 Affected System Network Upgrade(s) to be installed by
Transmission Provider.
{description{time}
1.2 First Equipment Order (including permitting).
{description{time}
1.2.1. Permitting and Land Rights--Transmission Provider
Affected System Network Upgrade(s)
{description{time}
1.3 Construction Schedule. Where applicable, construction of the
Affected System Network Upgrade(s) is scheduled as follows and will
be periodically updated as necessary:
Table 1--Transmission Provider Construction Activities
------------------------------------------------------------------------
Start
Milestone number Description date End date
------------------------------------------------------------------------
------------------------------------------------------------------------
------------------------------------------------------------------------
------------------------------------------------------------------------
------------------------------------------------------------------------
------------------------------------------------------------------------
[[Page 61304]]
Note: Construction schedule assumes that Transmission Provider
has obtained final authorizations and security from Affected System
Interconnection Customer and all necessary permits from Governmental
Authorities as necessary prerequisites to commence construction of
any of the Affected System Network Upgrade(s).
1.4 Payment Schedule.
1.4.1 Timing of and Adjustments to Affected System
Interconnection Customer's Payments and Security.
{description{time}
1.4.2 Monthly Payment Schedule. Affected System Interconnection
Customer's payment schedule is as follows.
{description{time}
Table 2--Affected System Interconnection Customer's Payment/Security
Obligations for Affected System Network Upgrade(s).
------------------------------------------------------------------------
Milestone number Description Date
------------------------------------------------------------------------
.......................
.......................
.......................
.......................
.......................
------------------------------------------------------------------------
Note: Affected System Interconnection Customer's payment or
provision of security as provided in this Agreement operates as a
condition precedent to Transmission Provider's obligations to
construct any Affected System Network Upgrade(s), and failure to
meet this schedule will constitute a Breach pursuant to Article 5.1
of this Agreement.
1.5 Permits, Licenses, and Authorizations.
{description{time}
Attachment B to Appendix 11
Two-Party Affected System Facilities Construction Agreement
Notification of Completed Construction
This Appendix B is a part of the Affected System Facilities
Construction Agreement between Affected System Interconnection
Customer and Transmission Provider. Where applicable, when
Transmission Provider has completed construction of the Affected
System Network Upgrade(s), Transmission Provider shall send notice
to Affected System Interconnection Customer in substantially the
form following:
{Date{time}
{Affected System Interconnection Customer Address{time}
Re: Completion of Affected System Network Upgrade(s)
Dear {Name or Title{time} :
This letter is sent pursuant to the Affected System Facilities
Construction Agreement between {Transmission Provider{time} and
{Affected System Interconnection Customer{time} , dated ______,
20__.
On {Date{time} , Transmission Provider completed to its
satisfaction all work on the Affected System Network Upgrade(s)
required to facilitate the safe and reliable interconnection and
operation of Affected System Interconnection Customer's {description
of generating facility{time} . Transmission Provider confirms that
the Affected System Network Upgrade(s) are in place.
Thank you.
{Signature{time}
{Transmission Provider Representative{time}
Attachment C to Appendix 11
Two-Party Affected System Facilities Construction Agreement
Exhibits
This Appendix C is a part of the Affected System Facilities
Construction Agreement among Affected System Interconnection
Customer and Transmission Provider.
Exhibit A1
Transmission Provider Site Map
Exhibit A2
Site Plan
Exhibit A3
Affected System Network Upgrade(s) Plan & Profile
Exhibit A4
Estimated Cost of Affected System Network Upgrade(s)
------------------------------------------------------------------------
Facilities to
be constructed Estimate in
Location by transmission dollars
provider
------------------------------------------------------------------------
Total:
------------------------------------------------------------------------
Appendix 12 to LGIP
Multiparty Affected System Facilities Construction Agreement
This agreement is made and entered into this ____ day of _____,
20__ by and among ________, organized and existing under the laws of
the State of _____ (Affected System Interconnection Customer);
_____, a _____ organized and existing under the laws of the State of
_____ (Affected System Interconnection Customer); and _____, an
entity organized under the laws of the State of ____ (Transmission
Provider). Affected System Interconnection Customers and
Transmission Provider each may be referred to as a ``Party'' or
collectively as the ``Parties.'' When it is not important to
differentiate among them, Affected System Interconnection Customers
each may be referred to as ``Affected System Interconnection
Customer'' or collectively as ``Affected System Interconnection
Customers.''
Recitals
Whereas, Affected System Interconnection Customers are proposing
to develop {description of generating facilities or generating
capacity additions to an existing generating facility{time} ,
consistent with the interconnection requests submitted by Affected
System Interconnection Customers to {name of host transmission
provider{time} , dated ____, for which {name of host transmission
provider{time} found impacts on Transmission Provider's
Transmission System; and
Whereas, Affected System Interconnection Customers desire to
interconnect the {generating facilities{time} to {name of host
transmission provider{time} 's transmission system; and
Whereas, additions, modifications, and upgrade(s) must be made
to certain existing facilities of Transmission Provider's
Transmission System to accommodate such interconnection; and
Whereas, Affected System Interconnection Customers have
requested, and Transmission Provider has agreed, to enter into this
Agreement for the purpose of facilitating the construction of
necessary Affected System Network Upgrade(s);
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, the Parties agree as follows:
Article 1
Definitions
When used in this Agreement, with initial capitalization, the
terms specified and not otherwise defined in this Agreement shall
have the meanings indicated in this LGIP.
Article 2
Term of Agreement
2.1 Effective Date. This Agreement shall become effective upon
execution by the Parties subject to acceptance by FERC (if
applicable), or if filed unexecuted, upon the date specified by
FERC.
2.2 Term.
2.2.1 General. This Agreement shall become effective as provided
in Article 2.1 and shall continue in full force and effect until the
earlier of (1) the final repayment, where applicable, by
Transmission Provider of the amount funded by Affected System
Interconnection Customers for Transmission Provider's design,
procurement, construction, and installation of the Affected System
Network Upgrade(s) provided in Appendix A; (2) the Parties agree to
mutually terminate this Agreement; (3) earlier termination is
permitted or provided for under Appendix A of this Agreement; or (4)
Affected System Interconnection Customers terminate this Agreement
after providing Transmission Provider with written notice at least
sixty (60) Calendar Days prior to the proposed termination date,
provided that Affected System Interconnection Customers have no
outstanding contractual obligations to Transmission Provider under
this Agreement. No termination of this Agreement shall be effective
until the Parties have complied with all Applicable Laws and
Regulations applicable to such termination. The term of this
Agreement may be adjusted upon mutual agreement of the Parties if
the commercial operation date(s) for the {generating
facilities{time} is adjusted in accordance with the rules and
procedures established by {name of host transmission provider{time}
or the in-service
[[Page 61305]]
date for the Affected System Network Upgrade(s) is adjusted in
accordance with the rules and procedures established by Transmission
Provider.
2.2.2 Termination Upon Default. Default shall mean the failure
of a Breaching Party to cure its Breach in accordance with Article 5
of this Agreement where Breach and Breaching Party are defined in
Article 5. Defaulting Party shall mean the Party that is in Default.
In the event of a Default by a Party, each non-Defaulting Party
shall have the termination rights described in Articles 5 and 6;
provided, however, Transmission Provider may not terminate this
Agreement if an Affected System Interconnection Customer is the
Defaulting Party and compensates Transmission Provider within thirty
(30) Calendar Days for the amount of damages billed to Affected
System Interconnection Customer(s) by Transmission Provider for any
such damages, including costs and expenses incurred by Transmission
Provider as a result of such Default. Notwithstanding the foregoing,
Default by one or more Affected System Interconnection Customers
shall not provide the other Affected System Interconnection
Customer(s), either individually or in concert, with the right to
terminate the entire Agreement. The non-Defaulting Party/Parties
may, individually or in concert, initiate the removal of an Affected
System Interconnection Customer that is a Defaulting Party from this
Agreement. Transmission Provider shall not terminate this Agreement
or the participation of any Affected System Interconnection Customer
without provision being made for Transmission Provider to be fully
reimbursed for all of its costs incurred under this Agreement.
2.2.3 Consequences of Termination. In the event of a termination
by a Party, other than a termination by Affected System
Interconnection Customer(s) due to a Default by Transmission
Provider, each Affected System Interconnection Customer whose
participation in this Agreement is terminated shall be responsible
for the payment to Transmission Provider of all amounts then due and
payable for construction and installation of the Affected System
Network Upgrade(s) (including, without limitation, any equipment
ordered related to such construction), plus all out-of-pocket
expenses incurred by Transmission Provider in connection with the
construction and installation of the Affected System Network
Upgrade(s), through the date of termination, and, in the event of
the termination of the entire Agreement, any actual costs which
Transmission Provider reasonably incurs in (1) winding up work and
construction demobilization and (2) ensuring the safety of persons
and property and the integrity and safe and reliable operation of
Transmission Provider's Transmission System. Transmission Provider
shall use Reasonable Efforts to minimize such costs. The cost
responsibility of other Affected System Interconnection Customers
shall be adjusted, as necessary, based on the payments by an
Affected System Interconnection Customer that is terminated from the
Agreement.
2.2.4 Reservation of Rights. Transmission Provider shall have
the right to make a unilateral filing with FERC to modify this
Agreement with respect to any rates, terms and conditions, charges,
classifications of service, rule or regulation under section 205 or
any other applicable provision of the Federal Power Act and FERC's
rules and regulations thereunder, and Affected System
Interconnection Customers shall have the right to make a unilateral
filing with FERC to modify this Agreement pursuant to section 206 or
any other applicable provision of the Federal Power Act and FERC's
rules and regulations thereunder; provided that each Party shall
have the right to protest any such filing by the other Party and to
participate fully in any proceeding before FERC in which such
modifications may be considered. Nothing in this Agreement shall
limit the rights of the Parties or of FERC under sections 205 or 206
of the Federal Power Act and FERC's rules and regulations
thereunder, except to the extent that the Parties otherwise mutually
agree as provided herein.
2.3 Filing. Transmission Provider shall file this Agreement (and
any amendment hereto) with the appropriate Governmental Authority,
if required. Affected System Interconnection Customers may request
that any information so provided be subject to the confidentiality
provisions of Article 8. Each Affected System Interconnection
Customer that has executed this Agreement, or any amendment thereto,
shall reasonably cooperate with Transmission Provider with respect
to such filing and to provide any information reasonably requested
by Transmission Provider needed to comply with applicable regulatory
requirements.
2.4 Survival. This Agreement shall continue in effect after
termination, to the extent necessary, to provide for final billings
and payments and for costs incurred hereunder, including billings
and payments pursuant to this Agreement; to permit the determination
and enforcement of liability and indemnification obligations arising
from acts or events that occurred while this Agreement was in
effect; and to permit each Party to have access to the lands of the
other Party pursuant to this Agreement or other applicable
agreements, to disconnect, remove, or salvage its own facilities and
equipment.
2.5 Termination Obligations. Upon any termination pursuant to
this Agreement or termination of the participation in this Agreement
of an Affected System Interconnection Customer, each Affected System
Interconnection Customer shall be responsible for the payment of its
proportionate share of all costs or other contractual obligations
incurred prior to the termination date, including previously
incurred capital costs, penalties for early termination, and costs
of removal and site restoration. The cost responsibility of the
other Affected System Interconnection Customers shall be adjusted as
necessary.
Article 3
Construction of Affected System Network Upgrade(s)
3.1 Construction.
3.1.1 Transmission Provider Obligations. Transmission Provider
shall (or shall cause such action to) design, procure, construct,
and install, and Affected System Interconnection Customers shall
pay, consistent with Article 3.2, the costs of all Affected System
Network Upgrade(s) identified in Appendix A. All Affected System
Network Upgrade(s) designed, procured, constructed, and installed by
Transmission Provider pursuant to this Agreement shall satisfy all
requirements of applicable safety and/or engineering codes and
comply with Good Utility Practice, and further, shall satisfy all
Applicable Laws and Regulations. Transmission Provider shall not be
required to undertake any action which is inconsistent with its
standard safety practices, its material and equipment
specifications, its design criteria and construction procedures, its
labor agreements, or any Applicable Laws and Regulations.
3.1.2 Suspension of Work.
3.1.2.1 Right to Suspend. Affected System Interconnection
Customers must jointly provide to Transmission Provider written
notice of their request for suspension. Only the milestones
described in the Appendices of this Agreement are subject to
suspension under this Article 3.1.2. Affected System Network
Upgrade(s) will be constructed on the schedule described in the
Appendices of this Agreement unless: (1) construction is prevented
by the order of a Governmental Authority; (2) the Affected System
Network Upgrade(s) are not needed by any other Interconnection
Customer; or (3) Transmission Provider determines that a Force
Majeure event prevents construction. In the event of (1), (2), or
(3), any security paid to Transmission Provider under Article 4.1 of
this Agreement shall be released by Transmission Provider upon the
determination by Transmission Provider that the Affected System
Network Upgrade(s) will no longer be constructed. If suspension
occurs, Affected System Interconnection Customers shall be
responsible for the costs which Transmission Provider incurs (i) in
accordance with this Agreement prior to the suspension; (ii) in
suspending such work, including any costs incurred to perform such
work as may be necessary to ensure the safety of persons and
property and the integrity of Transmission Provider's Transmission
System and, if applicable, any costs incurred in connection with the
cancellation of contracts and orders for material which Transmission
Provider cannot reasonably avoid; and (iii) reasonably incurs in
winding up work and construction demobilization; provided, however,
that, prior to canceling any such contracts or orders, Transmission
Provider shall obtain Affected System Interconnection Customers'
authorization. Affected System Interconnection Customers shall be
responsible for all costs incurred in connection with Affected
System Interconnection Customers' failure to authorize cancellation
of such contracts or orders.
Interest on amounts paid by Affected System Interconnection
Customers to Transmission Provider for the design, procurement,
construction, and installation of the Affected System Network
Upgrade(s) shall not accrue during periods in which
[[Page 61306]]
Affected System Interconnection Customers have suspended
construction under this Article 3.1.2.
Transmission Provider shall invoice Affected System
Interconnection Customers pursuant to Article 4 and will use
Reasonable Efforts to minimize its costs. In the event Affected
System Interconnection Customers suspend work by Affected System
Transmission Provider required under this Agreement pursuant to this
Article 3.1.2.1, and have not requested Affected System Transmission
Provider to recommence the work required under this Agreement on or
before the expiration of three (3) years following commencement of
such suspension, this Agreement shall be deemed terminated. The
three-year period shall begin on the date the suspension is
requested, or the date of the written notice to Affected System
Transmission Provider, whichever is earlier, if no effective date of
suspension is specified.
3.1.2.2 Recommencing of Work. If Affected System Interconnection
Customers request that Transmission Provider recommence construction
of Affected System Network Upgrade(s), Transmission Provider shall
have no obligation to afford such work the priority it would have
had but for the prior actions of Affected System Interconnection
Customers to suspend the work. In such event, Affected System
Interconnection Customers shall be responsible for any costs
incurred in recommencing the work. All recommenced work shall be
completed pursuant to an amended schedule for the interconnection
agreed to by the Parties. Transmission Provider has the right to
conduct a restudy of the Affected System Study if conditions have
materially changed subsequent to the request to suspend. Affected
System Interconnection Customers shall be responsible for the costs
of any studies or restudies required.
3.1.2.3 Right to Suspend Due to Default. Transmission Provider
reserves the right, upon written notice to Affected System
Interconnection Customers, to suspend, at any time, work by
Transmission Provider due to a Default by Affected System
Interconnection Customer(s). Defaulting-Affected System
Interconnection Customer(s) shall be responsible for any additional
expenses incurred by Transmission Provider associated with the
construction and installation of the Affected System Network
Upgrade(s) (as set forth in Article 2.2.3) upon the occurrence of a
Default pursuant to Article 5. Any form of suspension by
Transmission Provider shall not be barred by Articles 2.2.2, 2.2.3,
or 5.2.2, nor shall it affect Transmission Provider's right to
terminate the work or this Agreement pursuant to Article 6.
3.1.3 Construction Status. Transmission Provider shall keep
Affected System Interconnection Customers advised periodically as to
the progress of its design, procurement, and construction efforts,
as described in Appendix A. An Affected System Interconnection
Customer may, at any time and reasonably, request a progress report
from Transmission Provider. If, at any time, an Affected System
Interconnection Customer determines that the completion of the
Affected System Network Upgrade(s) will not be required until after
the specified in-service date, such Affected System Interconnection
Customer will provide written notice to all other Parties of such
later date for which the completion of the Affected System Network
Upgrade(s) would be required. Transmission Provider may delay the
in-service date of the Affected System Network Upgrade(s)
accordingly, but only if agreed to by all other Affected System
Interconnection Customers.
3.1.4 Timely Completion. Transmission Provider shall use
Reasonable Efforts to design, procure, construct, install, and test
the Affected System Network Upgrade(s) in accordance with the
schedule set forth in Appendix A, which schedule may be revised from
time to time by mutual agreement of the Parties. If any event occurs
that will affect the time or ability to complete the Affected System
Network Upgrade(s), Transmission Provider shall promptly notify all
other Parties. In such circumstances, Transmission Provider shall,
within fifteen (15) Calendar Days of such notice, convene a meeting
with Affected System Interconnection Customers to evaluate the
alternatives available to Affected System Interconnection Customers.
Transmission Provider shall also make available to Affected System
Interconnection Customers all studies and work papers related to the
event and corresponding delay, including all information that is in
the possession of Transmission Provider that is reasonably needed by
Affected System Interconnection Customers to evaluate alternatives,
subject to confidentiality arrangements consistent with Article 8.
Transmission Provider shall, at any Affected System Interconnection
Customer's request and expense, use Reasonable Efforts to accelerate
its work under this Agreement to meet the schedule set forth in
Appendix A, provided that (1) Affected System Interconnection
Customers jointly authorize such actions, such authorizations to be
withheld, conditioned, or delayed by a given Affected System
Interconnection Customer only if it can demonstrate that the
acceleration would have a material adverse effect on it; and (2) the
requesting Affected System Interconnection Customer(s) funds the
costs associated therewith in advance, or all Affected System
Interconnection Customers agree in advance to fund such costs based
on such other allocation method as they may adopt.
3.2 Interconnection Costs.
3.2.1 Costs. Affected System Interconnection Customers shall pay
to Transmission Provider costs (including taxes and financing costs)
associated with seeking and obtaining all necessary approvals and of
designing, engineering, constructing, and testing the Affected
System Network Upgrade(s), as identified in Appendix A, in
accordance with the cost recovery method provided herein. Except as
expressly otherwise agreed, Affected System Interconnection
Customers shall be collectively responsible for these costs, based
on their proportionate share of cost responsibility, as provided in
Appendix A. Unless Transmission Provider elects to fund the Affected
System Network Upgrade(s), they shall be initially funded by the
applicable Affected System Interconnection Customer.
3.2.1.1 Lands of Other Property Owners. If any part of the
Affected System Network Upgrade(s) is to be installed on property
owned by persons other than Affected System Interconnection
Customers or Transmission Provider, Transmission Provider shall, at
Affected System Interconnection Customers' expense, use efforts
similar in nature and extent to those that it typically undertakes
on its own behalf or on behalf of its Affiliates, including use of
its eminent domain authority to the extent permitted and consistent
with Applicable Laws and Regulations and, to the extent consistent
with such Applicable Laws and Regulations, to procure from such
persons any rights of use, licenses, rights-of-way, and easements
that are necessary to construct, operate, maintain, test, inspect,
replace, or remove the Affected System Network Upgrade(s) upon such
property.
3.2.2 Repayment.
3.2.2.1 Repayment. Consistent with articles 11.4.1 and 11.4.2 of
the Transmission Provider's pro forma LGIA, each Affected System
Interconnection Customer shall be entitled to a cash repayment by
Transmission Provider of the amount each Affected System
Interconnection Customer paid to Transmission Provider, if any, for
the Affected System Network Upgrade(s), including any tax gross-up
or other tax-related payments associated with the Affected System
Network Upgrade(s), and not refunded to Affected System
Interconnection Customer pursuant to Article 3.3.1 or otherwise. The
Parties may mutually agree to a repayment schedule, to be outlined
in Appendix A, not to exceed twenty (20) years from the commercial
operation date, for the complete repayment for all applicable costs
associated with the Affected System Network Upgrade(s). Any
repayment shall include interest calculated in accordance with the
methodology set forth in FERC's regulations at 18 CFR 35.19
a(a)(2)(iii) from the date of any payment for Affected System
Network Upgrade(s) through the date on which Affected System
Interconnection Customers receive a repayment of such payment
pursuant to this subparagraph. Interest shall not accrue during
periods in which Affected System Interconnection Customers have
suspended construction pursuant to Article 3.1.2.1. Affected System
Interconnection Customers may assign such repayment rights to any
person.
3.2.2.2 Impact of Failure to Achieve Commercial Operation. If an
Affected System Interconnection Customer's generating facility fails
to achieve commercial operation, but it or another generating
facility is later constructed and makes use of the Affected System
Network Upgrade(s), Transmission Provider shall at that time
reimburse such Affected System Interconnection Customers for the
portion of the Affected System Network Upgrade(s) it funded. Before
any such reimbursement can occur, Affected System Interconnection
Customer (or the entity that ultimately constructs the generating
facility, if different),
[[Page 61307]]
is responsible for identifying the entity to which the reimbursement
must be made.
3.3 Taxes.
3.3.1 Indemnification for Contributions in Aid of Construction.
With regard only to payments made by Affected System Interconnection
Customers to Transmission Provider for the installation of the
Affected System Network Upgrade(s), Transmission Provider shall not
include a gross-up for income taxes in the amounts it charges
Affected System Interconnection Customers for the installation of
the Affected System Network Upgrade(s) unless (1) Transmission
Provider has determined, in good faith, that the payments or
property transfers made by Affected System Interconnection Customers
to Transmission Provider should be reported as income subject to
taxation, or (2) any Governmental Authority directs Transmission
Provider to report payments or property as income subject to
taxation. Affected System Interconnection Customers shall reimburse
Transmission Provider for such costs on a fully grossed-up basis, in
accordance with this Article, within thirty (30) Calendar Days of
receiving written notification from Transmission Provider of the
amount due, including detail about how the amount was calculated.
The indemnification obligation shall terminate at the earlier of
(1) the expiration of the ten (10)-year testing period and the
applicable statute of limitation, as it may be extended by
Transmission Provider upon request of the Internal Revenue Service,
to keep these years open for audit or adjustment, or (2) the
occurrence of a subsequent taxable event and the payment of any
related indemnification obligations as contemplated by this Article.
Notwithstanding the foregoing provisions of this Article 3.3.1, and
to the extent permitted by law, to the extent that the receipt of
such payments by Transmission Provider is determined by any
Governmental Authority to constitute income by Transmission Provider
subject to taxation, Affected System Interconnection Customers shall
protect, indemnify, and hold harmless Transmission Provider and its
Affiliates, from all claims by any such Governmental Authority for
any tax, interest, and/or penalties associated with such
determination. Upon receiving written notification of such
determination from the Governmental Authority, Transmission Provider
shall provide Affected System Interconnection Customers with written
notification within thirty (30) Calendar Days of such determination
and notification. Transmission Provider, upon the timely written
request by any one or more Affected System Interconnection
Customer(s) and at the expense of such Affected System
Interconnection Customer(s), shall appeal, protest, seek abatement
of, or otherwise oppose such determination. Transmission Provider
reserves the right to make all decisions with regard to the
prosecution of such appeal, protest, abatement or other contest,
including the compromise or settlement of the claim; provided that
Transmission Provider shall cooperate and consult in good faith with
the requesting Affected System Interconnection Customer(s) regarding
the conduct of such contest. Affected System Interconnection
Customer(s) shall not be required to pay Transmission Provider for
the tax, interest, and/or penalties prior to the seventh (7th)
Calendar Day before the date on which Transmission Provider (1) is
required to pay the tax, interest, and/or penalties or other amount
in lieu thereof pursuant to a compromise or settlement of the
appeal, protest, abatement, or other contest; (2) is required to pay
the tax, interest, and/or penalties as the result of a final, non-
appealable order by a Governmental Authority; or (3) is required to
pay the tax, interest, and/or penalties as a prerequisite to an
appeal, protest, abatement, or other contest. In the event such
appeal, protest, abatement, or other contest results in a
determination that Transmission Provider is not liable for any
portion of any tax, interest, and/or penalties for which any
Affected System Interconnection Customer(s) has already made payment
to Transmission Provider, Transmission Provider shall promptly
refund to such Affected System Interconnection Customer(s) any
payment attributable to the amount determined to be non-taxable,
plus any interest (calculated in accordance with 18 CFR
35.19a(a)(2)(iii)) or other payments Transmission Provider receives
or to which Transmission Provider may be entitled with respect to
such payment. Each Affected System Interconnection Customer shall
provide Transmission Provider with credit assurances sufficient to
meet each Affected System Interconnection Customer's estimated
liability for reimbursement of Transmission Provider for taxes,
interest, and/or penalties under this Article 3.3.1. Such estimated
liability shall be stated in Appendix A.
To the extent that Transmission Provider is a limited liability
company and not a corporation, and has elected to be taxed as a
partnership, then the following shall apply: Transmission Provider
represents, and the Parties acknowledge, that Transmission Provider
is a limited liability company and is treated as a partnership for
federal income tax purposes. Any payment made by Affected System
Interconnection Customers to Transmission Provider for Affected
System Network Upgrade(s) is to be treated as an upfront payment. It
is anticipated by the Parties that any amounts paid by each Affected
System Interconnection Customer to Transmission Provider for
Affected System Network Upgrade(s) will be reimbursed to such
Affected System Interconnection Customer in accordance with the
terms of this Agreement, provided such Affected System
Interconnection Customer fulfills its obligations under this
Agreement.
3.3.2 Private Letter Ruling. At the request and expense of any
Affected System Interconnection Customer(s), Transmission Provider
shall file with the Internal Revenue Service a request for a private
letter ruling as to whether any property transferred or sums paid,
or to be paid, by such Affected System Interconnection Customer(s)
to Transmission Provider under this Agreement are subject to federal
income taxation. Each Affected System Interconnection Customer
desiring such a request will prepare the initial draft of the
request for a private letter ruling and will certify under penalties
of perjury that all facts represented in such request are true and
accurate to the best of such Affected System Interconnection
Customer's knowledge. Transmission Provider and such Affected System
Interconnection Customer(s) shall cooperate in good faith with
respect to the submission of such request.
3.3.3 Other Taxes. Upon the timely request by any one or more
Affected System Interconnection Customer(s), and at such Affected
System Interconnection Customer(s)' sole expense, Transmission
Provider shall appeal, protest, seek abatement of, or otherwise
contest any tax (other than federal or state income tax) asserted or
assessed against Transmission Provider for which such Affected
System Interconnection Customer(s) may be required to reimburse
Transmission Provider under the terms of this Agreement. Affected
System Interconnection Customer(s) who requested the action shall
pay to Transmission Provider on a periodic basis, as invoiced by
Transmission Provider, Transmission Provider's documented reasonable
costs of prosecuting such appeal, protest, abatement, or other
contest. The requesting Affected System Interconnection Customer(s)
and Transmission Provider shall cooperate in good faith with respect
to any such contest. Unless the payment of such taxes is a
prerequisite to an appeal or abatement or cannot be deferred, no
amount shall be payable by Affected System Interconnection
Customer(s) to Transmission Provider for such taxes until they are
assessed by a final, non-appealable order by any court or agency of
competent jurisdiction. In the event that a tax payment is withheld
and ultimately due and payable after appeal, Affected System
Interconnection Customer(s) will be responsible for all taxes,
interest, and penalties, other than penalties attributable to any
delay caused by Transmission Provider. Each Party shall cooperate
with the other Party to maintain each Party's tax status. Nothing in
this Agreement is intended to adversely affect any Party's tax-
exempt status with respect to the issuance of bonds including, but
not limited to, local furnishing bonds, as described in section
142(f) of the Internal Revenue Code.
Article 4
Security, Billing, and Payments
4.1 Provision of Security. By the earlier of (1) thirty (30)
Calendar Days prior to the due date for each Affected System
Interconnection Customer's first payment under the payment schedule
specified in Appendix A, or (2) the first date specified in Appendix
A for the ordering of equipment by Transmission Provider for
installing the Affected System Network Upgrade(s), each Affected
System Interconnection Customer shall provide Transmission Provider,
at each Affected System Interconnection Customer's option, a
guarantee, a surety bond, letter of credit, or other form of
security that is reasonably acceptable to Transmission Provider.
Such security for payment shall be in an amount sufficient to cover
the costs for constructing, procuring, and installing the applicable
portion of Affected System Network Upgrade(s) and shall be reduced
on a dollar-for-dollar basis for payments made to Transmission
Provider for these purposes.
[[Page 61308]]
The guarantee must be made by an entity that meets the
creditworthiness requirements of Transmission Provider and contain
terms and conditions that guarantee payment of any amount that may
be due from such Affected System Interconnection Customer, up to an
agreed-to maximum amount. The letter of credit must be issued by a
financial institution reasonably acceptable to Transmission Provider
and must specify a reasonable expiration date. The surety bond must
be issued by an insurer reasonably acceptable to Transmission
Provider and must specify a reasonable expiration date.
4.2 Invoice. Each Party shall submit to the other Parties, on a
monthly basis, invoices of amounts due, if any, for the preceding
month. Each invoice shall state the month to which the invoice
applies and fully describe the services and equipment provided. The
Parties may discharge mutual debts and payment obligations due and
owing to each other on the same date through netting, in which case
all amounts a Party owes to another Party under this Agreement,
including interest payments, shall be netted so that only the net
amount remaining due shall be paid by the owing Party.
4.3 Payment. Invoices shall be rendered to the paying Party at
the address specified by the Parties. The Party receiving the
invoice shall pay the invoice within thirty (30) Calendar Days of
receipt. All payments shall be made in immediately available funds
payable to the other Party, or by wire transfer to a bank named and
account designated by the invoicing Party. Payment of invoices by a
Party will not constitute a waiver of any rights or claims that
Party may have under this Agreement.
4.4 Final Invoice. Within six (6) months after completion of the
construction of the Affected System Network Upgrade(s) Transmission
Provider shall provide an invoice of the final cost of the
construction of the Affected System Network Upgrade(s) and shall set
forth such costs in sufficient detail to enable each Affected System
Interconnection Customer to compare the actual costs with the
estimates and to ascertain deviations, if any, from the cost
estimates. Transmission Provider shall refund, with interest
(calculated in accordance with 18 CFR 35.19a(a)(2)(iii)), to each
Affected System Interconnection Customer any amount by which the
actual payment by Affected System Interconnection Customer for
estimated costs exceeds the actual costs of construction within
thirty (30) Calendar Days of the issuance of such final construction
invoice.
4.5 Interest. Interest on any unpaid amounts shall be calculated
in accordance with 18 CFR 35.19a(a)(2)(iii).
4.6 Payment During Dispute. In the event of a billing dispute
among the Parties, Transmission Provider shall continue to construct
the Affected System Network Upgrade(s) under this Agreement as long
as each Affected System Interconnection Customer: (1) continues to
make all payments not in dispute; and (2) pays to Transmission
Provider or into an independent escrow account the portion of the
invoice in dispute, pending resolution of such dispute. If any
Affected System Interconnection Customer fails to meet these two
requirements, then Transmission Provider may provide notice to such
Affected System Interconnection Customer of a Default pursuant to
Article 5. Within thirty (30) Calendar Days after the resolution of
the dispute, the Party that owes money to another Party shall pay
the amount due with interest calculated in accordance with the
methodology set forth in 18 CFR 35.19a(a)(2)(iii).
Article 5
Breach, Cure, and Default
5.1 Events of Breach. A Breach of this Agreement shall include
the:
(a) Failure to pay any amount when due;
(b) Failure to comply with any material term or condition of
this Agreement, including but not limited to any material Breach of
a representation, warranty, or covenant made in this Agreement;
(c) Failure of a Party to provide such access rights, or a
Party's attempt to revoke access or terminate such access rights, as
provided under this Agreement; or
(d) Failure of a Party to provide information or data to another
Party as required under this Agreement, provided the Party entitled
to the information or data under this Agreement requires such
information or data to satisfy its obligations under this Agreement.
5.2 Definition. Breaching Party shall mean the Party that is in
Breach.
5.3 Notice of Breach, Cure, and Default. Upon the occurrence of
an event of Breach, any Party aggrieved by the Breach, when it
becomes aware of the Breach, shall give written notice of the Breach
to the Breaching Party and to any other person representing a Party
to this Agreement identified in writing to the other Party in
advance. Such notice shall set forth, in reasonable detail, the
nature of the Breach, and where known and applicable, the steps
necessary to cure such Breach.
5.2.1 Upon receiving written notice of the Breach hereunder, the
Breaching Party shall have a period to cure such Breach (hereinafter
referred to as the ``Cure Period'') which shall be sixty (60)
Calendar Days. If an Affected System Interconnection Customer is the
Breaching Party and the Breach results from a failure to provide
payments or security under Article 4.1 of this Agreement, the other
Affected System Interconnection Customers, either individually or in
concert, may cure the Breach by paying the amounts owed or by
providing adequate security, without waiver of contribution rights
against the breaching Affected System Interconnection Customer. Such
cure for the Breach of an Affected System Interconnection Customer
is subject to the reasonable consent of Transmission Provider.
Transmission Provider may also cure such Breach by funding the
proportionate share of the Affected System Network Upgrade costs
related to the Breach of Affected System Interconnection Customer.
Transmission Provider must notify all Parties that it will exercise
this option within thirty (30) Calendar Days of notification that an
Affected System Interconnection Customer has failed to provide
payments or security under Article 4.1.
5.2.2 In the event the Breach is not cured within the Cure
Period, the Breaching Party will be in Default of this Agreement,
and the non-Defaulting Parties may (1) act in concert to amend the
Agreement to remove an Affected System Interconnection Customer that
is in Default from this Agreement for cause and to make other
changes as necessary, or (2) either in concert or individually take
whatever action at law or in equity as may appear necessary or
desirable to enforce the performance or observance of any rights,
remedies, obligations, agreement, or covenants under this Agreement.
5.3 Rights in the Event of Default. Notwithstanding the
foregoing, upon the occurrence of Default, the non-Defaulting
Parties shall be entitled to exercise all rights and remedies it may
have in equity or at law.
Article 6
Termination of Agreement
6.1 Expiration of Term. Except as otherwise specified in this
Article 6, the Parties' obligations under this Agreement shall
terminate at the conclusion of the term of this Agreement.
6.2 Termination and Removal. Subject to the limitations set
forth in Article 6.3, in the event of a Default, termination of this
Agreement, as to a given Affected System Interconnection Customer or
in its entirety, shall require a filing at FERC of a notice of
termination, which filing must be accepted for filing by FERC.
6.3 Disposition of Facilities Upon Termination of Agreement.
6.3.1 Transmission Provider Obligations. Upon termination of
this Agreement, unless otherwise agreed to by the Parties in
writing, Transmission Provider:
(a) shall, prior to the construction and installation of any
portion of the Affected System Network Upgrade(s) and to the extent
possible, cancel any pending orders of, or return, such equipment or
material for such Affected System Network Upgrade(s);
(b) may keep in place any portion of the Affected System Network
Upgrade(s) already constructed and installed; and,
(c) shall perform such work as may be necessary to ensure the
safety of persons and property and to preserve the integrity of
Transmission Provider's Transmission System (e.g., construction
demobilization to return the system to its original state, wind-up
work).
6.3.2 Affected System Interconnection Customer Obligations. Upon
billing by Transmission Provider, each Affected System
Interconnection Customer shall reimburse Transmission Provider for
its share of any costs incurred by Transmission Provider in
performance of the actions required or permitted by Article 6.3.1
and for its share of the cost of any Affected System Network
Upgrade(s) described in Appendix A. Transmission Provider shall use
Reasonable Efforts to minimize costs and shall offset the amounts
owed by any salvage value of facilities, if applicable. Each
Affected System Interconnection Customer shall pay these costs
pursuant to Article 4.3 of this Agreement.
6.3.3 Pre-construction or Installation. Upon termination of this
Agreement and
[[Page 61309]]
prior to the construction and installation of any portion of the
Affected System Network Upgrade(s), Transmission Provider may, at
its option, retain any portion of such Affected System Network
Upgrade(s) not cancelled or returned in accordance with Article
6.3.1(a), in which case Transmission Provider shall be responsible
for all costs associated with procuring such Affected System Network
Upgrade(s). To the extent that an Affected System Interconnection
Customer has already paid Transmission Provider for any or all of
such costs, Transmission Provider shall refund Affected System
Interconnection Customer for those payments. If Transmission
Provider elects to not retain any portion of such facilities, and
one or more of Affected System Interconnection Customers wish to
purchase such facilities, Transmission Provider shall convey and
make available to the applicable Affected System Interconnection
Customer(s) such facilities as soon as practicable after Affected
System Interconnection Customer(s)' payment for such facilities.
6.4 Survival of Rights. Termination or expiration of this
Agreement shall not relieve any Party of any of its liabilities and
obligations arising hereunder prior to the date termination becomes
effective, and each Party may take whatever judicial or
administrative actions as appear necessary or desirable to enforce
its rights hereunder. The applicable provisions of this Agreement
will continue in effect after expiration, or early termination
hereof, to the extent necessary to provide for (1) final billings,
billing adjustments, and other billing procedures set forth in this
Agreement; (2) the determination and enforcement of liability and
indemnification obligations arising from acts or events that
occurred while this Agreement was in effect; and (3) the
confidentiality provisions set forth in Article 8.
Article 7
Subcontractors
7.1 Subcontractors. Nothing in this Agreement shall prevent a
Party from utilizing the services of subcontractors, as it deems
appropriate, to perform its obligations under this Agreement;
provided, however, that each Party shall require its subcontractors
to comply with all applicable terms and conditions of this Agreement
in providing such services, and each Party shall remain primarily
liable to the other Parties for the performance of such
subcontractor.
7.1.1 Responsibility of Principal. The creation of any
subcontract relationship shall not relieve the hiring Party of any
of its obligations under this Agreement. In accordance with the
provisions of this Agreement, each Party shall be fully responsible
to the other Parties for the acts or omissions of any subcontractor
it hires as if no subcontract had been made. Any applicable
obligation imposed by this Agreement upon a Party shall be equally
binding upon, and shall be construed as having application to, any
subcontractor of such Party.
7.1.2 No Third-Party Beneficiary. Except as may be specifically
set forth to the contrary herein, no subcontractor or any other
party is intended to be, nor will it be deemed to be, a third-party
beneficiary of this Agreement.
7.1.3 No Limitation by Insurance. The obligations under this
Article 7 will not be limited in any way by any limitation of any
insurance policies or coverages, including any subcontractor's
insurance.
Article 8
Confidentiality
8.1 Confidentiality. Confidential Information shall include,
without limitation, all information relating to a Party's
technology, research and development, business affairs, and pricing,
and any information supplied to the other Parties prior to the
execution of this Agreement.
Information is Confidential Information only if it is clearly
designated or marked in writing as confidential on the face of the
document, or, if the information is conveyed orally or by
inspection, if the Party providing the information orally informs
the Party receiving the information that the information is
confidential. The Parties shall maintain as confidential any
information that is provided and identified by a Party as Critical
Energy Infrastructure Information (CEII), as that term is defined in
18 CFR 388.113(c).
Such confidentiality will be maintained in accordance with this
Article 8. If requested by the receiving Party, the disclosing Party
shall provide in writing, the basis for asserting that the
information referred to in this Article warrants confidential
treatment, and the requesting Party may disclose such writing to the
appropriate Governmental Authority. Each Party shall be responsible
for the costs associated with affording confidential treatment to
its information.
8.1.1 Term. During the term of this Agreement, and for a period
of three (3) years after the expiration or termination of this
Agreement, except as otherwise provided in this Article 8 or with
regard to CEII, each Party shall hold in confidence and shall not
disclose to any person Confidential Information. CEII shall be
treated in accordance with FERC policies and regulations.
8.1.2 Scope. Confidential Information shall not include
information that the receiving Party can demonstrate: (1) is
generally available to the public other than as a result of a
disclosure by the receiving Party; (2) was in the lawful possession
of the receiving Party on a non-confidential basis before receiving
it from the disclosing Party; (3) was supplied to the receiving
Party without restriction by a non-Party, who, to the knowledge of
the receiving Party after due inquiry, was under no obligation to
the disclosing Party to keep such information confidential; (4) was
independently developed by the receiving Party without reference to
Confidential Information of the disclosing Party; (5) is, or
becomes, publicly known, through no wrongful act or omission of the
receiving Party or Breach of this Agreement; or (6) is required, in
accordance with Article 8.1.6 of this Agreement, to be disclosed by
any Governmental Authority or is otherwise required to be disclosed
by law or subpoena, or is necessary in any legal proceeding
establishing rights and obligations under this Agreement.
Information designated as Confidential Information will no longer be
deemed confidential if the Party that designated the information as
confidential notifies the receiving Party that it no longer is
confidential.
8.1.3 Release of Confidential Information. No Party shall
release or disclose Confidential Information to any other person,
except to its Affiliates (limited by the Standards of Conduct
requirements), subcontractors, employees, agents, consultants, or to
non-Parties that may be or are considering providing financing to or
equity participation with Affected System Interconnection
Customer(s), or to potential purchasers or assignees of Affected
System Interconnection Customer(s), on a need-to-know basis in
connection with this Agreement, unless such person has first been
advised of the confidentiality provisions of this Article 8 and has
agreed to comply with such provisions. Notwithstanding the
foregoing, a Party providing Confidential Information to any person
shall remain primarily responsible for any release of Confidential
Information in contravention of this Article 8.
8.1.4 Rights. Each Party shall retain all rights, title, and
interest in the Confidential Information that it discloses to the
receiving Party. The disclosure by a Party to the receiving Party of
Confidential Information shall not be deemed a waiver by the
disclosing Party or any other person or entity of the right to
protect the Confidential Information from public disclosure.
8.1.5 Standard of Care. Each Party shall use at least the same
standard of care to protect Confidential Information it receives as
it uses to protect its own Confidential Information from
unauthorized disclosure, publication, or dissemination. Each Party
may use Confidential Information solely to fulfill its obligations
to the other Party under this Agreement or its regulatory
requirements.
8.1.6 Order of Disclosure. If a court or a Government Authority
or entity with the right, power, and apparent authority to do so
requests or requires any Party, by subpoena, oral deposition,
interrogatories, requests for production of documents,
administrative order, or otherwise, to disclose Confidential
Information, that Party shall provide the disclosing Party with
prompt notice of such request(s) or requirement(s) so that the
disclosing Party may seek an appropriate protective order or waive
compliance with the terms of this Agreement. Notwithstanding the
absence of a protective order or waiver, the Party may disclose such
Confidential Information which, in the opinion of its counsel, the
Party is legally compelled to disclose. Each Party will use
Reasonable Efforts to obtain reliable assurance that confidential
treatment will be accorded any Confidential Information so
furnished.
8.1.7 Termination of Agreement. Upon termination of this
Agreement for any reason, each Party shall, within ten (10) Business
Days of receipt of a written request from the other Party, use
Reasonable Efforts to destroy, erase, or delete (with such
[[Page 61310]]
destruction, erasure, and deletion certified in writing to the
requesting Party) or return to the requesting Party any and all
written or electronic Confidential Information received from the
requesting Party, except that each Party may keep one copy for
archival purposes, provided that the obligation to treat it as
Confidential Information in accordance with this Article 8 shall
survive such termination.
8.1.8 Remedies. The Parties agree that monetary damages would be
inadequate to compensate a Party for another Party's Breach of its
obligations under this Article 8. Each Party accordingly agrees that
the disclosing Party shall be entitled to equitable relief, by way
of injunction or otherwise, if the receiving Party Breaches or
threatens to Breach its obligations under this Article 8, which
equitable relief shall be granted without bond or proof of damages,
and the Breaching Party shall not plead in defense that there would
be an adequate remedy at law. Such remedy shall not be deemed an
exclusive remedy for the Breach of this Article 8, but it shall be
in addition to all other remedies available at law or in equity. The
Parties further acknowledge and agree that the covenants contained
herein are necessary for the protection of legitimate business
interests and are reasonable in scope. No Party, however, shall be
liable for indirect, incidental, or consequential or punitive
damages of any nature or kind resulting from or arising in
connection with this Article 8.
8.1.9 Disclosure to FERC, its Staff, or a State Regulatory Body.
Notwithstanding anything in this Article 8 to the contrary, and
pursuant to 18 CFR 1b.20, if FERC or its staff, during the course of
an investigation or otherwise, requests information from a Party
that is otherwise required to be maintained in confidence pursuant
to this Agreement, the Party shall provide the requested information
to FERC or its staff, within the time provided for in the request
for information. In providing the information to FERC or its staff,
the Party must, consistent with 18 CFR 388.112, request that the
information be treated as confidential and non-public by FERC and
its staff and that the information be withheld from public
disclosure. Parties are prohibited from notifying the other Parties
to this Agreement prior to the release of the Confidential
Information to FERC or its staff. The Party shall notify the other
Parties to the Agreement when it is notified by FERC or its staff
that a request to release Confidential Information has been received
by FERC, at which time either of the Parties may respond before such
information would be made public, pursuant to 18 CFR 388.112.
Requests from a state regulatory body conducting a confidential
investigation shall be treated in a similar manner if consistent
with the applicable state rules and regulations.
8.1.10 Subject to the exception in Article 8.1.9, any
information that a disclosing Party claims is competitively
sensitive, commercial, or financial information under this Agreement
shall not be disclosed by the receiving Party to any person not
employed or retained by the receiving Party, except to the extent
disclosure is (1) required by law; (2) reasonably deemed by the
disclosing Party to be required to be disclosed in connection with a
dispute between or among the Parties, or the defense of litigation
or dispute; (3) otherwise permitted by consent of the disclosing
Party, such consent not to be unreasonably withheld; or (4)
necessary to fulfill its obligations under this Agreement or as
Transmission Provider or a balancing authority, including disclosing
the Confidential Information to a regional or national reliability
organization. The Party asserting confidentiality shall notify the
receiving Party in writing of the information that Party claims is
confidential. Prior to any disclosures of that Party's Confidential
Information under this subparagraph, or if any non-Party or
Governmental Authority makes any request or demand for any of the
information described in this subparagraph, the Party that received
the Confidential Information from the disclosing Party agrees to
promptly notify the disclosing Party in writing and agrees to assert
confidentiality and cooperate with the disclosing Party in seeking
to protect the Confidential Information from public disclosure by
confidentiality agreement, protective order, or other reasonable
measures.
Article 9
Information Access and Audit Rights
9.1 Information Access. Each Party shall make available to the
other Parties information necessary to verify the costs incurred by
the other Parties for which the requesting Party is responsible
under this Agreement and carry out obligations and responsibilities
under this Agreement, provided that the Parties shall not use such
information for purposes other than those set forth in this Article
9.1 and to enforce their rights under this Agreement.
9.2 Audit Rights. Subject to the requirements of confidentiality
under Article 8 of this Agreement, the accounts and records related
to the design, engineering, procurement, and construction of the
Affected System Network Upgrade(s) shall be subject to audit during
the period of this Agreement and for a period of twenty-four (24)
months following Transmission Provider's issuance of a final invoice
in accordance with Article 4.4. Affected System Interconnection
Customers may, jointly or individually, at the expense of the
requesting Party(ies), during normal business hours, and upon prior
reasonable notice to Transmission Provider, audit such accounts and
records. Any audit authorized by this Article 9.2 shall be performed
at the offices where such accounts and records are maintained and
shall be limited to those portions of such accounts and records that
relate to obligations under this Agreement.
Article 10
Notices
10.1 General. Any notice, demand, or request required or
permitted to be given by a Party to the other Parties, and any
instrument required or permitted to be tendered or delivered by a
Party in writing to another Party, may be so given, tendered, or
delivered, as the case may be, by depositing the same with the
United States Postal Service with postage prepaid, for transmission
by certified or registered mail, addressed to the Parties, or
personally delivered to the Parties, at the address set out below:
To Transmission Provider:
To Affected System Interconnection Customers:
10.2 Billings and Payments. Billings and payments shall be sent
to the addresses shown in Article 10.1 unless otherwise agreed to by
the Parties.
10.3 Alternative Forms of Notice. Any notice or request required
or permitted to be given by a Party to the other Parties and not
required by this Agreement to be given in writing may be so given by
telephone, facsimile, or email to the telephone numbers and email
addresses set out below:
To Transmission Provider:
To Affected System Interconnection Customers:
10.4 Execution and Filing. Affected System Interconnection
Customers shall either: (i) execute two originals of this tendered
Agreement and return them to Transmission Provider; or (ii) request
in writing that Transmission Provider file with FERC this Agreement
in unexecuted form. As soon as practicable, but not later than ten
(10) Business Days after receiving either the two executed originals
of this tendered Agreement (if it does not conform with a FERC-
approved standard form of this Agreement) or the request to file
this Agreement unexecuted, Transmission Provider shall file this
Agreement with FERC, together with its explanation of any matters as
to which Affected System Interconnection Customers and Transmission
Provider disagree and support for the costs that Transmission
Provider proposes to charge to Affected System Interconnection
Customers under this Agreement. An unexecuted version of this
Agreement should contain terms and conditions deemed appropriate by
Transmission Provider for the Affected System Interconnection
Customers' generating facilities. If the Parties agree to proceed
with design, procurement, and construction of facilities and
upgrades under the agreed-upon terms of the unexecuted version of
this Agreement, they may proceed pending FERC action.
Article 11--Miscellaneous
11.1 This Agreement shall include standard miscellaneous terms
including, but not limited to, indemnities, representations,
disclaimers, warranties, governing law, amendment, execution,
waiver, enforceability, and assignment, which reflect best practices
in the electric industry, that are consistent with regional
practices, Applicable Laws and Regulations, and the organizational
nature of each Party. All of these provisions, to the extent
practicable, shall be consistent with the provisions of this LGIP.
[Signature Page to Follow]
In witness whereof, the Parties have executed this Agreement in
multiple originals, each of which shall constitute and be an
original Agreement among the Parties.
[[Page 61311]]
Transmission Provider
{Transmission Provider{time}
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------
Affected System Interconnection Customer
{Affected System Interconnection Customer{time}
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------
Project No. __
Affected System Interconnection Customer
{Affected System Interconnection Customer{time}
By:--------------------------------------------------------------------
Name:------------------------------------------------------------------
Title:-----------------------------------------------------------------
Project No. __
Attachment A to Appendix 12--Multiparty Affected System Facilities
Construction Agreement
Affected System Network Upgrade(s), Cost Estimates and
Responsibility, Construction Schedule, and Monthly Payment Schedule
This Appendix A is a part of the Multiparty Affected System
Facilities Construction Agreement between Affected System
Interconnection Customers and Transmission Provider.
1.1 Affected System Network Upgrade(s) to be installed by
Transmission Provider.
{description{time}
1.2 First Equipment Order (including permitting).
{description{time}
1.2.1 Permitting and Land Rights--Transmission Provider Affected
System Network Upgrade(s).
{description{time}
1.3 Construction Schedule. Where applicable, construction of the
Affected System Network Upgrade(s) is scheduled as follows and will
be periodically updated as necessary:
Table 3--Transmission Provider Construction Activities
----------------------------------------------------------------------------------------------------------------
Milestone No. Description Start date End date
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Note: Construction schedule assumes that Transmission Provider
has obtained final authorizations and security from Affected System
Interconnection Customers and all necessary permits from
Governmental Authorities as necessary prerequisites to commence
construction of any of the Affected System Network Upgrade(s).
1.4 Payment Schedule.
1.4.1 Timing of and Adjustments to Affected System
Interconnection Customers' Payments and Security.
{description{time}
1.4.2 Monthly Payment Schedule. Affected System Interconnection
Customers' payment schedule is as follows.
{description{time}
Table 4--Affected System Interconnection Customers' Payment/Security
Obligations for Affected System Network Upgrade(s)
------------------------------------------------------------------------
Milestone No. Description Date
------------------------------------------------------------------------
------------------------------------------------------------------------
* Affected System Interconnection Customers' proportionate
responsibility for each payment is as follows:
Affected System Interconnection Customer 1 __._%
Affected System Interconnection Customer 2 __._%
Affected System Interconnection Customer N __._%
Note: Affected System Interconnection Customers' payment or
provision of security as provided in this Agreement operates as a
condition precedent to Transmission Provider's obligations to
construct any Affected System Network Upgrade(s), and failure to
meet this schedule will constitute a Breach pursuant to Article 5.1
of this Agreement.
1.5 Permits, Licenses, and Authorizations.
{description{time}
Attachment B to Appendix 12--Multiparty Affected System Facilities
Construction Agreement
Notification of Completed Construction
This Appendix B is a part of the Multiparty Affected System
Facilities Construction Agreement among Affected System
Interconnection Customers and Transmission Provider. Where
applicable, when Transmission Provider has completed construction of
the Affected System Network Upgrade(s), Transmission Provider shall
send notice to Affected System Interconnection Customers in
substantially the form following:
{Date{time}
{Affected System Interconnection Customers Addresses{time}
Re: Completion of Affected System Network Upgrade(s)
Dear {Name or Title{time} :
This letter is sent pursuant to the Multiparty Affected System
Facilities Construction Agreement among {Transmission
Provider{time} and {Affected System Interconnection
Customers{time} , dated ___, 20_.
On {Date{time} , Transmission Provider completed to its
satisfaction all work on the Affected System Network Upgrade(s)
required to facilitate the safe and reliable interconnection and
operation of Affected System Interconnection Customer's generating
facilities. Transmission Provider confirms that the Affected System
Network Upgrade(s) are in place.
Thank you.
{Signature{time}
{Transmission Provider Representative{time}
Attachment C to Appendix 12--Multiparty Affected System Facilities
Construction Agreement
Exhibits
This Appendix C is a part of the Multiparty Affected System
Facilities Construction Agreement among Affected System
Interconnection Customers and Transmission Provider.
Exhibit A1--Transmission Provider Site Map
Exhibit A2--Site Plan
Exhibit A3--Affected System Network Upgrade(s) Plan & Profile
Exhibit A4--Estimated Cost of Affected System Network Upgrade(s)
------------------------------------------------------------------------
Facilities to be
Location constructed by Estimate in
transmission provider dollars
------------------------------------------------------------------------
Total:
------------------------------------------------------------------------
[[Page 61312]]
Appendix D: Pro forma LGIA
Note: Deletions are in brackets and additions are in italics.
Standard Large Generator Interconnection Agreement
THIS STANDARD LARGE GENERATOR INTERCONNECTION AGREEMENT
(``Agreement'') is made and entered into this _ day of ___ 20_, by
and between _____, a _____ organized and existing under the laws of
the State/Commonwealth of ____ (``Interconnection Customer'' with a
Large Generating Facility), and _____, a _____ organized and
existing under the laws of the State/Commonwealth of ____
(``Transmission Provider and/or Transmission Owner'').
Interconnection Customer and Transmission Provider each may be
referred to as a ``Party'' or collectively as the ``Parties.''
Recitals
Whereas, Transmission Provider operates the Transmission System;
and
Whereas, Interconnection Customer intends to own, lease and/or
control and operate the Generating Facility identified as a Large
Generating Facility in Appendix C to this Agreement; and,
Whereas, Interconnection Customer and Transmission Provider have
agreed to enter into this Agreement for the purpose of
interconnecting the Large Generating Facility with the Transmission
System;
Now, therefore, in consideration of and subject to the mutual
covenants contained herein, it is agreed:
When used in this Standard Large Generator Interconnection
Agreement, terms with initial capitalization that are not defined in
Article 1 shall have the meanings specified in the Article in which
they are used or the Open Access Transmission Tariff (Tariff).
Article 1. Definitions
Adverse System Impact shall mean the negative effects due to
technical or operational limits on conductors or equipment being
exceeded that may compromise the safety and reliability of the
electric system.
Affected System shall mean an electric system other than [the]
Transmission Provider's Transmission System that may be affected by
the proposed interconnection.
Affected System Operator shall mean the entity that operates an
Affected System.
Affiliate shall mean, with respect to a corporation, partnership
or other entity, each such other corporation, partnership or other
entity that directly or indirectly, through one or more
intermediaries, controls, is controlled by, or is under common
control with, such corporation, partnership or other entity.
Ancillary Services shall mean those services that are necessary
to support the transmission of capacity and energy from resources to
loads while maintaining reliable operation of the Transmission
Provider's Transmission System in accordance with Good Utility
Practice.
Applicable Laws and Regulations shall mean all duly promulgated
applicable federal, state and local laws, regulations, rules,
ordinances, codes, decrees, judgments, directives, or judicial or
administrative orders, permits and other duly authorized actions of
any Governmental Authority.
[Applicable Reliability Council shall mean the reliability
council applicable to the Transmission System to which the
Generating Facility is directly interconnected.]
Applicable Reliability Standards shall mean the requirements and
guidelines of [NERC,]the [Applicable Reliability Council]Electric
Reliability Organization and the [Control Area]Balancing Authority
Area of the Transmission System to which the Generating Facility is
directly interconnected.
Balancing Authority shall mean an entity that integrates
resource plans ahead of time, maintains demand and resource balance
within a Balancing Authority Area, and supports interconnection
frequency in real time.
Balancing Authority Area shall mean the collection of
generation, transmission, and loads within the metered boundaries of
the Balancing Authority. The Balancing Authority maintains load-
resource balance within this area.
Base Case shall mean the base case power flow, short circuit,
and stability data bases used for the Interconnection Studies by
[the] Transmission Provider or Interconnection Customer.
Breach shall mean the failure of a Party to perform or observe
any material term or condition of the Standard Large Generator
Interconnection Agreement.
Breaching Party shall mean a Party that is in Breach of the
Standard Large Generator Interconnection Agreement.
Business Day shall mean Monday through Friday, excluding Federal
Holidays.
Calendar Day shall mean any day including Saturday, Sunday or a
Federal Holiday.
Cluster shall mean a group of one or more Interconnection
Requests that are studied together for the purpose of conducting a
Cluster Study.
Cluster Restudy shall mean a restudy of a Cluster Study
conducted pursuant to Section 7.5 of the LGIP.
Cluster Study shall mean the evaluation of one or
more Interconnection Requests within a Cluster as described in
Section 7 of the LGIP.
Clustering shall mean the process whereby one or more [a group
of]Interconnection Requests [is] are studied together, instead of
serially, [for the purpose of conducting the Interconnection System
Impact Study]as described in Section 7 of the LGIP.
Commercial Operation shall mean the status of a Generating
Facility that has commenced generating electricity for sale,
excluding electricity generated during Trial Operation.
Commercial Operation Date of a unit shall mean the date on which
the Generating Facility commences Commercial Operation as agreed to
by the Parties pursuant to Appendix E to the Standard Large
Generator Interconnection Agreement.
Confidential Information shall mean any confidential,
proprietary or trade secret information of a plan, specification,
pattern, procedure, design, device, list, concept, policy or
compilation relating to the present or planned business of a Party,
which is designated as confidential by the Party supplying the
information, whether conveyed orally, electronically, in writing,
through inspection, or otherwise.
Contingent Facilities shall mean those unbuilt Interconnection
Facilities and Network Upgrades upon which the Interconnection
Request's costs, timing, and study findings are dependent, and if
delayed or not built, could cause a need for restudies of the
Interconnection Request or a reassessment of the Interconnection
Facilities and/or Network Upgrades and/or costs and timing.
[Control Area shall mean an electrical system or systems bounded
by interconnection metering and telemetry, capable of controlling
generation to maintain its interchange schedule with other Control
Areas and contributing to frequency regulation of the
interconnection. A Control Area must be certified by an Applicable
Reliability Council.]
Default shall mean the failure of a Breaching Party to cure its
Breach in accordance with Article 17 of the Standard Large Generator
Interconnection Agreement.
Dispute Resolution shall mean the procedure for resolution of a
dispute between the Parties in which they will first attempt to
resolve the dispute on an informal basis.
Distribution System shall mean the Transmission Provider's
facilities and equipment used to transmit electricity to ultimate
usage points such as homes and industries directly from nearby
generators or from interchanges with higher voltage transmission
networks which transport bulk power over longer distances. The
voltage levels at which distribution systems operate differ among
areas.
Distribution Upgrades shall mean the additions, modifications,
and upgrades to the Transmission Provider's Distribution System at
or beyond the Point of Interconnection to facilitate interconnection
of the Generating Facility and render the transmission service
necessary to effect Interconnection Customer's wholesale sale of
electricity in interstate commerce. Distribution Upgrades do not
include Interconnection Facilities.
Effective Date shall mean the date on which the Standard Large
Generator Interconnection Agreement becomes effective upon execution
by the Parties subject to acceptance by FERC, or if filed
unexecuted, upon the date specified by FERC.
Electric Reliability Organization shall mean the North American
Electric Reliability Corporation or its successor organization.
Emergency Condition shall mean a condition or situation: (1)
that in the judgment of the Party making the claim is imminently
likely to endanger life or property; or (2) that, in the case of a
Transmission Provider, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the
security of, or damage to Transmission Provider's Transmission
System, Transmission Provider's Interconnection Facilities or the
electric systems of others to
[[Page 61313]]
which the Transmission Provider's Transmission System is directly
connected; or (3) that, in the case of Interconnection Customer, is
imminently likely (as determined in a non-discriminatory manner) to
cause a material adverse effect on the security of, or damage to,
the Generating Facility or Interconnection Customer's
Interconnection Facilities. System restoration and black start shall
be considered Emergency Conditions; provided, that Interconnection
Customer is not obligated by the Standard Large Generator
Interconnection Agreement to possess black start capability.
Energy Resource Interconnection Service shall mean an
Interconnection Service that allows the Interconnection Customer to
connect its Generating Facility to the Transmission Provider's
Transmission System to be eligible to deliver the Generating
Facility's electric output using the existing firm or nonfirm
capacity of the Transmission Provider's Transmission System on an as
available basis. Energy Resource Interconnection Service in and of
itself does not convey transmission service.
Engineering & Procurement (E&P) Agreement shall mean an
agreement that authorizes the Transmission Provider to begin
engineering and procurement of long lead-time items necessary for
the establishment of the interconnection in order to advance the
implementation of the Interconnection Request.
Environmental Law shall mean Applicable Laws or Regulations
relating to pollution or protection of the environment or natural
resources.
Federal Power Act shall mean the Federal Power Act, as amended,
16 U.S.C. 791a et seq.
FERC shall mean the Federal Energy Regulatory Commission
(Commission) or its successor.
Force Majeure shall mean any act of God, labor disturbance, act
of the public enemy, war, insurrection, riot, fire, storm or flood,
explosion, breakage or accident to machinery or equipment, any
order, regulation or restriction imposed by governmental, military
or lawfully established civilian authorities, or any other cause
beyond a Party's control. A Force Majeure event does not include
acts of negligence or intentional wrongdoing by the Party claiming
Force Majeure.
Generating Facility shall mean Interconnection Customer's
[device] device(s) for the production and/or storage for later
injection of electricity identified in the Interconnection Request,
but shall not include [the]Interconnection Customer's
Interconnection Facilities.
Generating Facility Capacity shall mean the net capacity of the
Generating Facility [and] or the aggregate net capacity of the
Generating Facility where it includes [multiple energy production
devices] more than one device for the production and/or storage for
later injection of electricity.
Good Utility Practice shall mean any of the practices, methods
and acts engaged in or approved by a significant portion of the
electric industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices,
reliability, safety and expedition. Good Utility Practice is not
intended to be limited to the optimum practice, method, or act to
the exclusion of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region.
Governmental Authority shall mean any federal, state, local or
other governmental regulatory or administrative agency, court,
commission, department, board, or other governmental subdivision,
legislature, rulemaking board, tribunal, or other governmental
authority having jurisdiction over the Parties, their respective
facilities, or the respective services they provide, and exercising
or entitled to exercise any administrative, executive, police, or
taxing authority or power; provided, however, that such term does
not include Interconnection Customer, Transmission Provider, or any
Affiliate thereof.
Hazardous Substances shall mean any chemicals, materials or
substances defined as or included in the definition of ``hazardous
substances,'' ``hazardous wastes,'' ``hazardous materials,''
``hazardous constituents,'' ``restricted hazardous materials,''
``extremely hazardous substances,'' ``toxic substances,''
``radioactive substances,'' ``contaminants,'' ``pollutants,''
``toxic pollutants'' or words of similar meaning and regulatory
effect under any applicable Environmental Law, or any other
chemical, material or substance, exposure to which is prohibited,
limited or regulated by any applicable Environmental Law.
Initial Synchronization Date shall mean the date upon which the
Generating Facility is initially synchronized and upon which Trial
Operation begins.
In-Service Date shall mean the date upon which the
Interconnection Customer reasonably expects it will be ready to
begin use of the Transmission Provider's Interconnection Facilities
to obtain back feed power.
Interconnection Customer shall mean any entity, including the
Transmission Provider, Transmission Owner or any of the Affiliates
or subsidiaries of either, that proposes to interconnect its
Generating Facility with the Transmission Provider's Transmission
System.
Interconnection Customer's Interconnection Facilities shall mean
all facilities and equipment, as identified in Appendix A of the
Standard Large Generator Interconnection Agreement, that are located
between the Generating Facility and the Point of Change of
Ownership, including any modification, addition, or upgrades to such
facilities and equipment necessary to physically and electrically
interconnect the Generating Facility to the Transmission Provider's
Transmission System. Interconnection Customer's Interconnection
Facilities are sole use facilities.
Interconnection Facilities shall mean [the]Transmission
Provider's Interconnection Facilities and [the]Interconnection
Customer's Interconnection Facilities. Collectively, Interconnection
Facilities include all facilities and equipment between the
Generating Facility and the Point of Interconnection, including any
modification, additions or upgrades that are necessary to physically
and electrically interconnect the Generating Facility to
[the]Transmission Provider's Transmission System. Interconnection
Facilities are sole use facilities and shall not include
Distribution Upgrades, Stand Alone Network Upgrades or Network
Upgrades.
Interconnection Facilities Study shall mean a study conducted by
[the]Transmission Provider or a third party consultant for
[the]Interconnection Customer to determine a list of facilities
(including Transmission Provider's Interconnection Facilities and
Network Upgrades as identified in the [Interconnection System
Impact]Cluster Study), the cost of those facilities, and the time
required to interconnect the Generating Facility with [the]
Transmission Provider's Transmission System. The scope of the study
is defined in Section 8 of the LGIP[the Standard Large Generator
Interconnection Procedures].
Interconnection Facilities Study Agreement shall mean the form
of agreement contained in Appendix 3[4] of the Standard Large
Generator Interconnection Procedures for conducting the
Interconnection Facilities Study.
[Interconnection Feasibility Study shall mean a preliminary
evaluation of the system impact and cost of interconnecting the
Generating Facility to the Transmission Provider's Transmission
System, the scope of which is described in Section 6 of the Standard
Large Generator Interconnection Procedures.]
[Interconnection Feasibility Study Agreement shall mean the form
of agreement contained in Appendix 2 of the Standard Large Generator
Interconnection Procedures for conducting the Interconnection
Feasibility Study.]
Interconnection Request shall mean an Interconnection Customer's
request, in the form of Appendix 1 to the LGIP [the Standard Large
Generator Interconnection Procedures], in accordance with the
Tariff, to interconnect a new Generating Facility, or to increase
the capacity of, or make a Material Modification to the operating
characteristics of, an existing Generating Facility that is
interconnected with the Transmission Provider's Transmission System.
Interconnection Service shall mean the service provided by the
Transmission Provider associated with interconnecting the
Interconnection Customer's Generating Facility to the Transmission
Provider's Transmission System and enabling it to receive electric
energy and capacity from the Generating Facility at the Point of
Interconnection, pursuant to the terms of the Standard Large
Generator Interconnection Agreement and, if applicable, the
Transmission Provider's Tariff.
Interconnection Study shall mean any of the following studies:
[the Interconnection Feasibility Study, the Interconnection System
Impact Study,] the Cluster Study, the Cluster Restudy, the Surplus
Interconnection Service System Impact Study, and the
[[Page 61314]]
Interconnection Facilities Study, described in the LGIP [the
Standard Large Generator Interconnection Procedures].
[Interconnection System Impact Study shall mean an engineering
study that evaluates the impact of the proposed interconnection on
the safety and reliability of Transmission Provider's Transmission
System and, if applicable, an Affected System. The study shall
identify and detail the system impacts that would result if the
Generating Facility were interconnected without project
modifications or system modifications, focusing on the Adverse
System Impacts identified in the Interconnection Feasibility Study,
or to study potential impacts, including but not limited to those
identified in the Scoping Meeting as described in the Standard Large
Generator Interconnection Procedures.]
Interconnection System Impact Study Agreement shall mean the
form of agreement contained in Appendix 3 of the Standard Large
Generator Interconnection Procedures for conducting the
Interconnection System Impact Study.]
IRS shall mean the Internal Revenue Service.
Joint Operating Committee shall be a group made up of
representatives from Interconnection Customers and the Transmission
Provider to coordinate operating and technical considerations of
Interconnection Service.
Large Generating Facility shall mean a Generating Facility
having a Generating Facility Capacity of more than 20 MW.
LGIA Deposit shall mean the deposit Interconnection Customer
submits when returning the executed LGIA, or within 10 Business Days
of requesting that the LGIA be filed unexecuted at the Commission,
in accordance with Section 11.3 of the LGIP.
Loss shall mean any and all losses relating to injury to or
death of any person or damage to property, demand, suits,
recoveries, costs and expenses, court costs, attorney fees, and all
other obligations by or to third parties, arising out of or
resulting from the other Party's performance, or non-performance of
its obligations under the Standard Large Generator Interconnection
Agreement on behalf of the Indemnifying Party, except in cases of
gross negligence or intentional wrongdoing by the Indemnifying
Party.
Material Modification shall mean those modifications that have
a material impact on the cost or timing of any Interconnection
Request with an equal or later Queue Position[queue priority date].
Metering Equipment shall mean all metering equipment installed
or to be installed at the Generating Facility pursuant to the
Standard Large Generator Interconnection Agreement at the metering
points, including but not limited to instrument transformers, MWh-
meters, data acquisition equipment, transducers, remote terminal
unit, communications equipment, phone lines, and fiber optics.
[NERC shall mean the North American Electric Reliability Council
or its successor organization.]
Network Resource shall mean any designated generating resource
owned, purchased, or leased by a Network Customer under the Network
Integration Transmission Service Tariff. Network Resources do not
include any resource, or any portion thereof, that is committed for
sale to third parties or otherwise cannot be called upon to meet the
Network Customer's Network Load on a non-interruptible basis.
Network Resource Interconnection Service shall mean an
Interconnection Service that allows the Interconnection Customer to
integrate its Large Generating Facility with the Transmission
Provider's Transmission System (1) in a manner comparable to that in
which the Transmission Provider integrates its generating facilities
to serve native load customers; or (2) in an RTO or ISO with market
based congestion management, in the same manner as Network
Resources. Network Resource Interconnection Service in and of itself
does not convey transmission service.
Network Upgrades shall mean the additions, modifications, and
upgrades to the Transmission Provider's Transmission System required
at or beyond the point at which the Interconnection Facilities
connect to the Transmission Provider's Transmission System to
accommodate the interconnection of the Large Generating Facility to
the Transmission Provider's Transmission System.
Notice of Dispute shall mean a written notice of a dispute or
claim that arises out of or in connection with the Standard Large
Generator Interconnection Agreement or its performance.
Optional Interconnection Study shall mean a sensitivity analysis
based on assumptions specified by the Interconnection Customer in
the Optional Interconnection Study Agreement.
Optional Interconnection Study Agreement shall mean the form of
agreement contained in Appendix 4[5] of the LGIP [the Standard Large
Generator Interconnection Procedures] for conducting the Optional
Interconnection Study.
Party or Parties shall mean Transmission Provider, Transmission
Owner, Interconnection Customer or any combination of the above.
Point of Change of Ownership shall mean the point, as set forth
in Appendix A to the Standard Large Generator Interconnection
Agreement, where the Interconnection Customer's Interconnection
Facilities connect to the Transmission Provider's Interconnection
Facilities.
Point of Interconnection shall mean the point, as set forth in
Appendix A to the Standard Large Generator Interconnection
Agreement, where the Interconnection Facilities connect to the
Transmission Provider's Transmission System.
Proportional Impact Method shall mean a technical analysis
conducted by Transmission Provider to determine the degree to which
each Generating Facility in the Cluster Study contributes to the
need for a specific System Network Upgrade.
Provisional Interconnection Service shall mean Interconnection
Service provided by Transmission Provider associated with
interconnecting the Interconnection Customer's Generating Facility
to Transmission Provider's Transmission System and enabling that
Transmission System to receive electric energy and capacity from the
Generating Facility at the Point of Interconnection, pursuant to the
terms of the Provisional Large Generator Interconnection Agreement
and, if applicable, the Tariff.
Provisional Large Generator Interconnection Agreement shall mean
the interconnection agreement for Provisional Interconnection
Service established between Transmission Provider and/or the
Transmission Owner and the Interconnection Customer. This agreement
shall take the form of the Large Generator Interconnection
Agreement, modified for provisional purposes.
Queue Position shall mean the order of a valid Interconnection
Request, relative to all other pending valid Interconnection
Requests, [that is] established pursuant to Section 4.1 of the LGIP.
[based upon the date and time of receipt of the valid
Interconnection Request by the Transmission Provider.]
Reasonable Efforts shall mean, with respect to an action
required to be attempted or taken by a Party under the Standard
Large Generator Interconnection Agreement, efforts that are timely
and consistent with Good Utility Practice and are otherwise
substantially equivalent to those a Party would use to protect its
own interests.
Scoping Meeting shall mean the meeting between representatives
of [the]Interconnection Customer(s) and Transmission Provider
conducted for the purpose of discussing the proposed Interconnection
Request and any alternative interconnection options,
[to]exchang[e]ing information including any transmission data and
earlier study evaluations that would be reasonably expected to
impact such interconnection options, refining information and models
provided by Interconnection Customer(s), discussing the Cluster
Study materials posted to OASIS pursuant to Section 3.5 of the LGIP,
and [to]analyz[e]ing such information[, and to determine the
potential feasible Points of Interconnection].
Site Control shall mean [documentation reasonably demonstrating]
the exclusive land right to develop, construct, operate, and
maintain the Generating Facility over the term of expected operation
of the Generating Facility. Site Control may be demonstrated by
documentation establishing: (1) ownership of, a leasehold interest
in, or a right to develop a site [for the purpose of constructing]of
sufficient size to construct and operate the Generating Facility;
(2) an option to purchase or acquire a leasehold site of sufficient
size to construct and operate the Generating Facility for such
purpose; or (3) [an exclusivity or other business relationship
between]any other documentation that clearly demonstrates the right
of Interconnection Customer[and the entity having the right to sell,
lease or grant Interconnection Customer the right to possess or]to
exclusively occupy a site [for such purpose.]of sufficient size to
construct and operate the Generating Facility. Transmission Provider
will maintain acreage requirements for each Generating Facility type
on its OASIS or public website.
[[Page 61315]]
Small Generating Facility shall mean a Generating Facility that
has a Generating Facility Capacity of no more than 20 MW.
Stand Alone Network Upgrades shall mean Network Upgrades that
are not part of an Affected System that an Interconnection Customer
may construct without affecting day-to-day operations of the
Transmission System during their construction and the following
conditions are met: (1) a Substation Network Upgrade must only be
required for a single Interconnection Customer in the Cluster and no
other Interconnection Customer in that Cluster is required to
interconnect to the same Substation Network Upgrades, and (2) a
System Network Upgrade must only be required for a single
Interconnection Customer in the Cluster, as indicated under
Transmission Provider's Proportional Impact Method. Both
[the]Transmission Provider and [the]Interconnection Customer must
agree as to what constitutes Stand Alone Network Upgrades and
identify them in Appendix A to the Standard Large Generator
Interconnection Agreement. If [the]Transmission Provider and
Interconnection Customer disagree about whether a particular Network
Upgrade is a Stand Alone Network Upgrade, [the]Transmission Provider
must provide [the]Interconnection Customer a written technical
explanation outlining why [the] Transmission Provider does not
consider the Network Upgrade to be a Stand Alone Network Upgrade
within 15 days of its determination.
Standard Large Generator Interconnection Agreement (LGIA) shall
mean the form of interconnection agreement applicable to an
Interconnection Request pertaining to a Large Generating Facility
that is included in the Transmission Provider's Tariff.
Standard Large Generator Interconnection Procedures (LGIP) shall
mean the interconnection procedures applicable to an Interconnection
Request pertaining to a Large Generating Facility that are included
in the Transmission Provider's Tariff.
Substation Network Upgrades shall mean Network Upgrades that are
required at the substation located at the Point of Interconnection.
Surplus Interconnection Service shall mean any unneeded portion
of Interconnection Service established in a Large Generator
Interconnection Agreement, such that if Surplus Interconnection
Service is utilized the total amount of Interconnection Service at
the Point of Interconnection would remain the same.
System Network Upgrades shall mean Network Upgrades that are
required beyond the substation located at the Point of
Interconnection.
System Protection Facilities shall mean the equipment, including
necessary protection signal communications equipment, required to
protect (1) the Transmission Provider's Transmission System from
faults or other electrical disturbances occurring at the Generating
Facility and (2) the Generating Facility from faults or other
electrical system disturbances occurring on the Transmission
Provider's Transmission System or on other delivery systems or other
generating systems to which the Transmission Provider's Transmission
System is directly connected.
Tariff shall mean the Transmission Provider's Tariff through
which open access transmission service and Interconnection Service
are offered, as filed with FERC, and as amended or supplemented from
time to time, or any successor tariff.
Transmission Owner shall mean an entity that owns, leases or
otherwise possesses an interest in the portion of the Transmission
System at the Point of Interconnection and may be a Party to the
Standard Large Generator Interconnection Agreement to the extent
necessary.
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 electricity in
interstate commerce and provides transmission service under the
Tariff. The term Transmission Provider should be read to include the
Transmission Owner when the Transmission Owner is separate from the
Transmission Provider.
Transmission Provider's Interconnection Facilities shall mean
all facilities and equipment owned, controlled, or operated by
[the]Transmission Provider from the Point of Change of Ownership to
the Point of Interconnection as identified in Appendix A to the
Standard Large Generator Interconnection Agreement, including any
modifications, additions or upgrades to such facilities and
equipment. Transmission Provider's Interconnection Facilities are
sole use facilities and shall not include Distribution Upgrades,
Stand Alone Network Upgrades or Network Upgrades.
Transmission System shall mean the facilities owned, controlled
or operated by the Transmission Provider or Transmission Owner that
are used to provide transmission service under the Tariff.
Trial Operation shall mean the period during which
Interconnection Customer is engaged in on-site test operations and
commissioning of the Generating Facility prior to Commercial
Operation.
Variable Energy Resource shall mean a device for the production
of electricity that is characterized by an energy source that: (1)
is renewable; (2) cannot be stored by the facility owner or
operator; and (3) has variability that is beyond the control of the
facility owner or operator.
Withdrawal Penalty shall mean the penalty assessed by
Transmission Provider to an Interconnection Customer that chooses to
withdraw or is deemed withdrawn from Transmission Provider's
interconnection queue or whose Generating Facility does not
otherwise reach Commercial Operation. The calculation of the
Withdrawal Penalty is set forth in Section 3.7.1 of the LGIP.
Article 2. Effective Date, Term, and Termination
2.1 Effective Date. This LGIA shall become effective upon
execution by the Parties subject to acceptance by FERC (if
applicable), or if filed unexecuted, upon the date specified by
FERC. Transmission Provider shall promptly file this LGIA with FERC
upon execution in accordance with Article 3.1, if required.
2.2 Term of Agreement. Subject to the provisions of Article 2.3,
this LGIA shall remain in effect for a period of ten (10) years from
the Effective Date or such other longer period as Interconnection
Customer may request (Term to be specified in individual agreements)
and shall be automatically renewed for each successive one-year
period thereafter.
2.3 Termination Procedures.
2.3.1 Written Notice. This LGIA may be terminated by
Interconnection Customer after giving Transmission Provider ninety
(90) Calendar Days advance written notice, or by Transmission
Provider notifying FERC after the Generating Facility permanently
ceases Commercial Operation.
2.3.2 Default. Either Party may terminate this LGIA in
accordance with Article 17.
2.3.3 Notwithstanding Articles 2.3.1 and 2.3.2, no termination
shall become effective until the Parties have complied with all
Applicable Laws and Regulations applicable to such termination,
including the filing with FERC of a notice of termination of this
LGIA, which notice has been accepted for filing by FERC.
2.4 Termination Costs. If a Party elects to terminate this
Agreement pursuant to Article 2.3 above, each Party shall pay all
costs incurred (including any cancellation costs relating to orders
or contracts for Interconnection Facilities and equipment) or
charges assessed by the other Party, as of the date of the other
Party's receipt of such notice of termination, that are the
responsibility of the Terminating Party under this LGIA. In the
event of termination by a Party, the Parties shall use commercially
Reasonable Efforts to mitigate the costs, damages and charges
arising as a consequence of termination. Upon termination of this
LGIA, unless otherwise ordered or approved by FERC:
2.4.1 With respect to any portion of Transmission Provider's
Interconnection Facilities that have not yet been constructed or
installed, Transmission Provider shall to the extent possible and
with Interconnection Customer's authorization cancel any pending
orders of, or return, any materials or equipment for, or contracts
for construction of, such facilities; provided that in the event
Interconnection Customer elects not to authorize such cancellation,
Interconnection Customer shall assume all payment obligations with
respect to such materials, equipment, and contracts, and
Transmission Provider shall deliver such material and equipment,
and, if necessary, assign such contracts, to Interconnection
Customer as soon as practicable, at Interconnection Customer's
expense. To the extent that Interconnection Customer has already
paid Transmission Provider for any or all such costs of materials or
equipment not taken by Interconnection Customer, Transmission
Provider shall promptly refund such amounts to Interconnection
Customer, less any costs, including penalties incurred by
Transmission Provider to cancel any pending orders of or return such
materials, equipment, or contracts.
If an Interconnection Customer terminates this LGIA, it shall be
responsible for all costs incurred in association with that
[[Page 61316]]
Interconnection Customer's interconnection, including any
cancellation costs relating to orders or contracts for
Interconnection Facilities and equipment, and other expenses
including any Network Upgrades for which Transmission Provider has
incurred expenses and has not been reimbursed by Interconnection
Customer.
2.4.2 Transmission Provider may, at its option, retain any
portion of such materials, equipment, or facilities that
Interconnection Customer chooses not to accept delivery of, in which
case Transmission Provider shall be responsible for all costs
associated with procuring such materials, equipment, or facilities.
2.4.3 With respect to any portion of the Interconnection
Facilities, and any other facilities already installed or
constructed pursuant to the terms of this LGIA, Interconnection
Customer shall be responsible for all costs associated with the
removal, relocation or other disposition or retirement of such
materials, equipment, or facilities.
2.5 Disconnection. Upon termination of this LGIA, the Parties
will take all appropriate steps to disconnect the Large Generating
Facility from the Transmission System. All costs required to
effectuate such disconnection shall be borne by the terminating
Party, unless such termination resulted from the non-terminating
Party's Default of this LGIA or such non-terminating Party otherwise
is responsible for these costs under this LGIA.
2.6 Survival. This LGIA shall continue in effect after
termination to the extent necessary to provide for final billings
and payments and for costs incurred hereunder, including billings
and payments pursuant to this LGIA; to permit the determination and
enforcement of liability and indemnification obligations arising
from acts or events that occurred while this LGIA was in effect; and
to permit each Party to have access to the lands of the other Party
pursuant to this LGIA or other applicable agreements, to disconnect,
remove or salvage its own facilities and equipment.
Article 3. Regulatory Filings
3.1 Filing. Transmission Provider shall file this LGIA (and any
amendment hereto) with the appropriate Governmental Authority, if
required. Interconnection Customer may request that any information
so provided be subject to the confidentiality provisions of Article
22. If Interconnection Customer has executed this LGIA, or any
amendment thereto, Interconnection Customer shall reasonably
cooperate with Transmission Provider with respect to such filing and
to provide any information reasonably requested by Transmission
Provider needed to comply with applicable regulatory requirements.
Article 4. Scope of Service
4.1 Interconnection Product Options. Interconnection Customer
has selected the following (checked) type of Interconnection
Service:
4.1.1 Energy Resource Interconnection Service
4.1.1.1 The Product. Energy Resource Interconnection Service
allows Interconnection Customer to connect the Large Generating
Facility to the Transmission System and be eligible to deliver the
Large Generating Facility's output using the existing firm or non-
firm capacity of the Transmission System on an ``as available''
basis. To the extent Interconnection Customer wants to receive
Energy Resource Interconnection Service, Transmission Provider shall
construct facilities identified in Attachment A.
4.1.1.2 Transmission Delivery Service Implications. Under Energy
Resource Interconnection Service, Interconnection Customer will be
eligible to inject power from the Large Generating Facility into and
deliver power across the interconnecting Transmission Provider's
Transmission System on an ``as available'' basis up to the amount of
MWs identified in the applicable stability and steady state studies
to the extent the upgrades initially required to qualify for Energy
Resource Interconnection Service have been constructed. Where
eligible to do so (e.g., PJM, ISO-NE, NYISO), Interconnection
Customer may place a bid to sell into the market up to the maximum
identified Large Generating Facility output, subject to any
conditions specified in the interconnection service approval, and
the Large Generating Facility will be dispatched to the extent
Interconnection Customer's bid clears. In all other instances, no
transmission delivery service from the Large Generating Facility is
assured, but Interconnection Customer may obtain Point-to-Point
Transmission Service, Network Integration Transmission Service, or
be used for secondary network transmission service, pursuant to
Transmission Provider's Tariff, up to the maximum output identified
in the stability and steady state studies. In those instances, in
order for Interconnection Customer to obtain the right to deliver or
inject energy beyond the Large Generating Facility Point of
Interconnection or to improve its ability to do so, transmission
delivery service must be obtained pursuant to the provisions of
Transmission Provider's Tariff. The Interconnection Customer's
ability to inject its Large Generating Facility output beyond the
Point of Interconnection, therefore, will depend on the existing
capacity of Transmission Provider's Transmission System at such time
as a transmission service request is made that would accommodate
such delivery. The provision of firm Point-to-Point Transmission
Service or Network Integration Transmission Service may require the
construction of additional Network Upgrades.
4.1.2 Network Resource Interconnection Service
4.1.2.1 The Product. Transmission Provider must conduct the
necessary studies and construct the Network Upgrades needed to
integrate the Large Generating Facility (1) in a manner comparable
to that in which Transmission Provider integrates its generating
facilities to serve native load customers; or (2) in an ISO or RTO
with market based congestion management, in the same manner as all
Network Resources. To the extent Interconnection Customer wants to
receive Network Resource Interconnection Service, Transmission
Provider shall construct the facilities identified in Attachment A
to this LGIA.
4.1.2.2 Transmission Delivery Service Implications. Network
Resource Interconnection Service allows Interconnection Customer's
Large Generating Facility to be designated by any Network Customer
under the Tariff on Transmission Provider's Transmission System as a
Network Resource, up to the Large Generating Facility's full output,
on the same basis as existing Network Resources interconnected to
Transmission Provider's Transmission System, and to be studied as a
Network Resource on the assumption that such a designation will
occur. Although Network Resource Interconnection Service does not
convey a reservation of transmission service, any Network Customer
under the Tariff can utilize its network service under the Tariff to
obtain delivery of energy from the interconnected Interconnection
Customer's Large Generating Facility in the same manner as it
accesses Network Resources. A Large Generating Facility receiving
Network Resource Interconnection Service may also be used to provide
Ancillary Services after technical studies and/or periodic analyses
are performed with respect to the Large Generating Facility's
ability to provide any applicable Ancillary Services, provided that
such studies and analyses have been or would be required in
connection with the provision of such Ancillary Services by any
existing Network Resource. However, if an Interconnection Customer's
Large Generating Facility has not been designated as a Network
Resource by any load, it cannot be required to provide Ancillary
Services except to the extent such requirements extend to all
generating facilities that are similarly situated. The provision of
Network Integration Transmission Service or firm Point-to-Point
Transmission Service may require additional studies and the
construction of additional upgrades. Because such studies and
upgrades would be associated with a request for delivery service
under the Tariff, cost responsibility for the studies and upgrades
would be in accordance with FERC's policy for pricing transmission
delivery services.
Network Resource Interconnection Service does not necessarily
provide Interconnection Customer with the capability to physically
deliver the output of its Large Generating Facility to any
particular load on Transmission Provider's Transmission System
without incurring congestion costs. In the event of transmission
constraints on Transmission Provider's Transmission System,
Interconnection Customer's Large Generating Facility shall be
subject to the applicable congestion management procedures in
Transmission Provider's Transmission System in the same manner as
Network Resources.
There is no requirement either at the time of study or
interconnection, or at any point in the future, that Interconnection
Customer's Large Generating Facility be designated as a
[[Page 61317]]
Network Resource by a Network Service Customer under the Tariff or
that Interconnection Customer identify a specific buyer (or sink).
To the extent a Network Customer does designate the Large Generating
Facility as a Network Resource, it must do so pursuant to
Transmission Provider's Tariff.
Once an Interconnection Customer satisfies the requirements for
obtaining Network Resource Interconnection Service, any future
transmission service request for delivery from the Large Generating
Facility within Transmission Provider's Transmission System of any
amount of capacity and/or energy, up to the amount initially
studied, will not require that any additional studies be performed
or that any further upgrades associated with such Large Generating
Facility be undertaken, regardless of whether or not such Large
Generating Facility is ever designated by a Network Customer as a
Network Resource and regardless of changes in ownership of the Large
Generating Facility. However, the reduction or elimination of
congestion or redispatch costs may require additional studies and
the construction of additional upgrades.
To the extent Interconnection Customer enters into an
arrangement for long term transmission service for deliveries from
the Large Generating Facility outside Transmission Provider's
Transmission System, such request may require additional studies and
upgrades in order for Transmission Provider to grant such request.
4.2 Provision of Service. Transmission Provider shall provide
Interconnection Service for the Large Generating Facility at the
Point of Interconnection.
4.3 Performance Standards. Each Party shall perform all of its
obligations under this LGIA in accordance with Applicable Laws and
Regulations, Applicable Reliability Standards, and Good Utility
Practice, and to the extent a Party is required or prevented or
limited in taking any action by such regulations and standards, such
Party shall not be deemed to be in Breach of this LGIA for its
compliance therewith. If such Party is a Transmission Provider or
Transmission Owner, then that Party shall amend the LGIA and submit
the amendment to FERC for approval.
4.4 No Transmission Delivery Service. The execution of this LGIA
does not constitute a request for, nor the provision of, any
transmission delivery service under Transmission Provider's Tariff,
and does not convey any right to deliver electricity to any specific
customer or Point of Delivery.
4.5 Interconnection Customer Provided Services. The services
provided by Interconnection Customer under this LGIA are set forth
in Article 9.6 and Article 13.5.1. Interconnection Customer shall be
paid for such services in accordance with Article 11.6.
Article 5. Interconnection Facilities Engineering, Procurement, &
Construction
5.1 Options. Unless otherwise mutually agreed to between the
Parties, Interconnection Customer shall select the In-Service Date,
Initial Synchronization Date, and Commercial Operation Date; and
either the Standard Option or Alternate Option set forth below, and
such dates and selected option shall be set forth in Appendix B,
Milestones. At the same time, Interconnection Customer shall
indicate whether it elects to exercise the Option to Build set forth
in Article 5.1.3 below. If the dates designated by Interconnection
Customer are not acceptable to Transmission Provider, Transmission
Provider shall so notify Interconnection Customer within thirty (30)
Calendar Days. Upon receipt of the notification that Interconnection
Customer's designated dates are not acceptable to Transmission
Provider, the Interconnection Customer shall notify Transmission
Provider within thirty (30) Calendar Days whether it elects to
exercise the Option to Build if it has not already elected to
exercise the Option to Build.
5.1.1 Standard Option. Transmission Provider shall design,
procure, and construct Transmission Provider's Interconnection
Facilities and Network Upgrades, using Reasonable Efforts to
complete Transmission Provider's Interconnection Facilities and
Network Upgrades by the dates set forth in Appendix B, Milestones.
Transmission Provider shall not be required to undertake any action
which is inconsistent with its standard safety practices, its
material and equipment specifications, its design criteria and
construction procedures, its labor agreements, and Applicable Laws
and Regulations. In the event Transmission Provider reasonably
expects that it will not be able to complete Transmission Provider's
Interconnection Facilities and Network Upgrades by the specified
dates, Transmission Provider shall promptly provide written notice
to Interconnection Customer and shall undertake Reasonable Efforts
to meet the earliest dates thereafter.
5.1.2 Alternate Option. If the dates designated by
Interconnection Customer are acceptable to Transmission Provider,
Transmission Provider shall so notify Interconnection Customer
within thirty (30) Calendar Days, and shall assume responsibility
for the design, procurement and construction of Transmission
Provider's Interconnection Facilities by the designated dates.
If Transmission Provider subsequently fails to complete
Transmission Provider's Interconnection Facilities by the In-Service
Date, to the extent necessary to provide back feed power; or fails
to complete Network Upgrades by the Initial Synchronization Date to
the extent necessary to allow for Trial Operation at full power
output, unless other arrangements are made by the Parties for such
Trial Operation; or fails to complete the Network Upgrades by the
Commercial Operation Date, as such dates are reflected in Appendix
B, Milestones; Transmission Provider shall pay Interconnection
Customer liquidated damages in accordance with Article 5.3,
Liquidated Damages, provided, however, the dates designated by
Interconnection Customer shall be extended day for day for each day
that the applicable RTO or ISO refuses to grant clearances to
install equipment.
5.1.3 Option to Build. Interconnection Customer shall have the
option to assume responsibility for the design, procurement and
construction of Transmission Provider's Interconnection Facilities
and Stand Alone Network Upgrades on the dates specified in Article
5.1.2. Transmission Provider and Interconnection Customer must agree
as to what constitutes Stand Alone Network Upgrades and identify
such Stand Alone Network Upgrades in Appendix A. Except for Stand
Alone Network Upgrades, Interconnection Customer shall have no right
to construct Network Upgrades under this option.
5.1.4 Negotiated Option. If the dates designated by
Interconnection Customer are not acceptable to Transmission
Provider, the Parties shall in good faith attempt to negotiate terms
and conditions (including revision of the specified dates and
liquidated damages, the provision of incentives, or the procurement
and construction of all facilities other than Transmission
Provider's Interconnection Facilities and Stand Alone Network
Upgrades if the Interconnection Customer elects to exercise the
Option to Build under Article 5.1.3). If the Parties are unable to
reach agreement on such terms and conditions, then pursuant to
Article 5.1.1 (Standard Option), Transmission Provider shall assume
responsibility for the design, procurement and construction of all
facilities other than Transmission Provider's Interconnection
Facilities and Stand Alone Network Upgrades if the Interconnection
Customer elects to exercise the Option to Build.
5.2 General Conditions Applicable to Option to Build. If
Interconnection Customer assumes responsibility for the design,
procurement and construction of Transmission Provider's
Interconnection Facilities and Stand Alone Network Upgrades,
(1) Interconnection Customer shall engineer, procure equipment,
and construct Transmission Provider's Interconnection Facilities and
Stand Alone Network Upgrades (or portions thereof) using Good
Utility Practice and using standards and specifications provided in
advance by Transmission Provider;
(2) Interconnection Customer's engineering, procurement and
construction of Transmission Provider's Interconnection Facilities
and Stand Alone Network Upgrades shall comply with all requirements
of law to which Transmission Provider would be subject in the
engineering, procurement or construction of Transmission Provider's
Interconnection Facilities and Stand Alone Network Upgrades;
(3) Transmission Provider shall review and approve the
engineering design, equipment acceptance tests, and the construction
of Transmission Provider's Interconnection Facilities and Stand
Alone Network Upgrades;
(4) prior to commencement of construction, Interconnection
Customer shall provide to Transmission Provider a schedule for
construction of Transmission Provider's Interconnection Facilities
and Stand Alone Network Upgrades, and shall promptly respond to
requests for information from Transmission Provider;
(5) at any time during construction, Transmission Provider shall
have the right to
[[Page 61318]]
gain unrestricted access to Transmission Provider's Interconnection
Facilities and Stand Alone Network Upgrades and to conduct
inspections of the same;
(6) at any time during construction, should any phase of the
engineering, equipment procurement, or construction of Transmission
Provider's Interconnection Facilities and Stand Alone Network
Upgrades not meet the standards and specifications provided by
Transmission Provider, Interconnection Customer shall be obligated
to remedy deficiencies in that portion of Transmission Provider's
Interconnection Facilities and Stand Alone Network Upgrades;
(7) Interconnection Customer shall indemnify Transmission
Provider for claims arising from Interconnection Customer's
construction of Transmission Provider's Interconnection Facilities
and Stand Alone Network Upgrades under the terms and procedures
applicable to Article 18.1 Indemnity;
(8) Interconnection Customer shall transfer control of
Transmission Provider's Interconnection Facilities and Stand Alone
Network Upgrades to Transmission Provider;
(9) Unless Parties otherwise agree, Interconnection Customer
shall transfer ownership of Transmission Provider's Interconnection
Facilities and Stand-Alone Network Upgrades to Transmission
Provider;
(10) Transmission Provider shall approve and accept for
operation and maintenance Transmission Provider's Interconnection
Facilities and Stand Alone Network Upgrades to the extent
engineered, procured, and constructed in accordance with this
Article 5.2; and
(11) Interconnection Customer shall deliver to Transmission
Provider ``as-built'' drawings, information, and any other documents
that are reasonably required by Transmission Provider to assure that
the Interconnection Facilities and Stand-Alone Network Upgrades are
built to the standards and specifications required by Transmission
Provider.
(12) If Interconnection Customer exercises the Option to Build
pursuant to Article 5.1.3, Interconnection Customer shall pay
Transmission Provider the agreed upon amount of [$ PLACEHOLDER] for
Transmission Provider to execute the responsibilities enumerated to
Transmission Provider under Article 5.2. Transmission Provider shall
invoice Interconnection Customer for this total amount to be divided
on a monthly basis pursuant to Article 12.
5.3 Liquidated Damages. The actual damages to Interconnection
Customer, in the event Transmission Provider's Interconnection
Facilities or Network Upgrades are not completed by the dates
designated by Interconnection Customer and accepted by Transmission
Provider pursuant to subparagraphs 5.1.2 or 5.1.4, above, may
include Interconnection Customer's fixed operation and maintenance
costs and lost opportunity costs. Such actual damages are uncertain
and impossible to determine at this time. Because of such
uncertainty, any liquidated damages paid by Transmission Provider to
Interconnection Customer in the event that Transmission Provider
does not complete any portion of Transmission Provider's
Interconnection Facilities or Network Upgrades by the applicable
dates, shall be an amount equal to \1/2\ of 1 percent per day of the
actual cost of Transmission Provider's Interconnection Facilities
and Network Upgrades, in the aggregate, for which Transmission
Provider has assumed responsibility to design, procure and
construct.
However, in no event shall the total liquidated damages exceed
20 percent of the actual cost of Transmission Provider's
Interconnection Facilities and Network Upgrades for which
Transmission Provider has assumed responsibility to design, procure,
and construct. The foregoing payments will be made by Transmission
Provider to Interconnection Customer as just compensation for the
damages caused to Interconnection Customer, which actual damages are
uncertain and impossible to determine at this time, and as
reasonable liquidated damages, but not as a penalty or a method to
secure performance of this LGIA. Liquidated damages, when the
Parties agree to them, are the exclusive remedy for the Transmission
Provider's failure to meet its schedule.
No liquidated damages shall be paid to Interconnection Customer
if: (1) Interconnection Customer is not ready to commence use of
Transmission Provider's Interconnection Facilities or Network
Upgrades to take the delivery of power for the Large Generating
Facility's Trial Operation or to export power from the Large
Generating Facility on the specified dates, unless Interconnection
Customer would have been able to commence use of Transmission
Provider's Interconnection Facilities or Network Upgrades to take
the delivery of power for Large Generating Facility's Trial
Operation or to export power from the Large Generating Facility, but
for Transmission Provider's delay; (2) Transmission Provider's
failure to meet the specified dates is the result of the action or
inaction of Interconnection Customer or any other Interconnection
Customer who has entered into an LGIA with Transmission Provider or
any cause beyond Transmission Provider's reasonable control or
reasonable ability to cure; (3) the Interconnection Customer has
assumed responsibility for the design, procurement and construction
of Transmission Provider's Interconnection Facilities and Stand
Alone Network Upgrades; or (4) the Parties have otherwise agreed.
5.4 Power System Stabilizers. [The]Interconnection Customer
shall procure, install, maintain and operate Power System
Stabilizers in accordance with the guidelines and procedures
established by the [Applicable Reliability Council]Electric
Reliability Organization. Transmission Provider reserves the right
to reasonably establish minimum acceptable settings for any
installed Power System Stabilizers, subject to the design and
operating limitations of the Large Generating Facility. If the Large
Generating Facility's Power System Stabilizers are removed from
service or not capable of automatic operation, Interconnection
Customer shall immediately notify Transmission Provider's system
operator, or its designated representative. The requirements of this
paragraph shall not apply to wind generators.
5.5 Equipment Procurement. If responsibility for construction of
Transmission Provider's Interconnection Facilities or Network
Upgrades is to be borne by Transmission Provider, then Transmission
Provider shall commence design of Transmission Provider's
Interconnection Facilities or Network Upgrades and procure necessary
equipment as soon as practicable after all of the following
conditions are satisfied, unless the Parties otherwise agree in
writing:
5.5.1 Transmission Provider has completed the Facilities Study
pursuant to the Facilities Study Agreement;
5.5.2 Transmission Provider has received written authorization
to proceed with design and procurement from Interconnection Customer
by the date specified in Appendix B, Milestones; and
5.5.3 Interconnection Customer has provided security to
Transmission Provider in accordance with Article 11.5 by the dates
specified in Appendix B, Milestones.
5.6 Construction Commencement. Transmission Provider shall
commence construction of Transmission Provider's Interconnection
Facilities and Network Upgrades for which it is responsible as soon
as practicable after the following additional conditions are
satisfied:
5.6.1 Approval of the appropriate Governmental Authority has
been obtained for any facilities requiring regulatory approval;
5.6.2 Necessary real property rights and rights-of-way have been
obtained, to the extent required for the construction of a discrete
aspect of Transmission Provider's Interconnection Facilities and
Network Upgrades;
5.6.3 Transmission Provider has received written authorization
to proceed with construction from Interconnection Customer by the
date specified in Appendix B, Milestones; and
5.6.4 Interconnection Customer has provided security to
Transmission Provider in accordance with Article 11.5 by the dates
specified in Appendix B, Milestones.
5.7 Work Progress. The Parties will keep each other advised
periodically as to the progress of their respective design,
procurement and construction efforts. Either Party may, at any time,
request a progress report from the other Party. If, at any time,
Interconnection Customer determines that the completion of
Transmission Provider's Interconnection Facilities will not be
required until after the specified In-Service Date, Interconnection
Customer will provide written notice to Transmission Provider of
such later date upon which the completion of Transmission Provider's
Interconnection Facilities will be required.
5.8 Information Exchange. As soon as reasonably practicable
after the Effective Date, the Parties shall exchange information
regarding the design and compatibility of the Parties'
Interconnection Facilities and compatibility of the Interconnection
Facilities with Transmission Provider's
[[Page 61319]]
Transmission System, and shall work diligently and in good faith to
make any necessary design changes.
5.9 Other Interconnection Options.
5.9.1 Limited Operation. If any of Transmission Provider's
Interconnection Facilities or Network Upgrades are not reasonably
expected to be completed prior to the Commercial Operation Date of
the Large Generating Facility, Transmission Provider shall, upon the
request and at the expense of Interconnection Customer, perform
operating studies on a timely basis to determine the extent to which
the Large Generating Facility and Interconnection Customer's
Interconnection Facilities may operate prior to the completion of
Transmission Provider's Interconnection Facilities or Network
Upgrades consistent with Applicable Laws and Regulations, Applicable
Reliability Standards, Good Utility Practice, and this LGIA.
Transmission Provider shall permit Interconnection Customer to
operate the Large Generating Facility and Interconnection Customer's
Interconnection Facilities in accordance with the results of such
studies.
5.9.2 Provisional Interconnection Service. Upon the request of
Interconnection Customer, and prior to completion of requisite
Interconnection Facilities, Network Upgrades, Distribution Upgrades,
or System Protection Facilities Transmission Provider may execute a
Provisional Large Generator Interconnection Agreement or
Interconnection Customer may request the filing of an unexecuted
Provisional Large Generator Interconnection Agreement with the
Interconnection Customer for limited Interconnection Service at the
discretion of Transmission Provider based upon an evaluation that
will consider the results of available studies. Transmission
Provider shall determine, through available studies or additional
studies as necessary, whether stability, short circuit, thermal,
and/or voltage issues would arise if Interconnection Customer
interconnects without modifications to the Generating Facility or
Transmission System. Transmission Provider shall determine whether
any Interconnection Facilities, Network Upgrades, Distribution
Upgrades, or System Protection Facilities that are necessary to meet
the requirements of [NERC] the Electric Reliability Organization, or
any applicable Regional Entity for the interconnection of a new,
modified and/or expanded Generating Facility are in place prior to
the commencement of Interconnection Service from the Generating
Facility. Where available studies indicate that such,
Interconnection Facilities, Network Upgrades, Distribution Upgrades,
and/or System Protection Facilities that are required for the
interconnection of a new, modified and/or expanded Generating
Facility are not currently in place, Transmission Provider will
perform a study, at the Interconnection Customer's expense, to
confirm the facilities that are required for Provisional
Interconnection Service. The maximum permissible output of the
Generating Facility in the Provisional Large Generator
Interconnection Agreement shall be studied and updated [on a
frequency determined by Transmission Provider and at the
Interconnection Customer's expense]. Interconnection Customer
assumes all risk and liabilities with respect to changes between the
Provisional Large Generator Interconnection Agreement and the Large
Generator Interconnection Agreement, including changes in output
limits and Interconnection Facilities, Network Upgrades,
Distribution Upgrades, and/or System Protection Facilities cost
responsibilities.
5.10 Interconnection Customer's Interconnection Facilities
('ICIF'). Interconnection Customer shall, at its expense, design,
procure, construct, own and install the ICIF, as set forth in
Appendix A, Interconnection Facilities, Network Upgrades and
Distribution Upgrades.
5.10.1 Interconnection Customer's Interconnection Facility
Specifications. Interconnection Customer shall submit initial
specifications for the ICIF, including System Protection Facilities,
to Transmission Provider at least one hundred eighty (180) Calendar
Days prior to the Initial Synchronization Date; and final
specifications for review and comment at least ninety (90) Calendar
Days prior to the Initial Synchronization Date. Transmission
Provider shall review such specifications to ensure that the ICIF
are compatible with the technical specifications, operational
control, and safety requirements of Transmission Provider and
comment on such specifications within thirty (30) Calendar Days of
Interconnection Customer's submission. All specifications provided
hereunder shall be deemed confidential.
5.10.2 Transmission Provider's Review. Transmission Provider's
review of Interconnection Customer's final specifications shall not
be construed as confirming, endorsing, or providing a warranty as to
the design, fitness, safety, durability or reliability of the Large
Generating Facility, or the ICIF. Interconnection Customer shall
make such changes to the ICIF as may reasonably be required by
Transmission Provider, in accordance with Good Utility Practice, to
ensure that the ICIF are compatible with the technical
specifications, operational control, and safety requirements of
Transmission Provider.
5.10.3 ICIF Construction. The ICIF shall be designed and
constructed in accordance with Good Utility Practice. Within one
hundred twenty (120) Calendar Days after the Commercial Operation
Date, unless the Parties agree on another mutually acceptable
deadline, Interconnection Customer shall deliver to Transmission
Provider ``as-built'' drawings, information and documents for the
ICIF, such as: a one-line diagram, a site plan showing the Large
Generating Facility and the ICIF, plan and elevation drawings
showing the layout of the ICIF, a relay functional diagram, relaying
AC and DC schematic wiring diagrams and relay settings for all
facilities associated with Interconnection Customer's step-up
transformers, the facilities connecting the Large Generating
Facility to the step-up transformers and the ICIF, and the
impedances (determined by factory tests) for the associated step-up
transformers and the Large Generating Facility. The Interconnection
Customer shall provide Transmission Provider specifications for the
excitation system, automatic voltage regulator, Large Generating
Facility control and protection settings, transformer tap settings,
and communications, if applicable.
5.11 Transmission Provider's Interconnection Facilities
Construction. Transmission Provider's Interconnection Facilities
shall be designed and constructed in accordance with Good Utility
Practice. Upon request, within one hundred twenty (120) Calendar
Days after the Commercial Operation Date, unless the Parties agree
on another mutually acceptable deadline, Transmission Provider shall
deliver to Interconnection Customer the following ``as-built''
drawings, information and documents for Transmission Provider's
Interconnection Facilities [include appropriate drawings and relay
diagrams].
Transmission Provider will obtain control of Transmission
Provider's Interconnection Facilities and Stand Alone Network
Upgrades upon completion of such facilities.
5.12 Access Rights. Upon reasonable notice and supervision by a
Party, and subject to any required or necessary regulatory
approvals, a Party (``Granting Party'') shall furnish at no cost to
the other Party (``Access Party'') any rights of use, licenses,
rights of way and easements with respect to lands owned or
controlled by the Granting Party, its agents (if allowed under the
applicable agency agreement), or any Affiliate, that are necessary
to enable the Access Party to obtain ingress and egress to
construct, operate, maintain, repair, test (or witness testing),
inspect, replace or remove facilities and equipment to: (i)
interconnect the Large Generating Facility with the Transmission
System; (ii) operate and maintain the Large Generating Facility, the
Interconnection Facilities and the Transmission System; and (iii)
disconnect or remove the Access Party's facilities and equipment
upon termination of this LGIA. In exercising such licenses, rights
of way and easements, the Access Party shall not unreasonably
disrupt or interfere with normal operation of the Granting Party's
business and shall adhere to the safety rules and procedures
established in advance, as may be changed from time to time, by the
Granting Party and provided to the Access Party.
5.13 Lands of Other Property Owners. If any part of Transmission
Provider or Transmission Owner's Interconnection Facilities and/or
Network Upgrades is to be installed on property owned by persons
other than Interconnection Customer or Transmission Provider or
Transmission Owner, Transmission Provider or Transmission Owner
shall at Interconnection Customer's expense use efforts, similar in
nature and extent to those that it typically undertakes on its own
behalf or on behalf of its Affiliates, including use of its eminent
domain authority, and to the extent consistent with state law, to
procure from such persons any rights of use, licenses, rights of way
and easements that are necessary to construct, operate, maintain,
test, inspect, replace or remove Transmission
[[Page 61320]]
Provider or Transmission Owner's Interconnection Facilities and/or
Network Upgrades upon such property.
5.14 Permits. Transmission Provider or Transmission Owner and
Interconnection Customer shall cooperate with each other in good
faith in obtaining all permits, licenses, and authorizations that
are necessary to accomplish the interconnection in compliance with
Applicable Laws and Regulations. With respect to this paragraph,
Transmission Provider or Transmission Owner shall provide permitting
assistance to Interconnection Customer comparable to that provided
to Transmission Provider's own, or an Affiliate's generation.
5.15 Early Construction of Base Case Facilities. Interconnection
Customer may request Transmission Provider to construct, and
Transmission Provider shall construct, using Reasonable Efforts to
accommodate Interconnection Customer's In-Service Date, all or any
portion of any Network Upgrades required for Interconnection
Customer to be interconnected to the Transmission System which are
included in the Base Case of the Facilities Study for
Interconnection Customer, and which also are required to be
constructed for another Interconnection Customer, but where such
construction is not scheduled to be completed in time to achieve
Interconnection Customer's In-Service Date.
5.16 Suspension. Interconnection Customer reserves the right,
upon written notice to Transmission Provider, to suspend at any time
all work by Transmission Provider associated with the construction
and installation of Transmission Provider's Interconnection
Facilities and/or Network Upgrades required under this LGIA with the
condition that Transmission System shall be left in a safe and
reliable condition in accordance with Good Utility Practice and
Transmission Provider's safety and reliability criteria. In such
event, Interconnection Customer shall be responsible for all
reasonable and necessary costs which Transmission Provider (i) has
incurred pursuant to this LGIA prior to the suspension and (ii)
incurs in suspending such work, including any costs incurred to
perform such work as may be necessary to ensure the safety of
persons and property and the integrity of the Transmission System
during such suspension and, if applicable, any costs incurred in
connection with the cancellation or suspension of material,
equipment and labor contracts which Transmission Provider cannot
reasonably avoid; provided, however, that prior to canceling or
suspending any such material, equipment or labor contract,
Transmission Provider shall obtain Interconnection Customer's
authorization to do so.
Transmission Provider shall invoice Interconnection Customer for
such costs pursuant to Article 12 and shall use due diligence to
minimize its costs. In the event Interconnection Customer suspends
work by Transmission Provider required under this LGIA pursuant to
this Article 5.16, and has not requested Transmission Provider to
recommence the work required under this LGIA on or before the
expiration of three (3) years following commencement of such
suspension, this LGIA shall be deemed terminated. The three-year
period shall begin on the date the suspension is requested, or the
date of the written notice to Transmission Provider, if no effective
date is specified.
5.17 Taxes.
5.17.1 Interconnection Customer Payments Not Taxable. The
Parties intend that all payments or property transfers made by
Interconnection Customer to Transmission Provider for the
installation of Transmission Provider's Interconnection Facilities
and the Network Upgrades shall be non-taxable, either as
contributions to capital, or as an advance, in accordance with the
Internal Revenue Code and any applicable state income tax laws and
shall not be taxable as contributions in aid of construction or
otherwise under the Internal Revenue Code and any applicable state
income tax laws.
5.17.2 Representations and Covenants. In accordance with IRS
Notice 2001-82 and IRS Notice 88-129, Interconnection Customer
represents and covenants that (i) ownership of the electricity
generated at the Large Generating Facility will pass to another
party prior to the transmission of the electricity on the
Transmission System, (ii) for income tax purposes, the amount of any
payments and the cost of any property transferred to Transmission
Provider for Transmission Provider's Interconnection Facilities will
be capitalized by Interconnection Customer as an intangible asset
and recovered using the straight-line method over a useful life of
twenty (20) years, and (iii) any portion of Transmission Provider's
Interconnection Facilities that is a ``dual-use intertie,'' within
the meaning of IRS Notice 88-129, is reasonably expected to carry
only a de minimis amount of electricity in the direction of the
Large Generating Facility. For this purpose, ``de minimis amount''
means no more than 5 percent of the total power flows in both
directions, calculated in accordance with the ``5 percent test'' set
forth in IRS Notice 88-129. This is not intended to be an exclusive
list of the relevant conditions that must be met to conform to IRS
requirements for non-taxable treatment.
At Transmission Provider's request, Interconnection Customer
shall provide Transmission Provider with a report from an
independent engineer confirming its representation in clause (iii),
above. Transmission Provider represents and covenants that the cost
of Transmission Provider's Interconnection Facilities paid for by
Interconnection Customer will have no net effect on the base upon
which rates are determined.
5.17.3 Indemnification for the Cost Consequences of Current Tax
Liability Imposed Upon the Transmission Provider. Notwithstanding
Article 5.17.1, Interconnection Customer shall protect, indemnify
and hold harmless Transmission Provider from the cost consequences
of any current tax liability imposed against Transmission Provider
as the result of payments or property transfers made by
Interconnection Customer to Transmission Provider under this LGIA
for Interconnection Facilities, as well as any interest and
penalties, other than interest and penalties attributable to any
delay caused by Transmission Provider.
Transmission Provider shall not include a gross-up for the cost
consequences of any current tax liability in the amounts it charges
Interconnection Customer under this LGIA unless (i) Transmission
Provider has determined, in good faith, that the payments or
property transfers made by Interconnection Customer to Transmission
Provider should be reported as income subject to taxation or (ii)
any Governmental Authority directs Transmission Provider to report
payments or property as income subject to taxation; provided,
however, that Transmission Provider may require Interconnection
Customer to provide security for Interconnection Facilities, in a
form reasonably acceptable to Transmission Provider (such as a
parental guarantee or a letter of credit), in an amount equal to the
cost consequences of any current tax liability under this Article
5.17. Interconnection Customer shall reimburse Transmission Provider
for such costs on a fully grossed-up basis, in accordance with
Article 5.17.4, within thirty (30) Calendar Days of receiving
written notification from Transmission Provider of the amount due,
including detail about how the amount was calculated.
The indemnification obligation shall terminate at the earlier of
(1) the expiration of the ten year testing period and the applicable
statute of limitation, as it may be extended by Transmission
Provider upon request of the IRS, to keep these years open for audit
or adjustment, or (2) the occurrence of a subsequent taxable event
and the payment of any related indemnification obligations as
contemplated by this Article 5.17.
5.17.4 Tax Gross-Up Amount. Interconnection Customer's liability
for the cost consequences of any current tax liability under this
Article 5.17 shall be calculated on a fully grossed-up basis. Except
as may otherwise be agreed to by the parties, this means that
Interconnection Customer will pay Transmission Provider, in addition
to the amount paid for the Interconnection Facilities and Network
Upgrades, an amount equal to (1) the current taxes imposed on
Transmission Provider (``Current Taxes'') on the excess of (a) the
gross income realized by Transmission Provider as a result of
payments or property transfers made by Interconnection Customer to
Transmission Provider under this LGIA (without regard to any
payments under this Article 5.17) (the ``Gross Income Amount'') over
(b) the present value of future tax deductions for depreciation that
will be available as a result of such payments or property transfers
(the ``Present Value Depreciation Amount''), plus (2) an additional
amount sufficient to permit Transmission Provider to receive and
retain, after the payment of all Current Taxes, an amount equal to
the net amount described in clause (1).
For this purpose, (i) Current Taxes shall be computed based on
Transmission Provider's composite federal and state tax rates at the
time the payments or property transfers are received and
Transmission Provider will be treated as being subject to tax at the
highest marginal rates in effect at that time (the ``Current Tax
Rate''), and (ii) the Present Value Depreciation Amount shall be
[[Page 61321]]
computed by discounting Transmission Provider's anticipated tax
depreciation deductions as a result of such payments or property
transfers by Transmission Provider's current weighted average cost
of capital. Thus, the formula for calculating Interconnection
Customer's liability to Transmission Owner pursuant to this Article
5.17.4 can be expressed as follows: (Current Tax Rate x (Gross
Income Amount--Present Value of Tax Depreciation))/(1-Current Tax
Rate). Interconnection Customer's estimated tax liability in the
event taxes are imposed shall be stated in Appendix A,
Interconnection Facilities, Network Upgrades and Distribution
Upgrades.
5.17.5 Private Letter Ruling or Change or Clarification of Law.
At Interconnection Customer's request and expense, Transmission
Provider shall file with the IRS a request for a private letter
ruling as to whether any property transferred or sums paid, or to be
paid, by Interconnection Customer to Transmission Provider under
this LGIA are subject to federal income taxation. Interconnection
Customer will prepare the initial draft of the request for a private
letter ruling, and will certify under penalties of perjury that all
facts represented in such request are true and accurate to the best
of Interconnection Customer's knowledge. Transmission Provider and
Interconnection Customer shall cooperate in good faith with respect
to the submission of such request.
Transmission Provider shall keep Interconnection Customer fully
informed of the status of such request for a private letter ruling
and shall execute either a privacy act waiver or a limited power of
attorney, in a form acceptable to the IRS, that authorizes
Interconnection Customer to participate in all discussions with the
IRS regarding such request for a private letter ruling. Transmission
Provider shall allow Interconnection Customer to attend all meetings
with IRS officials about the request and shall permit
Interconnection Customer to prepare the initial drafts of any
follow-up letters in connection with the request.
5.17.6 Subsequent Taxable Events. If, within 10 years from the
date on which the relevant Transmission Provider's Interconnection
Facilities are placed in service, (i) Interconnection Customer
Breaches the covenants contained in Article 5.17.2, (ii) a
``disqualification event'' occurs within the meaning of IRS Notice
88-129, or (iii) this LGIA terminates and Transmission Provider
retains ownership of the Interconnection Facilities and Network
Upgrades, Interconnection Customer shall pay a tax gross-up for the
cost consequences of any current tax liability imposed on
Transmission Provider, calculated using the methodology described in
Article 5.17.4 and in accordance with IRS Notice 90-60.
5.17.7 Contests. In the event any Governmental Authority
determines that Transmission Provider's receipt of payments or
property constitutes income that is subject to taxation,
Transmission Provider shall notify Interconnection Customer, in
writing, within thirty (30) Calendar Days of receiving notification
of such determination by a Governmental Authority. Upon the timely
written request by Interconnection Customer and at Interconnection
Customer's sole expense, Transmission Provider may appeal, protest,
seek abatement of, or otherwise oppose such determination. Upon
Interconnection Customer's written request and sole expense,
Transmission Provider may file a claim for refund with respect to
any taxes paid under this Article 5.17, whether or not it has
received such a determination. Transmission Provider reserves the
right to make all decisions with regard to the prosecution of such
appeal, protest, abatement or other contest, including the selection
of counsel and compromise or settlement of the claim, but
Transmission Provider shall keep Interconnection Customer informed,
shall consider in good faith suggestions from Interconnection
Customer about the conduct of the contest, and shall reasonably
permit Interconnection Customer or an Interconnection Customer
representative to attend contest proceedings.
Interconnection Customer shall pay to Transmission Provider on a
periodic basis, as invoiced by Transmission Provider, Transmission
Provider's documented reasonable costs of prosecuting such appeal,
protest, abatement or other contest. At any time during the contest,
Transmission Provider may agree to a settlement either with
Interconnection Customer's consent or after obtaining written advice
from nationally recognized tax counsel, selected by Transmission
Provider, but reasonably acceptable to Interconnection Customer,
that the proposed settlement represents a reasonable settlement
given the hazards of litigation. Interconnection Customer's
obligation shall be based on the amount of the settlement agreed to
by Interconnection Customer, or if a higher amount, so much of the
settlement that is supported by the written advice from nationally
recognized tax counsel selected under the terms of the preceding
sentence. The settlement amount shall be calculated on a fully
grossed-up basis to cover any related cost consequences of the
current tax liability. Any settlement without Interconnection
Customer's consent or such written advice will relieve
Interconnection Customer from any obligation to indemnify
Transmission Provider for the tax at issue in the contest.
5.17.8 Refund. In the event that (a) a private letter ruling is
issued to Transmission Provider which holds that any amount paid or
the value of any property transferred by Interconnection Customer to
Transmission Provider under the terms of this LGIA is not subject to
federal income taxation, (b) any legislative change or
administrative announcement, notice, ruling or other determination
makes it reasonably clear to Transmission Provider in good faith
that any amount paid or the value of any property transferred by
Interconnection Customer to Transmission Provider under the terms of
this LGIA is not taxable to Transmission Provider, (c) any
abatement, appeal, protest, or other contest results in a
determination that any payments or transfers made by Interconnection
Customer to Transmission Provider are not subject to federal income
tax, or (d) if Transmission Provider receives a refund from any
taxing authority for any overpayment of tax attributable to any
payment or property transfer made by Interconnection Customer to
Transmission Provider pursuant to this LGIA, Transmission Provider
shall promptly refund to Interconnection Customer the following:
(i) any payment made by Interconnection Customer under this
Article 5.17 for taxes that is attributable to the amount determined
to be non-taxable, together with interest thereon,
(ii) interest on any amounts paid by Interconnection Customer to
Transmission Provider for such taxes which Transmission Provider did
not submit to the taxing authority, calculated in accordance with
the methodology set forth in FERC's regulations at 18 CFR
35.19a(a)(2)(iii) from the date payment was made by Interconnection
Customer to the date Transmission Provider refunds such payment to
Interconnection Customer, and
(iii) with respect to any such taxes paid by Transmission
Provider, any refund or credit Transmission Provider receives or to
which it may be entitled from any Governmental Authority, interest
(or that portion thereof attributable to the payment described in
clause (i), above) owed to Transmission Provider for such
overpayment of taxes (including any reduction in interest otherwise
payable by Transmission Provider to any Governmental Authority
resulting from an offset or credit); provided, however, that
Transmission Provider will remit such amount promptly to
Interconnection Customer only after and to the extent that
Transmission Provider has received a tax refund, credit or offset
from any Governmental Authority for any applicable overpayment of
income tax related to Transmission Provider's Interconnection
Facilities.
The intent of this provision is to leave the Parties, to the
extent practicable, in the event that no taxes are due with respect
to any payment for Interconnection Facilities and Network Upgrades
hereunder, in the same position they would have been in had no such
tax payments been made.
5.17.9 Taxes Other Than Income Taxes. Upon the timely request by
Interconnection Customer, and at Interconnection Customer's sole
expense, Transmission Provider may appeal, protest, seek abatement
of, or otherwise contest any tax (other than federal or state income
tax) asserted or assessed against Transmission Provider for which
Interconnection Customer may be required to reimburse Transmission
Provider under the terms of this LGIA. Interconnection Customer
shall pay to Transmission Provider on a periodic basis, as invoiced
by Transmission Provider, Transmission Provider's documented
reasonable costs of prosecuting such appeal, protest, abatement, or
other contest. Interconnection Customer and Transmission Provider
shall cooperate in good faith with respect to any such contest.
Unless the payment of such taxes is a prerequisite to an appeal or
abatement or cannot be deferred, no amount shall be payable by
Interconnection Customer to Transmission Provider for such taxes
until they are assessed by a final, non-appealable order by any
court or agency of competent
[[Page 61322]]
jurisdiction. In the event that a tax payment is withheld and
ultimately due and payable after appeal, Interconnection Customer
will be responsible for all taxes, interest and penalties, other
than penalties attributable to any delay caused by Transmission
Provider.
5.17.10 Transmission Owners Who Are Not Transmission Providers.
If Transmission Provider is not the same entity as the Transmission
Owner, then (i) all references in this Article 5.17 to Transmission
Provider shall be deemed also to refer to and to include the
Transmission Owner, as appropriate, and (ii) this LGIA shall not
become effective until such Transmission Owner shall have agreed in
writing to assume all of the duties and obligations of Transmission
Provider under this Article 5.17 of this LGIA.
5.18 Tax Status. Each Party shall cooperate with the other to
maintain the other Party's tax status. Nothing in this LGIA is
intended to adversely affect any Transmission Provider's tax exempt
status with respect to the issuance of bonds including, but not
limited to, Local Furnishing Bonds.
5.19 Modification.
5.19.1 General. Either Party may undertake modifications to its
facilities. If a Party plans to undertake a modification that
reasonably may be expected to affect the other Party's facilities,
that Party shall provide to the other Party sufficient information
regarding such modification so that the other Party may evaluate the
potential impact of such modification prior to commencement of the
work. Such information shall be deemed to be confidential hereunder
and shall include information concerning the timing of such
modifications and whether such modifications are expected to
interrupt the flow of electricity from the Large Generating
Facility. The Party desiring to perform such work shall provide the
relevant drawings, plans, and specifications to the other Party at
least ninety (90) Calendar Days in advance of the commencement of
the work or such shorter period upon which the Parties may agree,
which agreement shall not unreasonably be withheld, conditioned or
delayed.
In the case of Large Generating Facility modifications that do
not require Interconnection Customer to submit an Interconnection
Request, Transmission Provider shall provide, within thirty (30)
Calendar Days (or such other time as the Parties may agree), an
estimate of any additional modifications to the Transmission System,
Transmission Provider's Interconnection Facilities or Network
Upgrades necessitated by such Interconnection Customer modification
and a good faith estimate of the costs thereof.
5.19.2 Standards. Any additions, modifications, or replacements
made to a Party's facilities shall be designed, constructed and
operated in accordance with this LGIA and Good Utility Practice.
5.19.3 Modification Costs. Interconnection Customer shall not be
directly assigned for the costs of any additions, modifications, or
replacements that Transmission Provider makes to Transmission
Provider's Interconnection Facilities or the Transmission System to
facilitate the interconnection of a third party to Transmission
Provider's Interconnection Facilities or the Transmission System, or
to provide transmission service to a third party under Transmission
Provider's Tariff. Interconnection Customer shall be responsible for
the costs of any additions, modifications, or replacements to
Interconnection Customer's Interconnection Facilities that may be
necessary to maintain or upgrade such Interconnection Customer's
Interconnection Facilities consistent with Applicable Laws and
Regulations, Applicable Reliability Standards or Good Utility
Practice.
Article 6. Testing and Inspection
6.1 Pre-Commercial Operation Date Testing and Modifications.
Prior to the Commercial Operation Date, Transmission Provider shall
test Transmission Provider's Interconnection Facilities and Network
Upgrades and Interconnection Customer shall test the Large
Generating Facility and Interconnection Customer's Interconnection
Facilities to ensure their safe and reliable operation. Similar
testing may be required after initial operation. Each Party shall
make any modifications to its facilities that are found to be
necessary as a result of such testing. Interconnection Customer
shall bear the cost of all such testing and modifications.
Interconnection Customer shall generate test energy at the Large
Generating Facility only if it has arranged for the delivery of such
test energy.
6.2 Post-Commercial Operation Date Testing and Modifications.
Each Party shall at its own expense perform routine inspection and
testing of its facilities and equipment in accordance with Good
Utility Practice as may be necessary to ensure the continued
interconnection of the Large Generating Facility with the
Transmission System in a safe and reliable manner. Each Party shall
have the right, upon advance written notice, to require reasonable
additional testing of the other Party's facilities, at the
requesting Party's expense, as may be in accordance with Good
Utility Practice.
6.3 Right to Observe Testing. Each Party shall notify the other
Party in advance of its performance of tests of its Interconnection
Facilities. The other Party has the right, at its own expense, to
observe such testing.
6.4 Right to Inspect. Each Party shall have the right, but shall
have no obligation to: (i) observe the other Party's tests and/or
inspection of any of its System Protection Facilities and other
protective equipment, including Power System Stabilizers; (ii)
review the settings of the other Party's System Protection
Facilities and other protective equipment; and (iii) review the
other Party's maintenance records relative to the Interconnection
Facilities, the System Protection Facilities and other protective
equipment. A Party may exercise these rights from time to time as it
deems necessary upon reasonable notice to the other Party. The
exercise or non-exercise by a Party of any such rights shall not be
construed as an endorsement or confirmation of any element or
condition of the Interconnection Facilities or the System Protection
Facilities or other protective equipment or the operation thereof,
or as a warranty as to the fitness, safety, desirability, or
reliability of same. Any information that a Party obtains through
the exercise of any of its rights under this Article 6.4 shall be
deemed to be Confidential Information and treated pursuant to
Article 22 of this LGIA.
Article 7. Metering
7.1 General. Each Party shall comply with the [Applicable
Reliability Council] Electric Reliability Organization requirements.
Unless otherwise agreed by the Parties, Transmission Provider shall
install Metering Equipment at the Point of Interconnection prior to
any operation of the Large Generating Facility and shall own,
operate, test and maintain such Metering Equipment. Power flows to
and from the Large Generating Facility shall be measured at or, at
Transmission Provider's option, compensated to, the Point of
Interconnection. Transmission Provider shall provide metering
quantities, in analog and/or digital form, to Interconnection
Customer upon request. Interconnection Customer shall bear all
reasonable documented costs associated with the purchase,
installation, operation, testing and maintenance of the Metering
Equipment.
7.2 Check Meters. Interconnection Customer, at its option and
expense, may install and operate, on its premises and on its side of
the Point of Interconnection, one or more check meters to check
Transmission Provider's meters. Such check meters shall be for check
purposes only and shall not be used for the measurement of power
flows for purposes of this LGIA, except as provided in Article 7.4
below. The check meters shall be subject at all reasonable times to
inspection and examination by Transmission Provider or its designee.
The installation, operation and maintenance thereof shall be
performed entirely by Interconnection Customer in accordance with
Good Utility Practice.
7.3 Standards. Transmission Provider shall install, calibrate,
and test revenue quality Metering Equipment in accordance with
applicable ANSI standards.
7.4 Testing of Metering Equipment. Transmission Provider shall
inspect and test all Transmission Provider-owned Metering Equipment
upon installation and at least once every two (2) years thereafter.
If requested to do so by Interconnection Customer, Transmission
Provider shall, at Interconnection Customer's expense, inspect or
test Metering Equipment more frequently than every two (2) years.
Transmission Provider shall give reasonable notice of the time when
any inspection or test shall take place, and Interconnection
Customer may have representatives present at the test or inspection.
If at any time Metering Equipment is found to be inaccurate or
defective, it shall be adjusted, repaired or replaced at
Interconnection Customer's expense, in order to provide accurate
metering, unless the inaccuracy or defect is due to Transmission
Provider's failure to maintain, then Transmission Provider shall
pay. If Metering Equipment fails to register,
[[Page 61323]]
or if the measurement made by Metering Equipment during a test
varies by more than two percent from the measurement made by the
standard meter used in the test, Transmission Provider shall adjust
the measurements by correcting all measurements for the period
during which Metering Equipment was in error by using
Interconnection Customer's check meters, if installed. If no such
check meters are installed or if the period cannot be reasonably
ascertained, the adjustment shall be for the period immediately
preceding the test of the Metering Equipment equal to one-half the
time from the date of the last previous test of the Metering
Equipment.
7.5 Metering Data. At Interconnection Customer's expense, the
metered data shall be telemetered to one or more locations
designated by Transmission Provider and one or more locations
designated by Interconnection Customer. Such telemetered data shall
be used, under normal operating conditions, as the official
measurement of the amount of energy delivered from the Large
Generating Facility to the Point of Interconnection.
Article 8. Communications
8.1 Interconnection Customer Obligations. Interconnection
Customer shall maintain satisfactory operating communications with
Transmission Provider's Transmission System dispatcher or
representative designated by Transmission Provider. Interconnection
Customer shall provide standard voice line, dedicated voice line and
facsimile communications at its Large Generating Facility control
room or central dispatch facility through use of either the public
telephone system, or a voice communications system that does not
rely on the public telephone system. Interconnection Customer shall
also provide the dedicated data circuit(s) necessary to provide
Interconnection Customer data to Transmission Provider as set forth
in Appendix D, Security Arrangements Details. The data circuit(s)
shall extend from the Large Generating Facility to the location(s)
specified by Transmission Provider. Any required maintenance of such
communications equipment shall be performed by Interconnection
Customer. Operational communications shall be activated and
maintained under, but not be limited to, the following events:
system paralleling or separation, scheduled and unscheduled
shutdowns, equipment clearances, and hourly and daily load data.
8.2 Remote Terminal Unit. Prior to the Initial Synchronization
Date of the Large Generating Facility, a Remote Terminal Unit, or
equivalent data collection and transfer equipment acceptable to the
Parties, shall be installed by Interconnection Customer, or by
Transmission Provider at Interconnection Customer's expense, to
gather accumulated and instantaneous data to be telemetered to the
location(s) designated by Transmission Provider through use of a
dedicated point-to-point data circuit(s) as indicated in Article
8.1. The communication protocol for the data circuit(s) shall be
specified by Transmission Provider. Instantaneous bi-directional
analog real power and reactive power flow information must be
telemetered directly to the location(s) specified by Transmission
Provider.
Each Party will promptly advise the other Party if it detects or
otherwise learns of any metering, telemetry or communications
equipment errors or malfunctions that require the attention and/or
correction by the other Party. The Party owning such equipment shall
correct such error or malfunction as soon as reasonably feasible.
8.3 No Annexation. Any and all equipment placed on the premises
of a Party shall be and remain the property of the Party providing
such equipment regardless of the mode and manner of annexation or
attachment to real property, unless otherwise mutually agreed by the
Parties.
8.4 Provision of Data from a Variable Energy Resource. The
Interconnection Customer whose Generating Facility contains at least
one[is] Variable Energy Resource shall provide meteorological and
forced outage data to the Transmission Provider to the extent
necessary for the Transmission Provider's development and deployment
of power production forecasts for that class of Variable Energy
Resources. The Interconnection Customer with a Variable Energy
Resource having wind as the energy source, at a minimum, will be
required to provide the Transmission Provider with site-specific
meteorological data including: temperature, wind speed, wind
direction, and atmospheric pressure. The Interconnection Customer
with a Variable Energy Resource having solar as the energy source,
at a minimum, will be required to provide the Transmission Provider
with site-specific meteorological data including: temperature,
atmospheric pressure, and irradiance. The Transmission Provider and
Interconnection Customer whose Generating Facility contains [is] a
Variable Energy Resource shall mutually agree to any additional
meteorological data that are required for the development and
deployment of a power production forecast. The Interconnection
Customer whose Generating Facility contains [is] a Variable Energy
Resource also shall submit data to the Transmission Provider
regarding all forced outages to the extent necessary for the
Transmission Provider's development and deployment of power
production forecasts for that class of Variable Energy Resources.
The exact specifications of the meteorological and forced outage
data to be provided by the Interconnection Customer to the
Transmission Provider, including the frequency and timing of data
submittals, shall be made taking into account the size and
configuration of the Variable Energy Resource, its characteristics,
location, and its importance in maintaining generation resource
adequacy and transmission system reliability in its area. All
requirements for meteorological and forced outage data must be
commensurate with the power production forecasting employed by the
Transmission Provider. Such requirements for meteorological and
forced outage data are set forth in Appendix C, Interconnection
Details, of this LGIA, as they may change from time to time.
Article 9. Operations
9.1 General. Each Party shall comply with the[Applicable
Reliability Council] Electric Reliability Organization requirements.
Each Party shall provide to the other Party all information that may
reasonably be required by the other Party to comply with Applicable
Laws and Regulations and Applicable Reliability Standards.
9.2 [Control Area]Balancing Authority Area Notification. At
least three months before Initial Synchronization Date,
Interconnection Customer shall notify Transmission Provider in
writing of the [Control Area]Balancing Authority Area in which the
Large Generating Facility will be located. If Interconnection
Customer elects to locate the Large Generating Facility in a[Control
Area] Balancing Authority Area other than the [Control
Area]Balancing Authority Area in which the Large Generating Facility
is physically located, and if permitted to do so by the relevant
transmission tariffs, all necessary arrangements, including but not
limited to those set forth in Article 7 and Article 8 of this LGIA,
and remote [Control Area]Balancing Authority Area generator
interchange agreements, if applicable, and the appropriate measures
under such agreements, shall be executed and implemented prior to
the placement of the Large Generating Facility in the other [Control
Area]Balancing Authority Area.
9.3 Transmission Provider Obligations. Transmission Provider
shall cause the Transmission System and Transmission Provider's
Interconnection Facilities to be operated, maintained and controlled
in a safe and reliable manner and in accordance with this LGIA.
Transmission Provider may provide operating instructions to
Interconnection Customer consistent with this LGIA and Transmission
Provider's operating protocols and procedures as they may change
from time to time. Transmission Provider will consider changes to
its operating protocols and procedures proposed by Interconnection
Customer.
9.4 Interconnection Customer Obligations. Interconnection
Customer shall at its own expense operate, maintain and control the
Large Generating Facility and Interconnection Customer's
Interconnection Facilities in a safe and reliable manner and in
accordance with this LGIA. Interconnection Customer shall operate
the Large Generating Facility and Interconnection Customer's
Interconnection Facilities in accordance with all applicable
requirements of the [Control Area]Balancing Authority Area of which
it is part, as such requirements are set forth in Appendix C,
Interconnection Details, of this LGIA. Appendix C, Interconnection
Details, will be modified to reflect changes to the requirements as
they may change from time to time. Either Party may request that the
other Party provide copies of the requirements set forth in Appendix
C, Interconnection Details, of this LGIA.
9.5 Start-Up and Synchronization. Consistent with the Parties'
mutually acceptable procedures, Interconnection Customer is
responsible for the proper synchronization of the Large Generating
[[Page 61324]]
Facility to Transmission Provider's Transmission System.
9.6 Reactive Power and Primary Frequency Response.
9.6.1 Power Factor Design Criteria.
9.6.1.1 Synchronous Generation. Interconnection Customer shall
design the Large Generating Facility to maintain a composite power
delivery at continuous rated power output at the Point of
Interconnection at a power factor within the range of 0.95 leading
to 0.95 lagging, unless [the]Transmission Provider has established
different requirements that apply to all synchronous generators in
the [Control Area]Balancing Authority Area on a comparable basis.
9.6.1.2 Non-Synchronous Generation. Interconnection Customer
shall design the Large Generating Facility to maintain a composite
power delivery at continuous rated power output at the high-side of
the generator substation at a power factor within the range of 0.95
leading to 0.95 lagging, unless[the] Transmission Provider has
established a different power factor range that applies to all non-
synchronous generators in the [Control Area]Balancing Authority Area
on a comparable basis. This power factor range standard shall be
dynamic and can be met using, for example, power electronics
designed to supply this level of reactive capability (taking into
account any limitations due to voltage level, real power output,
etc.) or fixed and switched capacitors, or a combination of the two.
This requirement shall only apply to newly interconnecting non-
synchronous generators that have not yet executed a Facilities Study
Agreement as of the effective date of the Final rule establishing
this requirement (Order No. 827).
9.6.2 Voltage Schedules. Once Interconnection Customer has
synchronized the Large Generating Facility with the Transmission
System, Transmission Provider shall require Interconnection Customer
to operate the Large Generating Facility to produce or absorb
reactive power within the design limitations of the Large Generating
Facility set forth in Article 9.6.1 (Power Factor Design Criteria).
Transmission Provider's voltage schedules shall treat all sources of
reactive power in the [Control Area]Balancing Authority Area in an
equitable and not unduly discriminatory manner. Transmission
Provider shall exercise Reasonable Efforts to provide
Interconnection Customer with such schedules at least one (1) day in
advance, and may make changes to such schedules as necessary to
maintain the reliability of the Transmission System. Interconnection
Customer shall operate the Large Generating Facility to maintain the
specified output voltage or power factor at the Point of
Interconnection within the design limitations of the Large
Generating Facility set forth in Article 9.6.1 (Power Factor Design
Criteria). If Interconnection Customer is unable to maintain the
specified voltage or power factor, it shall promptly notify the
System Operator.
9.6.2.1 Voltage Regulators. Whenever the Large Generating
Facility is operated in parallel with the Transmission System and
voltage regulators are capable of operation, Interconnection
Customer shall operate the Large Generating Facility with its
voltage regulators in automatic operation. If the Large Generating
Facility's voltage regulators are not capable of such automatic
operation, Interconnection Customer shall immediately notify
Transmission Provider's system operator, or its designated
representative, and ensure that such Large Generating Facility's
reactive power production or absorption (measured in MVARs) are
within the design capability of the Large Generating Facility's
generating unit(s) and steady state stability limits.
Interconnection Customer shall not cause its Large Generating
Facility to disconnect automatically or instantaneously from the
Transmission System or trip any generating unit comprising the Large
Generating Facility for an under or over frequency condition unless
the abnormal frequency condition persists for a time period beyond
the limits set forth in ANSI/IEEE Standard C37.106, or such other
standard as applied to other generators in the [Control
Area]Balancing Authority Area on a comparable basis.
9.6.3 Payment for Reactive Power. Transmission Provider is
required to pay Interconnection Customer for reactive power that
Interconnection Customer provides or absorbs from the Large
Generating Facility when Transmission Provider requests
Interconnection Customer to operate its Large Generating Facility
outside the range specified in Article 9.6.1, provided that if
Transmission Provider pays its own or affiliated generators for
reactive power service within the specified range, it must also pay
Interconnection Customer. Payments shall be pursuant to Article 11.6
or such other agreement to which the Parties have otherwise agreed.
9.6.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Large
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Large Generating Facility's
real power output in accordance with the droop and deadband
parameters and in the direction needed to correct frequency
deviations. Interconnection Customer is required to install a
governor or equivalent controls with the capability of operating:
(1) with a maximum 5 percent droop and 0.036 Hz
deadband; or (2) in accordance with the relevant droop, deadband,
and timely and sustained response settings from an approved [NERC]
Electric Reliability Organization [R]reliability [S]standard
providing for equivalent or more stringent parameters. The droop
characteristic shall be: (1) based on the nameplate capacity of the
Large Generating Facility, and shall be linear in the range of
frequencies between 59 to 61 Hz that are outside of the deadband
parameter; or (2) based an approved [NERC] Electric Reliability
Organization [R]reliability [S]standard providing for an equivalent
or more stringent parameter. The deadband parameter shall be: the
range of frequencies above and below nominal (60 Hz) in which the
governor or equivalent controls is not expected to adjust the Large
Generating Facility's real power output in response to frequency
deviations. The deadband shall be implemented: (1) without a step to
the droop curve, that is, once the frequency deviation exceeds the
deadband parameter, the expected change in the Large Generating
Facility's real power output in response to frequency deviations
shall start from zero and then increase (for under-frequency
deviations) or decrease (for over-frequency deviations) linearly in
proportion to the magnitude of the frequency deviation; or (2) in
accordance with an approved [NERC] Electric Reliability Organization
[R]reliability [S]standard providing for an equivalent or more
stringent parameter. Interconnection Customer shall notify
Transmission Provider that the primary frequency response capability
of the Large Generating Facility has been tested and confirmed
during commissioning. Once Interconnection Customer has synchronized
the Large Generating Facility with the Transmission System,
Interconnection Customer shall operate the Large Generating Facility
consistent with the provisions specified in Sections 9.6.4.1 and
9.6.4.2 of this Agreement. The primary frequency response
requirements contained herein shall apply to both synchronous and
non-synchronous Large Generating Facilities.
9.6.4.1 Governor or Equivalent Controls. Whenever the Large
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Large Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall: (1) in
coordination with Transmission Provider and/or the relevant
balancing authority, set the deadband parameter to: (1) a maximum of
0.036 Hz and set the droop parameter to a maximum of 5
percent; or (2) implement the relevant droop and deadband settings
from an approved [NERC] Electric Reliability Organization
[R]reliability [S]standard that provides for equivalent or more
stringent parameters. Interconnection Customer shall be required to
provide the status and settings of the governor or equivalent
controls to Transmission Provider and/or the relevant balancing
authority upon request. If Interconnection Customer needs to operate
the Large Generating Facility with its governor or equivalent
controls not in service, Interconnection Customer shall immediately
notify Transmission Provider and the relevant balancing authority,
and provide both with the following information: (1) the operating
status of the governor or equivalent controls (i.e., whether it is
currently out of service or when it will be taken out of service);
(2) the reasons for removing the governor or equivalent controls
from service; and (3) a reasonable estimate of when the governor or
equivalent controls will be returned to service. Interconnection
Customer shall make Reasonable Efforts to return its governor or
equivalent controls into service as soon as practicable.
Interconnection Customer shall make
[[Page 61325]]
Reasonable Efforts to keep outages of the Large Generating
Facility's governor or equivalent controls to a minimum whenever the
Large Generating Facility is operated in parallel with the
Transmission System.
9.6.4.2 Timely and Sustained Response. Interconnection Customer
shall ensure that the Large Generating Facility's real power
response to sustained frequency deviations outside of the deadband
setting is automatically provided and shall begin immediately after
frequency deviates outside of the deadband, and to the extent the
Large Generating Facility has operating capability in the direction
needed to correct the frequency deviation. Interconnection Customer
shall not block or otherwise inhibit the ability of the governor or
equivalent controls to respond and shall ensure that the response is
not inhibited, except under certain operational constraints
including, but not limited to, ambient temperature limitations,
physical energy limitations, outages of mechanical equipment, or
regulatory requirements. The Large Generating Facility shall sustain
the real power response at least until system frequency returns to a
value within the deadband setting of the governor or equivalent
controls. A Commission-approved [R]reliability [S]standard with
equivalent or more stringent requirements shall supersede the above
requirements.
9.6.4.3 Exemptions. Large Generating Facilities that are
regulated by the United States Nuclear Regulatory Commission shall
be exempt from Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this
Agreement. Large Generating Facilities that are behind the meter
generation that is sized-to-load (i.e., the thermal load and the
generation are near-balanced in real-time operation and the
generation is primarily controlled to maintain the unique thermal,
chemical, or mechanical output necessary for the operating
requirements of its host facility) shall be required to install
primary frequency response capability in accordance with the droop
and deadband capability requirements specified in Section 9.6.4, but
shall be otherwise exempt from the operating requirements in
Sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.4 of this Agreement.
9.6.4.4 Electric Storage Resources. Interconnection Customer
interconnecting a Generating Facility that contains an electric
storage resource shall establish an operating range in Appendix C of
its LGIA that specifies a minimum state of charge and a maximum
state of charge between which the electric storage resource will be
required to provide primary frequency response consistent with the
conditions set forth in Sections 9.6.4, 9.6.4.1, 9.6.4.2 and 9.6.4.3
of this Agreement. Appendix C shall specify whether the operating
range is static or dynamic, and shall consider (1) the expected
magnitude of frequency deviations in the interconnection; (2) the
expected duration that system frequency will remain outside of the
deadband parameter in the interconnection; (3) the expected
incidence of frequency deviations outside of the deadband parameter
in the interconnection; (4) the physical capabilities of the
electric storage resource; (5) operational limitations of the
electric storage resource due to manufacturer specifications; and
(6) any other relevant factors agreed to by Transmission Provider
and Interconnection Customer, and in consultation with the relevant
transmission owner or balancing authority as appropriate. If the
operating range is dynamic, then Appendix C must establish how
frequently the operating range will be reevaluated and the factors
that may be considered during its reevaluation.
Interconnection Customer's electric storage resource is required
to provide timely and sustained primary frequency response
consistent with Section 9.6.4.2 of this Agreement when it is online
and dispatched to inject electricity to the Transmission System and/
or receive electricity from the Transmission System. This excludes
circumstances when the electric storage resource is not dispatched
to inject electricity to the Transmission System and/or dispatched
to receive electricity from the Transmission System. If
Interconnection Customer's electric storage resource is charging at
the time of a frequency deviation outside of its deadband parameter,
it is to increase (for over-frequency deviations) or decrease (for
under-frequency deviations) the rate at which it is charging in
accordance with its droop parameter. Interconnection Customer's
electric storage resource is not required to change from charging to
discharging, or vice versa, unless the response necessitated by the
droop and deadband settings requires it to do so and it is
technically capable of making such a transition.
9.7 Outages and Interruptions.
9.7.1 Outages.
9.7.1.1 Outage Authority and Coordination. Each Party may in
accordance with Good Utility Practice in coordination with the other
Party remove from service any of its respective Interconnection
Facilities or Network Upgrades that may impact the other Party's
facilities as necessary to perform maintenance or testing or to
install or replace equipment. Absent an Emergency Condition, the
Party scheduling a removal of such facility(ies) from service will
use Reasonable Efforts to schedule such removal on a date and time
mutually acceptable to the Parties. In all circumstances, any Party
planning to remove such facility(ies) from service shall use
Reasonable Efforts to minimize the effect on the other Party of such
removal.
9.7.1.2 Outage Schedules. Transmission Provider shall post
scheduled outages of its transmission facilities on the OASIS.
Interconnection Customer shall submit its planned maintenance
schedules for the Large Generating Facility to Transmission Provider
for a minimum of a rolling twenty-four month period. Interconnection
Customer shall update its planned maintenance schedules as
necessary. Transmission Provider may request Interconnection
Customer to reschedule its maintenance as necessary to maintain the
reliability of the Transmission System; provided, however, adequacy
of generation supply shall not be a criterion in determining
Transmission System reliability. Transmission Provider shall
compensate Interconnection Customer for any additional direct costs
that Interconnection Customer incurs as a result of having to
reschedule maintenance, including any additional overtime, breaking
of maintenance contracts or other costs above and beyond the cost
Interconnection Customer would have incurred absent Transmission
Provider's request to reschedule maintenance. Interconnection
Customer will not be eligible to receive compensation, if during the
twelve (12) months prior to the date of the scheduled maintenance,
Interconnection Customer had modified its schedule of maintenance
activities.
9.7.1.3 Outage Restoration. If an outage on a Party's
Interconnection Facilities or Network Upgrades adversely affects the
other Party's operations or facilities, the Party that owns or
controls the facility that is out of service shall use Reasonable
Efforts to promptly restore such facility(ies) to a normal operating
condition consistent with the nature of the outage. The Party that
owns or controls the facility that is out of service shall provide
the other Party, to the extent such information is known,
information on the nature of the Emergency Condition, an estimated
time of restoration, and any corrective actions required. Initial
verbal notice shall be followed up as soon as practicable with
written notice explaining the nature of the outage.
9.7.2 Interruption of Service. If required by Good Utility
Practice to do so, Transmission Provider may require Interconnection
Customer to interrupt or reduce deliveries of electricity if such
delivery of electricity could adversely affect Transmission
Provider's ability to perform such activities as are necessary to
safely and reliably operate and maintain the Transmission System.
The following provisions shall apply to any interruption or
reduction permitted under this Article 9.7.2:
9.7.2.1 The interruption or reduction shall continue only for so
long as reasonably necessary under Good Utility Practice;
9.7.2.2 Any such interruption or reduction shall be made on an
equitable, non-discriminatory basis with respect to all generating
facilities directly connected to the Transmission System;
9.7.2.3 When the interruption or reduction must be made under
circumstances which do not allow for advance notice, Transmission
Provider shall notify Interconnection Customer by telephone as soon
as practicable of the reasons for the curtailment, interruption, or
reduction, and, if known, its expected duration. Telephone
notification shall be followed by written notification as soon as
practicable;
9.7.2.4 Except during the existence of an Emergency Condition,
when the interruption or reduction can be scheduled without advance
notice, Transmission Provider shall notify Interconnection Customer
in advance regarding the timing of such scheduling and further
notify Interconnection Customer of the expected duration.
Transmission Provider shall coordinate with Interconnection Customer
using Good Utility Practice to schedule the interruption or
reduction during periods of least impact to Interconnection Customer
and Transmission Provider;
[[Page 61326]]
9.7.2.5 The Parties shall cooperate and coordinate with each
other to the extent necessary in order to restore the Large
Generating Facility, Interconnection Facilities, and the
Transmission System to their normal operating state, consistent with
system conditions and Good Utility Practice.
9.7.3 [Under-Frequency and Over Frequency Conditions]Ride
Through Capability and Performance. The Transmission System is
designed to automatically activate a load-shed program as required
by the[Applicable Reliability Council]Electric Reliability
Organization in the event of an underfrequency system disturbance.
Interconnection Customer shall implement under-frequency and over-
frequency relay set points for the Large Generating Facility as
required by the [Applicable Reliability Council] Electric
Reliability Organization to ensure frequency ``ride through''
capability of the Transmission System. Large Generating Facility
response to frequency deviations of pre-determined magnitudes, both
under-frequency and over-frequency deviations, shall be studied and
coordinated with Transmission Provider in accordance with Good
Utility Practice. Interconnection Customer shall also implement
under-voltage and over-voltage relay set points, or equivalent
electronic controls, as required by the Electric Reliability
Organization to ensure voltage ``ride through'' capability of the
Transmission System. The term ``ride through'' as used herein shall
mean the ability of a Large Generating Facility to stay connected to
and synchronized with the Transmission System during system
disturbances within a range of under-frequency, [and]over-frequency,
under-voltage, and over-voltage conditions, in accordance with Good
Utility Practice and consistent with any standards and guidelines
that are applied to other Generating Facilities in the Balancing
Authority Area on a comparable basis. For abnormal frequency
conditions and voltage conditions within the ``no trip zone''
defined by Reliability Standard PRC-024-3 or successor mandatory
ride through reliability standards, the non-synchronous Large
Generating Facility must ensure that, within any physical
limitations of the Large Generating Facility, its control and
protection settings are configured or set to (1) continue active
power production during disturbance and post disturbance periods at
pre-disturbance levels, unless providing primary frequency response
or fast frequency response; (2) minimize reductions in active power
and remain within dynamic voltage and current limits, if reactive
power priority mode is enabled, unless providing primary frequency
response or fast frequency response; (3) not artificially limit
dynamic reactive power capability during disturbances; and (4)
return to pre-disturbance active power levels without artificial
ramp rate limits if active power is reduced, unless providing
primary frequency response or fast frequency response.
9.7.4 System Protection and Other Control Requirements.
9.7.4.1 System Protection Facilities. Interconnection Customer
shall, at its expense, install, operate and maintain System
Protection Facilities as a part of the Large Generating Facility or
Interconnection Customer's Interconnection Facilities. Transmission
Provider shall install at Interconnection Customer's expense any
System Protection Facilities that may be required on Transmission
Provider's Interconnection Facilities or the Transmission System as
a result of the interconnection of the Large Generating Facility and
Interconnection Customer's Interconnection Facilities.
9.7.4.2 Each Party's protection facilities shall be designed and
coordinated with other systems in accordance with Good Utility
Practice.
9.7.4.3 Each Party shall be responsible for protection of its
facilities consistent with Good Utility Practice.
9.7.4.4 Each Party's protective relay design shall incorporate
the necessary test switches to perform the tests required in Article
6. The required test switches will be placed such that they allow
operation of lockout relays while preventing breaker failure schemes
from operating and causing unnecessary breaker operations and/or the
tripping of Interconnection Customer's units.
9.7.4.5 Each Party will test, operate and maintain System
Protection Facilities in accordance with Good Utility Practice.
9.7.4.6 Prior to the In-Service Date, and again prior to the
Commercial Operation Date, each Party or its agent shall perform a
complete calibration test and functional trip test of the System
Protection Facilities. At intervals suggested by Good Utility
Practice and following any apparent malfunction of the System
Protection Facilities, each Party shall perform both calibration and
functional trip tests of its System Protection Facilities. These
tests do not require the tripping of any in-service generation unit.
These tests do, however, require that all protective relays and
lockout contacts be activated.
9.7.5 Requirements for Protection. In compliance with Good
Utility Practice, Interconnection Customer shall provide, install,
own, and maintain relays, circuit breakers and all other devices
necessary to remove any fault contribution of the Large Generating
Facility to any short circuit occurring on the Transmission System
not otherwise isolated by Transmission Provider's equipment, such
that the removal of the fault contribution shall be coordinated with
the protective requirements of the Transmission System. Such
protective equipment shall include, without limitation, a
disconnecting device or switch with load-interrupting capability
located between the Large Generating Facility and the Transmission
System at a site selected upon mutual agreement (not to be
unreasonably withheld, conditioned or delayed) of the Parties.
Interconnection Customer shall be responsible for protection of the
Large Generating Facility and Interconnection Customer's other
equipment from such conditions as negative sequence currents, over-
or under-frequency, sudden load rejection, over- or under-voltage,
and generator loss-of-field. Interconnection Customer shall be
solely responsible to disconnect the Large Generating Facility and
Interconnection Customer's other equipment if conditions on the
Transmission System could adversely affect the Large Generating
Facility.
9.7.6 Power Quality. Neither Party's facilities shall cause
excessive voltage flicker nor introduce excessive distortion to the
sinusoidal voltage or current waves as defined by ANSI Standard
C84.1-1989, in accordance with IEEE Standard 519, or any applicable
superseding electric industry standard. In the event of a conflict
between ANSI Standard C84.1-1989, or any applicable superseding
electric industry standard, ANSI Standard C84.1-1989, or the
applicable superseding electric industry standard, shall control.
9.8 Switching and Tagging Rules. Each Party shall provide the
other Party a copy of its switching and tagging rules that are
applicable to the other Party's activities. Such switching and
tagging rules shall be developed on a non-discriminatory basis. The
Parties shall comply with applicable switching and tagging rules, as
amended from time to time, in obtaining clearances for work or for
switching operations on equipment.
9.9 Use of Interconnection Facilities by Third Parties.
9.9.1 Purpose of Interconnection Facilities. Except as may be
required by Applicable Laws and Regulations, or as otherwise agreed
to among the Parties, the Interconnection Facilities shall be
constructed for the sole purpose of interconnecting the Large
Generating Facility to the Transmission System and shall be used for
no other purpose.
9.9.2 Third Party Users. If required by Applicable Laws and
Regulations or if the Parties mutually agree, such agreement not to
be unreasonably withheld, to allow one or more third parties to use
Transmission Provider's Interconnection Facilities, or any part
thereof, Interconnection Customer will be entitled to compensation
for the capital expenses it incurred in connection with the
Interconnection Facilities based upon the pro rata use of the
Interconnection Facilities by Transmission Provider, all third party
users, and Interconnection Customer, in accordance with Applicable
Laws and Regulations or upon some other mutually agreed upon
methodology. In addition, cost responsibility for ongoing costs,
including operation and maintenance costs associated with the
Interconnection Facilities, will be allocated between
Interconnection Customer and any third party users based upon the
pro rata use of the Interconnection Facilities by Transmission
Provider, all third party users, and Interconnection Customer, in
accordance with Applicable Laws and Regulations or upon some other
mutually agreed upon methodology. If the issue of such compensation
or allocation cannot be resolved through such negotiations, it shall
be submitted to FERC for resolution.
9.10 Disturbance Analysis Data Exchange. The Parties will
cooperate with one another in the analysis of disturbances to either
the Large Generating Facility or Transmission Provider's
Transmission System by gathering and providing access to any
information relating to any disturbance, including information from
oscillography, protective
[[Page 61327]]
relay targets, breaker operations and sequence of events records,
and any disturbance information required by Good Utility Practice.
Article 10. Maintenance
10.1 Transmission Provider Obligations. Transmission Provider
shall maintain the Transmission System and Transmission Provider's
Interconnection Facilities in a safe and reliable manner and in
accordance with this LGIA.
10.2 Interconnection Customer Obligations. Interconnection
Customer shall maintain the Large Generating Facility and
Interconnection Customer's Interconnection Facilities in a safe and
reliable manner and in accordance with this LGIA.
10.3 Coordination. The Parties shall confer regularly to
coordinate the planning, scheduling and performance of preventive
and corrective maintenance on the Large Generating Facility and the
Interconnection Facilities.
10.4 Secondary Systems. Each Party shall cooperate with the
other in the inspection, maintenance, and testing of control or
power circuits that operate below 600 volts, AC or DC, including,
but not limited to, any hardware, control or protective devices,
cables, conductors, electric raceways, secondary equipment panels,
transducers, batteries, chargers, and voltage and current
transformers that directly affect the operation of a Party's
facilities and equipment which may reasonably be expected to impact
the other Party. Each Party shall provide advance notice to the
other Party before undertaking any work on such circuits, especially
on electrical circuits involving circuit breaker trip and close
contacts, current transformers, or potential transformers.
10.5 Operating and Maintenance Expenses. Subject to the
provisions herein addressing the use of facilities by others, and
except for operations and maintenance expenses associated with
modifications made for providing interconnection or transmission
service to a third party and such third party pays for such
expenses, Interconnection Customer shall be responsible for all
reasonable expenses including overheads, associated with: (1)
owning, operating, maintaining, repairing, and replacing
Interconnection Customer's Interconnection Facilities; and (2)
operation, maintenance, repair and replacement of Transmission
Provider's Interconnection Facilities.
Article 11. Performance Obligation
11.1 Interconnection Customer Interconnection Facilities.
Interconnection Customer shall design, procure, construct, install,
own and/or control Interconnection Customer Interconnection
Facilities described in Appendix A, Interconnection Facilities,
Network Upgrades and Distribution Upgrades, at its sole expense.
11.2 Transmission Provider's Interconnection Facilities.
Transmission Provider or Transmission Owner shall design, procure,
construct, install, own and/or control the Transmission Provider's
Interconnection Facilities described in Appendix A, Interconnection
Facilities, Network Upgrades and Distribution Upgrades, at the sole
expense of the Interconnection Customer.
11.3 Network Upgrades and Distribution Upgrades. Transmission
Provider or Transmission Owner shall design, procure, construct,
install, and own the Network Upgrades and Distribution Upgrades
described in Appendix A, Interconnection Facilities, Network
Upgrades and Distribution Upgrades. [The]Interconnection Customer
shall be responsible for all costs related to Distribution Upgrades.
Unless Transmission Provider or Transmission Owner elects to fund
the capital for the Network Upgrades, they shall be solely funded by
Interconnection Customer.
11.4 Transmission Credits.
11.4.1 Repayment of Amounts Advanced for Network Upgrades.
Interconnection Customer shall be entitled to a cash repayment,
equal to the total amount paid to Transmission Provider and Affected
System Operator, if any, for the Network Upgrades, including any tax
gross-up or other tax-related payments associated with Network
Upgrades, and not refunded to Interconnection Customer pursuant to
Article 5.17.8 or otherwise, to be paid to Interconnection Customer
on a dollar-for-dollar basis for the non-usage sensitive portion of
transmission charges, as payments are made under Transmission
Provider's Tariff and Affected System's Tariff for transmission
services with respect to the Large Generating Facility. Any
repayment shall include interest calculated in accordance with the
methodology set forth in FERC's regulations at 18 CFR
35.19a(a)(2)(iii) from the date of any payment for Network Upgrades
through the date on which the Interconnection Customer receives a
repayment of such payment pursuant to this subparagraph.
Interconnection Customer may assign such repayment rights to any
person.
Notwithstanding the foregoing, Interconnection Customer,
Transmission Provider, and Affected System Operator may adopt any
alternative payment schedule that is mutually agreeable so long as
Transmission Provider and Affected System Operator take one of the
following actions no later than five years from the Commercial
Operation Date: (1) return to Interconnection Customer any amounts
advanced for Network Upgrades not previously repaid, or (2) declare
in writing that Transmission Provider or Affected System Operator
will continue to provide payments to Interconnection Customer on a
dollar-for-dollar basis for the non-usage sensitive portion of
transmission charges, or develop an alternative schedule that is
mutually agreeable and provides for the return of all amounts
advanced for Network Upgrades not previously repaid; however, full
reimbursement shall not extend beyond twenty (20) years from the
Commercial Operation Date.
If the Large Generating Facility fails to achieve commercial
operation, but it or another Generating Facility is later
constructed and makes use of the Network Upgrades, Transmission
Provider and Affected System Operator shall at that time reimburse
Interconnection Customer for the amounts advanced for the Network
Upgrades. Before any such reimbursement can occur, the
Interconnection Customer, or the entity that ultimately constructs
the Generating Facility, if different, is responsible for
identifying the entity to which reimbursement must be made.
11.4.2 Special Provisions for Affected Systems. Unless
Transmission Provider provides, under the LGIA, for the repayment of
amounts advanced to Affected System Operator for Network Upgrades,
Interconnection Customer and Affected System Operator shall enter
into an agreement that provides for such repayment. The agreement
shall specify the terms governing payments to be made by
Interconnection Customer to the Affected System Operator as well as
the repayment by the Affected System Operator.
11.4.3 Notwithstanding any other provision of this LGIA, nothing
herein shall be construed as relinquishing or foreclosing any
rights, including but not limited to firm transmission rights,
capacity rights, transmission congestion rights, or transmission
credits, that Interconnection Customer, shall be entitled to, now or
in the future under any other agreement or tariff as a result of, or
otherwise associated with, the transmission capacity, if any,
created by the Network Upgrades, including the right to obtain cash
reimbursements or transmission credits for transmission service that
is not associated with the Large Generating Facility.
11.5 Provision of Security. At least thirty (30) Calendar Days
prior to the commencement of the procurement, installation, or
construction of a discrete portion of a Transmission Provider's
Interconnection Facilities, Network Upgrades, or Distribution
Upgrades, Interconnection Customer shall provide Transmission
Provider, at Interconnection Customer's option, a guarantee, a
surety bond, letter of credit or other form of security that is
reasonably acceptable to Transmission Provider and is consistent
with the Uniform Commercial Code of the jurisdiction identified in
Article 14.2.1. Such security for payment, as specified in Appendix
B of this LGIA, shall be in an amount sufficient to cover the costs
for constructing, procuring and installing the applicable portion of
Transmission Provider's Interconnection Facilities, Network
Upgrades, or Distribution Upgrades and shall be reduced on a dollar-
for-dollar basis for payments made to Transmission Provider for
these purposes. Transmission Provider must use the LGIA Deposit
required in Section 11.3 of the LGIP before requiring
Interconnection Customer to submit security in addition to that LGIA
Deposit. Transmission Provider must specify, in Appendix B of this
LGIA, the dates for which Interconnection Customer must provide
additional security for construction of each discrete portion of
Transmission Provider's Interconnection Facilities, Network
Upgrades, or Distribution Upgrades and Interconnection Customer must
provide such additional security.
In addition:
11.5.1 The guarantee must be made by an entity that meets the
creditworthiness requirements of Transmission Provider, and contain
terms and conditions that guarantee payment of any amount that may
be due from
[[Page 61328]]
Interconnection Customer, up to an agreed-to maximum amount.
11.5.2 The letter of credit must be issued by a financial
institution reasonably acceptable to Transmission Provider and must
specify a reasonable expiration date.
11.5.3 The surety bond must be issued by an insurer reasonably
acceptable to Transmission Provider and must specify a reasonable
expiration date.
11.6 Interconnection Customer Compensation. If Transmission
Provider requests or directs Interconnection Customer to provide a
service pursuant to Articles 9.6.3 (Payment for Reactive Power), or
13.5.1 of this LGIA, Transmission Provider shall compensate
Interconnection Customer in accordance with Interconnection
Customer's applicable rate schedule then in effect unless the
provision of such service(s) is subject to an RTO or ISO FERC-
approved rate schedule. Interconnection Customer shall serve
Transmission Provider or RTO or ISO with any filing of a proposed
rate schedule at the time of such filing with FERC. To the extent
that no rate schedule is in effect at the time the Interconnection
Customer is required to provide or absorb any Reactive Power under
this LGIA, Transmission Provider agrees to compensate
Interconnection Customer in such amount as would have been due
Interconnection Customer had the rate schedule been in effect at the
time service commenced; provided, however, that such rate schedule
must be filed at FERC or other appropriate Governmental Authority
within sixty (60) Calendar Days of the commencement of service.
11.6.1 Interconnection Customer Compensation for Actions During
Emergency Condition. Transmission Provider or RTO or ISO shall
compensate Interconnection Customer for its provision of real and
reactive power and other Emergency Condition services that
Interconnection Customer provides to support the Transmission System
during an Emergency Condition in accordance with Article 11.6.
Article 12. Invoice
12.1 General. Each Party shall submit to the other Party, on a
monthly basis, invoices of amounts due for the preceding month. Each
invoice shall state the month to which the invoice applies and fully
describe the services and equipment provided. The Parties may
discharge mutual debts and payment obligations due and owing to each
other on the same date through netting, in which case all amounts a
Party owes to the other Party under this LGIA, including interest
payments or credits, shall be netted so that only the net amount
remaining due shall be paid by the owing Party.
12.2 Final Invoice. Within six months after completion of the
construction of Transmission Provider's Interconnection Facilities
and the Network Upgrades, Transmission Provider shall provide an
invoice of the final cost of the construction of Transmission
Provider's Interconnection Facilities and the Network Upgrades and
shall set forth such costs in sufficient detail to enable
Interconnection Customer to compare the actual costs with the
estimates and to ascertain deviations, if any, from the cost
estimates. Transmission Provider shall refund to Interconnection
Customer any amount by which the actual payment by Interconnection
Customer for estimated costs exceeds the actual costs of
construction within thirty (30) Calendar Days of the issuance of
such final construction invoice.
12.3 Payment. Invoices shall be rendered to the paying Party at
the address specified in Appendix F. The Party receiving the invoice
shall pay the invoice within thirty (30) Calendar Days of receipt.
All payments shall be made in immediately available funds payable to
the other Party, or by wire transfer to a bank named and account
designated by the invoicing Party. Payment of invoices by either
Party will not constitute a waiver of any rights or claims either
Party may have under this LGIA.
12.4 Disputes. In the event of a billing dispute between
Transmission Provider and Interconnection Customer, Transmission
Provider shall continue to provide Interconnection Service under
this LGIA as long as Interconnection Customer: (i) continues to make
all payments not in dispute; and (ii) pays to Transmission Provider
or into an independent escrow account the portion of the invoice in
dispute, pending resolution of such dispute. If Interconnection
Customer fails to meet these two requirements for continuation of
service, then Transmission Provider may provide notice to
Interconnection Customer of a Default pursuant to Article 17. Within
thirty (30) Calendar Days after the resolution of the dispute, the
Party that owes money to the other Party shall pay the amount due
with interest calculated in accord with the methodology set forth in
FERC's regulations at 18 CFR 35.19a(a)(2)(iii).
Article 13. Emergencies
13.1 Definition. ``Emergency Condition'' shall mean a condition
or situation: (i) that in the judgment of the Party making the claim
is imminently likely to endanger life or property; or (ii) that, in
the case of Transmission Provider, is imminently likely (as
determined in a non-discriminatory manner) to cause a material
adverse effect on the security of, or damage to the Transmission
System, Transmission Provider's Interconnection Facilities or the
Transmission Systems of others to which the Transmission System is
directly connected; or (iii) that, in the case of Interconnection
Customer, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the
security of, or damage to, the Large Generating Facility or
Interconnection Customer's Interconnection Facilities' System
restoration and black start shall be considered Emergency
Conditions; provided, that Interconnection Customer is not obligated
by this LGIA to possess black start capability.
13.2 Obligations. Each Party shall comply with the Emergency
Condition procedures of the applicable ISO/RTO, [NERC,] the
[Applicable Reliability Council]Electric Reliability Organization,
Applicable Laws and Regulations, and any emergency procedures agreed
to by the Joint Operating Committee.
13.3 Notice. Transmission Provider shall notify Interconnection
Customer promptly when it becomes aware of an Emergency Condition
that affects Transmission Provider's Interconnection Facilities or
the Transmission System that may reasonably be expected to affect
Interconnection Customer's operation of the Large Generating
Facility or Interconnection Customer's Interconnection Facilities.
Interconnection Customer shall notify Transmission Provider promptly
when it becomes aware of an Emergency Condition that affects the
Large Generating Facility or Interconnection Customer's
Interconnection Facilities that may reasonably be expected to affect
the Transmission System or Transmission Provider's Interconnection
Facilities. To the extent information is known, the notification
shall describe the Emergency Condition, the extent of the damage or
deficiency, the expected effect on the operation of Interconnection
Customer's or Transmission Provider's facilities and operations, its
anticipated duration and the corrective action taken and/or to be
taken. The initial notice shall be followed as soon as practicable
with written notice.
13.4 Immediate Action. Unless, in Interconnection Customer's
reasonable judgment, immediate action is required, Interconnection
Customer shall obtain the consent of Transmission Provider, such
consent to not be unreasonably withheld, prior to performing any
manual switching operations at the Large Generating Facility or
Interconnection Customer's Interconnection Facilities in response to
an Emergency Condition either declared by Transmission Provider or
otherwise regarding the Transmission System.
13.5 Transmission Provider Authority.
13.5.1 General. Transmission Provider may take whatever actions
or inactions with regard to the Transmission System or Transmission
Provider's Interconnection Facilities it deems necessary during an
Emergency Condition in order to (i) preserve public health and
safety, (ii) preserve the reliability of the Transmission System or
Transmission Provider's Interconnection Facilities, (iii) limit or
prevent damage, and (iv) expedite restoration of service.
Transmission Provider shall use Reasonable Efforts to minimize
the effect of such actions or inactions on the Large Generating
Facility or Interconnection Customer's Interconnection Facilities.
Transmission Provider may, on the basis of technical considerations,
require the Large Generating Facility to mitigate an Emergency
Condition by taking actions necessary and limited in scope to remedy
the Emergency Condition, including, but not limited to, directing
Interconnection Customer to shut-down, start-up, increase or
decrease the real or reactive power output of the Large Generating
Facility; implementing a reduction or disconnection pursuant to
Article 13.5.2; directing Interconnection Customer to assist with
blackstart (if available) or restoration efforts; or altering the
outage schedules of the Large Generating Facility and
Interconnection Customer's Interconnection Facilities.
Interconnection Customer shall comply with all of Transmission
Provider's operating
[[Page 61329]]
instructions concerning Large Generating Facility real power and
reactive power output within the manufacturer's design limitations
of the Large Generating Facility's equipment that is in service and
physically available for operation at the time, in compliance with
Applicable Laws and Regulations.
13.5.2 Reduction and Disconnection. Transmission Provider may
reduce Interconnection Service or disconnect the Large Generating
Facility or Interconnection Customer's Interconnection Facilities,
when such, reduction or disconnection is necessary under Good
Utility Practice due to Emergency Conditions. These rights are
separate and distinct from any right of curtailment of Transmission
Provider pursuant to Transmission Provider's Tariff. When
Transmission Provider can schedule the reduction or disconnection in
advance, Transmission Provider shall notify Interconnection Customer
of the reasons, timing and expected duration of the reduction or
disconnection. Transmission Provider shall coordinate with
Interconnection Customer using Good Utility Practice to schedule the
reduction or disconnection during periods of least impact to
Interconnection Customer and Transmission Provider. Any reduction or
disconnection shall continue only for so long as reasonably
necessary under Good Utility Practice. The Parties shall cooperate
with each other to restore the Large Generating Facility, the
Interconnection Facilities, and the Transmission System to their
normal operating state as soon as practicable consistent with Good
Utility Practice.
13.6 Interconnection Customer Authority. Consistent with Good
Utility Practice and the LGIA and the LGIP, Interconnection Customer
may take actions or inactions with regard to the Large Generating
Facility or Interconnection Customer's Interconnection Facilities
during an Emergency Condition in order to (i) preserve public health
and safety, (ii) preserve the reliability of the Large Generating
Facility or Interconnection Customer's Interconnection Facilities,
(iii) limit or prevent damage, and (iv) expedite restoration of
service. Interconnection Customer shall use Reasonable Efforts to
minimize the effect of such actions or inactions on the Transmission
System and Transmission Provider's Interconnection Facilities.
Transmission Provider shall use Reasonable Efforts to assist
Interconnection Customer in such actions.
13.7 Limited Liability. Except as otherwise provided in Article
11.6.1 of this LGIA, neither Party shall be liable to the other for
any action it takes in responding to an Emergency Condition so long
as such action is made in good faith and is consistent with Good
Utility Practice.
Article 14. Regulatory Requirements and Governing Law
14.1 Regulatory Requirements. Each Party's obligations under
this LGIA shall be subject to its receipt of any required approval
or certificate from one or more Governmental Authorities in the form
and substance satisfactory to the applying Party, or the Party
making any required filings with, or providing notice to, such
Governmental Authorities, and the expiration of any time period
associated therewith. Each Party shall in good faith seek and use
its Reasonable Efforts to obtain such other approvals. Nothing in
this LGIA shall require Interconnection Customer to take any action
that could result in its inability to obtain, or its loss of, status
or exemption under the Federal Power Act, the Public Utility Holding
Company Act of 1935, as amended, or the Public Utility Regulatory
Policies Act of 1978.
14.2 Governing Law.
14.2.1 The validity, interpretation and performance of this LGIA
and each of its provisions shall be governed by the laws of the
state where the Point of Interconnection is located, without regard
to its conflicts of law principles.
14.2.2 This LGIA is subject to all Applicable Laws and
Regulations.
14.2.3 Each Party expressly reserves the right to seek changes
in, appeal, or otherwise contest any laws, orders, rules, or
regulations of a Governmental Authority.
Article 15. Notices
15.1 General. Unless otherwise provided in this LGIA, any
notice, demand or request required or permitted to be given by
either Party to the other and any instrument required or permitted
to be tendered or delivered by either Party in writing to the other
shall be effective when delivered and may be so given, tendered or
delivered, by recognized national courier, or by depositing the same
with the United States Postal Service with postage prepaid, for
delivery by certified or registered mail, addressed to the Party, or
personally delivered to the Party, at the address set out in
Appendix F, Addresses for Delivery of Notices and Billings.
Either Party may change the notice information in this LGIA by
giving five (5) Business Days written notice prior to the effective
date of the change.
15.2 Billings and Payments. Billings and payments shall be sent
to the addresses set out in Appendix F.
15.3 Alternative Forms of Notice. Any notice or request required
or permitted to be given by a Party to the other and not required by
this Agreement to be given in writing may be so given by telephone,
facsimile or email to the telephone numbers and email addresses set
out in Appendix F.
15.4 Operations and Maintenance Notice. Each Party shall notify
the other Party in writing of the identity of the person(s) that it
designates as the point(s) of contact with respect to the
implementation of Articles 9 and 10.
Article 16. Force Majeure
16.1 Force Majeure.
16.1.1 Economic hardship is not considered a Force Majeure
event.
16.1.2 Neither Party shall be considered to be in Default with
respect to any obligation hereunder, (including obligations under
Article 4), other than the obligation to pay money when due, if
prevented from fulfilling such obligation by Force Majeure. A Party
unable to fulfill any obligation hereunder (other than an obligation
to pay money when due) by reason of Force Majeure shall give notice
and the full particulars of such Force Majeure to the other Party in
writing or by telephone as soon as reasonably possible after the
occurrence of the cause relied upon. Telephone notices given
pursuant to this article shall be confirmed in writing as soon as
reasonably possible and shall specifically state full particulars of
the Force Majeure, the time and date when the Force Majeure occurred
and when the Force Majeure is reasonably expected to cease. The
Party affected shall exercise due diligence to remove such
disability with reasonable dispatch, but shall not be required to
accede or agree to any provision not satisfactory to it in order to
settle and terminate a strike or other labor disturbance.
Article 17. Default
17.1 Default.
17.1.1 General. No Default shall exist where such failure to
discharge an obligation (other than the payment of money) is the
result of Force Majeure as defined in this LGIA or the result of an
act of omission of the other Party. Upon a Breach, the non-breaching
Party shall give written notice of such Breach to the breaching
Party. Except as provided in Article 17.1.2, the breaching Party
shall have thirty (30) Calendar Days from receipt of the Default
notice within which to cure such Breach; provided however, if such
Breach is not capable of cure within thirty (30) Calendar Days, the
breaching Party shall commence such cure within thirty (30) Calendar
Days after notice and continuously and diligently complete such cure
within ninety (90) Calendar Days from receipt of the Default notice;
and, if cured within such time, the Breach specified in such notice
shall cease to exist.
17.1.2 Right to Terminate. If a Breach is not cured as provided
in this article, or if a Breach is not capable of being cured within
the period provided for herein, the non-breaching Party shall have
the right to declare a Default and terminate this LGIA by written
notice at any time until cure occurs, and be relieved of any further
obligation hereunder and, whether or not that Party terminates this
LGIA, to recover from the breaching Party all amounts due hereunder,
plus all other damages and remedies to which it is entitled at law
or in equity. The provisions of this article will survive
termination of this LGIA.
17.2 Violation of Operating Assumptions for Generating
Facilities. If Transmission Provider requires Interconnection
Customer to memorialize the operating assumptions for the charging
behavior of a Generating Facility that includes at least one
electric storage resource in Appendix H of this LGIA, Transmission
Provider may consider Interconnection Customer to be in Breach of
the LGIA if Interconnection Customer fails to operate the Generating
Facility in accordance with those operating assumptions for charging
behavior. However, if Interconnection Customer operates contrary to
the operating assumptions for charging behavior specified in
Appendix H of this LGIA at the direction of Transmission Provider,
Transmission Provider shall not consider Interconnection Customer in
Breach of this LGIA.
[[Page 61330]]
Article 18. Indemnity, Consequential Damages and Insurance
18.1 Indemnity. The Parties shall at all times indemnify,
defend, and hold the other Party harmless from, any and all damages,
losses, claims, including claims and actions relating to injury to
or death of any person or damage to property, demand, suits,
recoveries, costs and expenses, court costs, attorney fees, and all
other obligations by or to third parties, arising out of or
resulting from the other Party's action or inactions of its
obligations under this LGIA on behalf of the Indemnifying Party,
except in cases of gross negligence or intentional wrongdoing by the
indemnified Party.
18.1.1 Indemnified Person. If an Indemnified Person is entitled
to indemnification under this Article 18 as a result of a claim by a
third party, and the Indemnifying Party fails, after notice and
reasonable opportunity to proceed under Article 18.1, to assume the
defense of such claim, such Indemnified Person may at the expense of
the Indemnifying Party contest, settle or consent to the entry of
any judgment with respect to, or pay in full, such claim.
18.1.2 Indemnifying Party. If an Indemnifying Party is obligated
to indemnify and hold any Indemnified Person harmless under this
Article 18, the amount owing to the Indemnified Person shall be the
amount of such Indemnified Person's actual Loss, net of any
insurance or other recovery.
18.1.3 Indemnity Procedures. Promptly after receipt by an
Indemnified Person of any claim or notice of the commencement of any
action or administrative or legal proceeding or investigation as to
which the indemnity provided for in Article 18.1 may apply, the
Indemnified Person shall notify the Indemnifying Party of such fact.
Any failure of or delay in such notification shall not affect a
Party's indemnification obligation unless such failure or delay is
materially prejudicial to the Indemnifying Party.
The Indemnifying Party shall have the right to assume the
defense thereof with counsel designated by such Indemnifying Party
and reasonably satisfactory to the Indemnified Person. If the
defendants in any such action include one or more Indemnified
Persons and the Indemnifying Party and if the Indemnified Person
reasonably concludes that there may be legal defenses available to
it and/or other Indemnified Persons which are different from or
additional to those available to the Indemnifying Party, the
Indemnified Person shall have the right to select separate counsel
to assert such legal defenses and to otherwise participate in the
defense of such action on its own behalf. In such instances, the
Indemnifying Party shall only be required to pay the fees and
expenses of one additional attorney to represent an Indemnified
Person or Indemnified Persons having such differing or additional
legal defenses.
The Indemnified Person shall be entitled, at its expense, to
participate in any such action, suit or proceeding, the defense of
which has been assumed by the Indemnifying Party. Notwithstanding
the foregoing, the Indemnifying Party (i) shall not be entitled to
assume and control the defense of any such action, suit or
proceedings if and to the extent that, in the opinion of the
Indemnified Person and its counsel, such action, suit or proceeding
involves the potential imposition of criminal liability on the
Indemnified Person, or there exists a conflict or adversity of
interest between the Indemnified Person and the Indemnifying Party,
in such event the Indemnifying Party shall pay the reasonable
expenses of the Indemnified Person, and (ii) shall not settle or
consent to the entry of any judgment in any action, suit or
proceeding without the consent of the Indemnified Person, which
shall not be reasonably withheld, conditioned or delayed.
18.2 Consequential Damages. Other than the Liquidated Damages
heretofore described, in no event shall either Party be liable under
any provision of this LGIA for any losses, damages, costs or
expenses for any special, indirect, incidental, consequential, or
punitive damages, including but not limited to loss of profit or
revenue, loss of the use of equipment, cost of capital, cost of
temporary equipment or services, whether based in whole or in part
in contract, in tort, including negligence, strict liability, or any
other theory of liability; provided, however, that damages for which
a Party may be liable to the other Party under another agreement
will not be considered to be special, indirect, incidental, or
consequential damages hereunder.
18.3 Insurance. Each party shall, at its own expense, maintain
in force throughout the period of this LGIA, and until released by
the other Party, the following minimum insurance coverages, with
insurers authorized to do business in the state where the Point of
Interconnection is located:
18.3.1 Employers' Liability and Workers' Compensation Insurance
providing statutory benefits in accordance with the laws and
regulations of the state in which the Point of Interconnection is
located.
18.3.2 Commercial General Liability Insurance including premises
and operations, personal injury, broad form property damage, broad
form blanket contractual liability coverage (including coverage for
the contractual indemnification) products and completed operations
coverage, coverage for explosion, collapse and underground hazards,
independent contractors coverage, coverage for pollution to the
extent normally available and punitive damages to the extent
normally available and a cross liability endorsement, with minimum
limits of One Million Dollars ($1,000,000) per occurrence/One
Million Dollars ($1,000,000) aggregate combined single limit for
personal injury, bodily injury, including death and property damage.
18.3.3 Comprehensive Automobile Liability Insurance for coverage
of owned and non-owned and hired vehicles, trailers or semi-trailers
designed for travel on public roads, with a minimum, combined single
limit of One Million Dollars ($1,000,000) per occurrence for bodily
injury, including death, and property damage.
18.3.4 Excess Public Liability Insurance over and above the
Employers' Liability Commercial General Liability and Comprehensive
Automobile Liability Insurance coverage, with a minimum combined
single limit of Twenty Million Dollars ($20,000,000) per occurrence/
Twenty Million Dollars ($20,000,000) aggregate.
18.3.5 The Commercial General Liability Insurance, Comprehensive
Automobile Insurance and Excess Public Liability Insurance policies
shall name the other Party, its parent, associated and Affiliate
companies and their respective directors, officers, agents, servants
and employees (``Other Party Group'') as additional insured. All
policies shall contain provisions whereby the insurers waive all
rights of subrogation in accordance with the provisions of this LGIA
against the Other Party Group and provide thirty (30) Calendar Days
advance written notice to the Other Party Group prior to anniversary
date of cancellation or any material change in coverage or
condition.
18.3.6 The Commercial General Liability Insurance, Comprehensive
Automobile Liability Insurance and Excess Public Liability Insurance
policies shall contain provisions that specify that the policies are
primary and shall apply to such extent without consideration for
other policies separately carried and shall state that each insured
is provided coverage as though a separate policy had been issued to
each, except the insurer's liability shall not be increased beyond
the amount for which the insurer would have been liable had only one
insured been covered. Each Party shall be responsible for its
respective deductibles or retentions.
18.3.7 The Commercial General Liability Insurance, Comprehensive
Automobile Liability Insurance and Excess Public Liability Insurance
policies, if written on a Claims First Made Basis, shall be
maintained in full force and effect for two (2) years after
termination of this LGIA, which coverage may be in the form of tail
coverage or extended reporting period coverage if agreed by the
Parties.
18.3.8 The requirements contained herein as to the types and
limits of all insurance to be maintained by the Parties are not
intended to and shall not in any manner, limit or qualify the
liabilities and obligations assumed by the Parties under this LGIA.
18.3.9 Within ten (10) days following execution of this LGIA,
and as soon as practicable after the end of each fiscal year or at
the renewal of the insurance policy and in any event within ninety
(90) days thereafter, each Party shall provide certification of all
insurance required in this LGIA, executed by each insurer or by an
authorized representative of each insurer.
18.3.10 Notwithstanding the foregoing, each Party may self-
insure to meet the minimum insurance requirements of Articles 18.3.2
through 18.3.8 to the extent it maintains a self-insurance program;
provided that, such Party's senior secured debt is rated at
investment grade or better by Standard & Poor's and that its self-
insurance program meets the minimum insurance requirements of
Articles 18.3.2 through 18.3.8. For any period of time that a
Party's senior secured debt is unrated by Standard & Poor's or is
rated at less than investment grade by Standard & Poor's, such Party
shall comply with the insurance requirements applicable to it under
Articles 18.3.2 through 18.3.9. In
[[Page 61331]]
the event that a Party is permitted to self-insure pursuant to this
article, it shall notify the other Party that it meets the
requirements to self-insure and that its self-insurance program
meets the minimum insurance requirements in a manner consistent with
that specified in Article 18.3.9.
18.3.11 The Parties agree to report to each other in writing as
soon as practical all accidents or occurrences resulting in injuries
to any person, including death, and any property damage arising out
of this LGIA.
Article 19. Assignment
19.1 Assignment. This LGIA may be assigned by either Party only
with the written consent of the other; provided that either Party
may assign this LGIA without the consent of the other Party to any
Affiliate of the assigning Party with an equal or greater credit
rating and with the legal authority and operational ability to
satisfy the obligations of the assigning Party under this LGIA; and
provided further that Interconnection Customer shall have the right
to assign this LGIA, without the consent of Transmission Provider,
for collateral security purposes to aid in providing financing for
the Large Generating Facility, provided that Interconnection
Customer will promptly notify Transmission Provider of any such
assignment. Any financing arrangement entered into by
Interconnection Customer pursuant to this article will provide that
prior to or upon the exercise of the secured party's, trustee's or
mortgagee's assignment rights pursuant to said arrangement, the
secured creditor, the trustee or mortgagee will notify Transmission
Provider of the date and particulars of any such exercise of
assignment right(s), including providing the Transmission Provider
with proof that it meets the requirements of Articles 11.5 and 18.3.
Any attempted assignment that violates this article is void and
ineffective. Any assignment under this LGIA shall not relieve a
Party of its obligations, nor shall a Party's obligations be
enlarged, in whole or in part, by reason thereof. Where required,
consent to assignment will not be unreasonably withheld, conditioned
or delayed.
Article 20. Severability
20.1 Severability. If any provision in this LGIA is finally
determined to be invalid, void or unenforceable by any court or
other Governmental Authority having jurisdiction, such determination
shall not invalidate, void or make unenforceable any other
provision, agreement or covenant of this LGIA; provided that if
Interconnection Customer (or any third party, but only if such third
party is not acting at the direction of Transmission Provider) seeks
and obtains such a final determination with respect to any provision
of the Alternate Option (Article 5.1.2), or the Negotiated Option
(Article 5.1.4), then none of these provisions shall thereafter have
any force or effect and the Parties' rights and obligations shall be
governed solely by the Standard Option (Article 5.1.1).
Article 21. Comparability
21.1 Comparability. The Parties will comply with all applicable
comparability and code of conduct laws, rules and regulations, as
amended from time to time.
Article 22. Confidentiality
22.1 Confidentiality. Confidential Information shall include,
without limitation, all information relating to a Party's
technology, research and development, business affairs, and pricing,
and any information supplied by either of the Parties to the other
prior to the execution of this LGIA.
Information is Confidential Information only if it is clearly
designated or marked in writing as confidential on the face of the
document, or, if the information is conveyed orally or by
inspection, if the Party providing the information orally informs
the Party receiving the information that the information is
confidential.
If requested by either Party, the other Party shall provide in
writing, the basis for asserting that the information referred to in
this Article 22 warrants confidential treatment, and the requesting
Party may disclose such writing to the appropriate Governmental
Authority. Each Party shall be responsible for the costs associated
with affording confidential treatment to its information.
22.1.1 Term. During the term of this LGIA, and for a period of
three (3) years after the expiration or termination of this LGIA,
except as otherwise provided in this Article 22, each Party shall
hold in confidence and shall not disclose to any person Confidential
Information.
22.1.2 Scope. Confidential Information shall not include
information that the receiving Party can demonstrate: (1) is
generally available to the public other than as a result of a
disclosure by the receiving Party; (2) was in the lawful possession
of the receiving Party on a non-confidential basis before receiving
it from the disclosing Party; (3) was supplied to the receiving
Party without restriction by a third party, who, to the knowledge of
the receiving Party after due inquiry, was under no obligation to
the disclosing Party to keep such information confidential; (4) was
independently developed by the receiving Party without reference to
Confidential Information of the disclosing Party; (5) is, or
becomes, publicly known, through no wrongful act or omission of the
receiving Party or Breach of this LGIA; or (6) is required, in
accordance with Article 22.1.7 of the LGIA, Order of Disclosure, to
be disclosed by any Governmental Authority or is otherwise required
to be disclosed by law or subpoena, or is necessary in any legal
proceeding establishing rights and obligations under this LGIA.
Information designated as Confidential Information will no longer be
deemed confidential if the Party that designated the information as
confidential notifies the other Party that it no longer is
confidential.
22.1.3 Release of Confidential Information. Neither Party shall
release or disclose Confidential Information to any other person,
except to its Affiliates (limited by the Standards of Conduct
requirements), subcontractors, employees, consultants, or to parties
who may be or considering providing financing to or equity
participation with Interconnection Customer, or to potential
purchasers or assignees of Interconnection Customer, on a need-to-
know basis in connection with this LGIA, unless such person has
first been advised of the confidentiality provisions of this Article
22 and has agreed to comply with such provisions. Notwithstanding
the foregoing, a Party providing Confidential Information to any
person shall remain primarily responsible for any release of
Confidential Information in contravention of this Article 22.
22.1.4 Rights. Each Party retains all rights, title, and
interest in the Confidential Information that each Party discloses
to the other Party. The disclosure by each Party to the other Party
of Confidential Information shall not be deemed a waiver by either
Party or any other person or entity of the right to protect the
Confidential Information from public disclosure.
22.1.5 No Warranties. By providing Confidential Information,
neither Party makes any warranties or representations as to its
accuracy or completeness. In addition, by supplying Confidential
Information, neither Party obligates itself to provide any
particular information or Confidential Information to the other
Party nor to enter into any further agreements or proceed with any
other relationship or joint venture.
22.1.6 Standard of Care. Each Party shall use at least the same
standard of care to protect Confidential Information it receives as
it uses to protect its own Confidential Information from
unauthorized disclosure, publication or dissemination. Each Party
may use Confidential Information solely to fulfill its obligations
to the other Party under this LGIA or its regulatory requirements.
22.1.7 Order of Disclosure. If a court or a Government Authority
or entity with the right, power, and apparent authority to do so
requests or requires either Party, by subpoena, oral deposition,
interrogatories, requests for production of documents,
administrative order, or otherwise, to disclose Confidential
Information, that Party shall provide the other Party with prompt
notice of such request(s) or requirement(s) so that the other Party
may seek an appropriate protective order or waive compliance with
the terms of this LGIA. Notwithstanding the absence of a protective
order or waiver, the Party may disclose such Confidential
Information which, in the opinion of its counsel, the Party is
legally compelled to disclose. Each Party will use Reasonable
Efforts to obtain reliable assurance that confidential treatment
will be accorded any Confidential Information so furnished.
22.1.8 Termination of Agreement. Upon termination of this LGIA
for any reason, each Party shall, within ten (10) Calendar Days of
receipt of a written request from the other Party, use Reasonable
Efforts to destroy, erase, or delete (with such destruction,
erasure, and deletion certified in writing to the other Party) or
return to the other Party, without retaining copies thereof, any and
all written or electronic Confidential Information received from the
other Party.
22.1.9 Remedies. The Parties agree that monetary damages would
be inadequate to compensate a Party for the other Party's Breach of
its obligations under this Article 22. Each Party accordingly agrees
that the other Party shall be entitled to equitable
[[Page 61332]]
relief, by way of injunction or otherwise, if the first Party
Breaches or threatens to Breach its obligations under this Article
22, which equitable relief shall be granted without bond or proof of
damages, and the receiving Party shall not plead in defense that
there would be an adequate remedy at law. Such remedy shall not be
deemed an exclusive remedy for the Breach of this Article 22, but
shall be in addition to all other remedies available at law or in
equity. The Parties further acknowledge and agree that the covenants
contained herein are necessary for the protection of legitimate
business interests and are reasonable in scope. No Party, however,
shall be liable for indirect, incidental, or consequential or
punitive damages of any nature or kind resulting from or arising in
connection with this Article 22.
22.1.10 Disclosure to FERC, its Staff, or a State.
Notwithstanding anything in this Article 22 to the contrary, and
pursuant to 18 CFR 1b.20, if FERC or its staff, during the course of
an investigation or otherwise, requests information from one of the
Parties that is otherwise required to be maintained in confidence
pursuant to this LGIA, the Party shall provide the requested
information to FERC or its staff, within the time provided for in
the request for information. In providing the information to FERC or
its staff, the Party must, consistent with 18 CFR 388.112, request
that the information be treated as confidential and non-public by
FERC and its staff and that the information be withheld from public
disclosure. Parties are prohibited from notifying the other Party to
this LGIA prior to the release of the Confidential Information to
FERC or its staff. The Party shall notify the other Party to the
LGIA when it is notified by FERC or its staff that a request to
release Confidential Information has been received by FERC, at which
time either of the Parties may respond before such information would
be made public, pursuant to 18 CFR 388.112. Requests from a state
regulatory body conducting a confidential investigation shall be
treated in a similar manner if consistent with the applicable state
rules and regulations.
22.1.11 Subject to the exception in Article 22.1.10, any
information that a Party claims is competitively sensitive,
commercial or financial information under this LGIA (``Confidential
Information'') shall not be disclosed by the other Party to any
person not employed or retained by the other Party, except to the
extent disclosure is (i) required by law; (ii) reasonably deemed by
the disclosing Party to be required to be disclosed in connection
with a dispute between or among the Parties, or the defense of
litigation or dispute; (iii) otherwise permitted by consent of the
other Party, such consent not to be unreasonably withheld; or (iv)
necessary to fulfill its obligations under this LGIA or as a
transmission service provider or a [Control Area]Balancing Authority
Area operator including disclosing the Confidential Information to
an RTO or ISO or to a regional or national reliability organization.
The Party asserting confidentiality shall notify the other Party in
writing of the information it claims is confidential. Prior to any
disclosures of the other Party's Confidential Information under this
subparagraph, or if any third party or Governmental Authority makes
any request or demand for any of the information described in this
subparagraph, the disclosing Party agrees to promptly notify the
other Party in writing and agrees to assert confidentiality and
cooperate with the other Party in seeking to protect the
Confidential Information from public disclosure by confidentiality
agreement, protective order or other reasonable measures.
Article 23. Environmental Releases
23.1 Each Party shall notify the other Party, first orally and
then in writing, of the release of any Hazardous Substances, any
asbestos or lead abatement activities, or any type of remediation
activities related to the Large Generating Facility or the
Interconnection Facilities, each of which may reasonably be expected
to affect the other Party. The notifying Party shall: (i) provide
the notice as soon as practicable, provided such Party makes a good
faith effort to provide the notice no later than twenty-four hours
after such Party becomes aware of the occurrence; and (ii) promptly
furnish to the other Party copies of any publicly available reports
filed with any Governmental Authorities addressing such events.
Article 24. Information Requirements
24.1 Information Acquisition. Transmission Provider and
Interconnection Customer shall submit specific information regarding
the electrical characteristics of their respective facilities to
each other as described below and in accordance with Applicable
Reliability Standards.
24.2 Information Submission by Transmission Provider. The
initial information submission by Transmission Provider shall occur
no later than one hundred eighty (180) Calendar Days prior to Trial
Operation and shall include Transmission System information
necessary to allow Interconnection Customer to select equipment and
meet any system protection and stability requirements, unless
otherwise agreed to by the Parties. On a monthly basis Transmission
Provider shall provide Interconnection Customer a status report on
the construction and installation of Transmission Provider's
Interconnection Facilities and Network Upgrades, including, but not
limited to, the following information: (1) progress to date; (2) a
description of the activities since the last report (3) a
description of the action items for the next period; and (4) the
delivery status of equipment ordered.
24.3 Updated Information Submission by Interconnection Customer.
The updated information submission by Interconnection Customer,
including manufacturer information, shall occur no later than one
hundred eighty (180) Calendar Days prior to the Trial Operation.
Interconnection Customer shall submit a completed copy of the Large
Generating Facility data requirements contained in Appendix 1 to the
LGIP. It shall also include any additional information provided to
Transmission Provider for the [Feasibility]Cluster Study and
Facilities Study. Information in this submission shall be the most
current Large Generating Facility design or expected performance
data. Information submitted for stability models shall be compatible
with Transmission Provider standard models. If there is no
compatible model, Interconnection Customer will work with a
consultant mutually agreed to by the Parties to develop and supply a
standard model and associated information.
If Interconnection Customer's data is materially different from
what was originally provided to Transmission Provider pursuant to
the Interconnection Study Agreement between Transmission Provider
and Interconnection Customer, then Transmission Provider will
conduct appropriate studies to determine the impact on Transmission
Provider Transmission System based on the actual data submitted
pursuant to this Article 24.3. [The]Interconnection Customer shall
not begin Trial Operation until such studies are completed.
24.4 Information Supplementation. Prior to the Operation Date,
the Parties shall supplement their information submissions described
above in this Article 24 with any and all ``as-built'' Large
Generating Facility information or ``as-tested'' performance
information that differs from the initial submissions or,
alternatively, written confirmation that no such differences exist.
The Interconnection Customer shall conduct tests on the Large
Generating Facility as required by Good Utility Practice such as an
open circuit ``step voltage'' test on the Large Generating Facility
to verify proper operation of the Large Generating Facility's
automatic voltage regulator.
Unless otherwise agreed, the test conditions shall include: (1)
Large Generating Facility at synchronous speed; (2) automatic
voltage regulator on and in voltage control mode; and (3) a five
percent change in Large Generating Facility terminal voltage
initiated by a change in the voltage regulators reference voltage.
Interconnection Customer shall provide validated test recordings
showing the responses of Large Generating Facility terminal and
field voltages. In the event that direct recordings of these
voltages is impractical, recordings of other voltages or currents
that mirror the response of the Large Generating Facility's terminal
or field voltage are acceptable if information necessary to
translate these alternate quantities to actual Large Generating
Facility terminal or field voltages is provided. Large Generating
Facility testing shall be conducted and results provided to
Transmission Provider for each individual generating unit in a
station.
Subsequent to the Operation Date, Interconnection Customer shall
provide Transmission Provider any information changes due to
equipment replacement, repair, or adjustment. Transmission Provider
shall provide Interconnection Customer any information changes due
to equipment replacement, repair or adjustment in the directly
connected substation or any adjacent Transmission Provider-owned
substation that may affect Interconnection Customer's
Interconnection Facilities equipment ratings, protection or
operating requirements. The Parties shall provide such information
no later than thirty (30) Calendar Days after the
[[Page 61333]]
date of the equipment replacement, repair or adjustment.
Article 25. Information Access and Audit Rights
25.1 Information Access. Each Party (the ``disclosing Party'')
shall make available to the other Party information that is in the
possession of the disclosing Party and is necessary in order for the
other Party to: (i) verify the costs incurred by the disclosing
Party for which the other Party is responsible under this LGIA; and
(ii) carry out its obligations and responsibilities under this LGIA.
The Parties shall not use such information for purposes other than
those set forth in this Article 25.1 and to enforce their rights
under this LGIA.
25.2 Reporting of Non-Force Majeure Events. Each Party (the
``notifying Party'') shall notify the other Party when the notifying
Party becomes aware of its inability to comply with the provisions
of this LGIA for a reason other than a Force Majeure event. The
Parties agree to cooperate with each other and provide necessary
information regarding such inability to comply, including the date,
duration, reason for the inability to comply, and corrective actions
taken or planned to be taken with respect to such inability to
comply. Notwithstanding the foregoing, notification, cooperation or
information provided under this article shall not entitle the Party
receiving such notification to allege a cause for anticipatory
breach of this LGIA.
25.3 Audit Rights. Subject to the requirements of
confidentiality under Article 22 of this LGIA, each Party shall have
the right, during normal business hours, and upon prior reasonable
notice to the other Party, to audit at its own expense the other
Party's accounts and records pertaining to either Party's
performance or either Party's satisfaction of obligations under this
LGIA. Such audit rights shall include audits of the other Party's
costs, calculation of invoiced amounts, Transmission Provider's
efforts to allocate responsibility for the provision of reactive
support to the Transmission System, Transmission Provider's efforts
to allocate responsibility for interruption or reduction of
generation on the Transmission System, and each Party's actions in
an Emergency Condition. Any audit authorized by this article shall
be performed at the offices where such accounts and records are
maintained and shall be limited to those portions of such accounts
and records that relate to each Party's performance and satisfaction
of obligations under this LGIA. Each Party shall keep such accounts
and records for a period equivalent to the audit rights periods
described in Article 25.4.
25.4 Audit Rights Periods.
25.4.1 Audit Rights Period for Construction-Related Accounts and
Records. Accounts and records related to the design, engineering,
procurement, and construction of Transmission Provider's
Interconnection Facilities and Network Upgrades shall be subject to
audit for a period of twenty-four months following Transmission
Provider's issuance of a final invoice in accordance with Article
12.2.
25.4.2 Audit Rights Period for All Other Accounts and Records.
Accounts and records related to either Party's performance or
satisfaction of all obligations under this LGIA other than those
described in Article 25.4.1 shall be subject to audit as follows:
(i) for an audit relating to cost obligations, the applicable audit
rights period shall be twenty-four months after the auditing Party's
receipt of an invoice giving rise to such cost obligations; and (ii)
for an audit relating to all other obligations, the applicable audit
rights period shall be twenty-four months after the event for which
the audit is sought.
25.5 Audit Results. If an audit by a Party determines that an
overpayment or an underpayment has occurred, a notice of such
overpayment or underpayment shall be given to the other Party
together with those records from the audit which support such
determination.
Article 26. Subcontractors
26.1 General. Nothing in this LGIA shall prevent a Party from
utilizing the services of any subcontractor as it deems appropriate
to perform its obligations under this LGIA; provided, however, that
each Party shall require its subcontractors to comply with all
applicable terms and conditions of this LGIA in providing such
services and each Party shall remain primarily liable to the other
Party for the performance of such subcontractor.
26.2 Responsibility of Principal. The creation of any
subcontract relationship shall not relieve the hiring Party of any
of its obligations under this LGIA. The hiring Party shall be fully
responsible to the other Party for the acts or omissions of any
subcontractor the hiring Party hires as if no subcontract had been
made; provided, however, that in no event shall Transmission
Provider be liable for the actions or inactions of Interconnection
Customer or its subcontractors with respect to obligations of
Interconnection Customer under Article 5 of this LGIA. Any
applicable obligation imposed by this LGIA upon the hiring Party
shall be equally binding upon, and shall be construed as having
application to, any subcontractor of such Party.
26.3 No Limitation by Insurance. The obligations under this
Article 26 will not be limited in any way by any limitation of
subcontractor's insurance.
Article 27. Disputes
27.1 Submission. In the event either Party has a dispute, or
asserts a claim, that arises out of or in connection with this LGIA
or its performance, such Party (the ``disputing Party'') shall
provide the other Party with written notice of the dispute or claim
(``Notice of Dispute''). Such dispute or claim shall be referred to
a designated senior representative of each Party for resolution on
an informal basis as promptly as practicable after receipt of the
Notice of Dispute by the other Party. In the event the designated
representatives are unable to resolve the claim or dispute through
unassisted or assisted negotiations within thirty (30) Calendar Days
of the other Party's receipt of the Notice of Dispute, such claim or
dispute may, upon mutual agreement of the Parties, be submitted to
arbitration and resolved in accordance with the arbitration
procedures set forth below. In the event the Parties do not agree to
submit such claim or dispute to arbitration, each Party may exercise
whatever rights and remedies it may have in equity or at law
consistent with the terms of this LGIA.
27.2 External Arbitration Procedures. Any arbitration initiated
under this LGIA shall be conducted before a single neutral
arbitrator appointed by the Parties. If the Parties fail to agree
upon a single arbitrator within ten (10) Calendar Days of the
submission of the dispute to arbitration, each Party shall choose
one arbitrator who shall sit on a three-member arbitration panel.
The two arbitrators so chosen shall within twenty (20) Calendar Days
select a third arbitrator to chair the arbitration panel. In either
case, the arbitrators shall be knowledgeable in electric utility
matters, including electric transmission and bulk power issues, and
shall not have any current or past substantial business or financial
relationships with any party to the arbitration (except prior
arbitration). The arbitrator(s) shall provide each of the Parties an
opportunity to be heard and, except as otherwise provided herein,
shall conduct the arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association
(``Arbitration Rules'') and any applicable FERC regulations or RTO
rules; provided, however, in the event of a conflict between the
Arbitration Rules and the terms of this Article 27, the terms of
this Article 27 shall prevail.
27.3 Arbitration Decisions. Unless otherwise agreed by the
Parties, the arbitrator(s) shall render a decision within ninety
(90) Calendar Days of appointment and shall notify the Parties in
writing of such decision and the reasons therefor. The arbitrator(s)
shall be authorized only to interpret and apply the provisions of
this LGIA and shall have no power to modify or change any provision
of this Agreement in any manner. The decision of the arbitrator(s)
shall be final and binding upon the Parties, and judgment on the
award may be entered in any court having jurisdiction. The decision
of the arbitrator(s) may be appealed solely on the grounds that the
conduct of the arbitrator(s), or the decision itself, violated the
standards set forth in the Federal Arbitration Act or the
Administrative Dispute Resolution Act. The final decision of the
arbitrator must also be filed with FERC if it affects jurisdictional
rates, terms and conditions of service, Interconnection Facilities,
or Network Upgrades.
27.4 Costs. Each Party shall be responsible for its own costs
incurred during the arbitration process and for the following costs,
if applicable: (1) the cost of the arbitrator chosen by the Party to
sit on the three member panel and one half of the cost of the third
arbitrator chosen; or (2) one half the cost of the single arbitrator
jointly chosen by the Parties.
Article 28. Representations, Warranties, and Covenants
28.1 General. Each Party makes the following representations,
warranties and covenants:
28.1.1 Good Standing. Such Party is duly organized, validly
existing and in good
[[Page 61334]]
standing under the laws of the state in which it is organized,
formed, or incorporated, as applicable; that it is qualified to do
business in the state or states in which the Large Generating
Facility, Interconnection Facilities and Network Upgrades owned by
such Party, as applicable, are located; and that it has the
corporate power and authority to own its properties, to carry on its
business as now being conducted and to enter into this LGIA and
carry out the transactions contemplated hereby and perform and carry
out all covenants and obligations on its part to be performed under
and pursuant to this LGIA.
28.1.2 Authority. Such Party has the right, power and authority
to enter into this LGIA, to become a Party hereto and to perform its
obligations hereunder. This LGIA is a legal, valid and binding
obligation of such Party, enforceable against such Party in
accordance with its terms, except as the enforceability thereof may
be limited by applicable bankruptcy, insolvency, reorganization or
other similar laws affecting creditors' rights generally and by
general equitable principles (regardless of whether enforceability
is sought in a proceeding in equity or at law).
28.1.3 No Conflict. The execution, delivery and performance of
this LGIA does not violate or conflict with the organizational or
formation documents, or bylaws or operating agreement, of such
Party, or any judgment, license, permit, order, material agreement
or instrument applicable to or binding upon such Party or any of its
assets.
28.1.4 Consent and Approval. Such Party has sought or obtained,
or, in accordance with this LGIA will seek or obtain, each consent,
approval, authorization, order, or acceptance by any Governmental
Authority in connection with the execution, delivery and performance
of this LGIA, and it will provide to any Governmental Authority
notice of any actions under this LGIA that are required by
Applicable Laws and Regulations.
Article 29. Joint Operating Committee
29.1 Joint Operating Committee. Except in the case of ISOs and
RTOs, Transmission Provider shall constitute a Joint Operating
Committee to coordinate operating and technical considerations of
Interconnection Service. At least six (6) months prior to the
expected Initial Synchronization Date, Interconnection Customer and
Transmission Provider shall each appoint one representative and one
alternate to the Joint Operating Committee. Each Interconnection
Customer shall notify Transmission Provider of its appointment in
writing. Such appointments may be changed at any time by similar
notice. The Joint Operating Committee shall meet as necessary, but
not less than once each calendar year, to carry out the duties set
forth herein. The Joint Operating Committee shall hold a meeting at
the request of either Party, at a time and place agreed upon by the
representatives. The Joint Operating Committee shall perform all of
its duties consistent with the provisions of this LGIA. Each Party
shall cooperate in providing to the Joint Operating Committee all
information required in the performance of the Joint Operating
Committee's duties. All decisions and agreements, if any, made by
the Joint Operating Committee, shall be evidenced in writing. The
duties of the Joint Operating Committee shall include the following:
29.1.1 Establish data requirements and operating record
requirements.
29.1.2 Review the requirements, standards, and procedures for
data acquisition equipment, protective equipment, and any other
equipment or software.
29.1.3 Annually review the one (1) year forecast of maintenance
and planned outage schedules of Transmission Provider's and
Interconnection Customer's facilities at the Point of
Interconnection.
29.1.4 Coordinate the scheduling of maintenance and planned
outages on the Interconnection Facilities, the Large Generating
Facility and other facilities that impact the normal operation of
the interconnection of the Large Generating Facility to the
Transmission System.
29.1.5 Ensure that information is being provided by each Party
regarding equipment availability.
29.1.6 Perform such other duties as may be conferred upon it by
mutual agreement of the Parties.
Article 30. Miscellaneous
30.1 Binding Effect. This LGIA and the rights and obligations
hereof, shall be binding upon and shall inure to the benefit of the
successors and assigns of the Parties hereto.
30.2 Conflicts. In the event of a conflict between the body of
this LGIA and any attachment, appendices or exhibits hereto, the
terms and provisions of the body of this LGIA shall prevail and be
deemed the final intent of the Parties.
30.3 Rules of Interpretation. This LGIA, unless a clear contrary
intention appears, shall be construed and interpreted as follows:
(1) the singular number includes the plural number and vice versa;
(2) reference to any person includes such person's successors and
assigns but, in the case of a Party, only if such successors and
assigns are permitted by this LGIA, and reference to a person in a
particular capacity excludes such person in any other capacity or
individually; (3) reference to any agreement (including this LGIA),
document, instrument or tariff means such agreement, document,
instrument, or tariff as amended or modified and in effect from time
to time in accordance with the terms thereof and, if applicable, the
terms hereof; (4) reference to any Applicable Laws and Regulations
means such Applicable Laws and Regulations as amended, modified,
codified, or reenacted, in whole or in part, and in effect from time
to time, including, if applicable, rules and regulations promulgated
thereunder; (5) unless expressly stated otherwise, reference to any
Article, Section or Appendix means such Article of this LGIA or such
Appendix to this LGIA, or such Section to the LGIP or such Appendix
to the LGIP, as the case may be; (6) ``hereunder'', ``hereof'',
``herein'', ``hereto'' and words of similar import shall be deemed
references to this LGIA as a whole and not to any particular Article
or other provision hereof or thereof; (7) ``including'' (and with
correlative meaning ``include'') means including without limiting
the generality of any description preceding such term; and (8)
relative to the determination of any period of time, ``from'' means
``from and including'', ``to'' means ``to but excluding'' and
``through'' means ``through and including''.
30.4 Entire Agreement. This LGIA, including all Appendices and
Schedules attached hereto, constitutes the entire agreement between
the Parties with reference to the subject matter hereof, and
supersedes all prior and contemporaneous understandings or
agreements, oral or written, between the Parties with respect to the
subject matter of this LGIA. There are no other agreements,
representations, warranties, or covenants which constitute any part
of the consideration for, or any condition to, either Party's
compliance with its obligations under this LGIA.
30.5 No Third Party Beneficiaries. This LGIA is not intended to
and does not create rights, remedies, or benefits of any character
whatsoever in favor of any persons, corporations, associations, or
entities other than the Parties, and the obligations herein assumed
are solely for the use and benefit of the Parties, their successors
in interest and, where permitted, their assigns.
30.6 Waiver. The failure of a Party to this LGIA to insist, on
any occasion, upon strict performance of any provision of this LGIA
will not be considered a waiver of any obligation, right, or duty
of, or imposed upon, such Party.
Any waiver at any time by either Party of its rights with
respect to this LGIA shall not be deemed a continuing waiver or a
waiver with respect to any other failure to comply with any other
obligation, right, duty of this LGIA. Termination or Default of this
LGIA for any reason by Interconnection Customer shall not constitute
a waiver of Interconnection Customer's legal rights to obtain an
interconnection from Transmission Provider. Any waiver of this LGIA
shall, if requested, be provided in writing.
30.7 Headings. The descriptive headings of the various Articles
of this LGIA have been inserted for convenience of reference only
and are of no significance in the interpretation or construction of
this LGIA.
30.8 Multiple Counterparts. This LGIA may be executed in two or
more counterparts, each of which is deemed an original but all
constitute one and the same instrument.
30.9 Amendment. The Parties may by mutual agreement amend this
LGIA by a written instrument duly executed by the Parties.
30.10 Modification by the Parties. The Parties may by mutual
agreement amend the Appendices to this LGIA by a written instrument
duly executed by the Parties. Such amendment shall become effective
and a part of this LGIA upon satisfaction of all Applicable Laws and
Regulations.
30.11 Reservation of Rights. Transmission Provider shall have
the right to make a unilateral filing with FERC to modify this LGIA
with respect to any rates, terms and conditions, charges,
classifications of service, rule or regulation under section 205 or
any
[[Page 61335]]
other applicable provision of the Federal Power Act and FERC's rules
and regulations thereunder, and Interconnection Customer shall have
the right to make a unilateral filing with FERC to modify this LGIA
pursuant to section 206 or any other applicable provision of the
Federal Power Act and FERC's rules and regulations thereunder;
provided that each Party shall have the right to protest any such
filing by the other Party and to participate fully in any proceeding
before FERC in which such modifications may be considered. Nothing
in this LGIA shall limit the rights of the Parties or of FERC under
sections 205 or 206 of the Federal Power Act and FERC's rules and
regulations thereunder, except to the extent that the Parties
otherwise mutually agree as provided herein.
30.12 No Partnership. This LGIA shall not be interpreted or
construed to create an association, joint venture, agency
relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party.
Neither Party shall have any right, power or authority to enter into
any agreement or undertaking for, or act on behalf of, or to act as
or be an agent or representative of, or to otherwise bind, the other
Party.
IN WITNESS WHEREOF, the Parties have executed this LGIA in
duplicate originals, each of which shall constitute and be an
original effective Agreement between the Parties.
[Insert name of Transmission Provider or Transmission Owner, if
applicable]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Appendix A to LGIA
Interconnection Facilities, Network Upgrades and Distribution Upgrades
1. Interconnection Facilities:
(a) {insert Interconnection Customer's Interconnection
Facilities{time} :
(b) {insert Transmission Provider's Interconnection
Facilities{time} :
2. Network Upgrades:
(a) {insert Stand Alone Network Upgrades{time} :
(b) {insert Substation Network Upgrades [Other Network
Upgrades]{time} :
(c) {insert System Network Upgrades{time} :
3. Distribution Upgrades:
Appendix B to LGIA
Milestones
Site Control
Check box if applicable [ ]
Interconnection Customer with qualifying regulatory limitations
must demonstrate 100% Site Control by {Transmission Provider to
insert date 180 days from the effective date of this LGIA{time} or
the LGIA may be terminated per Article 17 (Default) of this LGIA and
the Interconnection Customer may be subject to Withdrawal Penalties
per Section 3.7.1.1 of the Transmission Provider's LGIP (Calculation
of the Withdrawal Penalty).
Appendix C to LGIA
Interconnection Details
Appendix D to LGIA
Security Arrangements Details
Infrastructure security of Transmission System equipment and
operations and control hardware and software is essential to ensure
day-to-day Transmission System reliability and operational security.
FERC will expect all Transmission Providers, market participants,
and Interconnection Customers interconnected to the Transmission
System to comply with the recommendations offered by the President's
Critical Infrastructure Protection Board and, eventually, best
practice recommendations from the electric reliability authority.
All public utilities will be expected to meet basic standards for
system infrastructure and operational security, including physical,
operational, and cyber-security practices.
Appendix E to LGIA
Commercial Operation Date
This Appendix E is a part of the LGIA between Transmission
Provider and Interconnection Customer.
{Date{time}
{Transmission Provider Address{time}
Re: _____ Large Generating Facility
Dear: _____.
On {Date{time} {Interconnection Customer{time} has completed Trial
Operation of Unit No. __ . This letter confirms that
{Interconnection Customer{time} commenced Commercial Operation of
Unit No. __ at the Large Generating Facility, effective as of {Date
plus one day{time} .
Thank you.
{Signature{time}
{Interconnection Customer Representative{time}
Appendix F to LGIA
Addresses for Delivery of Notices and Billings
Notices:
Transmission Provider:
{To be supplied.{time}
Interconnection Customer:
{To be supplied.{time}
Billings and Payments:
Transmission Provider:
{To be supplied.{time}
Interconnection Customer:
{To be supplied.{time}
Alternative Forms of Delivery of Notices (telephone, facsimile or
email):
Transmission Provider:
{To be supplied.{time}
Interconnection Customer:
{To be supplied.{time}
APPENDIX G
Interconnection Requirements for a Wind Generating Plant
Appendix G sets forth requirements and provisions specific to a
wind generating plant or a Generating Facility that contains a wind
generating plant. All other requirements of this LGIA continue to
apply to wind generating plant interconnections.
A. Technical Standards Applicable to a Wind Generating Plant
i. Low Voltage Ride-Through (LVRT) Capability
A wind generating plant shall be able to remain online during
voltage disturbances up to the time periods and associated voltage
levels set forth in the standard below. The LVRT standard provides
for a transition period standard and a post-transition period
standard.
Transition Period LVRT Standard
The transition period standard applies to wind generating plants
subject to FERC Order 661 that have either: (i) interconnection
agreements signed and filed with the Commission, filed with the
Commission in unexecuted form, or filed with the Commission as non-
conforming agreements between January 1, 2006 and December 31, 2006,
with a scheduled in-service date no later than December 31, 2007, or
(ii) wind generating turbines subject to a wind turbine procurement
contract executed prior to December 31, 2005, for delivery through
2007.
1. Wind generating plants are required to remain in-service
during three-phase faults with normal clearing (which is a time
period of approximately 4-9 cycles) and single line to ground faults
with delayed clearing, and subsequent post-fault voltage recovery to
prefault voltage unless clearing the fault effectively disconnects
the generator from the system. The clearing time requirement for a
three-phase fault will be specific to the wind generating plant
substation location, as determined by and documented by the
transmission provider. The maximum clearing time the wind generating
plant shall be required to withstand for a three-phase fault shall
be 9 cycles at a voltage as low as 0.15 p.u., as measured at the
high side of the wind generating plant step-up transformer (i.e. the
transformer that steps the voltage up to the transmission
interconnection voltage or ``GSU''), after which, if the fault
remains following the location-specific normal clearing time for
three-phase faults, the wind generating plant may disconnect from
the transmission system.
2. This requirement does not apply to faults that would occur
between the wind generator terminals and the high side of the GSU or
to faults that would result in a voltage lower than 0.15 per unit on
the high side of the GSU serving the facility.
3. Wind generating plants may be tripped after the fault period
if this action is intended as part of a special protection system.
4. Wind generating plants may meet the LVRT requirements of this
standard by the performance of the generators or by installing
additional equipment (e.g., Static VAr
[[Page 61336]]
Compensator, etc.) within the wind generating plant or by a
combination of generator performance and additional equipment.
5. Existing individual generator units that are, or have been,
interconnected to the network at the same location at the effective
date of the Appendix G LVRT Standard are exempt from meeting the
Appendix G LVRT Standard for the remaining life of the existing
generation equipment. Existing individual generator units that are
replaced are required to meet the Appendix G LVRT Standard.
Post-transition Period LVRT Standard
All wind generating plants subject to FERC Order No. 661 and not
covered by the transition period described above must meet the
following requirements:
1. Wind generating plants are required to remain in-service
during three-phase faults with normal clearing (which is a time
period of approximately 4-9 cycles) and single line to ground faults
with delayed clearing, and subsequent post-fault voltage recovery to
prefault voltage unless clearing the fault effectively disconnects
the generator from the system. The clearing time requirement for a
three-phase fault will be specific to the wind generating plant
substation location, as determined by and documented by the
transmission provider. The maximum clearing time the wind generating
plant shall be required to withstand for a three-phase fault shall
be 9 cycles after which, if the fault remains following the
location-specific normal clearing time for three-phase faults, the
wind generating plant may disconnect from the transmission system. A
wind generating plant shall remain interconnected during such a
fault on the transmission system for a voltage level as low as zero
volts, as measured at the high voltage side of the wind GSU.
2. This requirement does not apply to faults that would occur
between the wind generator terminals and the high side of the GSU.
3. Wind generating plants may be tripped after the fault period
if this action is intended as part of a special protection system.
4. Wind generating plants may meet the LVRT requirements of this
standard by the performance of the generators or by installing
additional equipment (e.g., Static VAr Compensator) within the wind
generating plant or by a combination of generator performance and
additional equipment.
Existing individual generator units that are, or have been,
interconnected to the network at the same location at the effective
date of the Appendix G LVRT Standard are exempt from meeting the
Appendix G LVRT Standard for the remaining life of the existing
generation equipment. Existing individual generator units that are
replaced are required to meet the Appendix G LVRT Standard.
ii. Power Factor Design Criteria (Reactive Power)
The following reactive power requirements apply only to a newly
interconnecting wind generating plant that has executed a Facilities
Study Agreement as of the effective date of the Final rule
establishing the reactive power requirements for non-synchronous
generators in S[s]ection 9.6.1 of this LGIA (Order No. 827). A wind
generating plant to which this provision applies shall maintain a
power factor within the range of 0.95 leading to 0.95 lagging,
measured at the Point of Interconnection as defined in this LGIA, if
the Transmission Provider's [System Impact] Cluster Study shows that
such a requirement is necessary to ensure safety or reliability. The
power factor range standard can be met by using, for example, power
electronics designed to supply this level of reactive capability 606
(taking into account any limitations due to voltage level, real
power output, etc.) or fixed and switched capacitors if agreed to by
the Transmission Provider, or a combination of the two. The
Interconnection Customer shall not disable power factor equipment
while the wind plant is in operation. Wind plants shall also be able
to provide sufficient dynamic voltage support in lieu of the power
system stabilizer and automatic voltage regulation at the generator
excitation system if the System Impact Study shows this to be
required for system safety or reliability.
iii. Supervisory Control and Data Acquisition (SCADA) Capability
The wind plant shall provide SCADA capability to transmit data
and receive instructions from the Transmission Provider to protect
system reliability. The Transmission Provider and the wind plant
Interconnection Customer shall determine what SCADA information is
essential for the proposed wind plant, taking into account the size
of the plant and its characteristics, location, and importance in
maintaining generation resource adequacy and transmission system
reliability in its area.
Appendix H to LGIA
Operating Assumptions for Generating Facility
Check box if applicable [ ]
Operating Assumptions:
{insert operating assumptions that reflect the charging behavior
of the Generating Facility that includes at least one electric
storage resource{time}
Appendix E: Pro Forma SGIP
Note: Deletions are in brackets and additions are in italics.
Section 1. Application
* * * * *
1.4 Modification of the Interconnection Request
Any modification to machine data or equipment configuration or
to the interconnection site of the Small Generating Facility not
agreed to in writing by the Transmission Provider and the
Interconnection Customer may be deemed a withdrawal of the
Interconnection Request and may require submission of a new
Interconnection Request, unless proper notification of each Party by
the other and a reasonable time to cure the problems created by the
changes are undertaken. Any such modification of the Interconnection
Request must be accompanied by any resulting updates to the models
described in Attachment 2 of this SGIP.
* * * * *
Section 3. Study Process
* * * * *
3.3 Feasibility Study
3.3.1 The feasibility study shall identify any potential adverse
system impacts that would result from the interconnection of the
Small Generating Facility.
3.3.2 A deposit of the lesser of 50 percent of the good faith
estimated feasibility study costs or earnest money of $1,000 may be
required from the Interconnection Customer.
3.3.3 The scope of and cost responsibilities for the feasibility
study are described in the attached feasibility study agreement
(Attachment 6).
3.3.4 If the feasibility study shows no potential for adverse
system impacts, the Transmission Provider shall send the
Interconnection Customer a facilities study agreement, including an
outline of the scope of the study and a non-binding good faith
estimate of the cost to perform the study. If no additional
facilities are required, the Transmission Provider shall send the
Interconnection Customer an executable interconnection agreement
within five Business Days.
3.3.5 If the feasibility study shows the potential for adverse
system impacts, the review process shall proceed to the appropriate
system impact study(s).
3.3.6 The feasibility study shall evaluate static synchronous
compensators, static VAR compensators, advanced power flow control
devices, transmission switching, synchronous condensers, voltage
source converters, advanced conductors, and tower lifting.
Transmission Provider shall evaluate each identified alternative
transmission technology and determine whether it should be used,
consistent with Good Utility Practice and other applicable
regulatory requirements. Transmission Provider shall include an
explanation of the results of Transmission Provider's evaluation for
each technology in the feasibility study report.
3.4 System Impact Study
3.4.1 A system impact study shall identify and detail the
electric system impacts that would result if the proposed Small
Generating Facility were interconnected without project
modifications or electric system modifications, focusing on the
adverse system impacts identified in the feasibility study, or to
study potential impacts, including but not limited to those
identified in the scoping meeting. A system impact study shall
evaluate the impact of the proposed interconnection on the
reliability of the electric system.
3.4.2 If no transmission system impact study is required, but
potential electric power Distribution System adverse system impacts
are identified in the scoping meeting or shown in the feasibility
study, a distribution system impact study must be performed. The
Transmission Provider shall send the Interconnection Customer a
distribution system impact study agreement within 15 Business Days
of transmittal of the feasibility study report, including an outline
of the scope of the study and a non-binding
[[Page 61337]]
good faith estimate of the cost to perform the study, or following
the scoping meeting if no feasibility study is to be performed.
3.4.3 In instances where the feasibility study or the
distribution system impact study shows potential for transmission
system adverse system impacts, within five Business Days following
transmittal of the feasibility study report, the Transmission
Provider shall send the Interconnection Customer a transmission
system impact study agreement, including an outline of the scope of
the study and a non-binding good faith estimate of the cost to
perform the study, if such a study is required.
3.4.4 If a transmission system impact study is not required, but
electric power Distribution System adverse system impacts are shown
by the feasibility study to be possible and no distribution system
impact study has been conducted, [the]Transmission Provider shall
send [the]Interconnection Customer a distribution system impact
study agreement.
3.4.5 If the feasibility study shows no potential for
transmission system or Distribution System adverse system impacts,
the Transmission Provider shall send the Interconnection Customer
either a facilities study agreement (Attachment 8), including an
outline of the scope of the study and a non-binding good faith
estimate of the cost to perform the study, or an executable
interconnection agreement, as applicable.
3.4.6 In order to remain under consideration for
interconnection, the Interconnection Customer must return executed
system impact study agreements, if applicable, within 30 Business
Days.
3.4.7 A deposit of the good faith estimated costs for each
system impact study may be required from the Interconnection
Customer.
3.4.8 The scope of and cost responsibilities for a system impact
study are described in the attached system impact study agreement.
3.4.9 Where transmission systems and Distribution Systems have
separate owners, such as is the case with transmission-dependent
utilities (``TDUs'')--whether investor-owned or not--the
Interconnection Customer may apply to the nearest Transmission
Provider (Transmission Owner, Regional Transmission Operator, or
Independent Transmission Provider) providing transmission service to
the TDU to request project coordination. Affected Systems shall
participate in the study and provide all information necessary to
prepare the study.
3.4.10 The system impact study shall evaluate static synchronous
compensators, static VAR compensators, advanced power flow control
devices, transmission switching, synchronous condensers, voltage
source converters, advanced conductors, and tower lifting.
Transmission Provider shall evaluate each identified alternative
transmission technology and determine whether it should be used,
consistent with Good Utility Practice and other applicable
regulatory requirements. Transmission Provider shall include an
explanation of the results of Transmission Provider's evaluation for
each technology in the system impact study report.
* * * * *
Attachment 2
Small Generator Interconnection Request
(Application Form)
* * * * *
Models for Non-synchronous Small Generating Facilities
For a non-synchronous Small Generating Facility, Interconnection
Customer shall provide (1) a validated user-defined root mean
squared (RMS) positive sequence dynamics model; (2) an appropriately
parameterized generic library RMS positive sequence dynamics model,
including model block diagram of the inverter control and plant
control systems, as defined by the selection in Table 1 or a model
otherwise approved by the Western Electricity Coordinating Council,
that corresponds to Interconnection Customer's Small Generating
Facility; and (3) if applicable, a validated electromagnetic
transient model if Transmission Provider performs an electromagnetic
transient study as part of the interconnection study process. A
user-defined model is a set of programming code created by equipment
manufacturers or developers that captures the latest features of
controllers that are mainly software based and represents the
entities' control strategies but does not necessarily correspond to
any generic library model. Interconnection Customer must also
demonstrate that the model is validated by providing evidence that
the equipment behavior is consistent with the model behavior (e.g.,
an attestation from Interconnection Customer that the model
accurately represents the entire Small Generating Facility;
attestations from each equipment manufacturer that the user defined
model accurately represents the component of the Small Generating
Facility; or test data).
Table 1--Acceptable Generic Library RMS Positive Sequence Dynamics Models
----------------------------------------------------------------------------------------------------------------
GE PSLF Siemens PSS/E* PowerWorld simulator Description
----------------------------------------------------------------------------------------------------------------
pvd1........................ ......................... PVD1.................... Distributed PV system model.
der_a....................... DERAU1................... DER_A................... Distributed energy resource
model.
regc_a...................... REGCAU1, REGCA1.......... REGC_A.................. Generator/converter model.
regc_b...................... REGCBU1.................. REGC_B.................. Generator/converter model.
wt1g........................ WT1G1.................... WT1G and WT1G1.......... Wind turbine model for Type-1
wind turbines (conventional
directly connected induction
generator).
wt2g........................ WT2G1.................... WT2G and WT2G1.......... Generator model for generic
Type-2 wind turbines.
wt2e........................ WT2E1.................... WT2E and WT2E1.......... Rotor resistance control
model for wound-rotor
induction wind-turbine
generator wt2g.
reec_a...................... REECAU1, REECA1.......... REEC_A.................. Renewable energy electrical
control model.
reec_c...................... REECCU1.................. REEC_C.................. Electrical control model for
battery energy storage
system.
reec_d...................... REECDU1.................. REEC_D.................. Renewable energy electrical
control model.
wt1t........................ WT12T1................... WT1T and WT12T1......... Wind turbine model for Type-1
wind turbines (conventional
directly connected induction
generator).
wt1p_b...................... wt1p_b................... WT12A1U_B............... Generic wind turbine pitch
controller for WTGs of Types
1 and 2.
wt2t........................ WT12T1................... WT2T.................... Wind turbine model for Type-2
wind turbines (directly
connected induction
generator wind turbines with
an external rotor
resistance).
wtgt_a...................... WTDTAU1, WTDTA1.......... WTGT_A.................. Wind turbine drive train
model.
wtga_a...................... WTARAU1, WTARA1.......... WTGA_A.................. Simple aerodynamic model.
wtgp_a...................... WTPTAU1, WTPTA1.......... WTGPT_A................. Wind Turbine Generator Pitch
controller.
wtgq_a...................... WTTQAU1, WTTQA1.......... WTGTRQ_A................ Wind Turbine Generator Torque
controller.
wtgwgo_a.................... WTGWGOAU................. WTGWGO_A................ Supplementary control model
for Weak Grids.
wtgibffr_a.................. WTGIBFFRA................ WTGIBFFR_A.............. Inertial-base fast frequency
response control.
wtgp_b...................... WTPTBU1.................. WTGPT_B................. Wind Turbine Generator Pitch
controller.
wtgt_b...................... WTDTBU1.................. WTGT_B.................. Drive train model.
repc_a...................... Type 4: REPCAU1 (v33), REPC_A.................. Power Plant Controller.
REPCA1 (v34) Type 3:
REPCTAU1 (v33), REPCTA1
(v34).
repc_b...................... PLNTBU1.................. REPC_B.................. Power Plant Level Controller
for controlling several
plants/devices.
In regard to Siemens PSS/E*:
Names of other models for
interface with other
devices: REA3XBU1, REAX4BU1--
for interface with Type 3
and 4 renewable machines.
SWSAXBU1--for interface with
SVC (modeled as switched
shunt in powerflow).
[[Page 61338]]
SYNAXBU1--for interface with
synchronous condenser.
FCTAXBU1--for interface with
FACTS device.
repc_c...................... REPCCU................... REPC_C.................. Power plant controller.
----------------------------------------------------------------------------------------------------------------
* * * * *
Appendix F: Pro Forma SGIA
Note: Deletions are in brackets and additions are in italics.
* * * * *
Article 1. Scope and Limitations of Agreement
* * * * *
1.5 Responsibilities of the Parties
1.5.1 The Parties shall perform all obligations of this
Agreement in accordance with all Applicable Laws and Regulations,
Operating Requirements, and Good Utility Practice.
1.5.2 The Interconnection Customer shall construct,
interconnect, operate and maintain its Small Generating Facility and
construct, operate, and maintain its Interconnection Facilities in
accordance with the applicable manufacturer's recommended
maintenance schedule, and in accordance with this Agreement, and
with Good Utility Practice.
1.5.3 The Transmission Provider shall construct, operate, and
maintain its Transmission System and Interconnection Facilities in
accordance with this Agreement, and with Good Utility Practice.
1.5.4 The Interconnection Customer agrees to construct its
facilities or systems in accordance with applicable specifications
that meet or exceed those provided by the National Electrical Safety
Code, the American National Standards Institute, IEEE, Underwriter's
Laboratory, and Operating Requirements in effect at the time of
construction and other applicable national and state codes and
standards. The Interconnection Customer agrees to design, install,
maintain, and operate its Small Generating Facility so as to
reasonably minimize the likelihood of a disturbance adversely
affecting or impairing the system or equipment of the Transmission
Provider and any Affected Systems.
1.5.5 Each Party shall operate, maintain, repair, and inspect,
and shall be fully responsible for the facilities that it now or
subsequently may own unless otherwise specified in the Attachments
to this Agreement. Each Party shall be responsible for the safe
installation, maintenance, repair and condition of their respective
lines and appurtenances on their respective sides of the point of
change of ownership. The Transmission Provider and the
Interconnection Customer, as appropriate, shall provide
Interconnection Facilities that adequately protect the Transmission
Provider's Transmission System, personnel, and other persons from
damage and injury. The allocation of responsibility for the design,
installation, operation, maintenance and ownership of
Interconnection Facilities shall be delineated in the Attachments to
this Agreement.
1.5.6 The Transmission Provider shall coordinate with all
Affected Systems to support the interconnection.
1.5.7 The Interconnection Customer shall ensure ``frequency ride
through'' capability and ``voltage ride through'' capability of its
Small Generating Facility. The Interconnection Customer shall enable
these capabilities such that its Small Generating Facility shall not
disconnect automatically or instantaneously from the system or
equipment of the Transmission Provider and any Affected Systems for
a defined under-frequency or over-frequency condition, or an under-
voltage or over-voltage condition, as tested pursuant to S[s]ection
2.1 of this agreement. The defined conditions shall be in accordance
with Good Utility Practice and consistent with any standards and
guidelines that are applied to other generating facilities in the
Balancing Authority Area on a comparable basis. The Small Generating
Facility's protective equipment settings shall comply with the
Transmission Provider's automatic load-shed program. The
Transmission Provider shall review the protective equipment settings
to confirm compliance with the automatic load-shed program. The term
``ride through'' as used herein shall mean the ability of a Small
Generating Facility to stay connected to and synchronized with the
system or equipment of the Transmission Provider and any Affected
Systems during system disturbances within a range of conditions, in
accordance with Good Utility Practice and consistent with any
standards and guidelines that are applied to other generating
facilities in the Balancing Authority Area on a comparable basis.
The term ``frequency ride through'' as used herein shall mean the
ability of a Small Generating Facility to stay connected to and
synchronized with the system or equipment of the Transmission
Provider and any Affected Systems during system disturbances within
a range of under-frequency and over-frequency conditions, in
accordance with Good Utility Practice and consistent with any
standards and guidelines that are applied to other generating
facilities in the Balancing Authority Area on a comparable basis.
The term ``voltage ride through'' as used herein shall mean the
ability of a Small Generating Facility to stay connected to and
synchronized with the system or equipment of the Transmission
Provider and any Affected Systems during system disturbances within
a range of under-voltage and over-voltage conditions, in accordance
with Good Utility Practice and consistent with any standards and
guidelines that are applied to other generating facilities in the
Balancing Authority Area on a comparable basis. For abnormal
frequency conditions and voltage conditions within the ``no trip
zone'' defined by Reliability Standard PRC-024-3 or successor
mandatory ride through Applicable Reliability Standards, the non-
synchronous Small Generating Facility must ensure that, within any
physical limitations of the Small Generating Facility, its control
and protection settings are configured or set to (1) continue active
power production during disturbance and post disturbance periods at
pre-disturbance levels unless providing primary frequency response
or fast frequency response; (2) minimize reductions in active power
and remain within dynamic voltage and current limits, if reactive
power priority mode is enabled, unless providing primary frequency
response or fast frequency response; (3) not artificially limit
dynamic reactive power capability during disturbances; and (4)
return to pre-disturbance active power levels without artificial
ramp rate limits if active power is reduced, unless providing
primary frequency response or fast frequency response.
1.6 Parallel Operation Obligations
Once the Small Generating Facility has been authorized to
commence parallel operation, the Interconnection Customer shall
abide by all rules and procedures pertaining to the parallel
operation of the Small Generating Facility in the applicable
[control area]Balancing Authority Area, including, but not limited
to; (1) the rules and procedures concerning the operation of
generation set forth in the Tariff or by the applicable system
operator(s) for the Transmission Provider's Transmission System and;
(2) the Operating Requirements set forth in Attachment 5 of this
Agreement.
* * * * *
1.8 Reactive Power and Primary Frequency Response
1.8.1 Power Factor Design Criteria
1.8.1.1 Synchronous Generation. The Interconnection Customer shall
design its Small Generating Facility to maintain a composite power
delivery at continuous rated power output at the Point of
Interconnection at a power factor within the range of 0.95 leading to
0.95 lagging, unless the Transmission Provider has established
different requirements that apply to all similarly situated synchronous
generators in the [control area] Balancing Authority Area on a
comparable basis.
1.8.1.2 Non-Synchronous Generation. The Interconnection Customer
shall design its Small Generating Facility to maintain a composite
power delivery at continuous rated power output at the high-side of
the generator substation at a power factor within the range of 0.95
leading to 0.95 lagging, unless the Transmission Provider has
established a different power factor range that applies to all
similarly situated non-
[[Page 61339]]
synchronous generators in the [control area] Balancing Authority
Area on a comparable basis. This power factor range standard shall
be dynamic and can be met using, for example, power electronics
designed to supply this level of reactive capability (taking into
account any limitations due to voltage level, real power output,
etc.) or fixed and switched capacitors, or a combination of the two.
This requirement shall only apply to newly interconnecting non-
synchronous generators that have not yet executed a Facilities Study
Agreement as of the effective date of the Final rule establishing
this requirement (Order No. 827).
1.8.2 The Transmission Provider is required to pay the
Interconnection Customer for reactive power that the Interconnection
Customer provides or absorbs from the Small Generating Facility when
the Transmission Provider requests the Interconnection Customer to
operate its Small Generating Facility outside the range specified in
A[a]rticle 1.8.1. In addition, if the Transmission Provider pays its
own or affiliated generators for reactive power service within the
specified range, it must also pay the Interconnection Customer.
1.8.3 Payments shall be in accordance with the Interconnection
Customer's applicable rate schedule then in effect unless the
provision of such service(s) is subject to a regional transmission
organization or independent system operator FERC-approved rate
schedule. To the extent that no rate schedule is in effect at the
time the Interconnection Customer is required to provide or absorb
reactive power under this Agreement, the Parties agree to
expeditiously file such rate schedule and agree to support any
request for waiver of the Commission's prior notice requirement in
order to compensate the Interconnection Customer from the time
service commenced.
1.8.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Small
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Small Generating Facility's
real power output in accordance with the droop and deadband
parameters and in the direction needed to correct frequency
deviations. Interconnection Customer is required to install a
governor or equivalent controls with the capability of operating:
(1) with a maximum 5 percent droop and 0.036 Hz
deadband; or (2) in accordance with the relevant droop, deadband,
and timely and sustained response settings from an approved [NERC]
Electric Reliability Organization [R]reliability [S]standard
providing for equivalent or more stringent parameters. The droop
characteristic shall be: (1) based on the nameplate capacity of the
Small Generating Facility, and shall be linear in the range of
frequencies between 59 to 61 Hz that are outside of the deadband
parameter; or (2) based an approved [NERC] Electric Reliability
Organization [R]reliability [S]standard providing for an equivalent
or more stringent parameter. The deadband parameter shall be: the
range of frequencies above and below nominal (60 Hz) in which the
governor or equivalent controls is not expected to adjust the Small
Generating Facility's real power output in response to frequency
deviations. The deadband shall be implemented: (1) without a step to
the droop curve, that is, once the frequency deviation exceeds the
deadband parameter, the expected change in the Small Generating
Facility's real power output in response to frequency deviations
shall start from zero and then increase (for under-frequency
deviations) or decrease (for over-frequency deviations) linearly in
proportion to the magnitude of the frequency deviation; or (2) in
accordance with an approved [NERC] Electric Reliability Organization
[R]reliability [S]standard providing for an equivalent or more
stringent parameter. Interconnection Customer shall notify
Transmission Provider that the primary frequency response capability
of the Small Generating Facility has been tested and confirmed
during commissioning. Once Interconnection Customer has synchronized
the Small Generating Facility with the Transmission System,
Interconnection Customer shall operate the Small Generating Facility
consistent with the provisions specified in Sections 1.8.4.1 and
1.8.4.2 of this Agreement. The primary frequency response
requirements contained herein shall apply to both synchronous and
non-synchronous Small Generating Facilities.
1.8.4.1 Governor or Equivalent Controls. Whenever the Small
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Small Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall: (1) in
coordination with Transmission Provider and/or the relevant
[b]Balancing [a]Authority, set the deadband parameter to: (1) a
maximum of 0.036 Hz and set the droop parameter to a
maximum of 5 percent; or (2) implement the relevant droop and
deadband settings from an approved [NERC] Electric Reliability
Organization [R]reliability [S]standard that provides for equivalent
or more stringent parameters. Interconnection Customer shall be
required to provide the status and settings of the governor or
equivalent controls to Transmission Provider and/or the relevant
[b]Balancing [a]Authority upon request. If Interconnection Customer
needs to operate the Small Generating Facility with its governor or
equivalent controls not in service, Interconnection Customer shall
immediately notify Transmission Provider and the relevant
[b]Balancing [a]Authority, and provide both with the following
information: (1) the operating status of the governor or equivalent
controls (i.e., whether it is currently out of service or when it
will be taken out of service); (2) the reasons for removing the
governor or equivalent controls from service; and (3) a reasonable
estimate of when the governor or equivalent controls will be
returned to service. Interconnection Customer shall make Reasonable
Efforts to return its governor or equivalent controls into service
as soon as practicable. Interconnection Customer shall make
Reasonable Efforts to keep outages of the Small Generating
Facility's governor or equivalent controls to a minimum whenever the
Small Generating Facility is operated in parallel with the
Transmission System.
1.8.4.2 Timely and Sustained Response. Interconnection Customer
shall ensure that the Small Generating Facility's real power
response to sustained frequency deviations outside of the deadband
setting is automatically provided and shall begin immediately after
frequency deviates outside of the deadband, and to the extent the
Small Generating Facility has operating capability in the direction
needed to correct the frequency deviation. Interconnection Customer
shall not block or otherwise inhibit the ability of the governor or
equivalent controls to respond and shall ensure that the response is
not inhibited, except under certain operational constraints
including, but not limited to, ambient temperature limitations,
physical energy limitations, outages of mechanical equipment, or
regulatory requirements. The Small Generating Facility shall sustain
the real power response at least until system frequency returns to a
value within the deadband setting of the governor or equivalent
controls. A Commission-approved Reliability Standard with equivalent
or more stringent requirements shall supersede the above
requirements.
1.8.4.3 Exemptions. Small Generating Facilities that are
regulated by the United States Nuclear Regulatory Commission shall
be exempt from Sections 1.8.4, 1.8.4.1, and 1.8.4.2 of this
Agreement. Small Generating Facilities that are behind the meter
generation that is sized-to-load (i.e., the thermal load and the
generation are near-balanced in real-time operation and the
generation is primarily controlled to maintain the unique thermal,
chemical, or mechanical output necessary for the operating
requirements of its host facility) shall be required to install
primary frequency response capability in accordance with the droop
and deadband capability requirements specified in Section 1.8.4, but
shall be otherwise exempt from the operating requirements in
Sections 1.8.4, 1.8.4.1, 1.8.4.2, and 1.8.4.4 of this Agreement.
1.8.4.4 Electric Storage Resources. Interconnection Customer
interconnecting an electric storage resource shall establish an
operating range in Attachment 5 of its SGIA that specifies a minimum
state of charge and a maximum state of charge between which the
electric storage resource will be required to provide primary
frequency response consistent with the conditions set forth in
Sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 of this Agreement.
Attachment 5 shall specify whether the operating range is static or
dynamic, and shall consider: (1) the expected magnitude of frequency
deviations in the interconnection; (2) the expected duration that
system frequency will remain outside of the deadband parameter in
the interconnection; (3) the expected incidence of frequency
deviations outside of the deadband parameter in the interconnection;
(4) the physical capabilities of the electric
[[Page 61340]]
storage resource; (5) operational limitations of the electric
storage resource due to manufacturer specifications; and (6) any
other relevant factors agreed to by Transmission Provider and
Interconnection Customer, and in consultation with the relevant
transmission owner or [b]Balancing [a]Authority as appropriate. If
the operating range is dynamic, then Attachment 5 must establish how
frequently the operating range will be reevaluated and the factors
that may be considered during its reevaluation.
Interconnection Customer's electric storage resource is required
to provide timely and sustained primary frequency response
consistent with Section 1.8.4.2 of this Agreement when it is online
and dispatched to inject electricity to the Transmission System and/
or receive electricity from the Transmission System. This excludes
circumstances when the electric storage resource is not dispatched
to inject electricity to the Transmission System and/or dispatched
to receive electricity from the Transmission System. If
Interconnection Customer's electric storage resource is charging at
the time of a frequency deviation outside of its deadband parameter,
it is to increase (for over-frequency deviations) or decrease (for
under-frequency deviations) the rate at which it is charging in
accordance with its droop parameter. Interconnection Customer's
electric storage resource is not required to change from charging to
discharging, or vice versa, unless the response necessitated by the
droop and deadband settings requires it to do so and it is
technically capable of making such a transition.
* * * * *
Attachment 1
Glossary of Terms
Affected System--An electric system other than the Transmission
Provider's Transmission System that may be affected by the proposed
interconnection.
Applicable Laws and Regulations--All duly promulgated applicable
federal, state and local laws, regulations, rules, ordinances,
codes, decrees, judgments, directives, or judicial or administrative
orders, permits and other duly authorized actions of any
Governmental Authority.
Balancing Authority shall mean an entity that integrates
resource plans ahead of time, maintains demand and resource balance
within a Balancing Authority Area, and supports interconnection
frequency in real time.
Balancing Authority Area shall mean the collection of
generation, transmission, and loads within the metered boundaries of
the Balancing Authority. The Balancing Authority maintains load-
resource balance within this area.
Business Day--Monday through Friday, excluding Federal Holidays.
Default--The failure of a breaching Party to cure its breach
under the Small Generator Interconnection Agreement.
Distribution System--The Transmission Provider's facilities and
equipment used to transmit electricity to ultimate usage points such
as homes and industries directly from nearby generators or from
interchanges with higher voltage transmission networks which
transport bulk power over longer distances. The voltage levels at
which Distribution Systems operate differ among areas.
Distribution Upgrades--The additions, modifications, and
upgrades to the Transmission Provider's Distribution System at or
beyond the Point of Interconnection to facilitate interconnection of
the Small Generating Facility and render the transmission service
necessary to effect the Interconnection Customer's wholesale sale of
electricity in interstate commerce. Distribution Upgrades do not
include Interconnection Facilities.
Good Utility Practice--Any of the practices, methods and acts
engaged in or approved by a significant portion of the electric
industry during the relevant time period, or any of the practices,
methods and acts which, in the exercise of reasonable judgment in
light of the facts known at the time the decision was made, could
have been expected to accomplish the desired result at a reasonable
cost consistent with good business practices, reliability, safety
and expedition. Good Utility Practice is not intended to be limited
to the optimum practice, method, or act to the exclusion of all
others, but rather to be acceptable practices, methods, or acts
generally accepted in the region.
Governmental Authority--Any federal, state, local or other
governmental regulatory or administrative agency, court, commission,
department, board, or other governmental subdivision, legislature,
rulemaking board, tribunal, or other governmental authority having
jurisdiction over the Parties, their respective facilities, or the
respective services they provide, and exercising or entitled to
exercise any administrative, executive, police, or taxing authority
or power; provided, however, that such term does not include the
Interconnection Customer, the Interconnection Provider, or any
Affiliate thereof.
Interconnection Customer--Any entity, including the Transmission
Provider, the Transmission Owner or any of the affiliates or
subsidiaries of either, that proposes to interconnect its Small
Generating Facility with the Transmission Provider's Transmission
System.
Interconnection Facilities--The Transmission Provider's
Interconnection Facilities and the Interconnection Customer's
Interconnection Facilities. Collectively, Interconnection Facilities
include all facilities and equipment between the Small Generating
Facility and the Point of Interconnection, including any
modification, additions or upgrades that are necessary to physically
and electrically interconnect the Small Generating Facility to the
Transmission Provider's Transmission System. Interconnection
Facilities are sole use facilities and shall not include
Distribution Upgrades or Network Upgrades.
Interconnection Request--The Interconnection Customer's request,
in accordance with the Tariff, to interconnect a new Small
Generating Facility, or to increase the capacity of, or make a
Material Modification to the operating characteristics of, an
existing Small Generating Facility that is interconnected with the
Transmission Provider's Transmission System.
Material Modification--A modification that has a material impact
on the cost or timing of any Interconnection Request with a later
queue priority date.
Network Upgrades--Additions, modifications, and upgrades to the
Transmission Provider's Transmission System required at or beyond
the point at which the Small Generating Facility interconnects with
the Transmission Provider's Transmission System to accommodate the
interconnection of the Small Generating Facility with the
Transmission Provider's Transmission System. Network Upgrades do not
include Distribution Upgrades.
Operating Requirements--Any operating and technical requirements
that may be applicable due to Regional Transmission Organization,
Independent System Operator, [control area]Balancing Authority Area,
or [the]Transmission Providers requirements, including those set
forth in the Small Generator Interconnection Agreement.
Party or Parties--The Transmission Provider, Transmission Owner,
Interconnection Customer or any combination of the above.
Point of Interconnection--The point where the Interconnection
Facilities connect with the Transmission Provider's Transmission
System.
Reasonable Efforts--With respect to an action required to be
attempted or taken by a Party under the Small Generator
Interconnection Agreement, efforts that are timely and consistent
with Good Utility Practice and are otherwise substantially
equivalent to those a Party would use to protect its own interests.
Small Generating Facility--The Interconnection Customer's device
for the production and/or storage for later injection of electricity
identified in the Interconnection Request, but shall not include the
Interconnection Customer's Interconnection Facilities.
Tariff--The Transmission Provider or Affected System's Tariff
through which open access transmission service and Interconnection
Service are offered, as filed with the FERC, and as amended or
supplemented from time to time, or any successor tariff.
Transmission Owner--The entity that owns, leases or otherwise
possesses an interest in the portion of the Transmission System at
the Point of Interconnection and may be a Party to the Small
Generator Interconnection Agreement to the extent necessary.
Transmission Provider--The public utility (or its designated
agent) that owns, controls, or operates transmission or distribution
facilities used for the transmission of electricity in interstate
commerce and provides transmission service under the Tariff. The
term Transmission Provider should be read to include the
Transmission Owner when the Transmission Owner is separate from the
Transmission Provider.
Transmission System--The facilities owned, controlled or
operated by the
[[Page 61341]]
Transmission Provider or the Transmission Owner that are used to
provide transmission service under the Tariff.
Upgrades--The required additions and modifications to the
Transmission Provider's Transmission System at or beyond the Point
of Interconnection. Upgrades may be Network Upgrades or Distribution
Upgrades. Upgrades do not include Interconnection Facilities.
* * * * *
Improvements to Generator Interconnection--Docket No. RM22-14-000
Procedures and Agreements
DANLY, Commissioner, concurring:
1. I concur in the issuance of today's final rule. I write
separately to state that, while I continue to harbor misgivings
about the Commission's power to implement far-reaching, uniform
policies based on our authority under FPA section 206,\1\ I am
satisfied on this record that existing interconnection procedures in
both RTO and non-RTO regions have been shown to be unjust and
unreasonable, and that we take today's action consistent with the
standards articulated in precedent.\2\ Though I am not convinced
that this precedent will ultimately be proven correct in declaring
that ``the Commission may rely on `generic' or `general' findings of
a systemic problem to support imposition of an industry-wide
solution,'' the Commission is entitled to act under prevailing case
law.\3\
---------------------------------------------------------------------------
\1\ 16 U.S.C. 824e.
\2\ Improvements to Generator Interconnection Procedures &
Agreements, 184 FERC ] 61,054, at P 57 & n.149 (2023)
(Interconnection Rule) (citing S.C. Pub. Serv. Auth. v. FERC, 762
F.3d 41, 67 (D.C. Cir. 2014) (quoting Interstate Nat. Gas Ass'n v.
FERC, 285 F.3d 18, 37 (D.C. Cir. 2002))).
\3\ Id.
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2. I also agree that the relatively narrow reforms contemplated
in this final rule appear, based on this record, to be a just and
reasonable replacement rate. I am pleased that most of that which I
considered to be the most problematic elements in the Notice of
Proposed Rulemaking have been excluded from this rule.\4\ I also
remind parties of the availability of ``the independent entity
variation standard for regional transmission organizations (RTO) and
independent system operators (ISO) and the consistent with or
superior to standard for non-RTO/ISO transmission providers'' should
they choose to seek variations from these rules.\5\
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\4\ Improvements to Generator Interconnection Procedures &
Agreements, 179 FERC ] 61,194 (2022) (Danly, Comm'r, concurring at
PP 6-10) (NOPR Concurrence).
\5\ Interconnection Rule, 184 FERC ] 61,054 at P 10 (citation
omitted).
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3. While I vote to approve today's order, I will also thoroughly
review any requests for rehearing, particularly to the extent to
which parties to the proceeding wish to advance arguments that we
have exceeded our authority under FPA section 206, or that we have
failed to carry our evidentiary burden, either generally, or in a
sufficient number of specific cases that our order amounts to an
unlawful exercise of our powers.
4. I would have preferred to receive section 205 \6\ filings
from utilities proposing interconnection reforms--and indeed we have
received and ruled upon a number of such filings. Failing that, I
would have preferred for the Commission or interested parties to
have initiated FPA section 206 complaints against the RTOs or other
entities with interconnection delays, rather than to have proceeded
generically in an effort to establish uniformity.\7\ However, my
preferences do not make this rule unlawful, and I am satisfied that
today's rule is consistent with our legal obligations.
---------------------------------------------------------------------------
\6\ 16 U.S.C. 824d.
\7\ See NOPR Concurrence at PP 1, 4.
---------------------------------------------------------------------------
For these reasons, I respectfully concur.
-----------------------------------------------------------------------
James P. Danly,
Commissioner.
Improvements to Generator Interconnection--Docket No. RM22-14-000
Procedures and Agreements
CLEMENTS, Commissioner, concurring:
1. As the findings of this final rule illustrate, our nation is
facing a grid infrastructure crisis. Five years ago, the Commission
issued Order No. 845 in an effort to improve interconnection queue
delays, noting that ``despite Commission efforts to improve the
interconnection process . . . many interconnection customers
experience delays, and some interconnection queues have significant
backlogs and long timelines.'' \1\ Unfortunately, the same
observation can be made today, only the problem has gotten far
worse.\2\ As of the end of 2022, a staggering 10,000 projects
representing over 2,000 GW of potential generation and storage
capacity are stuck in line to connect to the grid.\3\ That is nearly
double the 1,250 GW of total installed capacity in the United States
today.\4\ Wait times have ``increased markedly,'' with Lawrence
Berkeley National Lab reporting that ``[t]he typical project built
in 2022 took 5 years from the interconnection request to commercial
operations, compared to 3 years in 2015 and [less than] 2 years in
2008.'' \5\ Meanwhile, interconnection costs have increased
significantly.\6\ Project completion rates are very low,\7\ and
late-stage withdrawal is becoming more common.\8\ In addition, the
typical timespan between the execution of a project's
interconnection agreement and its commercial operations date has
also increased, from roughly 17 months for projects built between
2007-2014 to around 22 months for projects built between 2015-
2022.\9\
---------------------------------------------------------------------------
\1\ 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, 166 FERC ] 61,137, 84 FR
8156 (Mar. 6, 2019), order on reh'g, Order No. 845-B, 168 FERC ]
61,092 (2019).
\2\ See Improvements to Generator Interconnection Procedures and
Agreements, Order No. 2023, 184 FERC ] 61,054, at PP 37-40 (2023)
[hereinafter Final Rule].
\3\ Joseph Rand et al., Lawrence Berkeley Nat'l Lab'y, Queued
Up: Characteristics of Power Plants Seeking Transmission
Interconnection As of the End of 2022, at 7-8 (Apr. 2023), https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf
[hereinafter Queued Up 2023].
\4\ Id. at 10.
\5\ Id. at 3.
\6\ See Final rule at P 41 (detailing interconnection cost
increases seen across different regions).
\7\ See Queued Up 2023 at 18-20.
\8\ Id. at 22.
\9\ Id. at 30.
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2. Ultimately, the dysfunction of the interconnection process
harms consumers. It prevents low-cost generation from coming online
that could have reduced the cost of electricity,\10\ and it harms
reliability. Several of the nation's largest grid operators have
stated that they could face resource adequacy problems if new
resource entry does not occur rapidly enough to match the pace of
resource retirements.\11\ Given these challenges and their attendant
impacts on consumers, I enthusiastically support this final rule,
which includes a number of helpful reforms that will improve
interconnection processes across the country. The bulk of these
reforms will widely extend proven best practices to utilities around
the country.
---------------------------------------------------------------------------
\10\ See, e.g., T. Bruce Tsuchida et al., The Brattle Grp.,
Unlocking the Queue with Grid-Enhancing Technologies: Case Study of
the Southwest Power Pool at 9 (Feb. 1, 2021), https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf (estimating that integrating 2,670 MW of new
generation in the Southwest Power Pool would yield annual production
cost savings of $175 million).
\11\ See PJM Interconnection, LLC, Energy Transition in PJM:
Resource Retirements, Replacements & Risks at 2 (Feb. 24, 2023),
energy-transition-in-pjm-resource-retirements-replacements-and-
risks.ashx; Midcontinent Indep. Sys. Operator, 2022 Regional
Resource Assessment at 4, 20 (Nov. 2022), https://cdn.misoenergy.org/2022%20Regional%20Resource%20Assessment%20Report627163.pdf; California Indep. Sys. Operator, Summer Loads and
Resources Assessment at 20 (May 18, 2022), http://www.caiso.com/Documents/2022-Summer-Loads-and-Resources-Assessment.pdf.
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3. What we have learned through consideration of comments to and
stakeholder engagement about the Commission's Notice of Proposed
Rulemaking, however, is that while this rule can be expected to
improve matters, more will be necessary to solve the problem. What
was perhaps considered a straightforward kitchen renovation has
become more complicated. After we have removed the cabinets and
taken out the drywall, we have discovered outdated wires, rusted
pipes and cracks in the foundation. None of these additional
challenges are insurmountable, but they are in some ways more
fundamental to getting that modern, working kitchen up and running.
4. I therefore write separately to highlight some of the
remaining issues and potential solutions parties have brought
forward that may address the remainder of the full interconnection
reform challenge, as well as to encourage stakeholders to remain
focused on taking additional critical steps toward addressing these
issues.
5. I do not suggest that solving the remaining challenges
related to interconnection will be easy. The record
[[Page 61342]]
reveals quite the opposite. A comprehensive solution set will
require out-of-the-box thinking in some areas and continued
incremental improvements in others.
6. Fortunately, we have received many thoughtful suggestions for
further reforms, which serve as the seeds for future solutions.
Below, I discuss two categories of promising ideas meriting further
discussion: (1) deeper reforms that get at some of the remaining
fundamental challenges with interconnection processes; and (2)
additional nuts and bolts changes that could enhance the
effectiveness of a variety of interconnection processes, but which
were not part of the proposal giving rise to this final rule.
7. I urge stakeholders to examine these and related suggestions,
and for transmission planners to adopt regionally appropriate
solutions beyond those required by this final rule.
I. Deeper reforms
8. In considering interconnection processes across the country,
twin challenges emerge as the most fundamental problems. First,
interconnection studies initially examine clusters of projects that
often bear little resemblance to what ultimately interconnects to
the system. They rely on a long and painful process of attrition to
arrive at a final set of projects along with corresponding network
upgrades.
9. More specifically, processes that rely solely on
interconnection applications to determine study scope, and which
require substantial study work for each customer based on inputs
that depend on other projects in the queue, have become overwhelmed.
For example, S&P reports that the California Independent System
Operator (CAISO) received more than 350 GW of projects in its latest
application window, driving its total queue to over 500 GW.\12\
Meanwhile, the Midcontinent Independent System Operator's (MISO)
queue has ballooned to 339 GW, while PJM Interconnection, LLC's
(PJM) has risen to 298 GW, both comfortably greater than the present
installed capacity of either region.\13\ According to a recent CAISO
stakeholder presentation, ``[t]he massive increase in
interconnection requests seeking to meet the accelerated cadence of
resource development . . . has overwhelmed critical planning and
engineering resources across the industry. . . . The current
generator interconnection processes simply cannot efficiently
accommodate the latest level of interconnection requests received.''
\14\ Other queues are similarly overwhelmed.\15\
---------------------------------------------------------------------------
\12\ Garrett Hering, California ISO Tackles `Broken'
Interconnection Process as Queue Tops 500 GW, S&P Global (July 19,
2023); see also CAISO, Cluster 15 Interconnection Requests, http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx
(last visited July 26, 2023).
\13\ Queued Up 2023 at 9-10.
\14\ CAISO, 2023 Interconnection Process Enhancements: Summary
of June 20 & 21 Track 2 Working Group Meeting--Revised Principles
and Problem Statements 1 and 2, at 4 (June 23, 2023), http://www.caiso.com/InitiativeDocuments/Revised-Principles-and-Problem-Statements-Interconnection-Process-Enhancements-2023-Track%202-Jun%2020-212023.pdf.
\15\ See Queued Up 2023 at 9 (showing very large amounts of
queue capacity across several regions).
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10. Second, project developers face enormous cost
uncertainty.\16\ Initial study results may be far different from
final costs because the number of projects reaching the facilities
study stage (the final stage before the execution of a generator
interconnection agreement) can be far fewer than those earlier
examined in the cluster study stage. As CAISO observed in a recent
stakeholder presentation, its ``[s]tudy results lose accuracy,
meaning and utility when the level of cluster [Interconnection
Resource] capacity [is] multiple times the existing or planned
transmission capacity for an area.'' \17\
---------------------------------------------------------------------------
\16\ See Final rule at P 43 (``Cost uncertainty poses an
especially significant obstacle because interconnection customers
may not be able to finance substantial increases in unexpected
interconnection costs.''). For example, in one relatively recent
interconnection cluster in MISO, the preliminary system impact study
estimated $3.2 billion in network upgrades for 31 projects, but that
estimate was cut to only $330 million by Decision Point I after more
than half of the projects withdrew. See Midcontinent Indep. Sys.
Operator, 169 FERC ] 61,173, at P 11 (2019).
\17\ CAISO, 2023 Interconnection Process Enhancements Track 2
Working Group at 10 (July 11, 2023), http://www.caiso.com/InitiativeDocuments/Presentation-Interconnection-Process-Enhancements-2023-Track-2-Working-Group-Jul112023.pdf.
---------------------------------------------------------------------------
11. Today's final rule will help to ameliorate these problems.
In particular, the rule's site control requirements,\18\ requirement
for an interconnection customer to select a definitive point of
interconnection,\19\ commercial readiness requirements,\20\ and
withdrawal penalty framework \21\ will each contribute to more
streamlined study clusters. As we have learned through this
proceeding, however, they will likely be inadequate, on their own,
to fully solve these deep challenges.\22\
---------------------------------------------------------------------------
\18\ See Final rule at PP 583-612.
\19\ Id. at PP 200-03.
\20\ Id. at PP 690-707.
\21\ Id. at PP 780-813].
\22\ The Arizona Corporation Commission, for example, argues
that ```first-ready' queue reforms that are not explicitly linked to
an effective rationing process will likely fail to help resolve the
growing backlog. Some mechanism to prioritize projects and allocate
scarce interconnection access to the highest quality projects is
likely needed.'' Arizona Commission Initial Comments at 1-2.
Similarly, a coalition of consumer groups and the R Street Institute
argues that the Commission's notice of proposed rulemaking in this
proceeding ``leaves many critical reforms unresolved.'' R Street
Institute et al. June 8, 2023 Comments in Support of Generator
Interconnection Reform Under RM22-14, at 2. See also Cypress Creek
Initial Comments at 12 (arguing that ``a cluster-based approach
alone, without further changes, will not provide adequate reform'').
---------------------------------------------------------------------------
12. In my estimation, the record of this proceeding, as well as
recent stakeholder initiatives, suggest several options for further
improvement. They are not necessarily exclusive of one another, and
appropriate application may depend on the particular regional
context. They include: (1) linking the interconnection process to
proactive transmission system planning; (2) in applicable regions,
aligning the interconnection process more closely with competitive
resource solicitations; and (3) transitioning to a ``focused''
interconnection process or ``connect and manage'' approach for all
energy-only resources.
A. Link The Interconnection Process to Proactive Transmission
System Planning
13. Foundationally, it should be acknowledged that for
interconnection reform to succeed, holistic, forward-looking
transmission planning, as included in the Commission's notice of
proposed rulemaking on regional planning and cost allocation,\23\
must also succeed. Interconnection processes are overloaded in part
because they are being relied on to build out core transmission
system infrastructure that should be considered in regional planning
processes. We know interconnection processes were not intended for,
and are ill suited to perform, this task. As a coalition of consumer
groups and the R Street Institute argues in a recent letter to the
Commission, ``[t]he cost of network upgrades can be dramatically
reduced through proactive regional transmission planning, which
enables major reductions in [Generator Interconnection] requirements
and delays.'' \24\ Even prior to the adoption of any final rule in
the Commission's regional transmission planning proceeding,
individual transmission providers can make significant strides
toward the cost-effective construction of new transmission
infrastructure via regionally tailored proposals and
initiatives.\25\
---------------------------------------------------------------------------
\23\ See Building for the Future Through Elec. Reg'l
Transmission Planning & Cost Allocation & Generator Interconnection,
179 FERC ] 61,028 (2022).
\24\ R Street Institute et al. June 8, 2023 Comments in Support
of Generator Interconnection Reform Under RM22-14, at 2.
\25\ See, e.g., MISO, MTEP21 Report Addendum: Long Range
Transmission Planning Tranche 1 Executive Summary at 1 (2022),
https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary 625790.pdf
(describing a proposed ``portfolio of 18 transmission projects
located in the MISO Midwest Subregions with a total investment of
$10.3 billion, and benefit-to-cost ratios average of 2.6'').
---------------------------------------------------------------------------
14. There may also be opportunities to streamline the
interconnection process by more closely linking it to the
transmission system planning process,\26\ or to carry out forward-
looking interconnection studies driven by a more holistic assessment
of interconnection needs.
---------------------------------------------------------------------------
\26\ See, e.g., AEE Initial Comments at 10-13 (advocating for a
closer linkage between transmission planning and generator
interconnection).
---------------------------------------------------------------------------
15. Southwest Power Pool (SPP) and its stakeholders have
embarked on a potentially promising initiative along these lines,
which proposes a ``Consolidated Planning Process'' that would
connect SPP's interconnection
[[Page 61343]]
process to its regional transmission planning process.\27\
Similarly, CAISO is seeking to ``[p]rioritize interconnection in
zones where transmission capacity exists or new transmission has
been approved, while providing opportunities to identify and provide
alternative points of interconnection or upgrades.'' \28\ Like SPP,
CAISO aims to overhaul a bloated queue that requires initial studies
that bear little relation to transmission system reality, and
instead chart a course to a new process that produces ``meaningful
study results that take into account system capability, resource
planning and procurement.'' \29\
---------------------------------------------------------------------------
\27\ See Southwest Power Pool, Consolidated Planning Process
Task Force, https://www.spp.org/stakeholder-groups-list/organizational-groups/board-of-directorsmembers-committee/consolidated-planning-process-task-force/ (last visited July 26,
2023); Southwest Power Pool, Consolidated Planning Process: Phase 1
Recommendations (May 17, 2023), https://www.spp.org/spp-documents-filings/?id=297513 (when accessing ``CPPTF Meeting Materials
20230621''). SPP proposes to calculate an ``entry fee,'' which would
involve per-MW costs of any ``regional'' or ``sub-regional''
interconnection network infrastructure, along with a ``local''
component derived from a narrower reliability assessment examining
any necessary facilities at the point of interconnection. See
Southwest Power Pool, CPP Entry Fee Rate Structure, at 20 (July 14,
2023), https://www.spp.org/spp-documents-filings/?id=297513 (when
accessing ``CPPTF Meeting Materials 20230714'') (setting forth entry
fee components). The key to SPP's proposal, as I understand it, is
that the regional and sub-regional components of the entry fee would
be identified by ``forward-casting,'' a ``longer-term assessment''
derived from estimated costs of interconnecting resources in a
fashion that is integrated with SPP's long-term regional plan. Id.
By assessing costs across a broader range of projects than any
individual cluster, and by calculating it based on SPP's proactive
planning vision rather than calculating costs for a hypothetical
cluster of initial applicants that will not all reach commercial
operation, SPP may be able to offer far greater cost certainty for
project developers and thereby greatly streamline and accelerate the
interconnection process. Id. at 11, 19 (illustrating a greatly
simplified flow chart for the consolidated planning approach as
compared to SPP's status quo).
\28\ CAISO, 2023 Interconnection Process Enhancements Track 2
Working Group at 9 (July 11, 2023), http://www.caiso.com/InitiativeDocuments/Presentation-Interconnection-Process-Enhancements-2023-Track-2-Working-Group-Jul112023.pdf.
\29\ Id.
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16. The promise of a forward-looking approach is also becoming
clear through the ongoing effort that MISO and SPP are pioneering in
the affected systems context. That effort, known as the Joint
Targeted Interconnection Queue (JTIQ), examines a larger portfolio
of projects to identify solutions that more efficiently solve their
collective needs.\30\ By assessing larger, long-term system needs
across study clusters, this approach identifies efficiencies that
could not be captured on a more project-specific basis.\31\
---------------------------------------------------------------------------
\30\ See generally SPP & MISO, SPP-MISO Joint Targeted
Interconnection Queue Cost Allocation and Affected System Study
Process Changes White Paper (Dec. 20, 2022), https://www.spp.org/documents/68518/spp-miso%20jtiq%20study%20updated%20white%20paper%2020221220.pdf.
Because this approach looks at projects that have reached the
affected systems study stage, it does not provide a template for
narrowing the initial pool of projects to facilitate meaningful
study results. But the forward-looking nature of the initiative may
nevertheless provide valuable insights to regional interconnection
processes more broadly.
\31\ See SPP & MISO, MISO-SPP Joint Targeted Interconnection
Queue Update at 7 (March 27, 2023), https://cdn.misoenergy.org/20230337%20MISO%20SPP%20JTIQ% 20Update628357.pdf.
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17. As these regions' proposals are still in flux and have yet
to be filed with the Commission, I do not prejudge them. But, at a
high level, it appears that these types of approaches may hold the
potential to provide developers more certainty; avoid a dynamic
whereby large upgrades are assigned to individual projects that then
drop from the queue, causing a cascading need for restudy; and
deliver benefits to consumers by identifying more efficient
infrastructure solutions than would be delivered on a piecemeal
basis.
18. Questions worth exploring as these types of processes
develop include:
a. How can the process ensure that fees charged to
interconnection customers provide the funds needed for the relevant
proactively-planned network upgrades, while providing developers
with a reasonable degree of cost certainty?;
b. Would a mechanism such as a competitive auction or open
season administered by the transmission provider be an effective
tool for allocating scarce interconnection capacity identified by
the forward-looking plans, and/or are there other processes that can
effectively streamline the study process?;
c. How can such processes be designed in a manner that is not
unduly discriminatory and is consistent with open access
principles?; and
d. What process is appropriate for interconnection applications
that do not align with the transmission provider's forward-looking
regional transmission plan?
B. Align Interconnection Processes With Competitive Resource
Solicitations
19. In some regions of the country, it may be appropriate to
link aspects of the interconnection process to resource
solicitation.\32\ The Colorado Public Utilities Commission (Colorado
Commission), for example, characterizes the interconnection queue
management processes of transmission providers in its state as
``highly functional.'' \33\ The key, it says, is that its ``existing
FERC-approved tariffs and bilateral market structure . . . ensures
that projects selected in [its] competitive resource planning and
acquisition process obtain scarce interconnection in a cost-
effective and timely manner.'' \34\
---------------------------------------------------------------------------
\32\ See, e.g., Clean Energy Associations Initial Comments at 38
(urging the acceptance of ``regionally specific proposals that would
align the interconnection process with competitive procurements
associated with resource planning, rather than placing them at
odds''). Such alignment may not be appropriate or feasible, of
course, in certain multi-state regions in which the bulk of resource
development is driven by anticipated market revenues.
\33\ Colorado Commission Initial Comments at 2.
\34\ Id.
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20. The Colorado Commission and Arizona Corporation Commission
(Arizona Commission) argue that a mechanism to allocate scarce
interconnection capacity is needed.\35\ The Colorado Commission
explains that if there is 400 MW of low-cost headroom on the system,
for instance, several commercially viable projects that collectively
exceed that amount may compete for that headroom yet be unviable on
a collective basis if all proceed.\36\ It contends that, lacking a
mechanism to allocate the headroom, a cluster study process may
result in an inefficient cycle of study, re-study and delay, without
necessarily ensuring that the 400 MW of headroom is used
efficiently.\37\ It argues that facilitating a process where state-
jurisdictional competitive solicitation can be used to allocate
scarce interconnection capacity is appropriate given ``state
priorities involving reliability, customer, and environmental
preferences.'' \38\
---------------------------------------------------------------------------
\35\ Arizona Commission Initial Comments at 1-2; Colorado
Commission Initial Comments at 21-27.
\36\ Colorado Commission Initial Comments at 21-27.
\37\ Id.
\38\ Id. at 29.
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21. FERC proposed a similar ``optional resource solicitation''
study in this proceeding. Our proposed process differed in a
critical respect: the resource solicitation was not granted a queue
position,\39\ and being selected in the resource solicitation would
not serve as a mechanism for allocating scarce interconnection
capacity. The possibility of more comprehensively aligning the
interconnection process with competitive resource solicitations
(beyond the jurisdictions where such an approach is currently used)
raises many questions, such as:
---------------------------------------------------------------------------
\39\ Commenters argue that the Commission should have proposed
to grant a queue position to the resource solicitation. See, e.g.,
Colorado Commission Reply Comments at 6; EEI Initial Comments at 5-
6; Xcel Initial Comments at 11-14; Clean Energy Associations Initial
Comments at 51. Without a queue position for the resource
solicitation, the costs identified in the study may not hold true
for the various queue positions of underlying resources.
---------------------------------------------------------------------------
a. How can competitive solicitations and interconnection
processes be designed to effectively coordinate with one another,
especially where the soliciting entity (e.g., a state) is different
from the transmission provider (e.g., an RTO)?
b. To be effective as a mechanism to allocate scarce
interconnection capacity, must a competitive solicitation be paired
with a mechanism such as further strengthened commercial readiness
requirements to limit the pool of resources in the queue not
responding to solicitations, or be designed in a fashion that limits
the interactions in the study process between resources responding
to the relevant solicitation(s) and those that do not? \40\ Can
[[Page 61344]]
such requirements be designed in a manner that is not unduly
discriminatory, and if so, how?
---------------------------------------------------------------------------
\40\ The Colorado Commission argues that if projects to be
studied as part of a competitive solicitation request are
``comingled with a much broader pool of speculative projects,'' the
process could become ``unworkable.'' Colorado Commission Reply
Comments at 5. It argues that, in the RTO context, commercial
readiness requirements will be inadequate for this task, and
suggests that the Commission allow transmission providers to
prioritize native load, using solicitations as a mechanism to
allocate scarce interconnection capacity. See Colorado Commission
Initial Comments at 21-30. In contrast, the Interwest Energy
Alliance argues that while competitive resource solicitations could
be a useful tool to organize a portion of the interconnection
process, they should not ``becom[e] the only pathway through the
cluster study process,'' because ``alternative pathways with
reasonable commercial readiness requirements may . . . reveal
opportunities for independent transmission companies (potentially
associated with independent generation developers) to discover cost-
effective ways to add much-needed transmission expansion through
additional lines along with additional interconnection capacity.''
Interwest Initial Comments at 11-12. Alternatives may be available
that allow for other development opportunities alongside resources
solicitation clusters. For example, a resource solicitation might be
granted its own cluster (so as to allow the soliciting entity to
understand the interconnection costs for its combination of
resources), while providing for serial processing of clusters
composed of resources not participating in the resource
solicitation. See Enel Initial Comments at 72 (arguing that if the
Commission were to adopt an optional resource solicitation process
that designated a queue position, it ``should be a separate queue
cycle with an intermediate queue priority between the Transmission
Provider's annual study clusters'').
---------------------------------------------------------------------------
c. Are safeguards necessary to render not unduly discriminatory
an interconnection process closely linked to a competitive
solicitation process, and if so, what safeguards are necessary or
appropriate? \41\
---------------------------------------------------------------------------
\41\ Several entities highlighted the need for guardrails to
prevent undue discrimination with regard to the Commission's
proposal of an optional resource solicitation study. See, e.g., R
Street Initial Comments at 15-16 (``Guardrails may be helpful to
prevent inefficiencies, preference or undue discrimination''); NARUC
Initial Comments at 26 (``NARUC strongly supports FERC's proposal to
limit the applicability of the optional resource solicitation study
to instances where the resource acquisition is overseen by a state
regulatory authority and is competitive and open. Without this
requirement, NARUC is concerned about the opportunity for load-
serving entities to potentially use the process in a way that would
inappropriately favor the interconnection of company-owned
resources.''); Pine Gate Initial Comments at 43 (advocating for
``appropriate safeguards''). This concern is heightened in the
context where the solicitation is granted a queue position, and/or
where inclusion in the solicitation serves as a commercial readiness
indicator.
---------------------------------------------------------------------------
d. Is linking the interconnection process to competitive
solicitations a viable option in RTO regions, in which state
solicitation processes play a large role in supporting new market
entrants but other paths to commercial viability may also exist?
C. Facilitate a ``Focused'' Interconnection Process
22. Other promising ideas for improving cost certainty and
reducing delays were put forward to the Commission in this
proceeding. In particular, several commenters endorse a more
``focused'' interconnection process that streamlines study scope and
reduces the need for restudies for projects requesting energy-only
service.\42\ As Enel observes, the dilemma of unwieldy studies and
cascading restudy needs, and the delay and cost uncertainty that
stems from these challenges, is ultimately caused by ``the
interdependence amongst Interconnection Customers.'' \43\ Cypress
Creek notes that ``[i]n one extreme example, a group of non-firm,
energy-only resource interconnection service (`ERIS') requests
triggered the need for upgrades up to 1,000 miles away on three
different systems.'' \44\ Accordingly, another way to facilitate a
more workable interconnection process could be to focus study of new
projects on their immediate impact to the system. While the number
of studies pursuant to such a process could still be large, their
scope would be smaller and the potential for cascading restudies
would be greatly reduced.
---------------------------------------------------------------------------
\42\ See, e.g., R Street Institute et al. June 8, 2023 Comments
in Support of Generator Interconnection Reform, at 2 (urging the
Commission to ``[c]onsider a focused interconnection study
approach''); Public Interest Organizations Initial Comments at 50-52
(highlighting the potential for a narrow study process for ERIS
resources to produce significantly faster interconnection
timelines); ACORE Initial Comments at 2-3 (identifying potential
benefits from an interconnection process ``focused on local
transmission needs only''); R Street Initial Comments at 6-7
(arguing that ERCOT's ``connect and manage'' approach is ``perhaps
the most effective'' domestic interconnection process).
\43\ Enel Initial Comments at 2.
\44\ Cypress Creek Initial Comments at 3-4 (citing
Pfeifenberger, Generation Interconnection and Transmission Planning
(Aug. 9, 2022), https://www.esig.energy/download/generation-interconnection-and-transmission-planning-johannespfeifenberger/?wpdmdl=9241&refresh=62f38b6a0e44a1660128106).
---------------------------------------------------------------------------
23. Johannes Pfeifenberger of The Brattle Group notes that,
using a ``connect and manage'' approach, the Electric Reliability
Council of Texas (ERCOT) has interconnected more generation more
quickly than other regions.\45\ Under its system, which ``limits
restudy needs,'' ``[p]rojects can be developed and interconnected
within 2-3 years,'' while ``in other regions, the interconnection
study process itself may take longer than that.'' \46\ Public
Interest Organizations state that ``[t]he UK's `Connect and Manage'
approach has reduced lead times by 5 years compared to its previous
`Invest and Connect' approach.'' \47\
---------------------------------------------------------------------------
\45\ See Pfeifenberger, Planning for Generation Interconnection
2 (May 31, 2022), https://www.brattle.com/wp-content/uploads/2022/05/Planning-for-Generation-Interconnection.pdf (showing that ERCOT
has interconnected more than 8 GW of capacity since 2021,
significantly more than all other RTOs, even those with considerably
greater peak load); see also Cypress Creek Initial Comments at 7.
\46\ Pfeifenberger, Planning for Generation Interconnection at
4.
\47\ Public Interest Organizations Initial Comments at 51.
---------------------------------------------------------------------------
24. While ERCOT's system, which treats all generators as energy-
only resources,\48\ may not provide a model for capacity resources,
it could provide a template for ERIS interconnection. Enel argues
that a ``focused'' approach to interconnection is appropriate for
resources seeking ERIS because ``the Transmission Provider is not
obligated to maintain the transmission system such that ERIS
generators can maintain the same level of as available injection
throughout the life of the generator,'' and accordingly, ``it would
be unreasonable to expect an ERIS generator to mitigate every
constraint identified'' in a more expansive study that uses a lower
transfer distribution factor (TDF) threshold to identify more remote
impacts of the project.\49\ Streamlining ERIS interconnection
assessment could allow transmission providers to focus their study
resources on a smaller number of requests seeking network resource
interconnection service (NRIS).\50\
---------------------------------------------------------------------------
\48\ See Cypress Creek Initial Comments at 7-8.
\49\ Enel Initial Comments at 23.
\50\ See Public Interest Organizations Initial Comments at 50-
52.
---------------------------------------------------------------------------
25. Cypress Creek argues that a more focused study approach
could be implemented across the many regions that provide an NRIS
interconnection option through use of a ``two-step ERIS-NRIS''
process by which the transmission provider could by default study
all resources for ERIS and provide a subsequent process by which an
interconnection customer can add firm rights.\51\ Such a process
might even feasibly provide a faster path to commercial operation
while still facilitating deliverable resources in the long run if
``NRIS requests [could] be connected more quickly on an ERIS basis
while NRIS-related network upgrade study and construction work is
still pending.'' \52\ While the final rule did not adopt the
recommendation for a two-step study process because it was outside
the scope of this proceeding,\53\ individual transmission providers
could propose to implement such a process on their own initiative or
the Commission could take up this suggestion in a subsequent
rulemaking.
---------------------------------------------------------------------------
\51\ Cypress Creek Initial Comments at 8-9.
\52\ Public Interest Organizations Initial Comments at 52.
Cypress Creek highlights that SPP currently allows for interim
energy-only injection service, providing for a subsequent process by
which a generator can add firm rights. Cypress Creek Initial
Comments at 8-9. Such a process to add deliverability rights to ERIS
resources may hold potential to facilitate immediate contributions
to system reliability by these resources, even if such resources are
not fully deliverable or compensated in capacity markets or
accounted for in applicable resource adequacy analysis.
\53\ Final rule at P 183.
---------------------------------------------------------------------------
26. Key questions that this approach raises include:
a. What is the appropriate mechanism to narrow the scope of ERIS
studies to limit the interdependence of projects in the study
process? For example, Enel argues that ERIS resources should be
studied using a minimum TDF threshold of 20 percent,\54\ and that
transmission providers should replace power flow models that assume
extreme grid conditions with more realistic economic
[[Page 61345]]
dispatch models reflecting security constrained economic
dispatch.\55\ How do these approaches interact and are they mutually
exclusive? Are there other appropriate mechanisms?
---------------------------------------------------------------------------
\54\ Enel Initial Comments at 21-25; see also AEE Reply Comments
at 10 (supporting a minimum impact threshold); SEIA Initial Comments
at 11 (same); Clean Energy Associations Initial Comments at 27
(same); Pine Gate Initial Comments at 19 (supporting a minimum
distribution factor impact threshold of 20 percent).
\55\ Enel Initial Comments at 73-74.
---------------------------------------------------------------------------
b. To the extent that ERIS studies are narrowed, are changes to
market dispatch rules or other measures appropriate to account for
the possibility that NRIS resources or resources with long-term firm
transmission service may be curtailed before them? \56\
---------------------------------------------------------------------------
\56\ Xcel objects to the treatment of ERIS resources in RTO
markets because ``[t]hese resources do not bear the costs necessary
to ensure that they are deliverable to load as NRIS resources or
ERIS resources that have acquired long term firm transmission
service do,'' and suggests that, as a consequence, it may be
appropriate for ``ERIS-only service [to] receive a lower dispatch
priority.'' Xcel Initial Comments at 15-16.
---------------------------------------------------------------------------
c. If a two-step study process that considers ERIS analysis
first is appropriate, how should it be designed? \57\ Would it be
effective to provide for a process that allows ERIS resources to be
converted to NRIS after they are constructed? \58\
---------------------------------------------------------------------------
\57\ Some regions currently employ a similar two-step process
that considers local project needs prior to considering
deliverability analysis non-local upgrades based on project
interactions. See, e.g., New York State Department Initial Comments
at 5-6 (describing NYISO's Class Year study process).
\58\ See Public Interest Organizations Initial Comments at 52
(arguing that ``[i]deally, the interconnecting customer would
receive an upfront estimate of typical curtailment levels to be
expected under ERIS and would have the option to apply for NRIS at a
later date if experienced curtailment levels rise above acceptable
levels''). Might such a process be able to efficiently examine a
large number of projects, while still requiring significantly fewer
restudies than existing interconnection processes by examining only
projects that have already secured ERIS?
---------------------------------------------------------------------------
d. Could a focused interconnection approach for ERIS resources
be combined with approaches above that may align the interconnection
process more closely with long-term transmission planning, and/or
use competitive selection processes to allocate scarce
interconnection capacity? \59\
---------------------------------------------------------------------------
\59\ For example, might a transmission provider efficiently
assess ERIS upgrades by studying them using a distribution factor of
20 percent, while simultaneously developing an ``entry fee'' or open
season process aligned with its forward-looking transmission plan to
fund upgrades to guarantee deliverability of NRIS resources?
---------------------------------------------------------------------------
II. General Interconnection Process Improvements
27. In addition to these deeper reforms, commenters identified
several potential incremental improvements to interconnection
processes that were not proposed in the Commission's notice of
proposed rulemaking. I discuss some of the most promising ideas
below, which in some or most cases may be applicable on a generic
basis.\60\
---------------------------------------------------------------------------
\60\ The discussion herein is not intended to comprehensively
capture all potential reforms, but rather to highlight some of the
ideas that may be appropriate for further stakeholder discussion.
---------------------------------------------------------------------------
A. Further Refine Study Assumptions
28. Commenters identified a number of ways that study
assumptions could be further clarified, which may help to streamline
and improve the accuracy of the interconnection process.
1. Clarify ERIS and NRIS Assumptions
29. As Enel points out, the Commission has not to date clarified
what ERIS studies should entail, and it has ``observed vastly
different treatments of'' resources seeking ERIS by different
transmission providers.\61\ As discussed above, a narrow approach to
ERIS studies may facilitate a more streamlined interconnection
process. In addition, some developers contend that grid operators
deploy widely varying study assumptions on issues such as whether
the models used allow for resource re-dispatch to mitigate any
reliability issues that are identified.\62\ They argue that
requiring ``a uniform set of minimum interconnection study
requirements'' would ``facilitate effective, efficient
interconnection queue processing.'' \63\
---------------------------------------------------------------------------
\61\ Enel Initial Comments at 26-27.
\62\ See, e.g., Cypress Creek Initial Comments at 6 n.11 (``Some
RTOs conduct power flow analyses that consider redispatch
opportunities (e.g., NYISO via a manual process, PJM via a
simplified approach) but many do not check if generation redispatch
can address an identified criteria violation.''); Pine Gate Initial
Comments at 54 (``The primary issues identified relative to current
study assumptions are extreme contingency scenarios and overly
conservative operational characteristics and strategies (i.e.,
redispatch protocols).'').
\63\ Pine Gate Initial Comments at 55; see also Cypress Creek
Initial Comments at 6 (``re-dispatch should be a standard
approach''); Clean Energy Associations Initial Comments at 28
(``[T]he study approach to re-dispatching the system to account for
proposed injections . . . is a crucial assumption that is not well
understood or defined, but can trigger significant upgrades and
increase complexity of interconnection process, even for energy-only
(non-firm) interconnection requests. . . . Economic redispatch
should be a standard approach to limit regional upgrades identified
in the study process, particularly for energy-only interconnection
requests.'').
---------------------------------------------------------------------------
30. While the Commission declined to provide direction on how
ERIS should be studied because such requests were outside the scope
of this final rule,\64\ the Commission could take up this topic as
part of a subsequent rulemaking. As an initial step, the Commission
could solicit information from transmission providers documenting
what assumptions and processes are used for ERIS and NRIS,
respectively, to provide a starting point for dialogue around what
study assumptions may be appropriate.\65\ Topics that may benefit
from further clarification include: (1) the definition and scope of
ERIS; (2) the study assumptions that should be implemented in
examining ERIS requests; and (3) the proper scope of study results
and other information that must be provided by transmission
providers to interconnection customers so that they can understand
the results.
---------------------------------------------------------------------------
\64\ Final rule at P 1291.
\65\ See Enel Initial Comments at 26-27.
---------------------------------------------------------------------------
2. Provide for More Accurate Assumptions Regarding Injection of Energy
by Resources
31. The final rule clarifies that its requirement to more
accurately reflect the proposed charging behavior of electric
storage resources extends only to ``the operating assumptions for
withdrawals of energy.'' \66\ In part due to concerns regarding the
administrative burden of extending the proposal to injections or
other resource types, the final rule declines to extend the reform
in these areas.\67\ But while the Commission determined that this
record did not support adopting a structure where such assumptions
would be studied at the request of individual generators, further
examination of how to render operating assumptions more accurate is
warranted.
---------------------------------------------------------------------------
\66\ Final rule at PP 1509, 1524.
\67\ Final rule at P 1529.
---------------------------------------------------------------------------
32. Many commenters argued that the Commission should also
require more accurate assumptions regarding injections of
storage.\68\ And as the final rule acknowledges, many commenters
``support eliminating unrealistic interconnection study assumptions
for resource types other than electric storage resources, such as
assuming that a solar facility will operate at night, or that a wind
resource will produce maximum output during low-wind seasons.'' \69\
Further, several commenters highlighted the benefits of using
realistic fuel-based dispatch assumptions in studies, as
demonstrated by MISO.\70\ The final rule ``acknowledge[s] that fuel-
based dispatch assumptions may be able to address some of the
identified challenges associated with inaccurate modeling
assumptions for all resource types and encourage[s] transmission
providers to
[[Page 61346]]
evaluate the merits of adopting it.'' \71\ Individual transmission
providers remain free to advance such assumptions on an individual
basis, and further examination of this concept could create a record
adequate for the Commission to determine whether to require fuel-
based operating assumptions on a generic basis, and if so, how to
precisely structure such a requirement.
---------------------------------------------------------------------------
\68\ See, e.g., Clean Energy Associations Initial Comments at 53
(``[T]he Clean Energy Associations recommend that the Commission
specify that transmission providers should also not study electric
storage resources as 100% injecting energy during low load periods
by default.'') (emphasis in original); NextEra Initial Comments at
37 (``Transmission providers should not study electric storage
resources as . . . injecting energy during low load and shoulder
periods, as [this does] not reasonably reflect typical operations of
such units.''); Pine Gate Initial Comments at 51 (arguing that the
Commission should prohibit transmission providers from using
unrealistic operating assumptions, which includes ``assuming that
electric storage resources will . . . discharge during light load
periods'').
\69\ Final rule at P 1480 (citing Enel Initial Comments at 74;
AES Clean Energy Initial Comments at 24-25; Ameren Initial Comments
at 29; CREA and NewSun Initial Comments at 92; Cypress Creek Initial
Comments at 9-10; Invenergy Initial Comments at 59-61; Microgrid
Resources Initial Comments at 7-8; Pine Gate Initial Comments at 54;
Public Interest Organizations Initial Comments at 48-49; R Street
Initial Comments at 16; rPlus Initial Comments at 6); see also id.
(``Ameren, Cypress Creek, Microgrid Resources, NARUC, Pine Gate, and
rPlus all request that the Commission extend this reform to allow
any resource type, not just electric storage or co-located
resources, to request that interconnection studies be based on their
particular operating assumptions and characteristics.'').
\70\ See Invenergy Initial Comments at 59-61 (highlighting
MISO's practice, as well as ``recently approved more realistic fuel-
based dispatch'' assumptions in SPP); see also Enel Initial Comments
at 77-78 (arguing that the Commission should require fuel-based
dispatch of generators in modeling ``[i]f Power flow analyses are
not replaced with SCED studies''); Interwest Reply Comment at 15
(urging the adoption of ``realistic fuel-based dispatch
assumptions'').
\71\ Final rule at P 1529.
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B. Use Automation To Facilitate More Efficient Interconnection
33. Currently, the interconnection study and queue process is
heavily labor-intensive, and market participants frequently suffer
from shortages of qualified study staff, including transmission
planners and engineers, in the face of a high volume of
interconnection requests.\72\ Accordingly, numerous commenters noted
the great potential of automation to conserve staffing resources and
speed up this process.\73\ The broad term ``automation'' in this
context can refer to a wide variety of time-saving steps to bring
the queue process fully into the digital age, such as standardized
data entry and collection; a web-based application process and data
submission with automated validation; automated study model
construction and study processes; and pre-population of manufacturer
models for relevant equipment.\74\ Commenters requested steps,
including the convening of a technical conference, to study how the
interconnection process might become more robustly automated to save
resources \75\ and facilitate other benefits, such as the more
robust integration of grid enhancing technologies (referred to as
``alternative transmission technologies'' in the final rule) into
the bulk power system.\76\ Of course, continuing to support career
path development in this area will remain critical. At the same
time, as we have seen in many other industries, automation done
right has the potential to save a great deal of unnecessary time,
effort, and expense. I support more deeply exploring the range of
options available in this domain.
---------------------------------------------------------------------------
\72\ See, e.g., Cal. Indep. Sys. Operator Corp., 176 FERC ]
61,207, at PP 7, 21 (2021) (noting CAISO's statement of its
difficulty in finding sufficient expert staff and consultants to
timely process a large cluster study); MISO, Informational Report,
Docket No. ER19-1960, at 12 (filed Nov. 16, 2020) (noting similar
delays); see also Akielly Hu, US Clean Energy Rollout Continues to
Be Hamstrung by Grid Challenges, Canary Media (June 13, 2023),
https://www.canarymedia.com/articles/transmission/us-clean-energy-rollout-continues-to-be-hamstrung-by-grid-challenges (noting that
``interconnection studies rely on a workforce of engineers at grid
operators, and experts say there are not enough to get the job
done,'' and quoting the author of Lawrence Berkeley National
Laboratory's Queued Up study as saying this staffing issue
represents a ``fundamental constraint'' on queue processing);
Avangrid Reply Comments at 12 (``Transmission providers are
processing unprecedented numbers of interconnection requests at a
time when these qualified transmission planners and engineers are
scarce.''); APPA-LPPC Initial Comments at 13 (noting that
``available industry system simulation tools'' can in some cases
ameliorate ``labor-intensive study obligations'').
\73\ See, e.g., California Energy Storage Alliance Initial
Comments at 5; NextEra Initial Comments at 14, 40; MISO Initial
Comments at 26 n.107; ACORE Initial Comments at 5; ACE-NY Initial
Comments at 2-3; Pine Gate Reply Comments at 5.
\74\ NextEra Initial Comments at 14, 40.
\75\ See NextEra Initial Comments at 14; Pine Gate Reply
Comments at 5.
\76\ See, e.g., WATT Coalition Reply Comments at 2-3.
---------------------------------------------------------------------------
C. Reduce Delay and Cost Overruns in Network Upgrade Construction
34. While there appears to be a lack of good data about the
timing and cost of construction of network upgrades once an
interconnection agreement is executed,\77\ developers have raised
concerns that they have little recourse if such upgrades are delayed
or subject to cost increases.\78\ As noted above, the Lawrence
Berkeley National Laboratory's Queued Up report does not trace the
cause of delays between execution of a project's interconnection
agreement and commercial operation, but shows that the average
timespan for this period has increased from roughly 17 months for
projects built between 2007-2014 to around 22 months for projects
built between 2015-2022, with projects in CAISO showing particularly
heightened delays.\79\ Enel contends that ``upgrades for
Interconnection Customers are only overseen by the Commission for
adherence to good utility practice standards,'' and ``[t]he
Commission does not review the timeliness or cost of upgrades unless
an Interconnection Customer elects to file an LGIA in unexecuted
form and challenge these specific assumptions,'' a choice that could
result in ``costly delays in project timelines that often outweigh
any benefit that might be gained from a favorable Commission
decision.'' \80\
---------------------------------------------------------------------------
\77\ See Queued Up 2023 at 30 (``[L]imited data were available
to analyze typical durations from interconnection agreement to
commercial operations.'').
\78\ See, e.g., Enel Initial Comments at 50 (``Under the current
standard[] of . . . good utility practice, there is a notable lack
of incentive, and often a disincentive, for Transmission Owners to
perform . . . EPC work in a timely and cost-conscious manner.'');
Pine Gate Initial Comments at 64 (expressing concern that limiting
the option for interconnection customers to self build will
``further exacerbate construction delays and . . . ultimately harm
consumers'').
\79\ See Queued Up 2023 at 30. ``The typical solar project built
in CAISO since 2018 took over 4 years to reach commercial operations
after securing an interconnection agreement; those built in 2022
averaged over 6 years.'' Id. (emphasis in original).
\80\ Enel Initial Comments at 50-51.
---------------------------------------------------------------------------
35. Accordingly, it may be appropriate for the Commission to
take action to facilitate more timely and cost-conscious
construction of such upgrades. One initial step could be for the
Commission to gather more data concerning delays that may affect the
commercial operation date of a generating facility, and to establish
``metrics associated with the delayed construction of facilities.''
\81\ The Commission could also consider adopting penalties for
delays or cost overruns, or an incentive structure for transmission
providers that carry out construction on time and on budget.\82\
---------------------------------------------------------------------------
\81\ Pine Gate Initial Comments at 64.
\82\ This issue has also arisen in the context of the
Commission's docket on transmission planning and cost management.
See, e.g., Advanced Energy Economy, Pre-Conference Comments, Docket
No. AD22-8, at 2-3 (filed Oct. 4, 2022) (noting that a ``major
driver[] of transmission cost increases in recent years [has] been .
. . incremental network upgrades identified in generator
interconnection studies''). In that docket, the Commission has
considered, and some commenters have supported, among other
measures, new independent entities to monitor transmission planning.
See, e.g., Electricity Transmission Competition Coalition, Comments,
Docket No. AD22-8, at 6 (filed Oct. 4, 2022); Harvard Electricity
Law Initiative, Comment, Docket No. AD22-8, at 18-31 (filed Mar. 23,
2023); R Street Institute, Comments, Docket No. AD22-8, at 6-7
(filed Mar. 23, 2023). To the extent that such entities are
established, the Commission could also consider tasking them with
monitoring the timely and cost-conscious construction of network
upgrades.
---------------------------------------------------------------------------
36. Finally, it may be appropriate to reconsider the scope of
``stand alone network upgrades'' to include facilities that may be
needed for multiple interconnection customers, and to develop a
process that either designates an interconnection customer to build
such upgrades, or competitively solicits bids to award construction
rights. While this final rule ``clarif[ies] that, for a network
upgrade to be eligible for treatment as a stand alone network
upgrade, the network upgrade must be required for only one
interconnection customer,'' \83\ it does so in order to ``explicitly
maintain[] the status quo.'' \84\ The Commission's Notice of
Proposed Rulemaking examined changes to the definition of stand
alone network upgrade necessary ``to implement a first-ready, first-
served cluster study process,'' \85\ and did not contemplate any
mechanism to ``prevent lengthy conflict and negotiations in
instances where multiple interconnection requests trigger the need
for a network upgrade'' beyond restricting such upgrades to those
that are required for only one interconnection customer.\86\
---------------------------------------------------------------------------
\83\ Final rule at P 192.
\84\ Id. at P 193.
\85\ Improvements to Generator Interconnection Procedures and
Agreements, Notice of Proposed Rulemaking, 179 FERC ] 61,194, at P
65 (2022).
\86\ Id.; see final rule at P 194 (requests to ``expand the
definition of stand alone network upgrade . . . are outside the
scope of this proceeding, which is not proposing to modify the scope
of interconnection customers' option to build certain stand alone
network upgrades but rather is only revising definitions insofar as
is necessary to implement reforms adopted elsewhere in this final
rule'').
---------------------------------------------------------------------------
37. Ideas were put forth in this proceeding, however, that may
hold potential to efficiently allocate construction rights and
obligations. In particular, one idea is that ``the Commission should
consider establishing a new third-party construction option''
pursuant to which stand alone network upgrades could ``be bid out
and built by third parties, such as non-incumbent utilities,
independent transmission developers or contractors.'' \87\ To
develop
[[Page 61347]]
such an option, the Commission would need to consider ``details such
as the posting of minimum design standards that must be met, the
criteria for choosing a winning bidder, the incentives to hold the
winning bidder to cost and schedule estimates, responsibility for
cost overruns, rights to own, operate and maintain the Stand-Alone
Network Upgrades, and the profit awarded to the winning bidder.''
\88\ Further process is warranted to examine this concept.\89\ I
encourage transmission providers to work with interconnection
customers and other stakeholders to explore structures such as this
that may provide greater certainty surrounding the timing and cost
of certain network upgrades.
---------------------------------------------------------------------------
\87\ Enel Initial Comments at 52; see also Pine Gate Initial
Comments at 63-64 (proposing that ``the Commission should grant the
interconnection customer with the largest projected impact on a
potential Stand Alone Network Upgrade facility the ability to elect
the option to build with priority falling to each interconnection
customer based on their interconnection request having the next
largest impact on the Stand Alone Network Upgrade'').
\88\ Enel Initial Comments at 52.
\89\ Enel notes that ``[t]he Commission could establish
workshops or other mechanisms to further explore and develop these
details.'' Id.
---------------------------------------------------------------------------
D. Address Challenges Faced by Projects Serving Tribes and Tribal
Communities
38. Beyond these recommendations to further facilitate efficient
interconnection of new resources, I encourage transmission providers
to examine potential changes to address important considerations of
equity and fairness related to interconnection of resources serving
or developed by Tribes. In particular, I encourage transmission
providers to examine whether any exceptions or waivers to the
commercial readiness requirements or withdrawal penalties framework
are appropriate for certain projects serving Tribal nations or their
communities. While the commercial readiness deposit and withdrawal
framework adopted in this final rule hold the potential to make
interconnection processes more efficient, they may act as a barrier
to projects serving or developed by Tribes in cases where such
projects adopt unique ownership and financing structures.\90\ This
may also be a concern with regard to projects developed by, or in
partnership with, communities that have been historically
marginalized or overburdened by pollution, and I encourage further
dialogue examining whether that is the case.
---------------------------------------------------------------------------
\90\ See OSPA Initial Comments at 8, 15-16 (arguing that SPP's
current security deposit regime has been ``an insuperable barrier to
renewable energy development on Tribal lands'').
---------------------------------------------------------------------------
39. For example, the Commission recently granted a waiver to the
SAGE Development Authority (SAGE), an entity developing a wind
generation project on Tribal land, to allow it more time to post
financial security as required by SPP.\91\ SAGE was created by the
Standing Rock Sioux Tribe and is developing the project through ``a
community-led process designed to, among other things, implement
Tribal values and ensure that the financial benefits of the Project
will in turn support further community projects intended to address
disparities around public health and other issues.'' \92\ The
Commission granted SAGE's requested waiver in part because ``due to
its unique Tribal business structure, it [was] unable to secure
credit in advance'' of the relevant security deposit deadline.\93\
Waiver ``provide[d] SAGE the time necessary to secure additional
credit.'' \94\
---------------------------------------------------------------------------
\91\ See SAGE Development Authority, 182 FERC ] 61,180 (2023).
\92\ Id. at P 4.
\93\ Id. at P 20.
\94\ Id.
---------------------------------------------------------------------------
40. To the extent this rule's deposit requirements subject
Tribal projects to greater risk, the need for similar waivers could
be heightened. Accordingly, I encourage further inquiry into whether
certain projects developed to serve Tribal communities or
disadvantaged communities may have other characteristics that
uniquely demonstrate commercial readiness as alternatives to the new
deposit requirements. The inquiry could also consider other measures
that may allow such projects to overcome any unique barriers that
they face.\95\
---------------------------------------------------------------------------
\95\ See also Energy Keepers Initial Comments at 2-3 (arguing
that it would not be ``unduly discriminatory or preferential for
transmission providers to expedite the processing of Native American
interconnection requests,'' considering ``prior environmental
justice inequities.'').
---------------------------------------------------------------------------
41. While challenges remain, the Commission's issuance of a
final rule today is an important step forward in the effort to
address interconnection backlogs around the country. The ideas for
continuing reform that I describe in this concurrence represent best
practices and innovative thinking by regions and stakeholders
considering how to solve the challenges the final rule does not
address. I encourage transmission providers, interconnection
customers and other stakeholders to consider the rule's requirements
a strong baseline and not a ceiling, and to continue to engage on
the topics I have addressed herein.
For these reasons, I respectfully concur.
-----------------------------------------------------------------------
Allison Clements,
Commissioner.
Improvements to Generator Interconnection Docket No. RM22-14-000
Procedures and Agreements--
CHRISTIE, Commissioner, concurring:
1. I concur to this final rule,\1\ which represents major
progress towards the primary goal we set out to accomplish last year
when we issued the NOPR: To move from a system of ``first come,
first served'' to a system of ``first ready, first served'' by
identifying generation projects in the interconnection queues that
are commercially more viable and then moving them ahead of requests
that are speculative and which have been causing major backlogs. I
write separately about four issues contained within:
---------------------------------------------------------------------------
\1\ Improvements to Generator Interconnection Procedures and
Agreements, 184 FERC ] 61,054 (2023) (Final Rule).
---------------------------------------------------------------------------
I. Evaluation of Alternative Transmission Technologies (Section
III.C.2.iii)
2. Alternative transmission technologies, or grid-enhancing
technologies (GETs), is a short-hand categorical term that covers a
sweeping array of very different technologies. A GET may hold the
potential of squeezing more juice--literally--out of the existing
transmission grid. By increasing the capacity of the existing grid,
a GET could reduce or even eliminate the need for the future
construction of new transmission assets. So the potential for cost-
savings from the use of GETs is too important to ignore.
3. One of the most promising GETs--dynamic line ratings (DLRs)--
could potentially save billions of dollars in avoided costs for new
transmission assets. DLRs are not covered by this final rule, but
are the subject of a separate proceeding,\2\ and I hope we will use
the record of that proceeding to move forward on a proposed rule to
require implementation of DLRs when and where DLRs will be
technologically sound and cost-effective.
---------------------------------------------------------------------------
\2\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110
(2022).
---------------------------------------------------------------------------
4. While DLRs have tremendous potential and should be pursued,
there is a problem with any categorical regulatory mandate to use
GETs, which is this: Some GETs work somewhere but not everywhere;
some work sometimes but not all the time; some only work under
certain weather conditions; some don't work at all, or at least not
as advertised; and some are only cost-effective where the congestion
costs are greater than the cost of the GET itself.
5. Given these engineering and economic realities, some
knowledgeable transmission planning experts have argued that GETs
categorically are not planning tools, but rather are operational
applications that should be deployed when and where their efficacy
is likely and can be appropriately proven. If they work in the real
world as advertised, they could reduce or eliminate the need for
future network upgrades or even backbone transmission assets, but
they should not be mandated as planning tools or as potential
substitutes for network upgrades caused by interconnection
requests.\3\
---------------------------------------------------------------------------
\3\ See PJM Initial Comments at 68 (``PJM therefore cautions the
Commission not to conflate the operational benefits of alternative
transmission technologies . . . with the need to address significant
capacity enhancement needs (short and long-term) or long-range
transmission needs under rapid growth or changing resource mix
scenarios.''); MISO Initial Comments at 121-22 (``Further, although
these technologies may be evaluated, the technologies identified by
the Commission still may not provide the appropriate solution from a
planning perspective. Many of the technologies identified are
appropriately considered as operational tools or short-term
solutions but are not necessarily appropriate for planning to
support a particular generator interconnection.'') (emphases added,
footnote omitted).
---------------------------------------------------------------------------
6. Against this cautious view of GETs, I recognize the
counterargument that transmission owners themselves have an economic
incentive to favor the construction of costly new transmission
assets rather than deploy GETs to squeeze out more capacity. New
transmission assets can be rate-based, and the transmission owner
can take advantage of the very generous formula rate treatment
offered here at the Commission (another issue I have raised concerns
about).\4\
[[Page 61348]]
So to overcome this incentive against GETs deployment, proponents
argue that the Commission should require it.
---------------------------------------------------------------------------
\4\ See, e.g., Sw. Power Pool, Inc., 183 FERC ] 61,151 (2023)
(Clements, Comm'r, and Christie, Comm'r, concurring at P 4)
(``Indeed, the Commission grants formula rate treatment, including a
presumption of prudence, to filings from transmission owners seeking
cost recovery for transmission projects without regard to whether
such projects have been subject to a serious vetting in any
proceeding in which both need and prudence of cost must be
demonstrated by the transmission developer. We have expressed
concerns about this lack of oversight previously, and this filing by
SPP illustrates exactly why that is a major problem pertinent to the
issue of rising consumer costs for transmission.''), https://www.ferc.gov/news-events/news/commissioner-clements-and-commissioner-christies-joint-concurrence-spp-project; Transmission
Planning and Cost Management, Technical Conference, Docket No. AD22-
8-000, Tr. 16:4-20:11 (Comm'r Mark Christie) (Oct. 6, 2022).
---------------------------------------------------------------------------
7. But--as usual--the economic incentives argument has more than
one side. The companies that sell GETs (and the organizations they
fund) stand to profit from any regulation mandating that their
products must be used. And generation developers (and the
organizations they fund) have every incentive to lobby for a
regulation mandating the use of GETS as a way to avoid paying the
costs of the traditional network upgrades made necessary by their
interconnections. This incentive is particularly salient in RTOs/
ISOs that use participant funding to pay for the costs of network
upgrades caused by the interconnecting customers (i.e., developers).
8. So--again, as usual with sweeping Commission regulations--
there is plenty of rent-seeking to go around. Striking the
appropriate balance--one that is in the public interest--is a
challenge. I believe this final rule--unlike the NOPR--does strike
the right balance, in terms of a requirement simply to evaluate GETs
in determining the appropriate network upgrade.
9. Importantly, the final rule makes it explicitly clear that
while it is requiring the evaluation of certain listed GETs in the
interconnection studies process, it is not requiring--nor even
suggesting--that a GET must be deployed as an alternative to a
necessary network upgrade. Indeed, the final rule explicitly says:
This final rule does not create a presumption in favor of
substituting alternative transmission technologies for necessary
traditional network upgrades, either categorically or in specific
cases. This final rule is agnostic as to whether, in a specific
case, an alternative transmission technology is an acceptable
alternative to a traditional network upgrade . . . .
10. The final rule also makes it explicitly clear that the
determination in each case is to be made at the sole discretion of
the transmission provider (i.e., RTO/ISOs or non-RTO transmission
providers), applying good utility practices, applicable reliability
standards, and other applicable regulatory requirements. To avoid
continual litigation aimed at the transmission provider's
determination in specific cases when a generation developer does not
want to pay the costs of a network upgrade, the final rule
explicitly makes clear that it is requiring a process of evaluation,
not mandating outcomes in specific cases. And it makes clear that if
the transmission provider performs the evaluation as required in the
final rule, it has complied with the final rule.
11. This agnosticism as to outcomes in specific cases is
critically important. Transmission providers must require the
appropriate network upgrade necessary to fix the reliability issue
caused by the interconnection request. If a GET is used instead, and
it fails to fix the reliability issue caused by the interconnection,
a later network upgrade will be required, one potentially more
costly than the network upgrade originally required. And who will
pay those costs? Certainly in RTOs/ISOs using participant funding,
load (retail consumers) should not. Sticking those costs on
consumers would raise a serious question of unjust and unreasonable
rates.
12. In summary though, I believe that this final rule strikes
the appropriate balance between requiring the evaluation of GETs,
but not mandating the use of a GET in specific cases unless the
transmission provider--and only the transmission provider--
determines it would work from a real-world applicability standpoint.
In all cases, the transmission provider should apply its engineering
expertise to come to the right determination as to the necessary
network upgrades. This final rule requires nothing less.
II. Repayment of Affected Systems Network Upgrade Costs (Section
III.B.2.c.iii(c))
13. The final rule essentially codifies existing precedent as to
the repayment of affected systems network upgrade costs when a
generation developer interconnects at or near a seam between an RTO
(which uses participant funding to pay for interconnection costs)
and a non-RTO, vertically integrated load-serving utility that uses
a crediting mechanism.
14. Three recent cases involving Duke Energy Progress, LLC
(Duke) in North Carolina \5\ illustrate my concern about the
Commission's repayment policy.\6\ In these cases, generation
developers located within the PJM footprint, which extends into a
corner of northeastern North Carolina due to Dominion Energy, Inc.'s
PJM membership, chose to interconnect very close to the seam with
Duke's North Carolina territory. Duke is a vertically integrated
utility regulated by the North Carolina Utilities Commission (NCUC)
on an Integrated Resource Plan (IRP) model. Duke builds transmission
(and generation) subject to an IRP approved by the NCUC, and the
costs of network upgrades caused by that new generation are paid by
retail consumers. Since the NCUC approves new generation through its
IRP process, which includes the costs to interconnect that new
generation, the NCUC decides the generation and interconnection
costs that are appropriately paid for by retail consumers.
---------------------------------------------------------------------------
\5\ Duke Energy Progress, LLC, 181 FERC ] 61,229 (2022), reh'g
deemed denied, 182 FERC ] 62,088 (2023); Duke Energy Progress, LLC,
180 FERC ] 61,005, order on reh'g, 181 FERC ] 61,197 (2022)
(Edgecombe Rehearing Order); Duke Energy Progress, LLC, 177 FERC ]
61,001 (2021), order on reh'g, 179 FERC ] 61,007 (2022) (American
Beech Rehearing Order). My concurrences to the Edgecombe Rehearing
Order and American Beech Rehearing Order set forth my concerns as
well. See Edgecombe Rehearing Order, 181 FERC ] 61,197 (Christie,
Comm'r, concurring) (Edgecombe Concurrence), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-rehearing-duke-energy-progress; American Beech Rehearing Order, 179
FERC ] 61,007 (Christie, Comm'r, concurring).
\6\ See Standardization of Generator Interconnection Agreements
& Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ]
61,103, at PP 693-696, 720-739 (2003), order on reh'g, Order No.
2003-A, 69 FR 15932, 106 FERC ] 61,220, at PP 584-586, order on
reh'g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ]
61,287 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (July
18, 2005), 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of
Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007). I note
that this policy applies not just to affected systems network
upgrades but also network upgrades on the host transmission
provider's system.
---------------------------------------------------------------------------
15. In these three cases, however, Duke was considered an
``affected system'' for the interconnection costs caused by the
generation developers located just across the seam in PJM's
footprint. So the affected systems network upgrades were not paid by
the developer (creating an incentive to locate close to the seam),
but by Duke's retail consumers through crediting pursuant to
Commission policy. And unlike the costs of transmission and network
upgrades built with the prior approval of the NCUC, no state-
approved IRP controls the construction of generation in the PJM
footprint in North Carolina. Not surprisingly, the NCUC and the NCUC
Public Staff, which represents consumers in North Carolina, filed
vigorous--and in my opinion, persuasive--comments in several
proceedings on these issues.\7\
---------------------------------------------------------------------------
\7\ See NCUC and NCUC Public Staff Initial Comments at 6; NCUC
and NCUC Public Staff, Joint Comments, Docket No. RM21-17-000, at 12
(filed Aug. 17, 2022); NCUC Public Staff, Comments, Docket No. RM21-
17-000, at 13-15 (filed Oct. 12, 2021); NCUC Public Staff Reply
Comments, Docket No. RM21-17-000, at 6 (filed Nov. 30, 2021)
(``[U]nder the crediting policy, ratepayers are left paying the bill
regardless of the benefits, or lack thereof, they received from the
network upgrades. Further, the [NCUC] Public Staff believes that
[interconnection customers] are beginning to `game' the system by
placing large merchant plants into the interconnection queue in
congested areas to take advantage of the crediting policy and fill
what excess capacity is then created with state jurisdictional
projects that would normally have to fund the upgrades
themselves.''); see also NCUC Public Staff, Motion to Intervene Out-
of-Time and Comment, Docket No. ER21-1955-003, at 1-9 (filed Nov. 9,
2021) (generally arguing, inter alia, that Duke customers will not
or will only minimally benefit from upgrading its system to
accommodate power being interconnected and delivering to PJM; that
Duke ratepayers are subsidizing costs that should be paid for by the
developer, the party that is both causing the costs to be incurred
and reaping the resulting benefits; that given the proliferation of
merchant generation trying to locate in this area of North Carolina,
the NCUC Public Staff is concerned that Duke ratepayers will be
burdened with potentially hundreds of millions of dollars in
affected systems network upgrade cost as a result of the
Commission's actions; and that the project in American Beech had not
yet received a CPCN from North Carolina so any decision put the
``cart before the horse.'').
---------------------------------------------------------------------------
[[Page 61349]]
16. While I recognize that the results in these cases were
consistent with prior precedent and Order No. 2003,\8\ I think that
precedent and, if necessary, Order No. 2003 itself, should be
revisited as to the affected systems repayment policy. I concur to
the issuance of this final rule because this final rule is not the
appropriate place to revisit the issue and because the final rule by
its own terms does not go beyond existing precedent.
---------------------------------------------------------------------------
\8\ See, e.g., Edgecombe Concurrence.
---------------------------------------------------------------------------
III. Inappropriate Allocation of Certain Costs to Consumers
17. As described below, while I support the final rule, I am
concerned that study delay penalties on RTOs/ISOs and the costs of
transmission provider heatmaps used as a tool for interconnection
customers will be inappropriately allocated to consumers even though
they both appear to provide much more of a benefit to generation
developers than consumers. I address each in turn.
A. Study Delay Penalties on RTO/ISOs (Section III.B.1.c.x)
18. The final rule adopts the NOPR proposal to eliminate the
reasonable efforts standard from the pro forma LGIP, and it adds a
new section to the pro forma LGIP that imposes penalties on
transmission providers who miss study deadlines. I have no qualms
about assessing penalties on non-RTO/ISO transmission providers and
transmission-owning members of RTOs/ISOs. These are generally
investor-owned companies and stockholders will bear such costs. On
the other hand, I have concerns about assessing study penalties on
RTOs/ISOs, as they are not-for-profit entities who do not have
stockholders. In my concurrence to the NOPR, I explained:
[T]he penalty provisions do not answer definitively the most
important question of all: Who will pay these penalties in an RTO or
ISO which has no stockholders? Consumers certainly should not pay,
directly or indirectly.\9\
---------------------------------------------------------------------------
\9\ Improvements to Generator Interconnection Procs. &
Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ] 61,194 (2022)
(Christie, Comm'r, concurring at P 3) (NOPR Concurrence), https://www.ferc.gov/news-events/news/e-1-commissioner-christies-concurrence-improvements-generator-interconnection.
The final rule does not fully address this question and does not
provide complete assurance that consumers will be protected.
19. However, the final rule does have some protections in place
to protect against consumers ultimately having to pay for study
delay penalties. First, the final rule modifies the NOPR proposal to
prohibit non-RTO/ISO transmission providers and transmission-owning
members of RTOs/ISOs from recovering study delay penalty amounts
through transmission rates.\10\ Second, the final rule modifies the
NOPR proposal to adopt a new provision in our regulations specifying
that, for RTOs/ISOs in which the transmission-owning members perform
certain interconnection studies, the study delay penalties will
automatically be imposed directly on the transmission-owning
member(s) that conducted the late study.
---------------------------------------------------------------------------
\10\ Final rule, Section III.B.1.c.ix.
---------------------------------------------------------------------------
20. But these provisions still leave open the question of how
RTOs/ISOs will recover those study delay penalties that are not
automatically imposed on a transmission-owning member. The final
rule essentially punts on this question, explaining that RTOs/ISOs
may submit an FPA section 205 filing to propose a default structure
for recovering study delay penalties and/or make individual FPA
section 205 filings to recover the costs of any specific study delay
penalties. I urge that any such RTO/ISO filing make protections to
consumers paramount.
B. Cost of Heatmap (Section III.A.1.c.iii)
21. This final rule requires transmission providers to publicly
post a ``heatmap'' with certain information after the completion of
each cluster study and cluster restudy period. The final rule finds
that the heatmap will benefit interconnection customers, including
prospective interconnection customers, by providing them further
transparency as to expected congestion and potential network
upgrades and therefore will reduce the number of speculative
interconnection requests. I agree that a requirement to post a
heatmap will greatly benefit interconnection customers and support
the requirement's addition to the pro forma LGIP.
22. Where I am concerned, however, is how the heatmap should be
funded. The final rule clarifies that transmission providers, not
interconnection customers, are responsible for paying the costs
associated with the heatmap requirement. Further, the final rule
contemplates transmission providers recovering the costs of the
heatmap from transmission customers and ex ante determines that such
rate treatment is appropriate because interconnection queue
efficiency benefits transmission customers. Commission policy may
dictate that interconnection queue efficiency benefits transmission
customers; \11\ 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.\12\
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\11\ Whether or not I agree with Commission policy is another
matter entirely. See, e.g., supra PP 13-16.
\12\ Joint Fed.-State Task Force on Elec. Transmission,
Technical Conference, Docket No. AD21-15-000, Tr. 37:9-20 (Comm'r
Mark Christie) (Nov. 15, 2022) (``Let's put this in context, and
talk about what's really at stake here. Last year national
transmission rate base went up over 9 percent. That's the third
consecutive year it's gone up over 9 percent. What goes into rate
base, goes into consumer's bills. Every nickel. And in the last
decade, national transmission rate base has almost tripled, and . .
. at 9 percent it's going to double again in the next eight years.
This is all going into customer's bills. So this is a hugely
important issue. This is a ton of money, this is big, big money.'').
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23. I believe this issue merits further scrutiny, and I look
forward to future comments on this issue.
IV. ``Hold Harmless'' Provisions (Sections I, III.A.6.c.iii, IV.C)
24. In my concurrence to the NOPR, I wrote that while I
supported the proposed queue reforms (subject, of course, to
comment):
I also caution strongly that we should avoid undermining through
this NOPR what the RTOs/ISOs, working through their stakeholder
processes, are already doing to fix their own queue problems. We
should recognize that each RTO/ISO is different and faces unique
local challenges and needs. The queue reforms proposed in today's
NOPR should be seen more as guideposts or general standards rather
than unyielding mandates that refuse to take local solutions into
consideration. I would allow RTOs/ISOs the opportunity to
demonstrate that if their own efforts to enact queue reforms achieve
the same goals in a different, but equally effective manner, their
individual reform may be acceptable in complying with any final
rule. While this NOPR currently recognizes the potential for
regional flexibility, I hope the need for such flexibility is
explicitly memorialized in any final rule.\13\
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\13\ NOPR Concurrence at P 4 (emphasis added, footnote omitted).
25. This final rule contains language that is intended to
recognize the earnest and good-faith efforts undertaken by the RTOs
to enact queue reforms. Some RTOs, such as PJM, have already
launched extensive queue reforms; others, such as CAISO, are hard at
work on developing queue reforms.
26. I concur because this final rule does contain language that
is at least intended to recognize the efforts of RTOs to act on
their own queue reforms without waiting on a Commission rulemaking.
Whether the language of this final rule adequately recognizes or
``holds harmless'' those efforts will be an issue for compliance
filings.
For these reasons, I concur.
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Mark C. Christie,
Commissioner.
[FR Doc. 2023-16628 Filed 9-5-23; 8:45 am]
BILLING CODE 6717-01-P